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pdfUNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. RM13-______
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
PRC-005-2 (PROTECTION SYSTEM MAINTENANCE)
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595– facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
William H. Edwards
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
February 26, 2013
TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY .................................................................................................... 2
II.
NOTICES AND COMMUNICATIONS ................................................................................ 4
III.
BACKGROUND ................................................................................................................. 5
A.
Regulatory Framework ..................................................................................................... 5
B.
History of PRC-005 and Project 2007-17 ........................................................................ 6
1.
PRC-005 and Related Reliability Standards ................................................................. 6
2.
NERC System Protection and Control Task Force ...................................................... 8
IV.
JUSTIFICATION FOR APPROVAL.................................................................................. 9
A.
Basis for Approval and Purpose of Proposed PRC-005-2 ............................................... 9
1.
Improvements Reflected in Proposed PRC-005-2...................................................... 11
2.
Commission Directives............................................................................................... 12
3.
Requirements in Proposed PRC-005-2 ....................................................................... 14
B.
V.
Enforceability of Proposed PRC-005-2.......................................................................... 18
SUMMARY OF RELIABILITY STANDARD DEVELOPMENT PROCEEDINGS ........ 19
A.
Overview of the Standard Drafting Team ...................................................................... 19
B.
Proposed PRC-005-2 Development History .................................................................. 19
VI.
1.
PRC-005-2 Development – Standard Authorization Request .................................... 19
2.
PRC-005-2 Development – Reauthorization .............................................................. 23
CONCLUSION .................................................................................................................. 27
Exhibit A
Order No. 672 Criteria
Exhibit B
Proposed Reliability Standard PRC-005-2
Exhibit C
Implementation Plan for Proposed Reliability Standard PRC-005-2
Exhibit D
Technical Justification: PRC-005-2 Protection System Maintenance
Exhibit E
PRC-005-2: Supplementary Reference and FAQ
Exhibit F
Technical Justification for Maintenance Intervals
Exhibit G
Mapping Document
Exhibit H
Consideration of Comments for Proposed Reliability Standard PRC-005-2
Exhibit I
Discussion of Assignments of VRFs and VSLs
Exhibit J
Record of Development of Proposed Reliability Standard PRC-005-2
i
TABLE OF CONTENTS
Exhibit K
Standard Drafting Team Roster for NERC Standards Development Project 200717 (Protection System Maintenance and Testing)
ii
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. RM13-______
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
PRC-005-2 (PROTECTION SYSTEM MAINTENANCE)
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 2 of the
Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”) 3 hereby submits for Commission approval:
•
proposed Reliability Standard PRC-005-2 – Protection System 4 Maintenance
(Exhibit B);
•
six new definitions (Protection System Maintenance Program, Unresolved
Maintenance Issue, Segment, Component Type, Component, and Countable Event);
•
the implementation plan for proposed PRC-005-2 (“Implementation Plan”) (Exhibit
C);
•
the Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for
proposed PRC-005-2 (Exhibit B and Exhibit I);
NERC also requests the retirement of the following Reliability Standards, effective in
accordance with the Implementation Plan:
1
16 U.S.C. § 824o (2006).
18 C.F.R. § 39.5 (2012).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Amer. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
4
Capitalized terms used but not defined in this Petition are intended to have the same meaning given to such
terms in the Glossary of Terms Used in NERC Reliability Standards, available at:
http://www.nerc.com/files/Glossary_of_Terms.pdf. (“NERC Glossary”)
2
1
•
PRC-005-1.1b (Transmission and Generation Protection System Maintenance and
Testing);
•
PRC-008-0 (Implementation and Documentation of Underfrequency Load Shedding
Equipment Maintenance Program);
•
PRC-011-0 (Undervoltage Load Shedding System Maintenance and Testing); and
•
PRC-017-0 (Special Protection System Maintenance and Testing).
As required by Section 39.5(a) 5 of the Commission’s regulations, this petition presents
the technical basis and purpose of the proposed Reliability Standard, a summary of the
development proceedings conducted by NERC for proposed PRC-005-2, and a demonstration
that the proposed Reliability Standard meets the criteria identified by the Commission in Order
No. 672. 6
I.
EXECUTIVE SUMMARY
NERC currently has four Reliability Standards that are mandatory and enforceable in the
United States and Canada that address various aspects of maintenance and testing of protection
and control systems. These Reliability Standards are PRC-005-1.1b, PRC-008-0, PRC-011-0,
and PRC-017-0. Proposed Reliability Standard PRC-005-2 consolidates these Reliability
Standards into a single proposed Reliability Standard. Proposed PRC-005-2 also addresses the
directives related to those Reliability Standards issued by the Commission in Order No. 693. 7
The primary purpose of proposed Reliability Standard PRC-005-2 is “[t]o document and
implement programs for the maintenance of all Protection Systems affecting the reliability of the
5
18 C.F.R. § 39.5(a) (2012).
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321 – 37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
7
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242
(“Order No. 693”), order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
6
2
Bulk Electric System [], so that these Protection Systems are kept in working order.” 8 Proposed
PRC-005-2 also:
(i) establishes minimum acceptable maintenance activities and accompanying maximum
allowable maintenance intervals, reflecting various technologies of the components being
addressed;
(ii) provides Transmission Owners, Generator Owners, and Distribution Providers
(together, “Functional Entities”) the flexibility to implement condition-based maintenance, by
adjusting the minimum acceptable maintenance activities and maximum allowable maintenance
intervals to reflect condition monitoring of the various Protection System Components; and
(iii) establishes requirements for effective implementation of performance-based
maintenance programs.
The proposed Reliability Standard will improve reliability by: (i) defining and
establishing minimum criteria for a Protection System Maintenance Program; (ii) reducing the
risk of Protection System Misoperations; 9 (iii) clearly stating the applicability of the
Requirements in proposed PRC-005-2 to certain Functional Entities and Facilities; (iv)
establishing Requirements for time-based maintenance programs that include maximum
allowable maintenance intervals for all relevant devices; and (v) establishing Requirements for
condition-based and performance-based maintenance programs where hands-on maintenance
intervals are adjusted to reflect the known and reported condition or the historical performance,
respectively, of the relevant devices.
8
See Exhibit B, proposed Reliability Standard PRC-005-2 “Purpose” statement.
“Misoperations” are (i) any failure of a Protection System element to operate within the specified time
when a fault or abnormal condition occurs within a zone of protection; (ii) any operation for a fault not within a zone
of protection (other than operation as backup protection for a fault in an adjacent zone that is not cleared within a
specified time for the protection for that zone); or (iii) any unintentional Protection System operation when no fault
or other abnormal condition has occurred unrelated to on-site maintenance and testing activity. See NERC Glossary
at 37.
9
3
Proposed Reliability Standard PRC-005-2 was approved by the NERC Board of Trustees
on November 7, 2012. Implementation for proposed PRC-005-2, as fully explained in Exhibit A
and in the Implementation Plan attached as Exhibit C, will be phased to appropriately balance
the reliability benefits to be achieved with the efforts, expense, and requirements associated with
implementation of and compliance with the improved proposed Reliability Standard. The
Effective Date of proposed PRC-005-2 (i.e., the Implementation Plan) reflects the importance of
having in place an improved, unified, and clarified Protection System maintenance Reliability
Standard.
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following: 10
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595– facsimile
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Assistant General Counsel
William H. Edwards*
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
10
Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2012), to allow the inclusion
of more than two persons on the service list in this proceeding.
4
III.
BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005, 11 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power
System, and with the duties of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1) 12
of the FPA states that all users, owners, and operators of the Bulk-Power System in the United
States will be subject to Commission-approved Reliability Standards. Section 215(d)(5) 13 of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability
Standard. Section 39.5(a) 14 of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes should become
mandatory and enforceable in the United States, and each modification to a Reliability Standard
that the ERO proposes should be made effective.
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the Bulk-Power System and to ensure that such Reliability Standards are
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA 15 and Section 39.5(c) 16 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the
content of a Reliability Standard.
11
12
13
14
15
16
16 U.S.C. § 824o (2006).
Id. § 824(b)(1).
Id. § 824o(d)(5).
18 C.F.R. § 39.5(a) (2012).
16 U.S.C. § 824o(d)(2).
18 C.F.R. § 39.5(c)(1).
5
B.
History of PRC-005 and Project 2007-17
With the development of the proposed PRC-005-2 Reliability Standard, the standard
drafting team for Project 2007-17 – Protection System Maintenance has followed the
observations and recommendations of the NERC System Protection and Control Task Force
(“SPCTF”) in its assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0
(“Assessment). 17 As discussed below, Project 2007-17 – Protection System Maintenance and
Testing also addresses the Commission’s directives from Order No. 693 related to PRC-005-1,
PRC-008-0, PRC-011-0, and PRC-017-0. To provide context for the approval of proposed PRC005-2, this section includes a brief summary of the history of PRC-005 and the Reliability
Standards proposed for retirement and a summary of the observations of the NERC SPCTF.
1.
PRC-005 and Related Reliability Standards
The Commission approved Reliability Standard PRC-005-1 in Order No. 693 18 and
directed NERC “to develop a modification … through the Reliability Standards development
process that includes a requirement that maintenance and testing of a protection system must be
carried out within a maximum allowable interval that is appropriate to the type of the protection
system and its impact on the reliability of the Bulk-Power System.” 19 The Commission also
17
NERC, NERC SPCTF Assessment of Standards: PRC-005-1 — Transmission and Generation Protection
System Maintenance and Testing, PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance
Programs, PRC-011-0 — UVLS System Maintenance and Testing, PRC-017-0 — Special Protection System
Maintenance and Testing, Mar. 8, 2007, available at http://www.nerc.com/docs/standards/sar/PRC-005-008-011017_Report_Approved_by_PC.pdf. (“SPCTF Assessment”). A supplement to the Assessment was also considered.
NERC, NERC SPCTF Supplemental Assessment Addressing FERC Order 693 Relative toPRC-005-1 —
Transmission and Generation Protection System Maintenance and Testing, PRC-008-0 — Underfrequency Load
Shedding Equipment Maintenance Programs, PRC-011-0 — UVLS System Maintenance and Testing, PRC-017-0 —
Special Protection System Maintenance and Testing, May 17, 2007, available at
http://www.nerc.com/docs/pc/spctf/Supplemental_Report_on_PRC-005-008-011-017_Approved_by_PC_2.pdf.
18
Order No. 693at P 1475.
19
Id.
6
directed NERC to consider suggestions made by commenters to “combine PRC-005, PRC-008,
PRC-011, and PRC-017 into a single Reliability Standard.” 20
Since Order No. 693, and during the time in which PRC-005-2 has been under
development, two interpretations of PRC-005-1 have been filed with and approved by the
Commission. In September 2011, the Commission approved NERC’s interpretation of
“transmission Protection System” as it appears in PRC-005-1, Requirements R1 and R2 (PRC005-1a). 21 A second interpretation of Requirement R1 was accepted in Order No. 758 22 (PRC005-1b). The second interpretation included five questions, each with a NERC response. As
part of its acceptance of the interpretation in Order No. 758, the Commission accepted NERC’s
commitments to address through the Reliability Standards development process concerns raised
with respect to the Protection System maintenance and testing Reliability Standard during the
Order No. 758 rulemaking process. The Commission also directed that concerns raised with
respect to reclosing relays be addressed within the reinitiated PRC-005 revisions. 23
On March 30, 2011, NERC submitted a petition for Commission approval of a proposed
modification to the definition of “Protection System” to close a reliability gap created by an
omission in the currently-approved definition. The Commission approved the modified
definition, which is referenced in proposed PRC-005-2. 24 On July 30, 2012, and in response to a
directive in Order No. 758, NERC submitted an informational filing to report to the Commission
that proposed PRC-005-2 was in the final stages of the development process, and revisions to
20
Id. (“We further direct the ERO to consider FirstEnergy’s and ISO-NE’s suggestion to combine PRC-0051, PRC-008-0, PRC-011-0 and PRC-017-0 into a single Reliability Standard through the Reliability Standards
development process.”).
21
N. Am. Elec. Reliability Corp., 136 FERC ¶ 61,208, P 11 (2011). The interpretation interpreted
“transmission Protection System” to mean “any Protection System that is installed for the purpose of detecting faults
on transmission elements (lines, buses, transformers, etc.) identified as being included in the Bulk Electric System []
and trips an interrupting device that interrupts current supplied directly from the [Bulk Electric System].”
22
Interpretation of Protection System Reliability Standard, Order No. 758, 138 FERC ¶ 61,094 (2012).
23
Id. at P 11, 27.
24
See N. Am. Elec. Reliability Corp., 138 FERC ¶ 61,095 (2012).
7
address the issues around the maintenance and testing of reclosing relays identified in the Order
No. 758 proceeding had been authorized for development and would be addressed in a
subsequent submission. 25
In Order No. 693, the Commission also approved PRC-008-0 (Implementation and
Documentation of Underfrequency Load Shedding Equipment Maintenance Program), PRC-0110 (Undervoltage Load Shedding System Maintenance and Testing), and PRC-017-0 (Special
Protection System Maintenance and Testing). Similar directives to those for PRC-005-1 were
issued for PRC-008, 26 PRC-011, 27 and PRC-017. 28 No changes to, or interpretations of these
Version 0 Reliability Standards have been submitted since approval.
2.
NERC System Protection and Control Task Force
In a March 8, 2007 Assessment, the NERC SPCTF determined that the existing PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 Reliability Standards contain several
fundamental flaws. In its Assessment, the group recommended that these four Reliability
Standards be reduced to one Reliability Standard. The SPCTF concluded that for all four
Reliability Standards: (1) the Requirements do not provide clear and sufficient guidance
concerning the maintenance and testing of the Protection Systems to achieve the commonly
stated purpose “[t]o ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System [] are maintained and tested”; (2) the Standards should
25
NERC Jul. 30, 2012 Informational Filing in Compliance with Order No. 758, Docket No. RM10-5. See
also NERC Project 2007-17 Protection System Maintenance - Phase 2 (Reclosing Relays), available at
http://www.nerc.com/filez/standards/Project_200717.2_Protection_System_Maintenance_and_Testing_Phase_2_Reclosing_Relays.html.
26
Order No. 693 at P 1492.
27
Id. at P 1516.
28
Id. at P 1546.
8
clearly state which power system elements are being addressed; and (3) the Requirements should
reflect the inherent differences between different technologies of Protection Systems. 29
IV.
JUSTIFICATION FOR APPROVAL
A.
Basis for Approval and Purpose of Proposed PRC-005-2
As discussed in detail in Exhibit A, proposed Reliability Standard PRC-005-2 satisfies
the Commission’s criteria in Order No. 672 and is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. Proposed PRC-005-2 meets the Commission’s directives
related to PRC-005-1 and the directives for the Reliability Standards proposed for retirement
from Order No. 693. 30 The proposed Reliability Standard also effectively combines the
reliability objectives of PRC-005, PRC-008, PRC-011, and PRC-017, into one Reliability
Standard. The improved proposed Reliability Standard protects reliability and creates increased
efficiency within the PRC-series of Reliability Standards by combining Reliability Standards
with similar reliability objectives.
The proposed PRC-005-2 Reliability Standard establishes Requirements for a time-based
maintenance program, where all relevant devices are maintained according to prescribed
maximum intervals. It also establishes Requirements for a condition-based maintenance
program, where the hands-on maintenance intervals are adjusted to reflect the known and
reported condition of the relevant devices. For a performance-based maintenance program, the
hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant
devices. Proposed PRC-005-2 also provides a comprehensive set of Requirements that define a
strong Protection Systems Maintenance Program. As a complement to the Requirements, the
29
SPCTF Assessment at 2.
Commission directives issued subsequent to Order No. 693 address additional requirements for
maintenance and testing of reclosing relays and of sudden-pressure relays in addition to other mechanical protective
devices. NERC plans to address these directives in subsequent phases or projects.
30
9
proposed PRC-005-2 Reliability Standard also includes detailed tables of minimum maintenance
activities and maximum maintenance intervals for all five component types addressed within the
NERC definition of Protection System. Functional Entities that monitor the actual condition of
their Protection System components are further empowered to utilize monitoring to improve the
efficiency and effectiveness of their Protection Systems Maintenance Program, and, with the
benefit of extensive Protection System performance data, to utilize that performance data to
further improve the efficiency and effectiveness of their Protection Systems Maintenance
Program.
The standard drafting team authored a number of technical documents included as
Exhibits to this petition, which provide detailed analysis of the proposed Reliability Standard and
answers to frequently asked questions regarding Protection Systems. A technical justification
document addressing the Requirements for proposed PRC-005-2 is included as Exhibit D, a
“Supplementary Reference and FAQ” document is included as Exhibit E, and finally a technical
justification document explaining the maintenance intervals in Tables 1, 2 & 3 of proposed PRC005-2 is included as Exhibit F, and finally, which contains descriptive, technical information
supporting the standard drafting team’s rationale and decisions for the Requirements and
associated tables. The “Supplementary Reference and FAQ” document was posted concurrently
with the Reliability Standard during each posting and will be linked with the proposed PRC-0052 Reliability Standard following approval. A mapping document is also included as Exhibit G
explaining the translation of objectives from the proposed Reliability Standards for retirement
into proposed PRC-005-2.
10
1.
Improvements Reflected in Proposed PRC-005-2
Proposed PRC-005-2 includes five Requirements, discussed below, which present a
comprehensive approach to documenting and implementing programs for the maintenance of all
Protection Systems affecting the reliability of the Bulk Electric System so that these Protection
Systems are kept in working order. The proposed Reliability Standard applies to Transmission
Owners, Generator Owners, and Distribution Providers 31 and to certain Facilities. 32 It also
centralizes and defines in one Reliability Standard, a Protection System Maintenance Program
that includes Transmission and Generation Protection Systems, Underfrequency Load Shedding
systems, Undervoltage Load Shedding systems, and Special Protection Systems, and also
establishes minimum criteria for that Protection System Maintenance Program. Further, the
proposed Reliability Standard reduces the risk of Protection System Misoperations by applying
consistent, best practice maintenance and inspection activities of Protections System
Components performed in accordance with the maximum intervals established in the proposed
Reliability Standard.
This approach represents an improvement over PRC-005-1 and the three Reliability
Standards proposed for retirement because, unlike proposed PRC-005-2, these Reliability
Standards do not contain details outlining the technical requirements for Protection System
Maintenance Programs. While these Reliability Standards require that applicable entities have a
maintenance program for Protection Systems, and that entities must be able to demonstrate they
are carrying out such a program, the Reliability Standards do not contain the technical
requirements for Protection System Maintenance Programs.
31
32
Proposed Reliability Standard PRC-005-2, section A.4, part 4.1.
Proposed Reliability Standard PRC-005-2, section A.4, part 4.2.
11
2.
Commission Directives
Proposed PRC-005-2 meets the Commission directives from Order No. 693 with respect
to: (1) including maximum allowable intervals in PRC-005; (2) combining PRC-005, PRC-008,
PRC-011, and PRC-017; and (3) considering whether Load Serving Entities and Transmission
Operators should be included in the applicability of the PRC-005 Reliability Standard. While
Additional directives related to the PRC-005 Reliability Standard were issued by the
Commission in a subsequent Order, Order No. 758, 33 these directives are being addressed in
future projects related to PRC-005.
a)
Maximum Allowable Intervals
In Order No. 693, the Commission directed NERC to revise PRC-005-1 to include a
Requirement that maintenance and testing of a protection system must be carried out within a
maximum allowable interval that is appropriate to the type of the protection system and its
impact on the reliability of the Bulk-Power System. 34 In response, proposed PRC-005-2
includes specific maximum allowable intervals within Tables 1-1 through 1-5, Table 2 and Table
3 for time-based programs. Additionally, a Requirement allowing performance-based
maintenance intervals was added.
b)
Combining PRC-005, PRC-008, PRC-011, and PRC-017
In Order No. 693, the Commission also directed the ERO to consider FirstEnergy’s and
ISO-NE’s suggestion to combine PRC-005-1, PRC-008-0, PRC-011-0 and PRC-017-0 into a
single Reliability Standard through the Reliability Standards development process. 35 The NERC
SPCTF’s Assessment also suggested combining the Reliability Standards. In response, NERC
33
34
35
Order No. 758 at P 11, 27.
Order No. 693 at P 1475.
Id.
12
has combined the Reliability Standards into the proposed PRC-005-2. As noted above, a
mapping document is provided as Exhibit G explaining the translation of objectives from the
proposed Reliability Standards for retirement into proposed PRC-005-2. NERC also notes that
similar directives to those for PRC-005-1 in Order No. 693 were issued for PRC-008, 36 PRC011, 37 and PRC-017 38 and are similarly addressed by the proposed Reliability Standard with the
exception of a directive to develop a modification to PRC-017-0 regarding the documentation of
the actual Special Protection Systems. 39 This directive is being addressed in an upcoming NERC
Project 2010-05.2, which includes in its scope PRC-012-0 and other Special Protection System
Reliability Standards.
c)
Applicability of Proposed PRC-005-2 to Load Serving Entities
and Transmission Operators
Lastly, the Commission directed NERC to consider whether Load Serving Entities and
Transmission Operators should be included in the applicability of the PRC-004 Reliability
Standard. 40 In a footnote, the Commission directed NERC to consider the same directive for
other Reliability Standards including PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0. 41
NERC considered the suggested changes to the applicability section of the proposed PRC-005-2
Reliability Standard, but determined that proposed PRC-005-2 should be applicable to the
equipment owners. While an equipment owner may need to coordinate with the operating
entities in order to schedule the actual maintenance, the responsibility resides with the equipment
owners to complete the required maintenance.
36
37
38
39
40
41
Id. at P 1492.
Id. at P 1516.
Id. at P 1546.
Order No. 693 at P 1545.
Id. at P 1469.
Id. at n. 384.
13
3.
Requirements in Proposed PRC-005-2
As noted above, proposed PRC-005-2 establishes Requirements for: (1) time-based
maintenance programs that include maximum allowable maintenance intervals for all relevant
devices; (2) condition-based maintenance programs where hands-on maintenance intervals are
adjusted to reflect the known and reported condition of the relevant devices; and (3)
performance-based maintenance programs where hands-on maintenance intervals are adjusted to
reflect the historical performance of the relevant devices.
Proposed PRC-005-2 also introduces six new definitions. With the exception of the
definition for “Protection System Maintenance Program”, the newly defined terms are intended
for use solely in proposed PRC-005-2 and therefore will not be located in the NERC Glossary of
Terms. These “local” definitions are found in the proposed PRC-005-2 Reliability Standard in
stand-alone text boxes. The definitions proposed for approval are as follows:
Protection System Maintenance Program – An ongoing
program by which Protection System components are kept in
working order and proper operation of malfunctioning components
is restored. A maintenance program for a specific component
includes one or more of the following activities:
•
•
•
•
•
Verify – Determine that the component is functioning
correctly.
Monitor – Observe the routine in-service operation of the
component.
Test – Apply signals to a component to observe functional
performance or output behavior, or to diagnose problems.
Inspect – Examine for signs of component failure, reduced
performance or degradation.
Calibrate – Adjust the operating threshold or measurement
accuracy of a measuring element to meet the intended
performance requirement.
Unresolved Maintenance Issue – A deficiency identified during a
maintenance activity that causes the component to not meet the
intended performance, cannot be corrected during the maintenance
interval, and requires follow-up corrective action.
14
Segment – Protection Systems or components of a consistent
design standard, or a particular model or type from a single
manufacturer that typically share other common elements.
Consistent performance is expected across the entire population of
a Segment. A Segment must contain at least sixty (60) individual
components.
Component Type – Any one of the five specific elements of the
Protection System definition.
Component – A Component is any individual discrete piece of
equipment included in a Protection System, including but not
limited to a protective relay or current sensing device. The
designation of what constitutes a control circuit Component is
dependent upon how an entity performs and tracks the testing of
the control circuitry. Some entities test their control circuits on a
breaker basis whereas others test their circuitry on a local zone of
protection basis. Thus, entities are allowed the latitude to
designate their own definitions of control circuit Components.
Another example of where the entity has some discretion on
determining what constitutes a single Component is the voltage
and current sensing devices, where the entity may choose either to
designate a full three-phase set of such devices or a single device
as a single Component.
Countable Event – A failure of a Component requiring repair or
replacement, any condition discovered during the maintenance
activities in Tables 1-1 through 1-5 and Table 3 which requires
corrective action or a Misoperation attributed to hardware failure
or calibration failure. Misoperations due to product design errors,
software errors, relay settings different from specified settings,
Protection System Component configuration errors, or Protection
System application errors are not included in Countable Events.
These new definitions are referenced throughout the Requirements of proposed
PRC-005-2.
Proposed PRC-005-2 includes the following Requirements: 42
42
A full technical justification for the Requirements of proposed PRC-005-2 is included in Exhibit D.
15
a)
Requirement R1
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall
establish a Protection System Maintenance Program (PSMP) for its Protection
Systems identified in Section 4.2. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
R1.1. Identify which maintenance method (time-based, performancebased per PRC-005 Attachment A, or a combination) is used to address
each Protection System Component Type. All batteries associated with
the station dc supply Component Type of a Protection System shall be
included in a time-based program as described in Table 1-4 and Table 3.
R1.2. Include the applicable monitored Component attributes applied to
each Protection System Component Type consistent with the maintenance
intervals specified in Tables 1-1 through 1-5, Table 2, and Table 3 where
monitoring is used to extend the maintenance intervals beyond those
specified for unmonitored Protection System Components.
Establishment of a Protection System Maintenance Program, as directed by Requirement
R1, is needed to detect and correct plausible age- and service-related degradation of Protection
System components. It is important that a Protection System continue to function as designed
over its service life to ensure reliability of the Bulk Electric System. Requirement R1 establishes
the obligation of a Functional Entity to establish a Protection System Maintenance Program for
its Protection Systems. Requirement R1 combines the reliability goals of developing detailed
tables of minimum maintenance activities and maximum maintenance intervals for all five
Protection System Component Types. These tables include adjustments to those minimum
maintenance activities and maximum maintenance intervals to reflect the benefits of any
condition monitoring that may be present.
b)
Requirement R2
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that
uses performance-based maintenance intervals in its PSMP shall follow the
procedure established in PRC-005 Attachment A to establish and maintain its
performance-based intervals. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
16
Requirement R2 addresses performance-based maintenance intervals. The Requirement
includes a reference to Attachment A to proposed PRC-005-2, which contains criteria for a
performance-based Protection System Maintenance Program. A technical justification for each
of the criteria is included in Exhibit D. The criteria within Attachment A are largely based on
application of statistical analysis theory. Performance-based maintenance is included in
proposed PRC-005-2 to allow utilities to adjust maintenance intervals based on their individual
experience with equipment types and manufacturers.
c)
Requirement R3
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that
utilizes time-based maintenance program(s) shall maintain its Protection System
Components that are included within the time-based maintenance program in
accordance with the minimum maintenance activities and maximum maintenance
intervals prescribed within Tables 1-1 through 1-5, Table 2, and Table 3.
[Violation Risk Factor: High] [Time Horizon: Operations Planning]
Requirement R3 requires the implementation of the minimum maintenance activities and
maximum allowable maintenance intervals in Requirement R1 and the tables within the proposed
Reliability Standard. The proper performance of Protection Systems is fundamental to the
reliability of the Bulk Electric System and proper performance of Protection Systems cannot be
assured without periodic maintenance of those systems.
d)
Requirement R4
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that
utilizes performance-based maintenance program(s) in accordance with
Requirement R2 shall implement and follow its PSMP for its Protection System
Components that are included within the performance-based program(s).
[Violation Risk Factor: High] [Time Horizon: Operations Planning]
17
For the same reliability reason as Requirement R3, Requirement R4 requires the
implementation of an entity’s Protection System Maintenance Program established pursuant to
Requirement R2.
e)
Requirement R5
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall
demonstrate efforts to correct identified Unresolved Maintenance Issues.
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
The reliability objective of this Requirement is to assure that Protection System
components are returned to working order following the discovery of failures or malfunctions
during scheduled maintenance. The maintenance activities specified in the Tables 1-1 through 15, Table 2, and Table 3 do not present any requirements related to restoration; therefore,
Requirement R5 of the proposed Reliability Standard was developed to require the entity to
“demonstrate efforts to correct identified Unresolved Maintenance Issues.”
B.
Enforceability of Proposed PRC-005-2
The proposed PRC-005-2 Reliability Standard contains Measures that support each
Requirement by clearly identifying what is required and how the Requirement will be enforced.
The Implementation Plan also discusses the documentation necessary during transition to
proposed PRC-005-2. The VSLs provide further guidance on the way that NERC will enforce
the Requirements of the proposed Reliability Standard. The VRFs and VSLs for the proposed
PRC-005-2 Reliability Standard comport with NERC and Commission guidelines related to their
assignment. For a detailed review of the VRFs, the VSLs, and the analysis of how the VRFs and
VSLs were determined using these guidelines, see Exhibit I. The VSLs have been developed
based on the situations an auditor may encounter during a compliance audit.
18
V.
SUMMARY OF RELIABILITY STANDARD DEVELOPMENT PROCEEDINGS
The extensive development record for proposed Reliability Standard PRC-005-2 is
summarized below. Exhibit H contains the Consideration of Comments Reports created during
the development of the proposed Reliability Standard. Exhibit J contains the complete record of
development for the proposed Reliability Standard.
A.
Overview of the Standard Drafting Team
When evaluating modified Reliability Standards, the Commission must give “due
weight” to the technical expertise of the ERO. 43 The technical expertise of the ERO is derived
from the standard drafting team. For this project, the standard drafting team consisted of 24
industry experts with substantial, robust, and distinguished industry experience across North
America, including both the continental United States and Canada. Standard drafting team
members had, on average, more than 27 years’ industry experience, with only five reporting less
than 20 years’ industry experience. The standard drafting team included experts in all facets of
protection systems and Underfrequency Load Shedding and Undervoltage Load Shedding
equipment engineering, operations, maintenance, and compliance. A standard drafting team
roster including member biographical information is included in Exhibit K.
B.
Proposed PRC-005-2 Development History
1.
PRC-005-2 Development – Standard Authorization Request
Project 2007-17 (Protection System Maintenance and Testing) was initiated on May 7,
2007 by a Standard Authorization Request (“SAR”) in response to Order No. 693, stakeholder
issues raised during the development of the “Version 0” Reliability Standards, and the SPCTF
Assessment. The Project 2007-17 SAR was posted for a 30-day public comment period from
June 11 through July 10, 2007. Stakeholders submitted 18 sets of comments, including
43
See 16 U.S.C. § 824o(d)(2) (2006).
19
comments from 85 different individuals representing more than 50 companies covering 8 of the
10 industry segments. Based on the comments received, no changes to the SAR were made by
the SAR drafting team, and the SAR was authorized to proceed to the standard drafting stage of
the standards development process.
a)
First Posting – Informal Comment Period
Proposed PRC-005-2 was first posted for a comment period from July 24, 2009 through
September 8, 2009. NERC received 57 sets of comments from more than 130 different
individuals, including 75 companies and representing all of the 10 industry segments.
Commenters provided feedback on the proposed Reliability Standard and on the accompanying
“Supplementary Reference” and “Frequently Asked Questions” documents circulated with the
proposed Reliability Standard. In response to the comments received, the standard drafting team
materially revised the proposed Reliability Standard and the accompanying documents,
including:
•
the name of the proposed Reliability Standard to its current name – “Protection
System Maintenance”;
•
the proposed Reliability Standard and tables addressing covered maintenance
activities and associated maintenance intervals;
•
the tables to improve clarity and address identified administrative concerns with
condition-based and performance-based maintenance programs; and
•
other clarifying changes to the proposed Reliability Standard, “Frequently Asked
Questions” document, the “Supplementary Reference” document, and minor changes
to the draft Implementation Plan.
20
b)
Second Posting – Formal Comment Period and Initial Ballot
To support the prioritization of this project in response to Commission’s concerns over
the lack of progress in meeting the directives from Order No. 693, the NERC Standards
Committee approved several deviations from the standards development process. 44 In
accordance with the deviations, a second draft of PRC-005-2 was posted for a 35-day public
comment period (from June 11 through July 16, 2010) and subject to an initial ballot (from July
8 through July 17, 2010). The second draft reflected the revisions identified in Section B.1.(a)
above, as well as VRFs, Time Horizons, Measures, and Compliance elements, including VSLs.
NERC received 58 sets of comments from more than 130 different individuals, including 70
companies and representing 8 of the 10 industry segments. Commenters provided feedback on
the maximum allowable intervals, the individual activities and intervals within the tables in the
proposed Reliability Standard, the VRF and VSL assignments, Measures, Time Horizons, and
the “Supplementary Reference” and “FAQs” documents. The first ballot was not approved, with
22.91% voting to approve after re-balloting.
In response to the comments received, the standard drafting team made a number of
changes to the proposed Reliability Standard. The standard drafting team rearranged and revised
the tables, to create one table for each of the five Protection System component types, as well as
a sixth table to address monitoring and alarming requirements to support extended intervals for
monitored Protection System components. The standard drafting team made several
modifications to the VRFs and VSLs, and revised the Time Horizons for both R3 and R4 from
“Long-Term Planning” to “Operations Planning”. All four Measures were changed in response
44
See Standards Announcement, available at
http://www.nerc.com/docs/standards/sar/PSMTinfo_document061110.pdf (requiring changes to the proposed
standard and definition be posted for 35-day comment periods (rather than 45-day comment periods); ballot pools to
be formed during the first 21 days of the 35-day comment periods; and initial ballots be conducted during the last 10
days of the 35-day comment periods).
21
to commenters’ suggestions. Last, a number of definitions, previously included only in the
Reference Documents, were added to the proposed Reliability Standard.
c)
Third Posting – Formal Comment Period and Successive
Ballot
A third draft of proposed PRC-005-2 was posted for a public 30-day formal comment
period (from November 17 through December 17, 2010) and subject to a successive ballot (from
December 10 through December 20, 2010). The third draft reflected the revisions identified in
Section B.1.(b). NERC received 44 sets of comments from more than 80 different individuals,
including 82 companies and representing 9 of the 10 industry segments. Commenters provided
feedback on the various Requirements in the proposed Reliability Standard, with feedback on the
rearrangement of the table generally positive, and objections raised with respect to the
percentage steps in several VSLs, notwithstanding their consistency with NERC’s VSL
guidelines. The ballot was not approved, with 44.65% voting to approve.
In response to the comments received, the standard drafting team made extensive changes
to the proposed Reliability Standard’s Requirements, including: removing a Requirement that
addressed calibration tolerances and a Requirement determined to be redundant; combined the
“Frequently Asked Questions” and “Supplementary Reference” documents; split Table 1-4;
addressed maintenance of station DC supply; and revised the Implementation Plan.
d)
Fourth Posting – Formal Comment Period and Successive
Ballot
A fourth draft of proposed PRC-005-2 was posted for a public 30-day formal comment
period (from April 12 through May 13, 2011) and subject to a successive ballot (from May 3
through May 13, 2011). The fourth draft reflected the revisions identified in Section B.1.(c).
NERC received 55 sets of comments from more than 176 different individuals, including
22
103companies and representing all of the 10 industry segments. The ballot achieved 67% and
moved to recirculation ballot. In response to the comments received on the fourth draft, the
standard drafting team clarified Requirement R1 and the tables, lengthened certain
implementation periods for Functional Entities not subject to regulatory approvals, revised the
VSLs, addressed comments regarding the definition of “Maintenance Correctable Issues,” and
supplemented the “Supplementary Reference and FAQ” document.
e)
Fifth Posting and Ballot
A fifth draft of PRC-005-2 was posted for a recirculation ballot and non-binding poll
from June 20 through June 30, 2011. The ballot was not approved, with only 64.76% voting to
approve.
2.
PRC-005-2 Development – Reauthorization
On August 11, 2011, with a revised SAR, the NERC Standards Committee re-authorized
Project 2007-17 and substantially modified the proposed PRC-005-2 Reliability Standard
(“Reauthorization”). 45 The second SAR included several changes made by the standard drafting
team to the original SAR. The title of the proposed Reliability Standard was changed to
“Protection System Maintenance”; reliability principle item #4 was deemed inapplicable and
removed; and the “Transmission and Generation” descriptor of Protection Systems was removed
from the “Detailed Description” area of the second SAR.
a)
First Posting – Formal Comment Period and Initial Ballot
A first draft of proposed PRC-005-2 following the Reauthorization was posted for a
public 45-day formal comment period (from August 15 through September 29, 2011) and subject
45
See NERC, Standards Committee Meeting Minutes, Aug. 11, 2011, available at
http://www.nerc.com/docs/standards/sc/sc_081111_approved_package.pdf.
23
to an initial ballot (from September 19 through September 29, 2011). The first draft reflected
revisions made since the fifth posting described in Section B.1.(e), including:
•
renaming “Maintenance Correctable Issue” to “Unresolved Maintenance Issue”;
•
revising the interval for various station dc supply and communications system
maintenance activities from three to four calendar months;
•
moving the maintenance activities and intervals for distributed Underfrequency Load
Shedding and Undervoltage Load Shedding systems from Tables 1-1 through 1-5 into
a new Table 3, to separately illustrate the requirements related to these systems;
•
revising the Implementation Plan; and
•
modifying the VSLs, VRFs, and “Supplementary Reference and FAQ” document to
reflect the listed changes and to respond to additional stakeholder comments received.
NERC received 48 sets of comments from more than 147 different individuals, including
98 companies and representing 9 of the 10 industry segments. The first ballot was not approved,
with only 61.10% voting to approve. In response to the comments received, the standard
drafting team revised the applicability of the proposed Reliability Standard to indicate that, for
generator-connected station service transformers, only the Protection Systems that trip the
generator, either directly or via a lockout relay, are included in the proposed Reliability Standard.
The standard drafting team also revised the Requirements and Measures associated with those
Requirements, clarified the Tables and the Implementation Plan, and modified the VSLs.
b)
Second Posting – Formal Comment Period and Successive
Ballot
A second draft of proposed PRC-005-2 was posted for a public 30-day formal comment
period (from February 28 through March 28, 2012) and subject to a successive ballot and nonbinding poll (from March 19 through March 28, 2012). The second draft reflected a Revised
24
Requirement R1, which stated that a Functional Entity’s Protection System Maintenance
Program must include for each Protection System component type an identification of the
maintenance method(s) used, and the identification of the relevant monitoring attributes applied.
In addition, Requirement R3 was split into three Requirements (a revised R3 and new R4 and
R5), and the VSLs and the “Supplementary Reference and FAQ” document was revised to
reflect the changes and additional stakeholder comments. NERC received 56 sets of comments
from more than 118 different individuals, including 98 companies and representing 9 of the 10
industry segments. The successive ballot received a 73.93% weighted segment vote and the
standard drafting team indicated it would consider the stakeholder comments submitted.
In response to the comments received, the standard drafting team revised the “Inspect”
element of the definition of Protection System Maintenance Program, clarified the definitions of
“Unresolved Maintenance Issue” and “Countable Event,” revised the “Applicability” section or
the proposed Reliability Standard in part 4.2.5.4, revised the first and last rows of Table 1-2, and,
with the assistance of the IEEE stationary battery committee, revised several other Tables with
respect to the verification that a station battery can perform properly. Clarifying, conforming,
and correcting changes were also made to the Requirements, Measures, VSLs, and the
Supplementary Reference Document.
c)
Third Posting – Formal Comment Period and Successive
Ballot
A third draft of proposed PRC-005-2 was posted for a public 30-day formal comment
period (from May 29 through June 27, 2012) and subject to a successive ballot (from June 18
through June 27, 2012). The third draft reflected the revisions identified in Section B.2.(b).
NERC received 51 sets of comments from more than 170 different individuals, including 110
companies and representing all 10 industry segments. The successive ballot received a 79%
25
weighted segment vote and the standard drafting team indicated it would consider the
stakeholder comments submitted.
In response to the comments received on the third draft, the standard drafting team made
minimal changes to the proposed Reliability Standard. Those changes included: changes to the
Tables, Implementation Plan; “Supplementary Reference and FAQ” document; and clarifying
changes to the mapping document.
d)
Fourth Posting – Formal Comment Period and Successive
Ballot
A fourth draft of proposed PRC-005-2 was posted for a public 30-day formal comment
period (from July 27 through August 27, 2012) and subject to a successive ballot (from August
17 through August 27, 2012). As noted in Section B.2.(b), the fourth draft reflects minor
changes to the Tables, along with changes to the Implementation Plan, mapping document and
“Supplementary Reference and FAQ” document. NERC received 36 sets of comments from
more than 102 different individuals, including 65 companies and representing 9 of the 10
industry segments. The successive ballot received an 80.31% weighted segment vote and the
standard drafting team indicated it would consider the stakeholder comments submitted.
In response to the comments received on the fourth draft, the standard drafting team
made editorial changes to the proposed Reliability Standard. For example, Table 1-2 was revised
such that “communications” would be plural in all occurrences of “communications systems,”
“identify” was added to the VSLs for Requirement R5, and grammatical and punctuation
corrections were made to the “Supplementary Reference and FAQ” document.
e)
Final Posting – Recirculation Ballot
Because the comments on the fourth draft did not require substantive revisions, proposed
PRC-005-2 proceeded to a recirculation ballot (from October 15 through October 24, 2012). The
26
recirculation ballot was ultimately approved, with 80.51% of the weighted segment vote voting
to approve proposed PRC-005-2.
f)
Board of Trustees Approval
NERC presented the final draft of the proposed PRC-005-2 Reliability Standard to
NERC’s Board of Trustees for approval on November 7, 2012. The Board of Trustees approved
the proposed Reliability Standard, and NERC staff recommended that it be filed with Applicable
Regulatory Authorities.
VI.
CONCLUSION
Proposed Reliability Standard PRC-005-2 should be approved because it supports the
important reliability goal of reducing Misoperations by requiring that owners of Protection
Systems perform specific maintenance activities for specific protection system components
within defined intervals. In addition, the effectiveness of compliance by Functional Entities with
the proposed PRC-005-2 Reliability Standard will be enhanced by the consolidation of
Reliability Standards PRC-005-1.1b, PRC-008-0, PRC-011-0, and PRC-017-0 into a single
Reliability Standard. Finally, proposed PRC-005-2 responds to outstanding directives set forth
in Order No. 693, as described herein. Accordingly, and for the reasons set forth above, NERC
respectfully requests that the Commission find that proposed Reliability Standard PRC-005-2 is
just, reasonable, not unduly discriminatory or preferential, and in the public interest and approve
proposed PRC-005-2 as filed in Exhibit B. NERC also requests that the Commission approve
the associated Implementation Plan included as Exhibit C, and the VRFs and VSLs for proposed
Reliability Standard PRC-005-2. Finally, NERC requests approval of the retirement of the PRC005-1.1b, PRC-008-0, PRC-011-0, PRC-017-0 effective according to the Implementation Plan.
Respectfully submitted,
27
/s/ William H. Edwards
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595– facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
William H. Edwards
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
February 26, 2013
28
CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the foregoing document upon all parties
listed on the official service list compiled by the Secretary in this proceeding. Dated at
Washington, D.C. this 26th day of February, 2013.
/s/ William H. Edwards
William H. Edwards
Attorney for North American Electric
Reliability Corporation
Exhibit A
Order No. 672 Criteria
EXHIBIT A
Order No. 672 Criteria for Reliability Standard PRC-005-2
In Order No. 672, 1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve that goal. 2
Proposed PRC-005-2 achieves the specific reliability goal of maintaining the proper
working order of Protection Systems. The proposed Standard achieves this goal by requiring
that applicable entities establish, implement, and document comprehensive Protection System
Maintenance Programs in accordance with the Requirements, Tables, and Attachment included
in the proposed Standard. By outlining the documentation and implementation of programs for
the maintenance of all Protection Systems affecting the reliability of the Bulk Electric System,
Protection Systems are kept in working order. Performance of these programs, applied
consistently throughout the North American Bulk-Power System and assured through the
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls
within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power
System facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such
facilities include all those necessary for operating an interconnected electric energy transmission network, or any
portion of that network, including control systems. The proposed Reliability Standard may apply to any design of
planned additions or modifications of such facilities that is necessary to provide for reliable operation. It may also
apply to Cybersecurity protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve this goal. Although any person may propose
a topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard
should be developed initially by persons within the electric power industry and community with a high level of
technical expertise and be based on sound technical and engineering criteria. It should be based on actual data and
lessons learned from past operating incidents, where appropriate. The process for ERO approval of a proposed
Reliability Standard should be fair and open to all interested persons.
compliance process, will produce well-maintained Protection Systems on a continent-wide basis.
Improved overall reliability of the Bulk Electric System will be a direct result of dependable
Protection Systems.
Protection Systems are comprised of components whose purpose is to monitor the
“health” of the Bulk Electric System and take immediate, corrective action when power system
conditions degrade to a point at which safety, stability, and reliability are at risk. Enacting a
proposed Standard which requires entities to assure the dependable performance of Protection
Systems guarding the Bulk Electric System —thus promoting reliable operation of the Bulk
Electric System — is a crucial element in maintaining Bulk-Power System reliability. It is,
therefore, imperative that entities conduct the kind of periodic verifications specified in these
Protection System Maintenance Programs to ensure Protection Systems will function properly
when called upon.
The proposed PRC-005-2 Reliability Standard also establishes a technically sound basis
for assuring that Protection Systems have maximum allowable time intervals applied on
specified maintenance activities that are appropriate for the types of technology employed in
Protection Systems. Specifically, the proposed Standard utilizes different types of maintenance
programs, requires minimum activities for Protection Systems, and creates criteria for a
statistical performance-based maintenance approach.
First, the proposed Reliability Standard contains three different types of maintenance
programs to provide Functional Entities with options to achieve the reliability goal. These
include traditional time-based methods, advanced technology condition-based methods and
statistical performance-based methods.
Second, minimum activities are included in the Tables for the various components of
Protection Systems in the proposed PRC-005-2 Standard. These activities provide a technically
sound means to ensure Protection Systems are kept in working order but do not specifically
prescribe “the how-to”. Entities must perform the activities required by this proposed Standard,
but have the flexibility to use various technologies to create their own Protection System
Maintenance Program. The activities listed in the Tables are accompanied by the maximum
allowable intervals appropriate for the activities and components listed. These activities enhance
reliability by making uniform requirements mandatory for entities inter-connected with the Bulk
Electric System throughout North America. Proposed PRC-005-2 now requires key activities
fostering consistent, effective maintenance.
Lastly, the criteria established in Requirement R2 of proposed PRC-005-2 and
Attachment A provide a technically sound methodology describing a statistical performancebased maintenance approach that allows for a maintenance program that can use trending,
success rates and statistical analysis to mold a maintenance program into the specific needs of an
entity without any compromise to the reliability of the Bulk Electric System.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to
what is required and who is required to comply. 3
The proposed Reliability Standard applies to Transmission Owners, Generator Owners, and
Distribution Providers and is clear and unambiguous as to what is required and who is required
to comply, in accordance with Order No. 672. The proposed Reliability Standard also clearly
lists the types of Facilities subject to compliance with proposed PRC-005-2.
3
Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user, owner,
or operator of such facilities, but not on others.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous regarding
what is required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know
what they are required to do to maintain reliability.
NERC Reliability Standard PRC-005-1b (the currently-effective Reliability Standard) is not
specific as to the applicable Protection Systems in generating stations. The proposed PRC-005-2
Reliability Standard adds specificity regarding these Protection Systems in that those Protection
Systems that could trip the generator, either directly or by a generator lockout relay, are
explicitly included.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
The proposed Reliability Standard includes clear and understandable consequences by
assigning each primary Requirement a VRF and a VSL in accordance with Order No. 672.
These elements support the determination of an initial value range for the base penalty amount
regarding violations of requirements in Commission-approved Reliability Standards, as defined
in the ERO Sanction Guidelines. Analysis of the VRFs and VSLs for proposed Reliability
Standard PRC-005-2 is contained in Exhibit I.
4
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.
4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner. 5
The proposed Reliability Standard contains Measures that support each Requirement by
clearly identifying what is required to demonstrate compliance and how the requirement will be
enforced. These Measures, included below, help provide clarity regarding how the
Requirements will be enforced, and ensure that the Requirements will be enforced in a clear,
consistent, and non-preferential manner and without prejudice to any party.
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
M2.
M3.
M4.
M5.
5
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System Component Type, the documentation shall include the type of
maintenance method applied (time-based, performance-based, or a combination of these
maintenance methods), and shall include all batteries associated with the station dc supply
Component Types in a time-based program as described in Table 1-4 and Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each protection Component Type (such as manufacturer’s
specifications or engineering drawings) of the appropriate monitored Component attributes as
specified in Tables 1-1 through 1-5, Table 2, and Table 3. (Part 1.2)
Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
Components included within its time-based program in accordance with Requirement R3. The
evidence may include but is not limited to dated maintenance records, dated maintenance
summaries, dated check-off lists, dated inspection records, or dated work orders.
Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System Components included in its performance-based program in accordance with
Requirement R4. The evidence may include but is not limited to dated maintenance records,
dated maintenance summaries, dated check-off lists, dated inspection records, or dated work
orders.
Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance
so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.
5. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without
regard to implementation cost or historical regional infrastructure design. 6
The proposed PRC-005-2 Reliability Standard achieves the reliability goal of maintaining
Protection Systems in working order effectively and efficiently in accordance with Order No.
672 by relying upon any single method or approach to performing maintenance activities. The
proposed PRC-005-2 is flexible enough to encourage the use of advanced technology that can
enhance Bulk Electric System reliability making the proposed Reliability Standard effective to
meet the reliability goal. The proposed Reliability Standard is effective in that it requires
Transmission Owners, Generator Owners, and Distribution Providers to have a Protection
System Maintenance Program.
This approach is efficient because it allows entities to design its own program without
specifically stating “how” a program must be tailored. Efficiency is also achieved, in part,
through the combination of four protection system Reliability Standards into a single Reliability
Standard, streamlining compliance and enforcement. The entities’ Protection System
Maintenance Program must include, at a minimum, the activities listed in the proposed PRC005-2 Tables. The activities listed must be performed with a frequency that is at least as
stringent as the maximum allowable time intervals stated in the proposed Reliability Standard.
The proposed Reliability Standard also requires the testing of Protection System
components while minimizing Bulk Electric System exposure to excessive planned and
unplanned system outages. The proposed Reliability Standard thus strikes a balance between
traditional recurring maintenance activities and the unnecessary additional time out-of-service
6
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.
that traditional maintenance approaches require. If Protection System components are
unnecessarily out-of-service, overall reliability of the Bulk Electric System can be negatively
affected.
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power
System reliability. Proposed Reliability Standards can consider costs to
implement for smaller entities, but not at consequences of less than excellence in
operating system reliability. 7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. To the contrary, the proposed Standard represents a significant improvement over the
previous version as described in the petition. The requirements in the proposed PRC-005-2
Reliability Standard propose a standard approach to all entities, without differentiation based on
entity size. The final proposed Reliability Standard clearly identifies the Requirements for
distributed Undervoltage Load Shedding and Underfrequency Load Shedding equipment. The
final proposed Reliability Standard also benefited from involvement from subject-matter-experts
from the Institute of Electrical and Electronics Engineers in better characterizing the
maintenance activities for station batteries. The end result of the standards development process
was a stronger proposed Reliability Standard that meets the Commission’s directives and
improves reliability.
7
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice — the socalled “lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the entity that
must comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.
All entities, small and large, are expected to comply with this proposed Reliability
Standard in the same manner. There are no Requirements in proposed PRC-005-2 that place
undue burden on small entities. All entities are expected to maintain similar equipment in a
similar fashion at similar intervals, and the amount of equipment to be maintained is directly
related to entity size. As a result, small entities may find the transition to the proposed
Reliability Standard PRC-005-2 to be less burdensome given the flexibility the mandated
Protection System Maintenance Program grants entities for determining the necessary
components to maintain.
The proposed PRC-005-2 Reliability Standard also allows an entity to implement a
performance-based Protection System Maintenance Program. Entities can share data across
ownership lines provided certain criteria are met. For example, two entities in such a shared
program may have populations of like components that can be aggregated with equivalent
Protection System Maintenance Program obligations for those components. The combined
entities’ shared program can show total populations, total numbers of components tested and
total failures found. The combined entities’ Protection System Maintenance Program would
follow the same intervals, test procedures, and statistical analysis. Entity cooperation would
allow the same outcome as if a process were applied to a single entity. There is no inherent
advantage or disadvantage to multiple entities cooperating in such a manner. The proposed
Reliability Standard is written such that small entities with small populations of equipment have
the same access to performance-based maintenance as the larger entities.
7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard
while not favoring one geographic area or regional model. It should take into
account regional variations in the organization and corporate structures of
transmission owners and operators, variations in generation fuel type and
ownership patterns, and regional variations in market design if these affect the
proposed Reliability Standard. 8
The proposed Reliability Standard applies throughout North America and does not favor
one geographic area or regional model.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 9
The proposed Reliability Standard does not restrict the available transmission capability or
limit use of the bulk-power system in a preferential manner. Specifically, the requirements in the
proposed Reliability Standard should cause no restriction of the grid because proper and timely
maintenance and testing of Protection System components helps to assure that the Bulk Electric
System operates in a safe and reliable manner under both normal and abnormal conditions.
9. The implementation time for the proposed Reliability Standard is reasonable. 10
The proposed effective date for the proposed Reliability Standard is just and reasonable
and appropriately balances the urgency in the need to implement the proposed Reliability
Standard against the reasonableness of the time allowed for those who must comply to develop
necessary procedures, software, facilities, staffing or other relevant capability. This will allow
8
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.
9
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to
the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed
Reliability Standard that has no undue negative effect on competition. Among other possible considerations, a
proposed Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power
System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an
unduly preferential manner. It should not create an undue advantage for one competitor over another.
10
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable,
FERC will consider also the timetable for implementation of the new requirements, including how the proposal
balances any urgency in the need to implement it against the reasonableness of the time allowed for those who must
comply to develop the necessary procedures, software, facilities, staffing or other relevant capability.
applicable entities adequate time to ensure compliance with the requirements. The proposed
effective date is explained in detail in the proposed Implementation Plan, attached as Exhibit C.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 11
The proposed Reliability Standard was developed in accordance with NERC’s
Commission-approved, ANSI- accredited processes for developing and approving Reliability
Standards. A complete description of the development process is contained in this petition in
Section V and the complete development record is included as Exhibit J. These processes
included, among other things, multiple comment periods, pre-ballot review periods, and balloting
periods. Additionally, all standard drafting team meetings were properly noticed and open to the
public. The initial and recirculation ballots both achieved a quorum and exceeded the required
ballot pool approval levels. The standard development process did include certain Standards
Committee-approved deviations and these are described in Section V of this petition.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has not identified any competing public interests regarding the request for
approval of this proposed Reliability Standard. No comments were received that indicated the
proposed Reliability Standard conflicts with other vital public interests.
11
Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commission-approved
Reliability Standard development process for the development of the particular proposed Reliability Standard in a
proper manner, especially whether the process was open and fair. However, we caution that we will not be
sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
Reliability Standard development process if it is conducted in good faith in accordance with the procedures
approved by FERC.
12
Order No. 672 at P 335. Finally, we understand that at times development of a proposed Reliability
Standard may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social, and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.
12. Proposed Reliability Standards must consider any other appropriate factors. 13
No other factors relevant to whether the proposed Reliability Standard is just and
reasonable were identified.
13
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable, we
will consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.
Exhibit B
Proposed Reliability Standard PRC-005-2
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems affecting the reliability of the Bulk Electric System (BES) so that these Protection
Systems are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems identified in
Section 4.2. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1
Standard PRC-005-2 — Protection System Maintenance
The PSMP shall:
1.1. Identify which maintenance method (time-based,
Component Type - Any one of
performance-based per PRC-005 Attachment A, or a
the five specific elements of the
combination) is used to address each Protection
Protection System definition.
System Component Type. All batteries associated
with the station dc supply Component Type of a Protection System shall be included in a
time-based program as described in Table 1-4 and Table 3.
1.2. Include the applicable monitored
Component attributes applied to each
Protection System Component Type
consistent with the maintenance intervals
specified in Tables 1-1 through 1-5,
Table 2, and Table 3 where monitoring is
used to extend the maintenance intervals
beyond those specified for unmonitored
Protection System Components.
R2. Each Transmission Owner, Generator Owner,
and Distribution Provider that uses
performance-based maintenance intervals in its
PSMP shall follow the procedure established in
PRC-005 Attachment A to establish and
maintain its performance-based intervals.
[Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
R3. Each Transmission Owner, Generator Owner,
Component – A component is any individual
discrete piece of equipment included in a
Protection System, including but not limited to
a protective relay or current sensing device.
The designation of what constitutes a control
circuit component is very dependent upon how
an entity performs and tracks the testing of the
control circuitry. Some entities test their
control circuits on a breaker basis whereas
others test their circuitry on a local zone of
protection basis. Thus, entities are allowed
the latitude to designate their own definitions
of control circuit components. Another
example of where the entity has some
discretion on determining what constitutes a
single component is the voltage and current
sensing devices, where the entity may choose
either to designate a full three-phase set of
such devices or a single device as a single
component.
and Distribution Provider that utilizes timebased maintenance program(s) shall maintain
its Protection System Components that are included within the time-based maintenance
program in accordance with the minimum maintenance activities and maximum maintenance
intervals prescribed within Tables 1-1 through 1-5, Table 2, and Table 3. [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection
Unresolved Maintenance Issue - A
System Components that are included within the
performance-based program(s). [Violation Risk
deficiency identified during a
Factor: High] [Time Horizon: Operations
maintenance activity that causes the
Planning]
component to not meet the intended
R5. Each Transmission Owner, Generator Owner, and
Distribution Provider shall demonstrate efforts to
correct identified Unresolved Maintenance Issues.
[Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
performance, cannot be corrected
during the maintenance interval, and
requires follow-up corrective action.
2
Standard PRC-005-2 — Protection System Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System Component Type, the documentation shall include the type of
maintenance method applied (time-based, performance-based, or a combination of these
maintenance methods), and shall include all batteries associated with the station dc supply
Component Types in a time-based program as described in Table 1-4 and Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each protection Component Type (such as manufacturer’s
specifications or engineering drawings) of the appropriate monitored Component attributes as
specified in Tables 1-1 through 1-5, Table 2, and Table 3. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
Components included within its time-based program in accordance with Requirement R3. The
evidence may include but is not limited to dated maintenance records, dated maintenance
summaries, dated check-off lists, dated inspection records, or dated work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System Components included in its performance-based program in accordance with
Requirement R4. The evidence may include but is not limited to dated maintenance records,
dated maintenance summaries, dated check-off lists, dated inspection records, or dated work
orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
3
Standard PRC-005-2 — Protection System Maintenance
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System Component, or all performances of each distinct maintenance
activity for the Protection System Component since the previous scheduled audit date,
whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
4
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Protection System Component Type
consistent with the maintenance
intervals specified in Tables 1-1
through 1-5, Table 2, and Table 3
where monitoring is used to extend
the maintenance intervals beyond
those specified for unmonitored
Protection System Components.
(Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity failed to
specify whether three or more
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
3) Maintained a Segment with
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
5
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
• Annually perform
maintenance on the greater
of 5% of the segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific Protection
System Component Type, in
accordance with the minimum
maintenance activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, and Table 3.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 5% but 10% or less of the
total Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 10% but 15% or less of
the total Components included
within a specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, and Table 3.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 15% of the total
Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3.
R4
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
5% or less of the annual scheduled
maintenance for a specific Protection
System Component Type in
accordance with their performancebased PSMP.
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
more than 5% but 10% or less of the
annual scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
more than 10% but 15% or less of
the annual scheduled maintenance
for a specific Protection System
Component Type in accordance with
their performance-based PSMP.
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
more than 15% of the annual
scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
R5
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
6
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Maintenance Issues.
Moderate VSL
identified Unresolved Maintenance
Issues.
High VSL
identified Unresolved Maintenance
Issues.
Severe VSL
Maintenance Issues.
7
Standard PRC-005-2 – Protection System Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — July 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order dated March 14, 2012).
Updated version from 1a to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
8
Standard PRC-005-2 – Protection System Maintenance
1.1b
May 9, 2012
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2
November7,
2012
Adopted by Board of Trustees
Complete revision,
absorbing maintenance
requirements from PRC005-1b, PRC-008-0,
PRC-011-0, PRC-017-0
9
Standard PRC-005-2 – Protection System Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval1
Maintenance Activities
For all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Verify acceptable measurement of power system input values.
Verify:
Monitored microprocessor protective relay with the following:
Settings are as specified.
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
12 calendar
years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values.
Alarming for power supply failure (see Table 2).
1
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
10
Standard PRC-005-2 – Protection System Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval1
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
12 calendar
years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
Alarming for change of settings (See Table 2).
11
Standard PRC-005-2 – Protection System Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 calendar
months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
6 calendar
years
12 calendar
years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with all of the following:
Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 calendar
years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
12
Standard PRC-005-2 – Protection System Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Maximum
Maintenance
Interval
Maintenance Activities
12 calendar years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
13
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Float voltage of battery charger
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
Battery continuity
Battery terminal connection resistance
18 Calendar
Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
Physical condition of battery rack
14
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
15
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
6 Calendar Months
Inspect:
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
16
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
17
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Float voltage of battery charger
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
18
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Verify that the dc supply can perform as manufactured when ac power
is not present.
19
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
20
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
21
Standard PRC-005-2 – Protection System Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 calendar
years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 calendar
years
Verify electrical operation of electromechanical lockout
devices.
Unmonitored control circuitry associated with SPS.
12 calendar
years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
12 calendar
years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPS whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
22
Standard PRC-005-2 – Protection System Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5 and Table 3, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance
activities are subject to the following maintenance requirements
Maximum
Component Attributes
Maintenance
Maintenance Activities
Interval
Any alarm path through which alarms in Tables 1-1 through 1-5 and Table 3 are
conveyed from the alarm origin to the location where corrective action can be
initiated, and not having all the attributes of the “Alarm Path with monitoring”
category below.
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
No periodic
maintenance
specified
None.
23
Standard PRC-005-2 – Protection System Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
Test and, if necessary calibrate
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 calendar
years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
Settings are as specified.
12 calendar
years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
12 calendar
years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
24
Standard PRC-005-2 – Protection System Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Alarming for change of settings (See Table 2).
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 calendar
years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 calendar
years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 calendar
years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 calendar
years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
25
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
Components included in each designated
Segment of the Protection System
Component population, with a minimum
Segment population of 60 Components.
Segment – Protection Systems or components
of a consistent design standard, or a
particular model or type from a single
manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least
sixty (60) individual components.
2. Maintain the Components in each
Segment according to the time-based
maximum allowable intervals established
in Tables 1-1 through 1-5 and Table 3
until results of maintenance activities for
the Segment are available for a minimum of 30 individual Components of the Segment.
3. Document the maintenance program activities and results for each Segment, including
maintenance dates and Countable Events
for each included Component.
Countable Event – A failure of a component
4. Analyze the maintenance program
activities and results for each Segment to
determine the overall performance of the
Segment and develop maintenance
intervals.
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5 and Table 3 which requires
corrective action, or a Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System component
configuration errors, or Protection System
application errors are not included in Countable
Events.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than 4%
of the Components within the Segment,
for the greater of either the last 30
Components maintained or all Components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System Components and Segments and/or
description if any changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
26
Standard PRC-005-2 – Protection System Maintenance
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Protection System Segment maintained through a performancebased PSMP experience 4% or more Countable Events, develop, document, and
implement an action plan to reduce the Countable Events to less than 4% of the Segment
population within 3 years.
27
Standard PRC-005-1.1b2 — Transmission and Generation Protection System
Maintenance and Testing
A. Introduction
1.
Transmission and Generation Protection System Maintenance and
Title:
Testing
2.
Number:
PRC-005-1.1b2
3.
Purpose:
To ensure all transmission and generationdocument and implement programs
for the maintenance of all Protection Systems affecting the reliability of the Bulk Electric
System (BES) are maintained and testedso that these Protection Systems are kept in working
order.
4.
Applicability:
4.1. Functional Entities:
4.1.4.1.1
Transmission Owner.
4.2.4.1.2
Generator Owner.
4.1.3
Distribution Provider that owns
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a transmissionSpecial Protection System (SPS)
for BES reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.3.4.2.5.4 Protection Systems for station service or excitation transformers
connected to the generator bus of generators which are part of the BES, that
act to trip the generator either directly or via lockout or tripping auxiliary
relays.
5.
In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no
regulatory approval is required, all requirements become effective upon Board of
Trustee’s adoption or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
See Implementation Plan
Effective Date:
1
Standard PRC-005-1.1b2 — Transmission and Generation Protection System
Maintenance and Testing
B. Requirements
R1. R1. Each Transmission Owner, Generator Owner, and
any Distribution Provider that ownsshall establish a
transmission Protection System and Maintenance
Component Type - Any one of
the five specific elements of the
Protection System definition.
Program (PSMP) for its Protection Systems identified in
Section 4.2. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method
(time-based, performance-based per
PRC-005 Attachment A, or a
combination) is used to address each
Generator Owner that owns a
generation or generator
interconnection Facility Protection
System shall haveComponent Type. All
batteries associated with the station dc
supply Component Type of a Protection
System maintenance and testingshall
be included in a time-based program for
as described in Table 1-4 and Table 3.
1.2. Include the applicable monitored
Component – A component is any individual
discrete piece of equipment included in a
Protection System, including but not limited to
a protective relay or current sensing device.
The designation of what constitutes a control
circuit component is very dependent upon how
an entity performs and tracks the testing of the
control circuitry. Some entities test their
control circuits on a breaker basis whereas
others test their circuitry on a local zone of
protection basis. Thus, entities are allowed
the latitude to designate their own definitions
of control circuit components. Another
example of where the entity has some
discretion on determining what constitutes a
single component is the voltage and current
sensing devices, where the entity may choose
either to designate a full three-phase set of
such devices or a single device as a single
component.
Component attributes applied to each
Protection SystemsSystem Component
Type consistent with the maintenance
intervals specified in Tables 1-1 through 1-5, Table 2, and Table 3 where monitoring is
used to extend the maintenance intervals beyond those specified for unmonitored
Protection System Components.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that affect the
reliability of the BES. Theuses performance-based maintenance intervals in its PSMP shall
follow the procedure established in PRC-005 Attachment A to establish and maintain its
performance-based intervals. [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System Components that are
included within the time-based maintenance program in accordance with the minimum
maintenance activities and maximum maintenance intervals prescribed within Tables 1-1
through 1-5, Table 2, and Table 3. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
2
Standard PRC-005-1.1b2 — Transmission and Generation Protection System
Maintenance and Testing
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System Components that are included within
the performance-based program(s). [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
Unresolved Maintenance Issue - A
deficiency identified during a
maintenance activity that causes the
component to not meet the intended
performance, cannot be corrected
during the maintenance interval, and
requires follow-up corrective action.
3
Standard PRC-005-1.1b2 — Transmission and Generation Protection System
Maintenance and Testing
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System Component Type, the documentation shall include: the type of
maintenance method applied (time-based, performance-based, or a combination of these
maintenance methods), and shall include all batteries associated with the station dc supply
Component Types in a time-based program as described in Table 1-4 and Table 3. (Part 1.1)
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation or generator
interconnection Facility Protection System shall provide documentation of its
Protection System maintenance and testing program and the implementation of that
program to its Regional Entity on request (within 30 calendar days). The
documentation of the program implementation shall include:
R2.1.
R2.2.
Evidence Protection System devices were maintained and tested within the
defined intervals.
Date each Protection System device was last tested/maintained.
Measures
Each Transmission Owner and any For Component Types that use monitoring to extend the
maintenance intervals, the responsible entity(s) shall have evidence for each protection
Component Type (such as manufacturer’s specifications or engineering drawings) of the
appropriate monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2,
and Table 3. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that owns a
transmission Protection System and each Generator Owner that owns a generation or
generator interconnection Facilityuses performance-based maintenance intervals shall have
evidence that its current performance-based maintenance program(s) is in accordance with
Requirement R2, which may include but is not limited to Component lists, dated maintenance
records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
that affects the reliability of the BES, shall have an associated Components included
within its time-based program in accordance with Requirement R3. The evidence may include
but is not limited to dated maintenance records, dated maintenance summaries, dated check-off
lists, dated inspection records, or dated work orders.
M1.M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System maintenance and testing program as
defined in Requirement 1Maintenance Program for the Protection System Components
included in its performance-based program in accordance with Requirement R4. The evidence
may include but is not limited to dated maintenance records, dated maintenance summaries,
dated check-off lists, dated inspection records, or dated work orders.
4
Standard PRC-005-1.1b2 — Transmission and Generation Protection System
Maintenance and Testing
M2.M5.
Each Transmission Owner, Generator Owner, and any Distribution Provider that owns a
transmission Protection System and each Generator Owner that owns a generation or
generator interconnection Facility Protection System that affects the reliability of the
BES, shall have evidence that it provided documentation of its associated Protection
System maintenance and testing program and the implementation of its program as
definedhas undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement 2R5. The evidence may include but is not limited to work
orders, replacement Component orders, invoices, project schedules with completed milestones,
return material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring ResponsibilityEnforcement Authority
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time FrameEnforcement Processes:
One calendar year.
DataCompliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and any Distribution Provider that owns
shall each keep data or evidence to show compliance as identified below unless directed
by its Compliance Enforcement Authority to retain specific evidence for a
transmissionlonger period of time as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System and each Generator Owner
that owns a generation or generator interconnection FacilityMaintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System, shall retain evidence of the implementation of its Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
5
Standard PRC-005-1.1b2 — Transmission and Generation Protection System
Maintenance and Testing
for the Protection System maintenance and testing program for three years. Component,
or all performances of each distinct maintenance activity for the Protection System
Component since the previous scheduled audit date, whichever is longer.
The Compliance Monitor shall retain any audit data for three yearsEnforcement
Authority shall keep the last audit records and all requested and submitted subsequent
audit records.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall each demonstrate compliance
through self-certification or audit (periodic, as part of targeted monitoring or
initiated by complaint or event), as determined by the Compliance Monitor.
None.
6
Standard PRC-005-1.1b2 — Transmission and Generation Protection System Maintenance and Testing
4.2. Violation Severity Levels (no changes)
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Protection System Component Type
consistent with the maintenance
intervals specified in Tables 1-1
through 1-5, Table 2, and Table 3
where monitoring is used to extend
the maintenance intervals beyond
those specified for unmonitored
Protection System Components.
(Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity failed to
specify whether three or more
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
3) Maintained a Segment with
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
7
Standard PRC-005-1.1b2 — Transmission and Generation Protection System Maintenance and Testing
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
• Annually perform
maintenance on the greater
of 5% of the segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific Protection
System Component Type, in
accordance with the minimum
maintenance activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, and Table 3.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 5% but 10% or less of the
total Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 10% but 15% or less of
the total Components included
within a specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, and Table 3.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 15% of the total
Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3.
R4
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
5% or less of the annual scheduled
maintenance for a specific Protection
System Component Type in
accordance with their performancebased PSMP.
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
more than 5% but 10% or less of the
annual scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
more than 10% but 15% or less of
the annual scheduled maintenance
for a specific Protection System
Component Type in accordance with
their performance-based PSMP.
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
more than 15% of the annual
scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
R5
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
8
Standard PRC-005-1.1b2 — Transmission and Generation Protection System Maintenance and Testing
Requirement
Number
Lower VSL
Maintenance Issues.
Moderate VSL
identified Unresolved Maintenance
Issues.
High VSL
identified Unresolved Maintenance
Issues.
Severe VSL
Maintenance Issues.
9
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance
and Testing
E. Regional DifferencesVariances
None identified.
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — July 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order dated March 14, 2012).
Updated version from 1a to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
10
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance
and Testing
1.1b
May 9, 2012
AdoptedPRC-005-1.1b was adopted by the
Board of Trustees as part of Project 2010-07
(GOTO).
2
November7,
2012
Adopted by Board of Trustees
Complete revision,
absorbing maintenance
requirements from PRC005-1b, PRC-008-0,
PRC-011-0, PRC-017-0
11
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance
and Testing
Appendix 1
12
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval1
Maintenance Activities
Requirement NumberFor all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years
Test and
Text, if necessary calibrate
For microprocessor relays:
Verify operation of Requirementthe relay inputs and outputs
that are essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input values.
1
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
13
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval1
Maintenance Activities
R1. Each Transmission Owner and any Distribution
Provider that owns a transmission Protection
System and each Generator Owner that owns
a generation Protection System shall have a
Protection System maintenance and testing
program for Protection Systems that affect the
reliability of the BES. The program shall
include:
R1.1. Maintenance and testing intervals and their
basis.
R1.2. Summary of maintenance and testing
procedures.
Monitored microprocessor protective relay with the following:
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Alarming for power supply failure (see Table 2).
12 calendar
years
R2. Each Transmission Owner and any Distribution
Provider that owns a transmission Protection
System and each Generator Owner that owns
a generation Protection System shall provide
documentation of its Protection System
maintenance and testing program and the
implementation of that program to its Regional
Reliability Organization on request (within 30
calendar days). The documentation of the
program implementation shall include:
R2.1 Evidence Protection System devices were
maintained and tested within the defined
intervals.
R2.2 Date each Protection System device was last
tested/maintained.Verify:
Settings are as specified.
14
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval1
Maintenance Activities
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
Alarming for change of settings (See Table 2).
12 calendar
years
The request for interpretation of PRC-005-1 Requirements
R1 and R2 focuses on the applicability of the term
“transmission Protection System.” The NERC Glossary of
Terms Used in Reliability Standards contains a definition of
“Protection System” but does not contain a definition of
transmission Protection System. In these two standards, use
of the phrase transmission Protection System indicates that
the requirements using this phrase are applicable to any
Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses,
transformers, etc.) identified as being included in the Bulk
Electric System (BES) and trips an interrupting device that
interrupts current supplied directly from the BES.
A Protection System for a radially connected transformer
energized from the BES would be considered a transmission
Protection System and subject to these standards only if the
protection trips an interrupting device that interrupts current
supplied directly from the BES and the transformer is a BES
element.Verify only the unmonitored relay inputs and outputs that
are essential to proper functioning of the Protection System.
15
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
16
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Appendix 2
17
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Requirement Number and Text of RequirementTable 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
18
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Component Attributes
R1. Each
Transmission
Owner and
any
Distribution
Provider that
owns a
transmission
Protection
System and
each
Generator
Owner that
owns a
generation
Protection
System shall
have a
Protection
System
maintenance
and testing
program for
Protection
Systems that
affect the
reliability of
the BES. The
program shall
include:
Maintenance Activities
R1.1.Maximum
Maintenance
and testing
intervals and
their basis.
R1.2. Summary of
maintenance and
testing
19
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Question:Any unmonitored communications system necessary for
correct operation of protective functions, and not having all the
monitoring attributes of a category below.
4 calendar months
Verify that the communications system is functional.
Does R1 require a maintenanceVerify that the
communications system meets performance criteria
pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
1. Verify operation of communications system inputs
and testing program for the battery chargers for
the “station batteries”outputs that are considered
partessential to proper functioning of the
Protection System?
6 calendar years
2. Does R1 require a maintenance and testing
program for auxiliary relays and sensing devices?
If so, what types of auxiliary relays and sensing
devices? (i.e transformer sudden pressure relays)
3. Does R1 require maintenance and testing of
transmission line re-closing relays?
4. Does R1 require a maintenance and testing
program for the DC circuitry that is just the
circuitry with relays and devices that control
actions on breakers, etc., or does R1 require a
program for the entire circuit from the battery
charger to the relays to circuit breakers and all
associated wiring?
5.
For R1, what are examples of "associated
communications systems" that are part of “Protection
Systems” that require a maintenance and testing
program?.
20
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Response:Any communications system with continuous monitoring or
periodic automated testing for the presence of the channel function, and
alarming for loss of function (See Table 2).
12 calendar years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and
outputs that are essential to proper functioning of the
Protection System.
21
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
1. While battery chargers are vital for ensuring “station
batteries” are available to support Protection System
functions, they are not identified within the definition of
“Protection Systems.” Therefore, PRC-005-1 does not require
maintenance and testing of battery chargers.
2. The existing definition of “Protection System” does not
include auxiliary relays; therefore, maintenance and testing of
such devices is not explicitly required. Maintenance and
testing of such devices is addressed to the degree that an
entity’s maintenance and testing program for 3 DC control
circuits involves maintenance and testing of imbedded
auxiliary relays. Maintenance and testing of devices that
respond to quantities other than electrical quantities (for
example, sudden pressure relays) are not included within
Requirement R1.
3. No. “Protective Relays” refer to devices that detect and take
action for abnormal conditions. Automatic restoration of
transmission lines is not a “protective” function.
4. PRC-005-1 requires that entities 1) address DC control
circuitry within their program, 2) have a basis for the
way they address this item, and 3) execute the program.
PRC-005-1 does not establish specific additional
requirements relative to the scope and/or methods
included within the program.
12 calendar years
Verify only the unmonitored communications system
inputs and outputs that are essential to proper functioning
of the Protection System
5. “Associated communication systems” refer to
communication systems used to convey essential
Protection System tripping logic, sometimes referred to
as pilot relaying or teleprotection. Examples include the
following:
carrier
Any communications equipment involved
relayingsystem with all of the following:
in power-line-
communications equipment involved in various types
of permissive protection system applications
direct transfer-trip systems
digital communication systems (which would include the
protection system communications functions of standard
22
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Maximum
Maintenance
Interval
Maintenance Activities
12 calendar years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
23
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Float voltage of battery charger
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
Battery continuity
Battery terminal connection resistance
18 Calendar
Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
Physical condition of battery rack
24
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
25
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
6 Calendar Months
Inspect:
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
26
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
27
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Float voltage of battery charger
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
28
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Verify that the dc supply can perform as manufactured when ac power
is not present.
29
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
30
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
31
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 calendar
years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 calendar
years
Verify electrical operation of electromechanical lockout
devices.
Unmonitored control circuitry associated with SPS.
12 calendar
years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
12 calendar
years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPS whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
32
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5 and Table 3, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance
activities are subject to the following maintenance requirements
Maximum
Component Attributes
Maintenance
Maintenance Activities
Interval
Any alarm path through which alarms in Tables 1-1 through 1-5 and Table 3 are
conveyed from the alarm origin to the location where corrective action can be
initiated, and not having all the attributes of the “Alarm Path with monitoring”
category below.
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
No periodic
maintenance
specified
None.
33
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
Test and, if necessary calibrate
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 calendar
years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
Settings are as specified.
12 calendar
years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
12 calendar
years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
34
Standard PRC-005-1.1b2 – Transmission and Generation Protection System Maintenance and Testing
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Alarming for change of settings (See Table 2).
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 calendar
years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 calendar
years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 calendar
years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 calendar
years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
35
Standard PRC-005-1.1b2 — Transmission and Generation Protection System Maintenance and Testing
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
Components included in each designated
Segment of the Protection System
Component population, with a minimum
Segment population of 60 Components.
Segment – Protection Systems or components
of a consistent design standard, or a
particular model or type from a single
manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least
sixty (60) individual components.
2. Maintain the Components in each
Segment according to the time-based
maximum allowable intervals established
in Tables 1-1 through 1-5 and Table 3
until results of maintenance activities for
the Segment are available for a minimum of 30 individual Components of the Segment.
3. Document the maintenance program activities and results for each Segment, including
maintenance dates and Countable Events
for each included Component.
Countable Event – A failure of a component
4. Analyze the maintenance program
activities and results for each Segment to
determine the overall performance of the
Segment and develop maintenance
intervals.
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5 and Table 3 which requires
corrective action, or a Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System component
configuration errors, or Protection System
application errors are not included in Countable
Events.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than 4%
of the Components within the Segment,
for the greater of either the last 30
Components maintained or all Components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System Components and Segments and/or
description if any changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
Page 36 of 6
Standard PRC-005-1.1b2 — Transmission and Generation Protection System Maintenance and Testing
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Protection System Segment maintained through a performancebased PSMP experience 4% or more Countable Events, develop, document, and
implement an action plan to reduce the Countable Events to less than 4% of the Segment
population within 3 years.
Page 37 of 6
Exhibit C
Implementation Plan for Proposed Reliability Standard PRC-005-2
Implementation Plan
Project 2007-17 Protection Systems Maintenance and Testing
PRC-005-02
Standards Involved
Approval:
• PRC-005-2 – Protection System Maintenance (PRC-005-2)
Retirements:
• PRC-005-1b – Transmission and Generation Protection System Maintenance and Testing (PRC005-1b)
• PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program (PRC-008-0)
• PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing (PRC-011-0)
• PRC-017-0 – Special Protection System Maintenance and Testing (PRC-017-0)
Prerequisite Approvals:
Revised definition of “Protection System.”
Background:
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard establish minimum maintenance activities for
Protection System component types and the maximum allowable maintenance intervals for these
maintenance activities. The maintenance activities established may not be presently performed by
some entities and the established maximum allowable intervals may be shorter than those
currently in use by some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
4.
The Implementation Schedule set forth in this document requires that entities develop their
revised Protection System Maintenance Program within twelve (12) months following applicable
regulatory approvals, or in those jurisdictions where no regulatory approval is required, on the first
day of the first calendar quarter twenty-four (24) months following NERC Board of Trustees
adoption. This anticipates that it will take approximately twelve (12) months to achieve regulatory
approvals following adoption by the NERC Board of Trustees.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally-distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 until that entity meets
the requirements of PRC-005-2 in accordance with this implementation plan. Each entity shall be
responsible for maintaining each of their Protection System components according to their
maintenance program already in place for the legacy standards (PRC-005-1b, PRC-008-0, PRC-011-0, and
PRC-017-0) or according to their maintenance program for PRC-005-2, but not both. Once an entity has
designated PRC-005-2 as its maintenance program for specific Protection System components, they
cannot revert to the original program for those components.
While entities are transitioning to the requirements of PRC-005-2, each entity must be prepared to
identify:
•
All of its applicable Protection System components.
•
Whether each component has last been maintained according to PRC-005-2 or under PRC-0051b, PRC-008-0, PRC-011-0, or PRC-017-0.
For activities being added to an entity’s program as part of PRC-005-2 implementation, evidence may be
available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC-005-2.
Retirement of Existing Standards:
Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0, which are being replaced by PRC-005-2,
shall remain active throughout the phased implementation period of PRC-005-2 and shall be applicable
to an entity’s Protection System component maintenance activities not yet transitioned to PRC-005-2.
Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired at midnight of the day
immediately prior to the first day of the first calendar quarter one hundred fifty-six (156) months
following applicable regulatory approval, or in those jurisdictions where no regulatory approval is
Project 2007-17 Protection Systems Maintenance and Testing
Implementation Plan
July 20, 2012
2
required, at midnight of the day immediately prior to the first day of the first calendar quarter one
hundred sixty-eight (168) months following NERC Board of Trustees adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
Project 2007-17 Protection Systems Maintenance and Testing
Implementation Plan
July 20, 2012
3
Implementation Plan for Requirements R1, R2 and R5:
Entities shall be 100% compliant on the first day of the first calendar quarter twelve (12) months following
applicable regulatory approvals, or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter twenty-four (24) months following NERC Board of Trustees adoption
or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System component maintenance activities with maximum allowable intervals of less
than one (1) calendar year, as established in Tables 1-1 through 1-5:
•
2.
For Protection System component maintenance activities with maximum allowable intervals one
(1) calendar year or more, but two (2) calendar years or less, as established in Tables 1-1 through 15:
•
3.
The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
eighteen (18) months following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter thirty (30)
months following NERC Board of Trustees adoption or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
thirty-six (36) months following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter forty-eight (48)
months following NERC Board of Trustees adoption or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.
For Protection System component maintenance activities with maximum allowable intervals of
three (3) calendar years, as established in Tables 1-1 through 1-5:
•
The entity shall be at least 30% compliant with PRC-005-2 on the first day of the first calendar
quarter twenty-four (24) months following applicable regulatory approval (or, for generating
plants with scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty-six (36) months following NERC
Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
•
The entity shall be at least 60% compliant with PRC-005-2 on the first day of the first calendar
quarter thirty-six (36) months following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter fortyeight (48) months following NERC Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
Project 2007-17 Protection Systems Maintenance and Testing
Implementation Plan
July 20, 2012
4
•
4.
The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
forty-eight (48) months following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter sixty (60)
months following NERC Board of Trustees adoption or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.
For Protection System component maintenance activities with maximum allowable intervals of six
(6) calendar years, as established in Tables 1-1 through 1-5 and Table 3:
•
The entity shall be at least 30% compliant with PRC-005-2 on the first day of the first calendar
quarter thirty-six (36) months following applicable regulatory approval (or, for generating
plants with scheduled outage intervals exceeding three years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter forty-eight (48) months following NERC
Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
• The entity shall be at least 60% compliant with PRC-005-2 on the first day of the first calendar
quarter sixty (60) months following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter seventytwo (72) months following NERC Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
• The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
eighty-four (84) months following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter ninety-six
(96) months following NERC Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
5.
For Protection System component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1-1 through 1-5, Table 2, and Table 3:
• The entity shall be at least 30% compliant with PRC-005-2 on the first day of the first calendar
quarter sixty (60) months following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter seventytwo (72) months following NERC Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
• The entity shall be at least 60% compliant with PRC-005-2 on the first day of the first calendar
quarter following one hundred eight (108) months following applicable regulatory approval, or
in those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees adoption
or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
Project 2007-17 Protection Systems Maintenance and Testing
Implementation Plan
July 20, 2012
5
• The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
one hundred fifty-six (156) months following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following NERC Board of Trustees adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
Applicability:
This standard applies to the following functional entities:
• Transmission Owner
• Generator Owner
• Distribution Provider
Project 2007-17 Protection Systems Maintenance and Testing
Implementation Plan
July 20, 2012
6
Exhibit D
Technical Justification: PRC-005-2 Protection System Maintenance
Technical Justification
PRC-005-2 Protection System Maintenance
The purpose of the proposed PRC-005-2 Reliability Standard is to document and implement programs
for the maintenance of all Protection Systems affecting the reliability of the Bulk Electric System (BES)
so that these Protection Systems are kept in working order. The proposed Reliability Standard further
combines the legacy Reliability Standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0, as these
legacy Reliability Standards have similar reliability goals and requirements. This purpose is consistent
with NERC’s goal to create and implement reliability standards that enable or support at least one of
the eight, defined Reliability Principles. The requirements of the proposed PRC-005-1 Reliability
Standard directly support the following Reliability Principles:
Reliability Principle 1 – Interconnected bulk power systems shall be planned and operated in a
coordinated manner to perform reliably under normal and abnormal conditions as defined in
the NERC Standards.
Reliability Principle 7 – The reliability of the interconnected bulk power systems shall be
assessed, monitored, and maintained on a wide-area basis.
The existing PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 Reliability Standards, as assessed by the
NERC System Protection and Control Task Force (SPCTF) in its report of March 8, 2007, contain several
fundamental flaws within the requirements. Within this assessment, the SPCTF asserts, for all four
standards, that:
“The listed requirements do not provide clear and sufficient guidance concerning the maintenance and
testing of the Protection Systems to achieve the commonly stated purpose which is “To ensure all
transmission and generation Protection Systems affecting the reliability of the Bulk Electric System
(BES) are maintained and tested.””
And further recommends that:
“The standards should clearly state which power system elements are being addressed.”
“The requirements should reflect the inherent differences between different technologies of
protection systems.”
“The terms maintenance programs and testing programs should be clearly defined in the
glossary. The terms “maintenance” and “testing” are not interchangeable, and the
requirements must be clear in their application. Additional terms may also have to be added to
the glossary for clarity.”
“The requirements of the existing standards, as stated, support time-based maintenance and
testing, and should be expanded to include condition-based and performance-based
maintenance and testing. The R1.2 summary of maintenance and testing procedures needs to
PRC-005-2 Protection System Maintenance
Technical Justification | October 2012
1
have some minimum defined sub-requirements to insure that the stated intent of the standards
is met to support review by the compliance monitor,” and
The SPCTF recommends that standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 … be
included in a new Standard Authorization Request for a single Protection System maintenance
and testing standard.
Relative to PRC-005-1, the Federal Energy Regulatory Commission (FERC), in Order 693 further directed
in paragraph 1476:
“… the Commission directs the ERO to develop a modification to PRC–005–1 through the Reliability
Standards development process that includes a requirement that maintenance and testing of a
protection system must be carried out within a maximum allowable interval that is appropriate to the
type of the protection system and its impact on the reliability of the Bulk-Power System. We further
direct the ERO to consider FirstEnergy’s and ISO–NE’s suggestion to combine PRC–005–1, PRC–008–0,
PRC–011–0, and PRC–017–0 into a single Reliability Standard through the Reliability Standards
development process.”
FERC offered, in paragraphs 1492, 1517, and 1547, similar directives regarding PRC-008-0, PRC-011-0,
and PRC-017-0, respectively.
With the development of the proposed PRC-005-2 Reliability Standard, the drafting team for Project
2007-17 – Protection System Maintenance, has followed the observations and recommendation of the
NERC SPCTF assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 including addressing
FERC’s directives from Order 693. The drafting team accomplishes this by:
1. Merging the reliability objectives of the four legacy standards.
2. Establishing minimum acceptable maintenance activities and accompanying maximum
allowable maintenance intervals, reflecting various technologies of the components being
addressed.
3. Providing entities the flexibility to implement condition-based maintenance by adjusting the
minimum acceptable maintenance activities and maximum allowable maintenance intervals to
reflect condition monitoring of the various Protection System components, and
4. Providing requirements for effective implementation of a performance-based maintenance
program.
The proposed PRC-005-2 Reliability Standard includes five requirements that:
1. Combines the reliability goals of developing detailed tables of minimum maintenance activities
and maximum maintenance intervals for all five component types addressed within the NERC
definition of Protection System. These tables include adjustments to those activities and
intervals to reflect the benefits of any condition monitoring that may be present.
PRC-005-2 Protection System Maintenance
Technical Justification | October 2012
2
2. Requires, within Requirement R1, that entities using a time-based maintenance program (which
includes condition-based maintenance) shall establish a Protection System Maintenance
Program (PSMP) that conforms to the tables described above.
3. Establishes, within Requirement R2, the opportunity and requirements for establishment of a
performance-based maintenance program for those entities that have (or wish to develop)
sufficient performance observations for their Protection System components such that they
may determine maintenance intervals other than those specified within the tables while
maintaining the level of reliability prescribed within the Standard.
4. Requires, within Requirements R3 and R4, that entities fully implement their PSMP as
determined pursuant to Requirement R1 for time-based maintenance programs and
Requirement R2 for performance-based maintenance programs, respectively.
5. Further requires, within Requirement R5, that entities initiate resolution of any issues
discovered during maintenance that cause the entities to be unable to return the associated
components to good working order. The drafting team elected to not require that entities
complete the resolution of these issues, as the time required to effectively resolve the
problems may vary widely depending on the scope of that resolution.
The proposed PRC-005-2 Reliability Standard provides a comprehensive set of requirements and
associated information (within the tables) that define a strong PSMP. Entities that monitor the actual
condition of their Protection System components are further empowered to utilize the monitoring to
improve the efficiency and effectiveness of their PSMP, and those entities that have extensive
performance data regarding their Protection System components to utilize that performance data to
further improve the efficiency and effectiveness of their PSMP.
PRC-005-2 Protection System Maintenance
Technical Justification | October 2012
3
Requirement R1:
R1.
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems identified in
Section 4.2. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is used to address each Protection System
Component Type. All batteries associated with the station dc supply Component Type
of a Protection System shall be included in a time-based program as described in
Table 1-4 and Table 3.
1.2. Include the applicable monitored Component attributes applied to each Protection
System Component Type consistent with the maintenance intervals specified in
Tables 1-1 through 1-5, Table 2, and Table 3 where monitoring is used to extend the
maintenance intervals beyond those specified for unmonitored Protection System
Components.
Background and Rationale
Establishment of a Protection System Maintenance Program as directed by Requirement R1 is
needed to detect and correct plausible age- and service-related degradation of Protection System
components. It is important that a Protection System continue to function as designed over its
service life to ensure reliability of the Bulk Electric System.
Requirement R1 establishes that entities develop a comprehensive maintenance program for
Protection System components addressing the elements specified in the Protection System
Maintenance Program definition:
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components
is restored. A maintenance program for a specific component includes one or more of the
following activities:
•
Verify — Determine that the component is functioning correctly.
•
Monitor — Observe the routine in-service operation of the component.
•
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
•
Inspect — Examine for signs of component failure, reduced performance and degradation.
•
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Maintenance and testing programs often incorporate the following types of maintenance practices:
PRC-005-2 Protection System Maintenance
Technical Justification | October 2012
4
TBM – time-based maintenance – externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have been
developed from prior experience or manufacturers’ recommendations. The TBM verification
interval is based on a variety of factors, including experience of the particular asset owner,
collective experiences of several asset owners who are members of a country or regional
council, etc. The maintenance intervals are fixed, and may range in number of months or in
years.
TBM can include review of recent power system events near the particular terminal. Operating
records may verify that some portion of the Protection System has operated correctly since the
last test occurred. If specific protection scheme components have demonstrated correct
performance within specifications, the maintenance test time clock can be reset for those
components.
PBM – performance-based maintenance - intervals are established based on analytical or
historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied by
adjustments to maintenance intervals are used to justify continued use of PBM-developed
extended intervals when test failures or in-service failures occur infrequently.
The Performance Based Maintenance (PBM) program ensures no more than a 4% failure rate
for each segment of a component type. There could be more or less than 4 failures per year
depending on the population size of the segment. The 4% number was developed using the
following:
General experience of the drafting team based on open discussions of past performance.
Test results provided by Consumers Energy for the years 1998-2008 showing a yearly average of
7.5% out-of-tolerance relay test results and a yearly average of 1.5% defective rate.
Two failure analysis reports from Tennessee Valley Authority (TVA) where TVA identified
problematic equipment based on a noticeably higher failure of a certain relay type (failure rate
of 2.5%) and voltage transformer type (failure rate of 3.6%).
Refer to Supplementary Reference and FAQ Document - Section 9.1 for a discussion and
examples for the application of the 4% failure rate.
CBM – condition-based maintenance – continuously or frequently reported results from nondisruptive self monitoring of components demonstrate operational status as those components
remain in service. Whatever is verified by CBM does not require manual testing, but taking
advantage of this requires precise technical focus on exactly what parts are included as part of
the self diagnostics. While the term “Condition-Based-Maintenance” (CBM) is no longer used
within the Standard itself, it is important to note that the concepts of CBM are a part of the
Standard (in the form of extended time intervals through status-monitoring). These extended
time intervals are only allowed (in the absence of PBM) if the condition of the device is
monitored (CBM). As a consequence of the “monitored-basis-time-intervals” existing within the
PRC-005-2 Protection System Maintenance
Technical Justification | October 2012
5
Standard, the explanatory discussions within the Supplementary Reference and FAQ Document
concerned with CBM will remain and are discussed as CBM.
A key feature of condition-based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the protection system owner knows
about it, for the monitored segments of the protection system. In some cases, the verification is
practically continuous - the time interval between verifications is minutes or seconds. Thus,
technically sound, condition-based verification, meets the directives of FERC Order 693 even
more effectively than the strictly time-based tests of the same system components while
minimizing the potential for human performance errors during maintenance activities.
Microprocessor based Protection System components that perform continuous self-monitoring
verify correct operation of most components within the device. Self-monitoring capabilities
may include battery continuity, float voltages, unintentional grounds, the ac signal inputs to a
relay, analog measuring circuits, processors and memory for measurement, protection, and
data communications, trip circuit monitoring, and protection or data communications signals
(and many, many more measurements). For those conditions, failure of a self-monitoring
routine generates an alarm and may inhibit operation to avoid false trips. When internal
components, such as critical output relay contacts, are not equipped with self-monitoring, they
can be manually tested. The method of testing may be local or remote, or through inherent
performance of the scheme during a system event.
TBM, PBM, and CBM can be combined for individual components, or within a complete Protection
System. The following diagram illustrates the relationship between various types of maintenance
practices described in this section. In the Venn diagram the overlapping regions show the relationship
of TBM with PBM historical information and the inherent continuous monitoring offered through CBM.
This figure shows:
Region 1: The TBM intervals that are increased based on known reported operational condition
of individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been
subject to TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
PRC-005-2 Protection System Maintenance
Technical Justification | October 2012
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Relationship of time-based maintenance types
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The PSMP shall:
R1, Part 1.1 Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is used to address each Protection System component
type.
Requirement R1, Part 1.1 gives entities the flexibility to choose between the various methods
listed above to maintain their Protection System equipment.
All batteries associated with the station dc supply Component Type of a Protection
System shall be included in a time-based program as described in Table 1-4 and Table 3.
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a performance-based maintenance (PBM) program
for its Protection Systems. These inherent variances in the aging process of a battery cell make
establishment of a designated segment based on manufacturer and type of battery impossible.
Requirement R1, Part 1.2
Include the applicable monitored Component attributes applied to each
Protection System Component Type consistent with the maintenance intervals specified in Tables 1PRC-005-2 Protection System Maintenance
Technical Justification | October 2012
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1 through 1-5, Table 2, and Table 3 where monitoring is used to extend the maintenance intervals
beyond those specified for unmonitored Protection System Components.
It is necessary for entities to specify the monitoring attributes utilized in their PSMP to demonstrate
the existence of the monitoring elements which permit using the extended maintenance intervals
established in Tables 1-1 through 1-5, Table 2, and Table 3 of the standard.
All maintenance is fundamentally time-based. Default time-based intervals are commonly established
to assure proper functioning of each component of the Protection System, when data on the reliability
of the components is not available other than observations from time-based maintenance. Excessive
maintenance can actually decrease the reliability of the component or system. It is not unusual to
cause failure of a component by removing it from service and restoring it. The improper application of
test signals may cause failure of a component. Making use of the extended intervals by employing
component monitoring minimizes human performance errors. The following factors may influence the
established default intervals:
If continuous indication of the functional condition of a component is available (from relays or
chargers or any self monitoring device), then the intervals may be extended or manual testing
may be eliminated. This is referred to as condition-based maintenance or CBM. CBM is valid
only for precisely the components subject to monitoring. In the case of microprocessor-based
relays, self-monitoring may not include automated diagnostics of every component within a
microprocessor.
Previous maintenance history for a group of components of a common type may indicate that
the maintenance intervals can be extended while still achieving the desired level of
performance. This is referred to as performance-based maintenance or PBM. It is also
sometimes referred to as reliability-centered maintenance or RCM, but PBM is used in this
document.
Observed proper operation of a component may be regarded as a maintenance verification of
the respective component or element in a microprocessor-based device. For such an
observation, the maintenance interval may be reset only to the degree that can be verified by
data available on the operation. For example, the trip of an electromechanical relay for a fault
verifies the trip contact and trip path, but only through the relays in series that actually
operated; one operation of this relay cannot verify correct calibration.
PRC-005-2 Protection System Maintenance
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Requirement R2:
Overview
Requirement 2, stated below, deals with performance based maintenance. The requirement refers to
Attachment A. Rather than simply list Attachment A, the requirements of Attachment A are listed
below with a technical justification discussion for each. The criteria within Attachment A are largely
based on application of statistical analysis theory.
Requirement R2
Requirement R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses
performance-based maintenance intervals in its PSMP shall follow the procedure established in
PRC-005 Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
Background and Rationale
Performance-based maintenance (PBM) is included in PRC-005-2 to allow utilities to adjust
maintenance intervals based on their individual experience with equipment types and manufacturer.
The utility must create a segment of components
Segment – Protection Systems or
with similar manufacturer and model characteristics
components of a consistent design standard,
of statistically significant size.
or a particular model or type from a single
manufacturer that typically share other
Based on equipment failure(s) and out-ofcommon elements. Consistent performance
tolerance(s), called Countable Events, in any given
is expected across the entire population of a
year, the utility then sets its maintenance interval to
segment. A segment must contain at least
keep the Countable Events below 4%. Performancesixty (60) individual components.
based maintenance is discussed at length in Section
9.1 of the Supplementary Reference and FAQ
Document for PRC-005-2. Many of the technical
Countable Event – A failure of a component
justifications shown below come from the
requiring repair or replacement, any
Supplementary Reference and FAQ Document.
condition discovered during the maintenance
Each criterion of Attachment A is individually
activities in Tables 1-1 through 1-5 and Table
discussed.
3 which requires corrective action, or a
Misoperation attributed to hardware failure
1. Develop a list with a description of
or calibration failure. Misoperations due to
Components included in each designated
product design errors, software errors, relay
Segment of the Protection System
settings different from specified settings,
Component population, with a minimum
Protection System component configuration
Segment population of 60 Components.
errors, or Protection System application
A sample size requirement can be errors are not included in Countable Events.
estimated using the bound on the Error of
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Distribution Formula when the expected result is of a “Pass/Fail” format and will be between 0
and 1.0.
The Error of Distribution Formula is:
1
n
z
Where:
= bound on the error of distribution (allowable error)
z = standard error
= expected failure rate
n = sample size required
Solving for n provides:
n
1
z
2
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
= 4% (see number 5 below)
Using the equation above, n=59.0. The Standard Drafting Team chose to use the round
number of 60 for the requirement.
2. Maintain the Components in each Segment according to the time-based maximum allowable
intervals established in Tables 1-1 through 1-5 and Table 3 until results of maintenance
activities for the Segment are available for a minimum of 30 individual Components of the
Segment.
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003)
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To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation , the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics - Picturing the World, Larson, Farber,
2003)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968)
3. Document the maintenance program activities and results for each Segment, including
maintenance dates and Countable Events for each included Component.
This criterion needs little justification. To analyze system performance, the activities and
results must be documented.
4. Analyze the maintenance program activities and results for each Segment to determine the
overall performance of the Segment and develop maintenance intervals.
This criterion states the obvious for a program that is based on the performance results of the
Segment.
5. Determine the maximum allowable maintenance interval for each Segment such that the
Segment experiences Countable Events on no more than 4% of the Components within the
Segment, for the greater of either the last 30 Components maintained or all Components
maintained in the previous year.
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The performance-based maintenance (PBM) program ensures no more than a 4% failure rate
for each segment of a Component Type. The 4% number was developed using the following:
General experience of the drafting team based on open discussions of past
performance.
Test results provided by Consumers Energy for the years 1998-2008 showing a yearly
average of 7.5% out-of-tolerance relay test results and a yearly average of 1.5%
defective rate.
Two failure analysis reports from Tennessee Valley Authority (TVA) where TVA identified
problematic equipment based on a noticeably higher failure of a certain relay type
(failure rate of 2.5%) and voltage transformer type (failure rate of 3.6%).
In addition to the number “30” discussion from number 2 above, the Error of Distribution
formula discussed in number 1 above allows the number of components that should be
included in a sample size for evaluation of the appropriate testing interval to be smaller
because a lower confidence level is acceptable since the sample testing is repeated or
updated annually. For this reason, the following assumptions are made:
B = 5%
z = 1.44 (85% confidence level)
= 4%
Using the equation above, n=31.8. The Standard Drafting Team chose to use the
round number of 30.
To maintain the technical justification for the ongoing use of a performance-based
PSMP, the following additional criteria are provided:
1. At least annually, update the list of Protection System Components and Segments and/or
description if any changes occur within the Segment.
“Annually” was chosen as a reasonable time frame to update Component Segments due to
Component installation, replacement, and retirement.
2. Perform maintenance on the greater of 5% of the Components (addressed in the performance
based PSMP) in each Segment or 3 individual Components within the Segment in each year.
Note: this 5% threshold sets a practical limitation on total length of time between intervals at
20 years regardless of performance.
This criterion ensures that a utility keeps a flow of recent data to use in its annual analysis. The
Standard Drafting Team felt that 20 years was the maximum time that should be allowed
before a Component should be checked or maintained. The minimum number of three allows
for the same 20 years interval based on the minimum Segment population of 60 (60/3=20).
PRC-005-2 Protection System Maintenance
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3. For the prior year, analyze the maintenance program activities and results for each Segment to
determine the overall performance of the Segment.
Note: “Annually” was chosen as a reasonable time frame to allow for collection of new data to
update the program’s performance analysis.
4. Using the prior year’s data, determine the maximum allowable maintenance interval for each
Segment such that the Segment experiences Countable Events on no more than 4% of the
Components within the Segment, for the greater of either the last 30 Components maintained
or all Components maintained in the previous year.
Note: Refer to number 5 above.
5. If the Components in a Protection System Segment maintained through a performance-based
PSMP experience 4% or more Countable Events, develop, document, and implement an action
plan to reduce the Countable Events to less than 4% of the Segment population within 3 years.
Note: The 4% number is discussed in number 5 above. Three years was chosen by the drafting
team because it allows time to modify the program and for the effects of a modified program to
be observed.
Requirement R3:
R3.
Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance programs shall maintain its Protection System Components that are
included within the time-based maintenance program in accordance with the minimum
maintenance activities and maximum maintenance intervals prescribed within Tables 1-1
through 1-5, Table 2, and Table 3. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
Background and Rationale
NERC Reliability Principle 1 establishes that “Interconnected bulk power systems shall be planned and
operated in a coordinated manner to perform reliably under normal and abnormal conditions as
defined in the NERC Standards.”
NERC Reliability Principle 7 establishes that “The reliability of the interconnected bulk power systems
shall be assessed, monitored, and maintained on a wide-area basis.”
The proper performance of Protection Systems is fundamental to the reliability of the Bulk Electric
System (BES) as embodied in Reliability Principles 1 and 7, and proper performance of Protection
Systems cannot be assured without periodic maintenance of those systems.
PRC-005-2 Protection System Maintenance
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Therefore, Requirement R3 requires the implementation of the minimum maintenance activities and
maximum allowable maintenance intervals as elucidated in Requirement R1 and the tables within the
standard.
PRC-005-2 Protection System Maintenance
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Requirement R4:
R4.
Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System Components that are included
within the performance-based program(s). [Violation Risk Factor: High] [Time Horizon:
Operations Planning]
Background and Rationale
NERC Reliability Principle 1 establishes that “Interconnected bulk power systems shall be planned and
operated in a coordinated manner to perform reliably under normal and abnormal conditions as
defined in the NERC Standards.”
NERC Reliability Principle 7 establishes that “The reliability of the interconnected bulk power systems
shall be assessed, monitored, and maintained on a wide-area basis.”
The proper performance of Protection Systems is fundamental to the reliability of the Bulk Electric
System (BES) as embodied in Reliability Principles 1 and 7, and proper performance of Protection
Systems cannot be assured without periodic maintenance of those systems.
Therefore, Requirement R4 requires the implementation of an entity’s Protection System Maintenance
Program established pursuant to Requirement R2.
Requirement R5:
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
Unresolved Maintenance Issue - A
deficiency identified during a
Background and Rationale
maintenance activity that causes the
component to not meet the intended
The reliability objective of this requirement is to assure
performance, cannot be corrected
that Protection System components are returned to during the maintenance interval, and
working order following the discovery of failures or requires follow-up corrective action.
malfunctions during scheduled maintenance. The
maintenance activities specified in the Tables 1-1 through 1-5, Table 2, and Table 3 do not present any
requirements related to restoration; therefore Requirement R5 of the Standard was developed to
require the entity to “demonstrate efforts to correct identified Unresolved Maintenance Issues”.
PRC-005-2 Protection System Maintenance
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The drafting team does not believe entities should be found in violation of a maintenance program
requirement because of the inability to complete a remediation program within the original
maintenance interval. The drafting team does believe corrective actions should be timely but
concludes it would be impossible to postulate all possible remediation projects and therefore,
impossible to specify bounding time frames for resolution of all possible Unresolved Maintenance
Issues or what documentation might be sufficient to provide proof that effective corrective action has
been initiated. Therefore Requirement R5 requires only the entity demonstrate efforts to correct the
Unresolved Maintenance Issues.
Management of completion of the identified Unresolved Maintenance Issue is a complex topic that
falls outside of the scope of this standard. There can be any number of supply, process and
management problems that make setting repair deadlines impossible. The drafting team specifically
chose to require the entity to “demonstrate efforts to correct …” because of the concern that many
more complex Unresolved Maintenance Issues might require greater than the remaining maintenance
interval to resolve. For example, a problem might be identified on a VRLA battery during a 6 month
check. In instances such as one that requiring battery replacement as part of the long term resolution,
it is highly unlikely that the battery could be replaced in time to meet the 6 calendar month
requirement for this maintenance activity.
During the period of time that the Protection System is operating in a degraded mode, NERC Standard
PRC-001-1 requires that operating entities be informed of any Protection System failures that reduce
reliability, and several NERC IRO-series and TOP-series standards require that operating entities
operate the system in a manner that assures reliability while recognizing any system degradation.
PRC-005-2 Protection System Maintenance
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Exhibit E
PRC-005-2: Supplementary Reference and FAQ
Supplementary Reference
and FAQ
PRC-005-2 Protection System Maintenance
October 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Ta b le o f Co n t e n t s
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ......................... 2
2.2 Protection System Definition ................................................................................................ 3
2.3 Applicability of New Protection System Maintenance Standards ........................................ 3
2.3.1 Frequently Asked Questions: ............................................................................................. 4
2.4.1 Frequently Asked Questions: ............................................................................................. 6
3. Protection Systems Product Generations ................................................................................... 8
4. Definitions ................................................................................................................................. 10
4.1 Frequently Asked Questions: .............................................................................................. 11
5. Time-Based Maintenance (TBM) Programs .............................................................................. 13
5.1 Maintenance Practices ....................................................................................................... 13
5.1.1 Frequently Asked Questions: ....................................................................................... 15
5.2 Extending Time-Based Maintenance .............................................................................. 16
5.2.1 Frequently Asked Questions: ....................................................................................... 16
6. Condition-Based Maintenance (CBM) Programs ...................................................................... 18
6.1 Frequently Asked Questions: .............................................................................................. 18
7. Time-Based Versus Condition-Based Maintenance .................................................................. 20
7.1 Frequently Asked Questions: .............................................................................................. 20
8. Maximum Allowable Verification Intervals .............................................................................. 26
8.1 Maintenance Tests.............................................................................................................. 26
8.1.1 Table of Maximum Allowable Verification Intervals.................................................... 26
ii
PRC-005-2 Supplementary Reference and FAQ – October 2012
8.1.2 Additional Notes for Tables 1-1 through 1-5 and Table 3 ........................................... 28
8.1.3 Frequently Asked Questions: ....................................................................................... 29
8.2 Retention of Records .......................................................................................................... 34
8.2.1 Frequently Asked Questions: ....................................................................................... 34
8.3 Basis for Table 1 Intervals ................................................................................................... 36
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .............................. 37
9. Performance-Based Maintenance Process ............................................................................... 40
9.1 Minimum Sample Size......................................................................................................... 41
9.2 Frequently Asked Questions: .............................................................................................. 43
10. Overlapping the Verification of Sections of the Protection System ....................................... 54
10.1 Frequently Asked Questions: ............................................................................................ 54
11. Monitoring by Analysis of Fault Records ................................................................................ 55
11.1 Frequently Asked Questions: ............................................................................................ 56
12. Importance of Relay Settings in Maintenance Programs ....................................................... 57
12.1 Frequently Asked Questions: ............................................................................................ 57
13. Self-Monitoring Capabilities and Limitations ......................................................................... 60
13.1 Frequently Asked Questions: ............................................................................................ 61
14. Notification of Protection System Failures ............................................................................. 62
15. Maintenance Activities ........................................................................................................... 63
15.1 Protective Relays (Table 1-1) ............................................................................................ 63
15.1.1 Frequently Asked Questions: ..................................................................................... 63
15.2 Voltage & Current Sensing Devices (Table 1-3) ............................................................ 63
15.2.1 Frequently Asked Questions: ..................................................................................... 65
15.3 Control circuitry associated with protective functions (Table 1-5) .............................. 66
15.3.1 Frequently Asked Questions: ..................................................................................... 68
iii
PRC-005-2 Supplementary Reference and FAQ – October 2012
15.4 Batteries and DC Supplies (Table 1-4)........................................................................... 70
15.4.1 Frequently Asked Questions: ..................................................................................... 70
15.5 Associated communications equipment (Table 1-2) ........................................................ 85
15.5.1 Frequently Asked Questions: ..................................................................................... 86
15.6 Alarms (Table 2) ................................................................................................................ 89
15.6.1 Frequently Asked Questions: ..................................................................................... 89
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)............................................... 90
15.7.1 Frequently Asked Questions: ..................................................................................... 90
15.8 Examples of Evidence of Compliance ............................................................................... 91
15.8.1 Frequently Asked Questions: ......................................................................................... 91
References .................................................................................................................................... 93
Figures ........................................................................................................................................... 95
Figure 1: Typical Transmission System ..................................................................................... 95
Figure 2: Typical Generation System ........................................................................................ 96
Figure 1 & 2 Legend – components of Protection Systems .......................................................... 97
Appendix A .................................................................................................................................... 98
Appendix B .................................................................................................................................. 101
Protection System Maintenance Standard Drafting Team ......................................................... 101
iv
PRC-005-2 Supplementary Reference and FAQ – October 2012
1 . I n t ro d u ct io n a n d Su m m a ry
Note: This supplementary reference for PRC-005-2 is neither mandatory nor enforceable.
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and Canada and address various aspects of maintenance and testing of Protection and
Control Systems.
These standards are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for
Protection Systems, and that these entities must be able to demonstrate they are carrying out
such a program, there are no specifics regarding the technical requirements for Protection
System maintenance programs.
Furthermore, FERC Order 693 directed additional
modifications respective to Protection System maintenance programs. PRC-005-2 combines
and replaces PRC-005, PRC-008, PRC-011 and PRC-017.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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2 . Ne e d fo r Ve r ifyin g P ro t e ct io n Sys t e m P e rfo rm a n ce
Protective relays have been described as silent sentinels, and do not generally demonstrate
their performance until a Fault or other power system problem requires that they operate to
protect power system Elements, or even the entire Bulk Electric System (BES). Lacking Faults,
switching operations or system problems, the Protection Systems may not operate, beyond
static operation, for extended periods. A Misoperation - a false operation of a Protection
System or a failure of the Protection System to operate, as designed, when needed - can result
in equipment damage, personnel hazards, and wide-area Disturbances or unnecessary
customer outages. Maintenance or testing programs are used to determine the performance
and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be
visited at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct
plausible age and service related degradation of the Protection System components, such that a
properly built and commissioned Protection System will continue to function as designed over
its service life.
Similarly station batteries, which are an important part of the station dc supply, are not called
upon to provide instantaneous dc power to the Protection System until power is required by
the Protection System to operate circuit breakers or interrupting devices to clear Faults or to
isolate equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC-005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC-005-1 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC-005-2, the definition of Protection System was:
Protective relays, associated communications Systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
PRC-005-2 Supplementary Reference and FAQ – October 2012
2
Requirements: The owner shall have a documented maintenance program with test intervals.
The owner must keep records showing that the maintenance was performed at the specified
intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
•
Protective relays which respond to electrical quantities,
•
Communications systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting Faults on BES Elements (lines, buses,
transformers, etc.).”
The drafting team intends that this standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the Element is a BES Element, then the Protection
System protecting that Element should then be included within this standard. If there is
regional variation to the definition, then there will be a corresponding regional variation to the
Protection Systems that fall under this standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the standard language should simply be applicable to Protection Systems for
BES Elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions.
See the NERC Glossary of Terms for the present, in-force definition. See the applicable Regional
Reliability Organization for any applicable allowed variations.
While this standard will undergo revisions in the future, this standard will not attempt to keep
up with revisions to the NERC definition of BES, but, rather, simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because GOs
and TOs have equipment that is BES equipment. The standard brings in Distribution Providers
(DP) because, depending on the station configuration of a particular substation, there may be
Protection System equipment installed at a non-transmission voltage level (Distribution
PRC-005-2 Supplementary Reference and FAQ – October 2012
3
Provider equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would
apply to this equipment. An example is underfrequency load-shedding, which is frequently
applied well down into the distribution system to meet PRC-007-0.
As this standard is intended to replace the existing PRC-005, PRC-008, PRC-011 and PRC-017,
those standards are used in the construction of this revision of PRC-005-1. Much of the original
intent of those standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example, the original PRC-008 was
constructed quite differently than the original PRC-005. The drafting team agrees with the
intent of this and notes that distributed tripping schemes would have to exhibit multiple
failures to trip before they would prove to be significant, as opposed to a single failure to trip
of, for example, a transmission Protection System Bus Differential lock-out relay. While many
failures of these distribution breakers could add up to be significant, it is also believed that
distribution breakers are operated often on just Fault clearing duty; and, therefore, the
distribution circuit breakers are operated at least as frequently as stipulated in any requirement
in this standard.
Additionally, since this standard will now replace PRC-011, it will be important to make the
distinction between under-voltage Protection Systems that protect individual Loads and
Protection Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had
been applicable under PRC-011 will now be applicable under this revision of PRC-005-1. An
example of an under-voltage load-shedding scheme that is not applicable to this standard is
one in which the tripping action was intended to prevent low distribution voltage to a specific
Load from a Transmission system that was intact except for the line that was out of service, as
opposed to preventing a Cascading outage or Transmission system collapse.
It had been correctly noted that the devices needed for PRC-011 are the very same types of
devices needed in PRC-005.
Thus, a standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems, and replace some other standards at the same time.
2.3.1 Frequently Asked Questions:
W hat exactly is the BES, or Bulk Electric System ?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used in
Reliability Standards, and is not being modified within this draft standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, Interconnections with neighboring Systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission Facilities serving only
Load with one transmission source are generally not included in this definition.
The BES definition is presently undergoing the process of revision.
Each regional entity implements a definition of the Bulk Electric System that is based on this
NERC definition; in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
PRC-005-2 Supplementary Reference and FAQ – October 2012
4
W hy is Distribution Provider included w ithin the Applicable Entities and as a
responsible entity w ithin several of the requirem ents? W ouldn’t anyone having
relevant Facilities be a Transm ission Ow ner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
W e have an under voltage load-shedding (UVLS) system in place that prevents one
of our distribution substations from supplying ex trem ely low voltage in the case of a
specific transm ission line outage. The transm ission line is part of the BES. Does this
m ean that our UVLS system falls w ithin this standard?
The situation, as stated, indicates that the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission System that was intact, except for
the line that was out of service, as opposed to preventing Cascading outage or Transmission
System Collapse.
This standard is not applicable to this UVLS.
W e have a UFLS or UVLS schem e that sheds the necessary Load through
distribution-side circuit breakers and circuit reclosers.
Do the trip-test
requirem ents for circuit breakers apply to our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant, as opposed to a single failure to trip of, for example, a
transmission Protection System bus differential lock-out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just Fault clearing duty; and, therefore, the distribution circuit breakers
are operated at least as frequently as any requirements that might have appeared in this
standard.
W e have a UFLS schem e that, in som e locales, sheds the necessary Load through
non-BES circuit breakers and, occasionally, even circuit sw itchers. Do the trip-test
requirem ents for circuit breakers apply to our situation?
If your “non-BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements, and otherwise would not have been brought into this standard, then the answer
is that there are no trip-test requirements. For these devices that are otherwise non-BES
assets, these tripping schemes would have to exhibit multiple failures to trip before they would
prove to be as significant as, for example, a single failure to trip of a transmission Protection
System bus differential lock-out relay.
How does the “Facilities” section of “Applicability” track w ith the standards that w ill
be retired once PR C-005-2 becom es effective?
In establishing PRC-005-2, the drafting team has combined legacy standards PRC-005-1, PRC008-0, PRC-011-0, and PRC-017-0. The merger of the subject matter of these standards is
reflected in Applicability 4.2.
PRC-005-2 Supplementary Reference and FAQ – October 2012
5
The intent of the drafting team is that the legacy standards be reflected in PRC-005-2 as
follows:
•
•
•
•
•
Applicability of PRC-005-1 for Protection Systems relating to non-generator
elements of the BES is addressed in 4.2.1;
Applicability of PRC-008-0 for underfrequency load shedding systems is addressed in
4.2.2;
Applicability of PRC-011-0 for undervoltage load shedding relays is addressed in
4.2.3;
Applicability of PRC-017-0 for Special Protection Systems is addressed in 4.2.4;
Applicability of PRC-005-1 for Protection Systems for BES generators is addressed in
4.2.5.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this standard applies are those protective relays that respond to electrical quantities
and provide a trip output to trip coils, dc control circuitry or associated communications
equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94
(tripping or trip-free relay), as these devices are tripping relays that respond to the trip signal of
the protective relay that processed the signals from the current and voltage-sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
2.4.1 Frequently Asked Questions:
Are pow er circuit reclosers, reclosing relays, closing circuits and auto-restoration
schem es covered in this Standard?
No. This standard covers protective relays that use electrical quantity measurements to
determine anomalies and to trip a portion of the BES. Reclosers, reclosing relays, closing
circuits and auto-restoration schemes are used to cause devices to close, as opposed to
electrical-measurement relays and their associated circuits that cause circuit interruption from
the BES; such closing devices and schemes are more appropriately covered under other NERC
standards. There is one notable exception: Since PRC-017 will be superseded by PRC-005-2,
then if a Special Protection System (previously covered by PRC-017) incorporates automatic
closing of breakers, then the SPS-related closing devices must be tested accordingly.
I use m y protective relays only as sources of m etered quantities and breaker status
for SCADA and EM S through a substation distributed R TU or data concentrator to
the control center. W hat are the m aintenance requirem ents for the relays?
This standard addresses Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.). Protective relays, providing only the
functions mentioned in the question, are not included.
Are R everse Pow er Relays installed on the low -voltage side of distribution banks
considered to be com ponents of “Protection System s that are installed for the
purpose of detecting Faults on BES Elem ents (lines, buses, transform ers, etc.)”?
PRC-005-2 Supplementary Reference and FAQ – October 2012
6
Reverse power relays are often installed to detect situations where the transmission source
becomes deenergized and the distribution bank remains energized from a source on the lowvoltage side of the transformer and the settings are calculated based on the charging current of
the transformer from the low-voltage side. Although these relays may operate as a result of a
fault on a BES element, they are not ‘installed for the purpose of detecting’ these faults.
Is a Sudden Pressure R elay an auxiliary tripping relay?
No. IEEE C37.2-2008 assigns the Device No.# 94 to auxiliary tripping relays. Sudden pressure
relays are assigned Device No.# 63. Sudden pressure relays are presently excluded from the
standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded. The
trip path from a sudden pressure device is a part of the Protection System control circuitry. The
sensing element is omitted from PRC-005-2 testing requirements because the SDT is unaware
of industry-recognized testing protocol for the sensing elements. The SDT believes that
Protection Systems that trip (or can trip) the BES should be included. This position is consistent
with the currently-approved PRC-005-1a, consistent with the SAR for Project 2007-17, and
understands this to be consistent with the position of FERC staff.
M y m echanical device does not operate electrically and does not have calibration
settings; w hat m aintenance activities apply?
You must conduct a test(s) to verify the integrity of any trip circuit that is a part of a Protection
System. This standard does not cover circuit breaker maintenance or transformer
maintenance. The standard also does not presently cover testing of devices, such as sudden
pressure relays (63), temperature relays (49), and other relays which respond to mechanical
parameters, rather than electrical parameters. There is an expectation that Fault pressure
relays and other non-electrically initiated devices may become part of some maintenance
standard. This standard presently covers trip paths. It might seem incongruous to test a trip
path without a present requirement to test the device; and, thus, be arguably more work for
nothing. But one simple test to verify the integrity of such a trip path could be (but is not
limited to) a voltage presence test, as a dc voltage monitor might do if it were installed
monitoring that same circuit.
The standard specifically m entions aux iliary and lock-out relays.
aux iliary tripping relay?
W hat is an
An auxiliary relay, IEEE Device No.# 94, is described in IEEE Standard C37.2-2008 as: “A device
that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping
by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open
automatically, even though its closing circuit is maintained closed.”
W hat is a lock-out relay?
A lock-out relay, IEEE Device No.# 86, is described in IEEE Standard C37.2 as: “A device that trips
and maintains the associated equipment or devices inoperative until it is reset by an operator,
either locally or remotely.”
PRC-005-2 Supplementary Reference and FAQ – October 2012
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3 . P ro t e ct io n Sys t e m s P r o d u ct Ge n e ra t io n s
The likelihood of failure and the ability to observe the operational state of a critical Protection
System both depends on the technological generation of the relays, as well as how long they
have been in service. Unlike many other transmission asset groups, protection and control
systems have seen dramatic technological changes spanning several generations. During the
past 20 years, major functional advances are primarily due to the introduction of
microprocessor technology for power system devices, such as primary measuring relays,
monitoring devices, control Systems, and telecommunications equipment.
Modern microprocessor-based relays have six significant traits that impact a maintenance
strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs, such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified
periodically.
•
Ability to capture Fault records showing how the Protection System responded to a
Fault in its zone of protection, or to a nearby Fault for which it is required not to
operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-Fault times. The relays can compute values, such as MW and
MVAR line flows, that are sometimes used for operational purposes, such as SCADA.
•
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording and measurement.
•
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages, or from relay front
panel button requests.
•
Construction from electronic components, some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of battery chargers, associated
communications equipment, voltage and current-measuring devices, and even the control
circuitry (in the form of software-latches replacing lock-out relays, etc.).
Any Protection System component can have self-monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
This standard also recognizes the distinct advantage of using advanced technology to justifiably
defer or even eliminate traditional maintenance. Just as a hand-held calculator does not
require routine testing and calibration, neither does a calculation buried in a microprocessorbased device that results in a “lock-out.” Thus, the software-latch 86 that replaces an electroPRC-005-2 Supplementary Reference and FAQ – October 2012
8
mechanical 86 does not require routine trip testing. Any trip circuitry associated with the “soft
86” would still need applicable verification activities performed, but the actual “86” does not
have to be “electrically operated” or even toggled.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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4 . De fin it io n s
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning
components is restored. A maintenance program for a specific component includes one or
more of the following activities:
•
Verify — Determine that the component is functioning correctly.
•
Monitor — Observe the routine in-service operation of the component.
•
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
•
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
•
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
•
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity
that causes the component to not meet the intended performance, cannot be corrected
during the maintenance interval,and requires follow-up corrective action.
•
Segment – Protection Systems or components of a consistent design standard, or a
particular model or type from a single manufacturer that typically share other common
elements. Consistent performance is expected across the entire population of a
Segment. A Segment must contain at least sixty (60) individual components.
•
Component Type - Any one of the five specific elements of the Protection System
definition.
•
Component – A Component is any individual discrete piece of equipment included in a
Protection System, including but not limited to a protective relay or current sensing
device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some
entities test their control circuits on a breaker basis whereas others test their circuitry
on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit Components. Another example of where the
entity has some discretion on determining what constitutes a single Component is the
voltage and current sensing devices, where the entity may choose either to designate a
full three-phase set of such devices or a single device as a single Component.*
•
Countable Event – A failure of a Component requiring repair or replacement, any
condition discovered during the maintenance activities in Tables 1-1 through 1-5 and
Table 3 which requires corrective action or a Misoperation attributed to hardware
failure or calibration failure. Misoperations due to productdesign errors, software
errors, relay settings different from specified settings, Protection SystemComponent
configuration errors, or Protection System application errors are not included in
Countable Events.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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4.1 Frequently Asked Questions:
W hy does PR C-005-2 not specifically require m aintenance and testing procedures,
as reflected in the previous standard, PR C-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the Tables 1-1 through 1-5, Table 2 and Table 3 (collectively the “Tables”), and the
various components of the definition established for a “Protection System Maintenance
Program,” PRC-005-2 establishes the activities and time basis for a Protection System
Maintenance Program to a level of detail not previously required.
Please clarify w hat is m eant by “restore” in the definition of m aintenance.
The description of “restore” in the definition of a Protection System Maintenance Program
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R5 of the standard does
require that the entity “shall demonstrate efforts to correct any identified Unresolved
Maintenance Issues.” Some examples of restoration (or correction of Unresolved Maintenance
Issues) include, but are not limited to, replacement of capacitors in distance relays to bring
them to working order; replacement of relays, or other Protection System components, to bring
the Protection System to working order; upgrade of electromechanical or solid-state protective
relays to microprocessor-based relays following the discovery of failed components.
Restoration, as used in this context, is not to be confused with restoration rules as used in
system operations. Maintenance activity necessarily includes both the detection of problems
and the repairs needed to eliminate those problems. This standard does not identify all of the
Protection System problems that must be detected and eliminated, rather it is the intent of this
standard that an entity determines the necessary working order for their various devices, and
keeps them in working order. If an equipment item is repaired or replaced, then the entity can
restart the maintenance-time-interval-clock, if desired; however, the replacement of
equipment does not remove any documentation requirements that would have been required
to verify compliance with time-interval requirements. In other words, do not discard
maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long-range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
Please clarify what is meant by “…demonstrate efforts to correct an Unresolved
Maintenance Issue…”; why not measure the completion of the corrective action?
Management of completion of the identified Unresolved Maintenance Issue is a complex topic
that falls outside of the scope of this standard. There can be any number of supply, process and
management problems that make setting repair deadlines impossible. The SDT specifically
chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex Unresolved Maintenance Issues might require greater
PRC-005-2 Supplementary Reference and FAQ – October 2012
11
than the remaining maintenance interval to resolve (and yet still be a “closed-end process”).
For example, a problem might be identified on a VRLA battery during a six-month check. In
instances such as one that requiring battery replacement as part of the long-term resolution, it
is highly unlikely that the battery could be replaced in time to meet the six-calendar-month
requirement for this maintenance activity. The SDT does not believe entities should be found in
violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective
actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution
of all possible Unresolved Maintenance Issues, or what documentation might be sufficient to
provide proof that effective corrective action is being undertaken.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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5 . Tim e -Ba s e d Ma in t e n a n ce ( TBM) P ro g ra m s
Time-based maintenance is the process in which Protection Systems are maintained or verified
according to a time schedule. The scheduled program often calls for technicians to travel to the
physical site and perform a functional test on Protection System components. However, some
components of a TBM program may be conducted from a remote location - for example,
tripping a circuit breaker by communicating a trip command to a microprocessor relay to
determine if the entire Protection System tripping chain is able to operate the breaker.
Similarly, all Protection System components can have the ability to remotely conduct tests,
either on-command or routinely; the running of these tests can extend the time interval
between hands-on maintenance activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or
testing intervals are applied for components or groups of components. The intervals
may have been developed from prior experience or manufacturers’ recommendations.
The TBM verification interval is based on a variety of factors, including experience of the
particular asset owner, collective experiences of several asset owners who are members
of a country or regional council, etc. The maintenance intervals are fixed and may range
in number of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time
clock can be reset for those components.
•
PBM – Performance-Based Maintenance - intervals are established based on analytical
or historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBMdeveloped extended intervals when test failures or in-service failures occur infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from
non-disruptive self-monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what
parts are included as part of the self-diagnostics. While the term “Condition-BasedMaintenance” (CBM) is no longer used within the standard itself, it is important to note
that the concepts of CBM are a part of the standard (in the form of extended time
intervals through status-monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored-basis-time-intervals” existing within the standard, the
explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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Microprocessor-based Protection System components that perform continuous selfmonitoring verify correct operation of most components within the device. Selfmonitoring capabilities may include battery continuity, float voltages, unintentional
grounds, the ac signal inputs to a relay, analog measuring circuits, processors and
memory for measurement, protection, and data communications, trip circuit
monitoring, and protection or data communications signals (and many, many more
measurements). For those conditions, failure of a self-monitoring routine generates an
alarm and may inhibit operation to avoid false trips. When internal components, such
as critical output relay contacts, are not equipped with self-monitoring, they can be
manually tested. The method of testing may be local or remote, or through inherent
performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours, or even milliseconds between non-disruptive self-monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram, the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
•
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
•
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have
been subject to TBM.
•
Region 3: Optimal TBM intervals based on regions 1 and 2.
TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
PRC-005-2 Supplementary Reference and FAQ – October 2012
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5.1.1 Frequently Asked Questions:
The standard seem s very com plicated, and is difficult to understand.
sim plified?
Can it be
Because the standard is establishing parameters for condition-based Maintenance (R1) and
Performance-Based Maintenance (R2), in addition to simple time-based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time-based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened
time intervals, then it may, as long as the component has the listed monitoring attributes. If an
entity wishes to use historical performance of its Protection System components to perform
Performance-Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
W e have an electrom echanical (unm onitored) relay that has a trip output to a
lockout relay (unm onitored) w hich trips our transform er off-line by tripping the
transform er’s high-side and low -side circuit breakers. W hat testing m ust be done
for this system ?
This system is made up of components that are all unmonitored. Assuming a time-based
Protection System maintenance program schedule (as opposed to a Performance-Based
PRC-005-2 Supplementary Reference and FAQ – October 2012
15
maintenance program), each component must be maintained per the most frequent hands-on
activities listed in the Tables.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly
established to assure proper functioning of each component of the Protection System, when
data on the reliability of the components is not available other than observations from timebased maintenance. The following factors may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self-monitoring device), then the intervals may be extended, or
manual testing may be eliminated. This is referred to as condition-based maintenance
or CBM. CBM is valid only for precisely the components subject to monitoring. In the
case of microprocessor-based relays, self-monitoring may not include automated
diagnostics of every component within a microprocessor.
•
Previous maintenance history for a group of components of a common type may
indicate that the maintenance intervals can be extended, while still achieving the
desired level of performance. This is referred to as Performance-Based Maintenance, or
PBM. It is also sometimes referred to as reliability-centered maintenance, or RCM; but
PBM is used in this document.
•
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor-based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a Fault verifies the trip contact and trip path, but only
through the relays in series that actually operated; one operation of this relay cannot
verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is
not unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Questions:
If I show the protective device out of service w hile it is being repaired, then can I
add it back as a new protective device w hen it returns? If not, m y relay testing
history w ould show that I w as out of com pliance for the last m aintenance cycle.
The maintenance and testing requirements (R5) (in essence) state “…shall demonstrate efforts
to correct any identified Unresolved Maintenance Issues.” The type of corrective activity is not
stated; however it could include repairs or replacements.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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6 . Co n d it io n -Ba s e d Ma in t e n a n ce ( CBM) P ro g ra m s
Condition-based maintenance is the process of gathering and monitoring the information
available from modern microprocessor-based relays and other intelligent electronic devices
(IEDs) that monitor Protection System elements. These devices generate monitoring
information during normal operation, and the information can be assessed at a convenient
location remote from the substation. The information from these relays and IEDs is divided into
two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
Faults and Disturbances, metered values, and binary input status reports. Some of
these are available on the device front panel display, but may be available via data
communications ports. Large files of Fault information can only be retrieved via data
communications. These results comprise a mass of data that must be further analyzed
for evidence of the operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems
by incorrect operation before being caught in the next test round. The frequent or
continuous nature of CBM makes the effective verification interval far shorter than any
required TBM maximum interval. To use the extended time intervals available through
Condition Based Maintenance, simply look for the rows in the Tables that refer to
monitored items.
6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a 24-hour
attended control room. Does this qualify as an extended time interval condition-based
(monitored) system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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When documenting the basis for inclusion of components into the appropriate levels of
monitoring, as per Requirement R1 (Part 1.4) of the standard, is it necessary to provide this
documentation about the device by listing of every component and the specific monitoring
attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered monitored and subject to the
rows for monitored equipment of Table 1-4 requirements, as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device-level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered monitored
and subject to the rows for monitored equipment of Table 1-4 requirements, as all
substation dc supply battery chargers are equipped with dc voltage alarms and ground
detection alarms that are sent to the manned control center. The dc supply battery
chargers of Substation X, Substation Y, and Substation Z are considered unmonitored and
subject to the rows for unmonitored equipment in Table 1-4 requirements, as they are not
equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure, but should be retrievable if
requested by an auditor.
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7 . Tim e -Ba s e d Ve r s u s Co n d it io n -Ba s e d
Ma in t e n a n ce
Time-based and condition-based (or monitored) maintenance programs are both acceptable, if
implemented according to technically sound requirements. Practical programs can employ a
combination of time-based and condition-based maintenance. The standard requirements
introduce the concept of optionally using condition monitoring as a documented element of a
maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule, dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability Standards
for the Bulk-Power System, directed NERC to submit a modification to PRC-005-1 that includes
a requirement that maintenance and testing of a Protection System must be carried out within
a maximum allowable interval that is appropriate to the type of the Protection System and its
impact on the reliability of the Bulk Power System. Accordingly, this Supplementary Reference
Paper refers to the specific maximum allowable intervals in PRC-005-2. The defined time limits
allow for longer time intervals if the maintained component is monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the Protection System owner knows
about it, for the monitored segments of the Protection System. In some cases, the verification is
practically continuous - the time interval between verifications is minutes or seconds. Thus,
technically sound, condition-based verification, meets the verification requirements of the FERC
order even more effectively than the strictly time-based tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection Systems to
reduce the need for periodic site visits and invasive testing of components by on-site
technicians. This periodic testing must be conducted within the maximum time intervals
specified in Tables 1-1 through 1-5 and Table 2 of PRC-005-2.
7.1 Frequently Asked Questions:
W hat is a Calendar Year?
Calendar Year - January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have
to occur on or before December 31, 2010.
Please provide an ex am ple of “4 Calendar M onths”.
If a maintenance activity is described as being needed every four Calendar Months then it is
performed in a (given) month and due again four months later. For example a battery bank is
inspected in month number 1 then it is due again before the end of the month number5. And
specifically consider that you perform your battery inspection on January 3, 2010 then it must
be inspected again before the end of May. Another example could be that a four-month
inspection was performed in January is due in May, but if performed in March (instead of May)
PRC-005-2 Supplementary Reference and FAQ – October 2012
20
would still be due four months later therefore the activity is due again July. Basically every “four
Calendar Months” means to add four months from the last time the activity was performed.
Please provide an exam ple of the unm onitored versus other levels of m onitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but is not limited to, an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
•
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A vented Lead-Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
•
A circuit breaker with a trip coil, and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2, the
particular components have maximum activity intervals of:
Every four calendar months, inspect:
Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
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Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power System input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained as detailed in Table 1-5
of the standard under the ‘Unmonitored Control Circuitry Associated with Protective
Functions" section’
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
•
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A vented lead-acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
• A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (Maximum
Allowable Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and
Monitoring), the particular components have maximum activity intervals of:
Every four calendar months, inspect:
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Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Every six calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Battery performance test (if internal ohmic tests are not opted)
Every 12 calendar years, verify the following:
Current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
All trip paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1-5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions" section
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
•
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
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23
•
Vented Lead-Acid battery without any alarms connected to SCADA
(unmonitored)
•
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (Maximum Allowable
Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and Monitoring),
the particular components shall have maximum activity intervals of:
Every four calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Condition of all individual battery cells (where visible)
Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
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Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1-5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions section
Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required,
by this standard, to be checked
W hy do com ponents have different m aintenance activities and intervals if they are
m onitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of
Protection System components. Condition-Based Maintenance is a valuable asset to improve
reliability.
Can all com ponents in a Protection System be m onitored?
No. For some components in a Protection System, monitoring will not be relevant. For
example, a battery will always need some kind of inspection.
W e have a 30-year-old oil circuit breaker w ith a red indicating lam p on the
substation relay panel that is illum inated only if there is continuity through the
breaker trip coil. There is no SCADA m onitor or relay m onitor of this trip coil. The
line protection relay package that trips this circuit breaker is a m icroprocessor relay
that has an integral alarm relay that w ill assert on a num ber of conditions that
includes a loss of pow er to the relay. This alarm contact connects to our SCADA
system and alerts our 24-hour operations center of relay trouble w hen the alarm
contact closes. This m icroprocessor relay trips the circuit breaker only and does not
m onitor trip coil continuity or other things such as trip current. Are the com ponents
m onitored or not? How often m ust I perform m aintenance?
The protective relay is monitored and can be maintained every 12 years, or when an
Unresolved Maintenance Issue arises. The control circuitry can be maintained every 12 years.
The circuit breaker trip coil(s) has to be electrically operated at least once every six years.
W hat is a m itigating device?
A mitigating device is the device that acts to respond as directed by a Special Protection
System. It may be a breaker, valve, distributed control system, or any variety of other devices.
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8 . Ma x im u m Allo w a b le Ve rifica t io n I n t e rva ls
The maximum allowable testing intervals and maintenance activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older
Protection System components require. As explained below, there are some sections of the
Protection System that monitoring or data analysis may not verify. Verifying these sections of
the Protection Systems requires some persistent TBM activity in the maintenance program.
However, some of this TBM can be carried out remotely - for example, exercising a circuit
breaker through the relay tripping circuits using the relay remote control capabilities can be
used to verify function of one tripping path and proper trip coil operation, if there has been no
Fault or routine operation to demonstrate performance of relay tripping circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure
that individual components are still operating within acceptable performance parameters - this
type of test is needed for components susceptible to degraded or changing characteristics due
to aging and wear. Full system performance tests may be used to confirm that the total
Protection System functions from measurement of power system values, to properly identifying
Fault characteristics, to the operation of the interrupting devices.
8.1.1 Table of M axim um Allow able Verification I ntervals
Table 1 (collectively known as Table 1, individually called out as Tables 1-1 through 1-5), Table 2
and Table 3 in the standard specify maximum allowable verification intervals for various
generations of Protection Systems and categories of equipment that comprise Protection
Systems. The right column indicates maintenance activities required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications-assisted transmission Protection System comprising
substation equipment at each terminal and a telecommunications channel for relaying between
the two substations. Figure 2 shows an example of a generation Protection System. The
various sub-systems of a Protection System that need to be verified are shown.
Non-distributed UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated
in these figures. Non-distributed UFLS, UVLS and SPS all use identical equipment as Protection
Systems in the performance of their functions; and, therefore, have the same maintenance
needs.
Distributed UFLS and UVLS Systems, which use local sensing on the distribution System and trip
co-located non-BES interrupting devices, are addressed in Table 3 with reduced maintenance
activities.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC-005-2:
•
First find the Table associated with your component. The tables are arranged in the
order of mention in the definition of Protection System;
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26
o Table 1-1 is for protective relays,
o Table 1-2 is for the associated communications systems,
o Table 1-3 is for current and voltage sensing devices,
o Table 1-4 is for station dc supply and
o Table 1-5 is for control circuits.
o Table 2, is for alarms; this was broken out to simplify the other tables.
o Table 3 is for components which make-up distributed UFLS and UVLS Systems.
•
Next look within that table for your device and its degree of monitoring. The Tables
have different hands-on maintenance activities prescribed depending upon the degree
to which you monitor your equipment. Find the maintenance activity that applies to the
monitoring level that you have on your piece of equipment.
•
This Maintenance activity is the minimum maintenance activity that must be
documented.
•
If your Performance-Based Maintenance (PBM) plan requires more activities, then you
must perform and document to this higher standard. (Note that this does not apply
unless you utilize PBM.)
•
After the maintenance activity is known, check the maximum maintenance interval; this
time is the maximum time allowed between hands-on maintenance activity cycles of
this component.
•
If your Performance-Based Maintenance plan requires activities more often than the
Tables maximum, then you must perform and document those activities to your more
stringent standard. (Note that this does not apply unless you utilize PBM.)
•
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system;
this combination would require hands-on maintenance activity on the relay at least
once every 12 years and attention paid to the communications system as often as every
four months.
•
An entity does not have to utilize the extended time intervals made available by this use
of condition-based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available on each of the five Tables. While the
maintenance activities resulting from this choice would require more maintenance manhours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. These degrees of monitoring, or levels, range from the
legacy unmonitored through a system that is more comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC-005-2.
There may be any number of reasons that an entity chooses a more stringent plan than the
PRC-005-2 Supplementary Reference and FAQ – October 2012
27
minimums prescribed within PRC-005-2, most notable of which is an entity using performance
based maintenance methodology. If an entity has a Performance-Based Maintenance program,
then that plan must be followed, even if the plan proves to be more stringent than the
minimums laid out in the Tables.
8.1.2 Additional Notes for Tables 1-1 through 1-5 and Table 3
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified
within the Table interval as other unmonitored relays but may be verified as functional
by means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the
station battery and charger. Unlike most Protection System components, physical
inspection of station batteries for signs of component failure, reduced performance, and
degradation are required to ensure that the station battery is reliable enough to deliver
dc power when required. IEEE Standards 450, 1188, and 1106 for vented lead-acid,
valve-regulated lead-acid, and nickel-cadmium batteries, respectively (which are the
most commonly used substation batteries on the NERC BES) have been developed as an
important reference source of maintenance recommendations. The Protection System
owner might want to follow the guidelines in the applicable IEEE recommended
practices for battery maintenance and testing, especially if the battery in question is
used for application requirements in addition to the protection and control demands
covered under this standard. However, the Standard Drafting Team has tailored the
battery maintenance and testing guidelines in PRC-005-2 for the Protection System
owner which are application specific for the BES Facilities. While the IEEE
recommendations are all encompassing, PRC-005-2 is a more economical approach
while addressing the reliability requirements of the BES.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform
properly, it will not affect the integrity of the overall program. Thus, these distributed
systems have decreased requirements as compared to other Protection Systems.
6. Voltage & current sensing device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should
PRC-005-2 Supplementary Reference and FAQ – October 2012
28
be verified to be as expected (phase value and phase relationships are both equally
important to verify).
7. “End-to-end test,” as used in this Supplementary Reference, is any testing procedure
that creates a remote input to the local communications-assisted trip scheme. While
this can be interpreted as a GPS-type functional test, it is not limited to testing via GPS.
Any remote scheme manipulation that can cause action at the local trip path can be
used to functionally-test the dc control circuitry. A documented Real-time trip of any
given trip path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc control circuit trip. Or another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a Real-time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure
acceptable measurement of power system input values.
9. Notes 1-8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities, but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the standard is technology- and method-neutral in
most cases.
8.1.3 Frequently Asked Questions:
W hat is m eant by “Verify that settings are as specified” m aintenance activity in
Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor- based relays.
For relay maintenance departments that choose to test microprocessor-based relays in the
same manner as electromechanical relays are tested, the testing process sometimes requires
that some specific functions be disabled. Later tests might enable the functions previously
disabled, but perhaps still other functions or logic statements were then masked out. It is
imperative that, when the relay is placed into service, the settings in the relay be the settings
that were intended to be in that relay or as the standard states “…settings are as specified.”
Many of the microprocessor- based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement, a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is that settings
of the component be as specified at the conclusion of maintenance activities, whether those
settings may have “drifted” since the prior maintenance or whether changes were made as part
of the testing process.
PRC-005-2 Supplementary Reference and FAQ – October 2012
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Are electrom echanical relays included in the “Verify that settings are as specified”
m aintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection; and, thus, the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable, as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage m easurem ents by com parison to other
quantities seem s reasonable. How , though, can I verify residual or neutral
currents, or 3V0 voltages, by com parison, w hen m y system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system Disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known Fault locations.
W hat does this Standard require for testing an aux iliary tripping relay?
Table 1 and Table 3 requires that a trip test must verify that the auxiliary tripping relay(s)
and/or lockout relay(s) which are directly in a trip path from the protective relay to the
interrupting device trip coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System ?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end-to-end test. In other words it may be tested in
piecemeal fashion provided all of the pieces are verified.
W hat about SPS interfaces betw een different entities or ow ners?
As in all of the Protection System requirements, SPS segments can be tested individually, thus
minimizing the need to accommodate complex maintenance schedules.
W hat do I have to do if I am using a phasor m easurem ent unit (PM U) as part of a
Protection System or Special Protection System ?
Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I m aintain a Special Protection System or relay sensing for non-distributed
UFLS or UVLS System s?
Since components of the SPS, UFLS and UVLS are the same types of components as those in
Protection Systems, then these components should be maintained like similar components
used for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
PRC-005-2 Supplementary Reference and FAQ – October 2012
30
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example, an SPS that trips a remote circuit breaker might be
tested by testing the various parts of the scheme in overlapping segments. Another method is
to document the Real-time tripping of an SPS scheme should that occur. Forced trip tests of
circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established m axim um allow able intervals do not align w ell w ith the scheduled
outages for m y pow er plant. Can I ex tend the m aintenance to the nex t scheduled
outage follow ing the established m ax im um interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance
intervals were selected with typical plant outages, among other things, in mind.
If I am unable to com plete the m aintenance, as required, due to a m ajor natural
disaster (hurricane, earthquake, etc.), how w ill this affect m y com pliance w ith this
standard?
The Sanction Guidelines of the North American Electric Reliability Corporation, effective
January 15, 2008, provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
W hat if m y observed testing results show a high incidence of out-of-tolerance
relays; or, even w orse, I am experiencing num erous relay M isoperations due to the
relays being out-of-tolerance?
The established maximum time intervals are mandatory only as a not-to-exceed limitation. The
establishment of a maximum is measurable. But any entity can choose to test some or all of
their Protection System components more frequently (or to express it differently, exceed the
minimum requirements of the standard). Particularly if you find that the maximum intervals in
the standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest.
W e believe that the four-m onth interval betw een inspections is unneccessary. W hy
can w e not perform these inspections tw ice per year?
The Standard Drafting Team, through the comment process, has discovered that routine
monthly inspections are not the norm. To align routine station inspections with other
important inspections, the four-month interval was chosen. In lieu of station visits, many
activities can be accomplished with automated monitoring and alarming.
Our m aintenance plan calls for us to perform routine protective relay tests every 3
years. If w e are unable to achieve this schedule, but w e are able to com plete the
procedures in less than the m ax im um tim e interval ,then are w e in or out of
com pliance?
PRC-005-2 Supplementary Reference and FAQ – October 2012
31
According to R3, if you have a time-based maintenance program, then you will be in violation of
the standard only if you exceed the maximum maintenance intervals prescribed in the Tables.
According to R4, if your device in question is part of a Performance-Based Maintenance
program, then you will be in violation of the standard if you fail to meet your PSMP, even if you
do not exceed the maximum maintenance intervals prescribed in the Tables. The intervals in
the Tables are associated with TBM and CBM; Attachment A is associated with PBM.
Please provide a sam ple list of devices or system s that m ust be verified in a
generator, generator step-up transform er, generator connected station service or
generator connected excitation transform er to m eet the requirem ents of this
m aintenance standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay, may include, but are not necessarily limited to:
•
Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
•
Loss-of-field relays
•
Volts-per-hertz relays
•
Negative sequence overcurrent relays
•
Over voltage and under voltage protection relays
•
Stator-ground relays
•
Communications-based Protection Systems such as transfer-trip systems
•
Generator differential relays
•
Reverse power relays
•
Frequency relays
•
Out-of-step relays
•
Inadvertent energization protection
•
Breaker failure protection
For generator step-up, generator-connected station service transformers, or generator
connected excitation transformers, operation of any of the following associated protective
relays frequently would result in a trip of the generating unit; and, as such, would be included
in the program:
•
Transformer differential relays
•
Neutral overcurrent relay
•
Phase overcurrent relays
Relays which trip breakers serving station auxiliary Loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program, even if the loss of the those Loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
PRC-005-2 Supplementary Reference and FAQ – October 2012
32
this program, even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal-conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
In the case w here a plant does not have a generator connected station service
transform er such that it is norm ally fed from a system connected station service
transform er, is it still the drafting team ’s intent to ex clude the Protection System s
for these system connected aux iliary transform ers from scope even w hen the loss
of the norm al (system connected) station service transform er w ill result in a trip of
a BES generating Facility?
The SDT does not intend that the system-connected station service transformers be included in
the Applicability. The generator-connected station service transformers and generator
connected excitation transformers are often connected to the generator bus directly without
an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
W hat is m eant by “verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System ?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping,” one needs to realize that
sometimes there are more inputs and outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly
operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock-out relays (86) (used to convey the tripping current to the trip coils)
need to be electrically operated to prove the capability of the device to change state. These
tests need to be accomplished at least every six years, unless PBM methodology is applied.
The contacts on the 86 or auxiliary tripping relays (94) that change state to pass on the trip
current to a breaker trip coil need only be checked every 12 years with the control circuitry.
W hat is the difference betw een a distributed UFLS/ UVLS and a non-distributed
UFLS/ UVLS schem e?
A distributed UFLS or UVLS scheme contains individual relays which make independent Load
shed decisions based on applied settings and localized voltage and/or current inputs. A
distributed scheme may involve an enable/disable contact in the scheme and still be considered
a distributed scheme. A non-distributed UFLS or UVLS scheme involves a system where there is
some type of centralized measurement and Load shed decision being made. A non-distributed
UFLS/UVLS scheme is considered similar to an SPS scheme and falls under Table 1 for
maintenance activities and intervals.
PRC-005-2 Supplementary Reference and FAQ – October 2012
33
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three-year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC-005-2 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for
the Protection System components, or to the previous scheduled (on-site) audit date, whichever
is longer.
This requirement assures that the documentation shows that the interval between
maintenance cycles correctly meets the maintenance interval limits. The requirement is
actually alerting the industry to documentation requirements already implemented by audit
teams. Evidence of compliance bookending the interval shows interval accomplished instead of
proving only your planned interval.
The SDT is aware that, in some cases, the retention period could be relatively long. But, the
retention of documents simply helps to demonstrate compliance.
8.2.1 Frequently Asked Questions:
Please use a specific ex am ple to dem onstrate the data retention requirem ents.
The data retention requirements are intended to allow the availability of maintenance records
to demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested every three calendar years, with a maximum allowed grace period of an additional 18
months. This entity would be required to maintain its records of maintenance of its last two
routine scheduled tests. Thus, its test records would have a latest routine test, as well as its
previous routine test. The interval between tests is, therefore, provable to an auditor as being
within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements, while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance-Based Maintenance, then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced, then the entity can restart the maintenance-time-intervalclock if desired; however, the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements. In other words, do not discard maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long-range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
PRC-005-2 Supplementary Reference and FAQ – October 2012
34
W hat does this M aintenance Standard say about com m issioning? Is it necessary to
have docum entation in your m aintenance history of the com pletion of com m ission
testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a Facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC-005-2, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are
not generally done routinely like staged-Fault-tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation, and need not be reverified within an ongoing maintenance program. Example – it is not necessary to re-verify
correct terminal strip wiring on an ongoing basis.
PRC-005-2 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC-005-2 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components, such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content;
and, therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC-005-2 would help that entity
prove time interval maximums by setting the initial time clock.
How do you determ ine the initial due date for m aintenance?
The initial due date for maintenance should be based upon when a Protection System was
tested. Alternatively, an entity may choose to use the date of completion of the commission
testing of the Protection System component and the system was placed into service as the
starting point in determining its first maintenance due dates. Whichever method is chosen, for
newly installed Protection Systems the components should not be placed into service until
minimum maintenance activities have taken place.
It is conceivable that there can be a (substantial) difference in time between the date of testing,
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non-compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in-service
PRC-005-2 Supplementary Reference and FAQ – October 2012
35
dates, then the testing date should be followed because it is the degradation of components
that is the concern. While accuracy fluctuations may decrease when components are not
energized, there are cases when degradation can take place, even though the device is not
energized. Minimizing the time between commissioning tests and in-service dates will help.
If I m iss tw o battery inspections four tim es out of 100 Protection System
com ponents on m y transm ission system , does that count as 2% or 8% w hen
counting Violation Severity Level (VSL) for R 3?
The entity failed to complete its scheduled program on two of its 100 Protection System
components, which would equate to 2% for application to the VSL Table for Requirement R3.
This VSL is written to compare missed components to total components. In this case two
components out of 100 were missed, or 2%.
How do I achieve a “grace period” w ithout being out of com pliance?
The objective here is to create a time extension within your own PSMP that still does not
violate the maximum time intervals stated in the standard. Remember that the maximum time
intervals listed in the Tables cannot be extended.
For the purposes of this example, concentrating on just unmonitored protective relays – Table
1-1 specifies a maximum time interval (between the mandated maintenance activities) of six
calendar years. Your plan must ensure that your unmonitored relays are tested at least once
every six calendar years. You could, within your PSMP, require that your unmonitored relays be
tested every four calendar years, with a maximum allowable time extension of 18 calendar
months. This allows an entity to have deadlines set for the auto-generation of work orders, but
still has the flexibility in scheduling complex work schedules. This also allows for that 18
calendar months to act as a buffer, in effect a grace period within your PSMP, in the event of
unforeseen events. You will note that this example of a maintenance plan interval has a
planned time of four years; it also has a built-in time extension allowed within the PSMP, and
yet does not exceed the maximum time interval allowed by the standard. So while there are no
time extensions allowed beyond the standard, an entity can still have substantial flexibility to
maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007,
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I-17 (Transmission Relay System
Performance Comparison). Review of the I-17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the
members to also provide definitively-known data for other entities. The survey represented 470
GW of peak Load, or 4% of the NERC peak Load. Maintenance interval averages were compiled
by weighting reported intervals according to the size (based on peak Load) of the reporting
PRC-005-2 Supplementary Reference and FAQ – October 2012
36
utility. Thus, the averages more accurately represent practices for the large populations of
Protection Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of five years
for electromechanical or solid state relays, and seven years for unmonitored microprocessor
relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond
seven years, based on favorable experience with the particular products they have installed. To
provide a technical basis for such extension, the SPCTF authors developed a recommendation
of 10 years using the Markov modeling approach from [1], as summarized in Section 8.4. The
results of this modeling depend on the completeness of self-testing or monitoring. Accordingly,
this extended interval is allowed by Table 1, only when such relays are monitored as specified in
the attributes of monitoring contained in Tables 1-1 through 1-5 and Table 2. Monitoring is
capable of reporting Protection System health issues that are likely to affect performance
within the 10 year time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10-year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval
actually degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level.
The industry has experience with self-monitoring microprocessor relays that leads to the Table
1 value for a monitored relay, as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
•
Relay Unavailability - the probability that the relay is out of service due to failure or
maintenance activity while the power system Element to be protected is in service.
•
Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a Fault occurs, leading to failure to operate for the Fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test).
ST = 0 if there is no self-monitoring; ST = 1 for full monitoring. Practical ST values are estimated
to range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that
were the same as those used in [1] with the following exceptions:
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal Fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup Fault clearing time of 50
cycles)
PRC-005-2 Supplementary Reference and FAQ – October 2012
37
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for relay unavailability and abnormal unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay mean time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields
no failure discoveries that approach the negative impact of removing the relays from service
and running the tests.
The PSMT SDT discussed the practical need for “time-interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally, it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “timeinterval extension” or “grace periods.” To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time-interval extension, while still
following FERC Order 693, the Standard Drafting Team arrived at a six-year interval for the
electromechanical relay, instead of the five-year interval arrived at by the SPCTF. The PSMT
SDT has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10-year interval was chosen, even though there was
“…no significant change in unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection
System; thus, the maximum allowed interval for these components has been set to 12 years.
Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum
Maintenance Interval.” The PSMT SDT deemed it necessary to include the term “Calendar” to
facilitate annual maintenance planning, scheduling and implementation. This need is the result
of known occurrences of system requirements that could cause maintenance schedules to be
missed by a few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need
to have schedules be met to the day. An electromechanical protective relay that is maintained
in year number one need not be revisited until six years later (year number seven). For
PRC-005-2 Supplementary Reference and FAQ – October 2012
38
example, a relay was maintained April 10, 2008; maintenance would need to be completed no
later than December 31, 2014.
Though not a requirement of this standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP, the entity should
abide by their chosen language.
PRC-005-2 Supplementary Reference and FAQ – October 2012
39
9 . P e rfo r m a n ce -Ba s e d Ma in t e n a n ce P r o ce s s
In lieu of using the Table 1 intervals, a Performance-Based Maintenance process may be used to
establish maintenance intervals (PRC-005 Attachment A Criteria for a Performance-Based
Protection System Maintenance Program). A Performance-Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance-Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order
to provide historical justification for intervals, other than those established in Table 1.
Furthermore, the asset owner must regularly analyze these records of corrective actions to
develop a ranking of causes. Recurrent problems are to be highlighted, and remedial action
plans are to be documented to mitigate or eliminate recurrent problems.
Entities with Performance-Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and
implement continuous improvement actions. Since no maintenance program can ever
guarantee that no malfunction can possibly occur, documentation of a Performance-Based
Maintenance program would serve the utility well in explaining to regulators and the public a
Misoperation leading to a major System outage event.
A Performance-Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001-2000, Quality Management Systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance-Based Maintenance (PBM) program, the asset owner must
first sort the various Protection System components into population segments. Any population
segment must be comprised of at least 60 individual units; if any asset owner opts for PBM, but
does not own 60 units to comprise a population, then that asset owner may combine data from
other asset owners until the needed 60 units is aggregated. Each population segment must be
composed of a grouping of Protection Systems or components of a consistent design standard
or particular model or type from a single manufacturer and subjected to similar environmental
factors. For example: One segment cannot be comprised of both GE & Westinghouse electromechanical lock-out relays; likewise, one segment cannot be comprised of 60 GE lock-out
relays, 30 of which are in a dirty environment, and the remaining 30 from a clean environment.
This PBM process cannot be applied to batteries, but can be applied to all other components of
a Protection System, including (but not limited to) specific battery chargers, instrument
transformers, trip coils and/or control circuitry (etc.).
PRC-005-2 Supplementary Reference and FAQ – October 2012
40
9.1 Minimum Sample Size
Large Sam ple Size
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003.)
To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003.)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation σ, the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics - Picturing the World, Larson, Farber,
2003.)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005.)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968.)
Error of Distribution Form ula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a
“Pass/Fail” format and will be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
Β = bound on the error of distribution (allowable error)
z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
PRC-005-2 Supplementary Reference and FAQ – October 2012
41
z
n = π(1 − π)
Β
2
M inim um Population Size to use Perform ance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason, the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
M inim um Sam ple Size to evaluate Perform ance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
R ecom m endation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are
recommended (and required within the standard):
Minimum Population Size to use Performance-Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance-Based Program = 30.
Once the population segment is defined, then maintenance must begin within the intervals as
outlined for the device described in the Tables 1-1 through 1-5. Time intervals can be
lengthened provided the last year’s worth of components tested (or the last 30 units
maintained, whichever is more) had fewer than 4%Countable Events. It is notable that 4% is
specifically chosen because an entity with a small population (30 units) would have to adjust its
time intervals between maintenance if more than one Countable Event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to
adjust the time interval between maintenance activities if even one unit is found out of
tolerance or causes a Misoperation.
PRC-005-2 Supplementary Reference and FAQ – October 2012
42
The minimum number of units that can be tested in any given year is 5% of the population.
Note that this 5% threshold sets a practical limitation on total length of time between intervals
at 20 years.
If at any time the number of Countable Events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more), then the time period
between manual maintenance activities must be decreased. There is a time limit on reaching
the decreased time at which the Countable Events is less than 4%; this must be attained within
three years.
9.2 Frequently Asked Questions:
I’m a sm all entity and cannot aggregate a population of Protection System
com ponents to establish a segm ent required for a Perform ance-Based Protection
System M aintenance Program . How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect
to the requirements of the Standard. The requirements established for Performance-Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power-plant
vs. substation, and weather conditions.
Can an ow ner go straight to a Perform ance-Based M aintenance program schedule, if
they have previously gathered records?
Yes. An owner can go to a Performance-Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance-Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a Performance-Based Maintenance program then they will need to wait until they can prove
compliance.
W hen establishing a Perform ance-Based M aintenance program , can I use test data
from the device m anufacturer, or industry survey results, as results to help establish
a basis for m y Perform ance-Based intervals?
No, you must use actual in-service test data for the components in the segment.
W hat types of M isoperations or events are not considered Countable Events in the
Perform ance-Based Protection System M aintenance (PBM ) Program ?
Countable Events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re-calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
Misoperations during system installation or maintenance activities are not considered
Countable Events. Examples of excluded human errors include relay setting errors, design
PRC-005-2 Supplementary Reference and FAQ – October 2012
43
errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
misapplication, and components not specified correctly for their installation. Obviously, if one is
setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human-error is not pertinent data might be in the area of testing “86” lock-out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into a
performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial sixyear interval they find zero type “X” failures, but human error led to tripping a BES Element 100
times; they find 100 type “Y” failures and had an additional 100 human-error caused tripping
incidents. In this example the human-error caused Misoperations should not be used to judge
the performance of either type of LOR. Analysis of the data might lead “Entity A” to change
time intervals. Type “X” LOR can be placed into extended time interval testing because of its
low failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
Certain types of Protection System component errors that cause Misoperations are not
considered Countable Events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
W hat are som e ex am ples of m ethods of correcting segm ent perfom ance for
Perform ance-Based M aintenance?
There are a number of methods that may be useful for correcting segment performance for
mal-performing segments in a Performance-Based Maintenance system. Some examples are
listed below.
•
The maximum allowable interval, as established by the Performance-Based
Maintenance system, can be decreased. This may, however, be slow to correct the
performance of the segment.
•
Identifiable sub-groups of components within the established segment, which have
been identified to be the mal-performing portion of the segment, can be broken out as
an independent segment for target action. Each resulting segment must satisfy the
minimum population requirements for a Performance-Based Maintenance program in
order to remain within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
components within the mal-performing segment can be replaced with other
components (electromechanical distance relays with microprocessor relays, for
example) to remove the mal-performing segment.
If I find (and correct) a Unresolved M aintenance Issue as a result of a M isoperation
investigation (R e: PR C-004), how does this affect m y Perform ance-Based
M aintenance program ?
PRC-005-2 Supplementary Reference and FAQ – October 2012
44
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC-004 required Misoperation investigation/corrective action), the actions
performed can count as a maintenance activity provided the activities in the relevant Tables
have been done, and, if you desire, “reset the clock” on everything you’ve done. In a
Performance-Based Maintenance program, you also need to record the Unresolved
Maintenance Issue as a Countable Event within the relevant component group segment and
use it in the analysis to determine your correct Performance-Based Maintenance interval for
that component group. Note that “resetting the clock” should not be construed as interfering
with an entity’s routine testing schedule because the “clock-reset” would actually make for a
decreased time interval by the time the next routine test schedule comes around.
For example a relay scheme, consisting of four relays, is tested on 1-1-11 and the PSMP has a
time interval of 3 calendar years with an allowable extension of 1 calendar year. The relay
would be due again for routine testing before the end of the year 2015. This mythical relay
scheme has a Misoperation on 6-1-12 that points to one of the four relays as bad. Investigation
proves a bad relay and a new one is tested and installed in place of the original. This
replacement relay actually could be retested before the end of the year 2016 (clock-reset) and
not be out of compliance. This requires tracking maintenance by individual relays and is
allowed. However, many companies schedule maintenance in other ways like by substation or
by circuit breaker or by relay scheme. By these methods of tracking maintenance that “replaced
relay” will be retested before the end of the year 2015. This is also acceptable. In no case was a
particular relay tested beyond the PSMP of four years max, nor was the 6 year max of the
Standard exceeded. The entity can reset the clock if they desire or the entity can continue with
original schedules and, in effect, test even more frequently.
W hy are batteries excluded from PBM ? W hat about exclusion of batteries from
condition based m aintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system Disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
PRC-005-2 Supplementary Reference and FAQ – October 2012
45
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance-Based Protection System
Maintenance (PBM) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance-changing criteria.
Similarly, Functional Entities that want to establish a condition-based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands-on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a
station dc supply. Inspection of the battery is required on a Maximum Maintenance Interval
listed in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1-4).
Please provide an ex am ple of the calculations involved in ex tending m aintenance
tim e intervals using PBM .
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30. For the sake of example only the
following will show 6 failures per year, reality may well have different numbers of failures every
year. PBM requires annual assessment of failures found per units tested. After the first year of
tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure rate. This entity is now
allowed to extend the maintenance interval if they choose. The entity chooses to extend the
maintenance interval of this population segment out to 10 years. This represents a rate of 100
units tested per year; entity selects 100 units to be tested in the following year. After that year
of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures. This entity
has now exceeded the acceptable failure rate for these devices and must accelerate testing of
all of the units at a higher rate such that the failure rate is found to be less than 4% per year;
the entity has three years to get this failure rate down to 4% or less (per year). In response to
the 6% failure rate, the entity decreases the testing interval to 8 years. This means that they will
now test 125 units per year (1000/8). The entity has just two years left to get the test rate
corrected.
After a year, they again find six failures out of the 125 units tested. 6/125= 5% failures. In
response to the 5% failure rate, the entity decreases the testing interval to seven years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to
get the test rate corrected. After a year, they again find six failures out of the 143 units tested.
6/143= 4.2% failures.
(Note that the entity has tried five years and they were under the 4% limit and they tried seven
years and they were over the 4% limit. They must be back at 4% failures or less in the next year
so they might simply elect to go back to five years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to six years.
This means that they will now test 167 units per year (1000/6). After a year, they again find six
PRC-005-2 Supplementary Reference and FAQ – October 2012
46
failures out of the 167 units tested. 6/167= 3.6% failures. Entity found that they could
maintain the failure rate at no more than 4% failures by maintaining the testing interval at six
years or less. Entity chose six-year interval and effectively extended their TBM (five years)
program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested/year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Test
Total
Population Interval
(P)
(I)
# of
Units to
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
PRC-005-2 Supplementary Reference and FAQ – October 2012
47
Please provide an ex am ple of the calculations involved in ex tending m aintenance
tim e intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of
the trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three-phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment – Protection Systems or components of a consistent design standard, or a particular
model or type from a single manufacturer that typically share other common elements.
Consistent performance is expected across the entire population of a segment. A segment must
contain at least sixty (60) individual components.
Example:
Entity has 1,000 circuit breakers, all of which have two trip coils, for a total of 2,000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard, then this is
greater than the minimum sample requirement of 60.
For the sake of further example, the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V-insulation panel wiring, and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago, the entity developed their own internal construction crew and
now builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper-sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their control circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
PRC-005-2 Supplementary Reference and FAQ – October 2012
48
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the operations control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2,000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored; therefore, the trip paths are
continuously tested and the circuit will alarm when there is a failure. These alarms have to be
verified every 12 years for correct operation.
The entity now has 1,000 trip coils (and associated trip paths) remaining that they have elected
to count as control circuits. The entity has instituted a process that requires the verification of
every trip path to each trip coil (one unit), including the electrical activation of the trip coil.
(The entity notes that the trip coils will have to be tripped electrically more often than the trip
path verification, and is taking care of this activity through other documentation of Real-time
Fault operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30. For the sake of example
only, the following will show three failures per year; reality may well have different numbers of
failures every year. PBM requires annual assessment of failures found per units tested. After
the first year of tests, the entity finds three failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
PRC-005-2 Supplementary Reference and FAQ – October 2012
49
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12-year interval, and
effectively extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20-year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Test
Total
Population Interval
(P)
(I)
Units to
# of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC-005-2 Supplementary Reference and FAQ – October 2012
50
Please provide an exam ple of the calculations involved in ex tending m aintenance
tim e intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays”
as all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific Element. This entity calls this set of
protective relays a “Relay Scheme.” Thus, this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off-line tests during generator outages, whereas a
transmission maintenance group might create a process that utilizes Real-time system values
measured at the relays. Under the included definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three-phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment – Protection Systems or components of a consistent design standard, or a particular
model or type from a single manufacturer that typically share other common elements.
Consistent performance is expected across the entire population of a segment. A segment must
contain at least sixty (60) individual components.
Example:
Entity has 2000 “Relay Schemes,” all of which have three current signals supplied from bushing
CTs, and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard, and this population is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1,000) are supplied with current signals from ANSI STD C800 bushing
CTs and voltage signals from PTs built by ACME Electric MFR CO. All of the relay panels and
cable pulls were built with consistent standards, and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built-in
that compare DNP values of voltages and currents (or Watts and VARs), as interpreted by the
MPC relays and alarm for an entity-accepted tolerance level of accuracy. This newer segment
of their “Voltage and Current Sensing” population is different than the original segment,
consistent (standards, construction and performance expectations) within the new segment
and constitutes the remainder of the entity’s population.
PRC-005-2 Supplementary Reference and FAQ – October 2012
51
The entity is tracking many thousands of voltage and current signals within 2,000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But
half of all of the relay schemes voltage and current signals are monitored; therefore, the
voltage and current signals are continuously tested and the circuit will alarm when there is a
failure; these alarms have to be verified every 12 years for correct operation.
The entity now has 1,000 relay schemes worth of voltage and current signals remaining that
they have elected to count within their relay schemes designation. The entity has instituted a
process that requires the verification of these voltage and current signals within each relay
scheme (one unit).
(Please note - a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay, all the way to the signal source itself. Having many sources
of problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PTs). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level; thus, any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal
to be delivered all the way to the relay.
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30. For the sake of example only, the following will
show three failures per year; reality may well have different numbers of failures every year.
PBM requires annual assessment of failures found per units tested. After the first year of tests,
the entity finds three failures in the 100 units tested. 3/100= 3% failure rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4%failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
PRC-005-2 Supplementary Reference and FAQ – October 2012
52
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1,000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12-year interval and effectively
extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested/year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20-year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Test
Total
Population Interval
(P)
(I)
Units to
# of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chose
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC-005-2 Supplementary Reference and FAQ – October 2012
53
1 0 . Ove r la p p in g t h e Ve r ifica t io n o f Se ct io n s o f t h e
P ro t e ct io n Sys t e m
Tables 1-1 through 1-5 require that every Protection System component be periodically
verified. One approach, but not the only method, is to test the entire protection scheme as a
unit, from the secondary windings of voltage and current sources to breaker tripping. For
practical ongoing verification, sections of the Protection System may be tested or monitored
individually. The boundaries of the verified sections must overlap to ensure that there are no
gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection
System may be divided into multiple overlapping sections with a different maintenance
methodology for each section:
•
Time-based maintenance with appropriate maximum verification intervals for
categories of equipment, as given in the Tables 1-1 through 1-5;
•
Monitoring as described in Tables 1-1 through 1-5;
•
A Performance-Based Maintenance program as described in Section 9 above, or
Attachment A of the standard;
•
Opportunistic verification using analysis of Fault records, as described in Section
11
10.1 Frequently Asked Questions:
M y system has alarm s that are gathered once daily through an auto-polling system ;
this is not really a conventional SCADA system but does it m eet the Table 1
requirem ents for inclusion as a m onitored system ?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the Unresolved Maintenance Issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
PRC-005-2 Supplementary Reference and FAQ – October 2012
54
1 1 . Mo n it o rin g b y An a lys is o f Fa u lt Re co rd s
Many users of microprocessor relays retrieve Fault event records and oscillographic records by
data communications after a Fault. They analyze the data closely if there has been an apparent
Misoperation, as NERC standards require. Some advanced users have commissioned automatic
Fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured Digital
Fault Recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time-interval based check on Protection Systems whose operations are analyzed.
Even electromechanical Protection Systems instrumented with DFR channels may achieve some
CBM benefit. The completeness of the verification then depends on the number and variety of
Faults in the vicinity of the relay that produce relay response records and the specific data
captured.
A typical Fault record will verify particular parts of certain Protection Systems in the vicinity of
the Fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external Fault records that
completely verify the Protection System.
For example, Fault records may verify that the particular relays that tripped are able to trip via
the control circuit path that was specifically used to clear that Fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other
nearby Protection Systems may verify that they restrain from tripping for a Fault just outside
their respective zones of protection. The ensemble of internal Fault and nearby external Fault
event data can verify major portions of the Protection System, and reset the time clock for the
Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using Fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple Faults close to either
side of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection
System that can actually be proven using the PMU or DME data.
If Fault record data is used to show that portions or all of a Protection System have been
verified to meet Table 1 requirements, the owner must retain the Fault records used, and the
maintenance-related conclusions drawn from this data and used to defer Table 1 tests, for at
least the retention time interval given in Section 8.2.
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11.1 Frequently Asked Questions:
I use m y protective relays for Fault and Disturbance recording, collecting
oscillographic records and event records via com m unications for Fault analysis to
m eet NER C and DM E requirem ents. W hat are the m aintenance requirem ents for the
relays?
For relays used only as Disturbance Monitoring Equipment, NERC Standard PRC-018-1 R3 & R6
states the maintenance requirements and is being addressed by a standards activity that is
revising PRC-002-1 and PRC-018-1. For protective relays “that are designed to provide
protection for the BES,” this standard applies, even if they also perform DME functions.
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1 2 . I m p o r t a n ce o f Re la y Se t t in g s in Ma in t e n a n ce
P ro g ra m s
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single selfmonitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of Fault records may or may
not reveal setting problems. To minimize risk of setting errors after commissioning, the user
should enforce strict settings data base management, with reconfirmation (manual or
automatic) that the installed settings are correct whenever maintenance activity might have
changed them; for background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this
requirement is simple: With legacy relays (non-microprocessor protective relays), it is necessary
to know the value of the intended setting in order to test, adjust and calibrate the relay.
Proving that the relay works per specified setting was the de facto procedure. However, with
the advanced microprocessor relays, it is possible to change relay settings for the purpose of
verifying specific functions and then neglect to return the settings to the specified values.
While there is no specific requirement to maintain a settings management process, there
remains a need to verify that the settings left in the relay are the intended, specified settings.
This need may manifest itself after any of the following:
•
One or more settings are changed for any reason.
•
A relay fails and is repaired or replaced with another unit.
•
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing w hen I have to upgrade firm w are of a m icroprocessor
relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity has
the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade, then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
PRC-005-2 Supplementary Reference and FAQ – October 2012
57
regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
If I upgrade m y old relays, then do I have to m aintain m y previous equipm ent
m aintenance docum entation?
If an equipment item is repaired or replaced, then the entity can restart the maintenanceactivity-time-interval-clock, if desired; however, the replacement of equipment does not
remove any documentation requirements. The requirements in the standard are intended to
ensure that an entity has a maintenance plan, and that the entity adheres to minimum activities
and maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment, then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
W e have a num ber of installations w here w e have changed our Protection System
com ponents. Som e of the changes w ere upgrades, but others w ere sim ply system
rating changes that m erely required taking relays “out-of-service”. W hat are our
responsibilities w hen it com es to “out-of-service” devices?
Assuming that your system up-rates, upgrades and overall changes meet any and all other
requirements and standards, then the requirements of PRC-005-2 are simple – if the Protection
System component performs a Protection System function, then it must be maintained. If the
component no longer performs Protection System functions, then it does not require
maintenance activities under the Tables of PRC-005-2. While many entities might physically
remove a component that is no longer needed, there is no requirement in PRC-005-2 to remove
such component(s). Obviously, prudence would dictate that an “out-of-service” device is truly
made inactive. There are no record requirements listed in PRC-005-2 for Protection System
components not used.
W hile perform ing relay testing of a protective device on our Bulk Electric System , it
w as discovered that the protective device being tested w as either broken or out of
calibration. Does this satisfy the relay testing requirem ent, even though the
protective device tested bad, and m ay be unable to be placed back into service?
Yes, PRC-005-2 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-2
requirement, although the protective device may be unable to be returned to service under
normal calibration adjustments. R5 states:
“R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct any identified Unresolved Maintenance Issues.”
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC standards.
If I show the protective device out of service w hile it is being repaired, then can I
add it back as a new protective device w hen it returns? If not, m y relay testing
history w ould show that I w as out of com pliance for the last m aintenance cycle.
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The maintenance and testing requirements (R5) state “…shall demonstrate efforts to correct
any identified Unresolved Maintenance Issues...” The type of corrective activity is not stated;
however, it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity might ask about the status
of your corrective actions.
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1 3 . Se lf- Mo n it o rin g Ca p a b ilit ie s a n d Lim it a t io n s
Microprocessor relay proponents have cited the self-monitoring capabilities of these products
for nearly 20 years. Theoretically, any element that is monitored does not need a periodic
manual test. A problem today is that the community of manufacturers and users has not
created clear documentation of exactly what is and is not monitored. Some unmonitored but
critical elements are buried in installed systems that are described as self-monitoring.
To utilize the extended time intervals allowed by monitoring, the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with
the unmonitored intervals established in Table 1 and Table 3.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands-on
maintenance requirement), the manufacturers of the microprocessor-based self-monitoring
components in the Protection System should publish for the user a document or map that
shows:
•
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
•
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
This manufacturer’s information can be used by the registered entity to document compliance
of the monitoring attributes requirements by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
•
Extending the monitoring to include the alarm transmission Facilities through
which failures are reported within a given time frame to allocate where action
can be taken to initiate resolution of the alarm attributed to an Unresolved
Maintenance Issue, so that failures of monitoring or alarming systems also lead
to alarms and action.
•
Documenting the plans for verification of any unmonitored components
according to the requirements of Table 1 and Table 3.
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13.1 Frequently Asked Questions:
I can’t figure out how to dem onstrate com pliance w ith the requirem ents for the
highest level of m onitoring of Protection System s. W hy does this M aintenance
Standard describe a m aintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring, the standard establishes the necessary requirements for
when such equipment becomes available.
By creating a roadmap for development, this provision makes the standard technology-neutral.
The Standard Drafting Team wants to avoid the need to revise the standard in a few years to
accommodate technology advances that may be coming to the industry.
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1 4 . No t ifica t io n o f P ro t e ct io n Sys t e m Fa ilu re s
When a failure occurs in a Protection System, power system security may be compromised, and
notification of the failure must be conducted in accordance with relevant NERC standard(s).
Knowledge of the failure may impact the system operator’s decisions on acceptable Loading
conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System owner also encourages the system owner to execute repairs as rapidly as possible. In
some cases, a microprocessor relay or carrier set can be replaced in hours; wiring termination
failures may be repaired in a similar time frame. On the other hand, a component in an
electromechanical or early-generation electronic relay may be difficult to find and may hold up
repair for weeks. In some situations, the owner may have to resort to a temporary protection
panel, or complete panel replacement.
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1 5 . Ma in t e n a n ce Act ivit ie s
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance, but if its battery
maintenance program is lacking, then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC-005-2 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore, manual intervention to
perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and
voltage sensing devices and are used to isolate a Faulted Element of the BES. Devices that
sense thermal, vibration, seismic, pressure, gas, or any other non-electrical inputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor-based
equipment in the following ways; the relays should meet the asset owners’ tolerances:
•
Non-microprocessor devices must be tested with voltage and/or current applied to the
device.
•
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Questions:
W hat calibration tolerance should be applied on electrom echanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber-optic Hall-effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type
of voltage and current sensing devices included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these
signals is to know that the expected output from these components actually reaches the
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63
protective relay. Therefore, the proof of the proper operation of these components also
demonstrates the integrity of the wiring (or other medium used to convey the signal) from the
current and voltage sensing device, all the way to the protective relay. The following
observations apply:
•
There is no specific ratio test, routine test or commissioning test mandated.
•
There is no specific documentation mandated.
•
It is required that the signal be present at the relay.
•
This expectation can be arrived at from any of a number of means; including, but not
limited to, the following: By calculation, by comparison to other circuits, by
commissioning tests, by thorough inspection, or by any means needed to verify the
circuit meets the asset owner’s Protection System maintenance program.
•
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this, therefore, tests the CT, as well as the wiring from the relay all the
back to the CT.
•
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during Load conditions, at the input to the relay.
•
Another example of testing the various voltage and/or current sensing devices is to
query the microprocessor relay for the Real-time Loading; this can then be compared to
other devices to verify the quantities applied to this relay. Since the input devices have
supplied the proper values to the protective relay, then the verification activity has been
satisfied. Thus, event reports (and oscillographs) can be used to verify that the voltage
and current sensing devices are performing satisfactorily.
•
Still another method is to measure total watts and vars around the entire bus; this
should add up to zero watts and zero vars, thus proving the voltage and/or current
sensing devices system throughout the bus.
•
Another method for proving the voltage and/or current-sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
•
Any other method that verifies the input to the protective relay from the device that
produces the current or voltage signal sample.
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15.2.1 Frequently Asked Questions:
W hat is m eant by “… verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays … ”
Do w e need to perform
ratio, polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current-sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all-inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different
current transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional
testing on the panel wiring to ensure that the values arrive at those relays) with the
other phases, and verify that residual currents are within expected bounds.
•
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay (such as, but not limited to,
a query to the microprocessor relay) to another protective relay monitoring the same
line, with currents supplied by different CTs.
•
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi-meters, voltmeter, clamp-on ammeters, etc.) and
verified by calculations and known ratios to be the values expected. For example, a
single PT on a 100KV bus will have a specific secondary value that, when multiplied by
the PT ratio, arrives at the expected bus value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned
relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring Systems.
Is w iring insulation or hi-pot testing required by this M aintenance Standard?
No, wiring insulation and equipment hi-pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
PRC-005-2 Supplementary Reference and FAQ – October 2012
65
and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify the
insulation of the wiring between the instrument transformer and the relay.
M y plant generator and transform er relays are electrom echanical and do not have
m etering functions, as do m icroprocessor- based relays. In order for m e to com pare
the instrum ent transform er inputs to these relays to the secondary values of other
m etered instrum ent transform ers m onitoring the sam e prim ary voltage and current
signals, it w ould be necessary to tem porarily connect test equipm ent, like
voltm eters and clam p on am m eters, to m easure the input signals to the relays. This
practice seem s very risky, and a plant trip could result if the technician w ere to
m ake an error w hile m easuring these current and voltage signals. How can I avoid
this risk? Also, w hat if no other instrum ent transform ers are available w hich
m onitor the sam e prim ary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays, but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests, such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests to
adequately “verify the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays …” while eliminating the risk of tripping an in service generator
or transformer. Similarly, this same offline test methodology can be used to verify the relay
input voltage and current signals to relays when there are no other instrument transformers
monitoring available for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the
relays. It includes the wiring (or other signal conveyance) from every trip output to every trip
coil. It includes any device needed for the correct processing of the needed trip signal to the
trip coil of the interrupting device; this requirement is meant to capture inputs and outputs to
and from a protective relay that are necessary for the correct operation of the protective
functions. In short, every trip path must be verified; the method of verification is optional to
the asset owner. An example of testing methods to accomplish this might be to verify, with a
volt-meter, the existence of the proper voltage at the open contacts, the open circuited input
circuit and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker
(or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete
functional test. If a suitable monitoring system is installed that verifies every parallel trip path,
then the manual-intervention testing of those parallel trip paths can be eliminated; however,
the actual operation of the circuit breaker must still occur at least once every six years. This sixyear tripping requirement can be completed as easily as tracking the Real-time Fault-clearing
operations on the circuit breaker, or tracking the trip coil(s) operation(s) during circuit breaker
routine maintenance actions.
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The circuit-interrupting device should not be confused with a motor-operated disconnect. The
intent of this standard is to require maintenance intervals and activities on Protection Systems
equipment, and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground
switch as an interrupting device, if this ground switch is utilized in a Protection System and
forces a ground Fault to occur that then results in an expected Protection System operation to
clear the forced ground Fault. The SDT believes that this is essentially a transferred-tripping
device without the use of communications equipment. If this high-speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years, and any electromechanically operated device will have to be tested every six years. If the
spring-operated ground switch can be disconnected from the solenoid triggering unit, then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay
(86) that may exist in any particular trip scheme. If the lock-out relays (86) are
electromechanical type components, then they must be trip tested. The PSMT SDT considers
these components to share some similarities in failure modes as electromechanical protective
relays; as such, there is a six-year maximum interval between mandated maintenance tasks
unless PBM is applied.
Contacts of the 86 and/or 94 that pass the trip current on to the circuit interrupting device trip
coils will have to be checked as part of the 12 year requirement. Contacts of the 86 and/or 94
lock relay that operate non-BES interrupting devices are not required. Normally-open contacts
that are not used to pass a trip signal and normally-closed contacts do not have to be verified.
Verification of the tripping paths is the requirement.
While relays that do not respond to electrical quantities are presently excluded from this
standard, their control circuits are included if the relay is installed to detect Faults on BES
Elements. Thus, the control circuit of a BES transformer sudden pressure relay should be
verified every 12 years, assuming its integrity is not monitored. While a sudden pressure relay
control circuit is included within the scope of PRC-005-2, other alarming relay control circuits,
(i.e., SF-6 low gas) are not included, even though they may trip the breaker being monitored.
New technology is also accommodated here; there are some tripping systems that have
replaced the traditional hard-wired trip circuitry with other methods of trip-signal conveyance
such as fiber-optics. It is the intent of the PSMT SDT to include this, and any other, technology
that is used to convey a trip signal from a protective relay to a circuit breaker (or other
interrupting device) within this category of equipment. The requirement for these systems is
verification of the tripping path.
Monitoring of the control circuit integrity allows for no maintenance activity on the control
circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or
tripping auxiliary relays). Monitoring of integrity means to monitor for continuity and/or
presence of voltage on each trip path. For Ethernet or fiber-optic control systems, monitoring
of integrity means to monitor communication ability between the relay and the circuit breaker.
The trip path from a sudden pressure device is a part of the Protection System control circuitry.
The sensing element is omitted from PRC-005-2 testing requirements because the SDT is
unaware of industry-recognized testing protocol for the sensing elements. The SDT believes
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67
that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17,
and understands this to be consistent with the position of FERC staff.
15.3.1 Frequently Asked Questions:
Is it perm issible to verify circuit breaker tripping at a different tim e (and interval)
than w hen w e verify the protective relays and the instrum ent transform ers?
Yes, provided the entire Protective System is tested within the individual component’s
maximum allowable testing intervals.
The Protection System M aintenance Standard describes requirem ents for verifying
the tripping of circuit breakers. W hat is this telling m e about m aintenance of circuit
breakers?
Requirements in PRC-005-2 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC-005-2 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit trip path, as established in Table 1-5
“Protection System Control Circuitry (Trip coils and aux iliary relays)”?
Table 1-5 specifies that each breaker trip coil and lockout relays that carry trip current to
a trip coil must be operated within the specified time period. The required operations
may be via targeted maintenance activities, or by documented operation of these
devices for other purposes such as Fault clearing.
Are high-speed ground sw itch trip coils included in the dc control circuitry?
Yes. PRC-005-2 includes high-speed grounding switch trip coils within the dc control circuitry to
the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES
protection com ponent, have to be tested per Table 1.5? (R efer to Table 3 for
ex am ples 1 and 2) Example 1: A non-BES circuit breaker that is tripped via a Protection
System to which PRC-005-2 applies might be (but is not limited to) a 12.5KV circuit breaker
feeding (non-black-start) radial Loads but has a trip that originates from an under-frequency
(81) relay.
•
The relay must be verified.
•
The voltage signal to the relay must be verified.
•
All of the relevant dc supply tests still apply.
•
.
•
The unmonitored trip circuit between the relay and any lock-out or auxiliary relay must
be verified every 12 years.
•
The unmonitored trip circuit between the lock-out (or auxiliary relay) and the non-BES
breaker does not have to be proven with an electrical trip.
•
In the case where there is no lock-out or auxiliary tripping relay used, the trip circuit to
the non-BES breaker does not have to be proven with an electrical trip.
PRC-005-2 Supplementary Reference and FAQ – October 2012
68
•
The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip.
Example 2: A Transmission Owner may have a non-BES breaker that is tripped via a Protection
System to which PRC-005-2 applies, which may be (but is not limted to) a 13.8 KV circuit
breaker feeding (non-black-start) radial Loads but has a trip that originates from a BES 115KV
line relay.
•
•
•
•
•
•
•
•
The relay must be verified
The voltage signal to the relay must be verified
All of the relevant dc supply tests still apply
The unmonitored trip circuit between the relay and any lock-out (86) or auxiliary (94)
relay must be verified every 12 years
The unmonitored trip circuit between the lock-out (86) (or auxiliary (94)) relay and the
non-BES breaker does not have to be proven with an electrical trip
In the case where there is no lockout (86) or auxiliary (94) tripping relay used, the trip
circuit to the non-BES breaker does not have to be proven with an electrical trip.
The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip
Example 3: A Generator Owner may have an non-BES circuit breaker that is tripped via a
Protection System to which PRC-005-2 applies, such as the generator field breaker and low-side
breakers on station service/excitation transformers connected to the generator bus.
Trip testing of the generator field breaker and low side station service/excitation transformer
breaker(s) via lockout or auxiliairy tripping relays are not required since these breakers may be
associated with radially fed loads and are not considered to be BES breakers. An example of an
otherwise non-BES circuit breaker that is tripped via a BES protection component might be (but
is not limited to) a 6.9kV station service transformer source circuit breaker but has a trip that
originates from a generator differential (87) relay.
•
The differential relay must be verified.
•
The current signals to the relay must be verified.
•
All of the relevant dc supply tests still apply.
•
The unmonitored trip circuit between the relay and any lock-out or auxiliary relay must
be verified every 12 years.
•
The unmonitored trip circuit between the lock-out (or auxiliary relay) and the non-BES
breaker does not have to be proven with an electrical trip.
•
In the case where there is no lock-out or auxiliary tripping relay used, the trip circuit to
the non-BES breaker does not have to be proven with an electrical trip.
•
The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip.
However, it is very prudent to verify the tripping of such breakers for the integrity of the overall
generation plant.
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69
Do I have to verify operation of breaker “a” contacts or any other norm ally closed
aux iliary contacts in the trip path of each breaker as part of m y control circuit test?
Operation of normally-closed contacts does not have to be verified. Verification of the tripping
paths is the requirement. The continuity of the normally closed contacts will be verified when
the tripping path is verified.
15.4 Batteries and DC Supplies (Table 1-4)
The NERC definition of a Protection System is:
•
Protective relays which respond to electrical quantities,
•
Communications Systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
The station battery is not the only component that provides dc power to a Protection System.
In the new definition for Protection System, “station batteries” are replaced with “station dc
supply” to make the battery charger and dc producing stored energy devices (that are not a
battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner
to other conventional methods of showing continuity. Continuity, as used in Table 1-4 of the
standard, refers to verifying that there is a continuous current path from the positive terminal
of the station battery set to the negative terminal. Without verifying continuity of a station
battery, there is no way to determine that the station battery is available to supply dc power to
the station. An open battery string will be an unavailable power source in the event of loss of
the battery charger.
Batteries cannot be a unique population segment of a Performance-Based Maintenance
Program (PBM) because there are too many variables in the electrochemical process to
completely isolate all of the performance-changing criteria necessary for using PBM on battery
Systems. However, nothing precludes the use of a PBM process for any other part of a dc
supply besides the batteries themselves.
15.4.1 Frequently Asked Questions:
W hat constitutes the station dc supply, as m entioned in the definition of Protective
System ?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers, as well as dc systems that do not utilize batteries. This
revision of PRC-005-2 is intended to capture these devices that were not included under the
previous definition. The station direct current (dc) supply normally consists of two
components: the battery charger and the station battery itself. There are also emerging
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70
technologies that provide a source of dc supply that does not include either a battery or
charger.
Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1-4.
Emerging Technologies - Station dc supplies are currently being developed that use other
energy storage technologies besides the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1-4 presents maintenance activities and maximum allowable
testing intervals for these new station dc supply technologies. However, because these
technologies are relatively new, the maintenance activities for these station dc supplies may
change over time.
W hat did the PSM T SDT m ean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity (no open circuits) of a battery set by various methods, and not
to limit the owner to other conventional methods of showing continuity – lack of an open
circuit. Continuity, as used in Table 1-4 of the standard, refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative
terminal (no open circuit). Without verifying continuity of a station battery, there is no way to
determine that the station battery is available to supply dc power to the station. Whether it is
caused from an open cell or a bad external connection, an open battery string will be an
unavailable power source in the event of loss of the battery charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path, the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery
must be capable of supplying dc current, both for continuous dc loads and for tripping breakers
and switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
•
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor-based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
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71
harmonics. With the loss of continuity in the battery, the filter provided by the battery
is no longer present.
•
Loss of electrical continuity of the station battery will cause, in most battery chargers,
regardless of the battery charger’s output current capability, a delayed response in full
output current from the charger. Almost all chargers have an intentional one- to twosecond delay to switch from a low substation dc load current to the maximum output of
the charger. This delay would cause the opening of circuit breakers to be delayed,
which could violate system performance standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery, unless the battery charger is taken out of service. At that
time, a break in the continuity of the station battery current path will be revealed because
there will be no voltage on the station dc circuitry. This particular test method, while proving
battery continuity, may not be acceptable to all installations.
Although the standard prescribes what must be accomplished during the maintenance activity,
it does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
•
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged, there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path
through the battery.
•
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of
the various dc-supplied equipment in the station should be considered before using this
approach.
•
Manufacturers of microprocessor-controlled battery chargers have developed methods
for their equipment to periodically (or continuously) test for battery continuity. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
•
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
•
Internal ohmic measurements of the cells and units of lead-acid batteries (VRLA & VLA)
can detect lack of continuity within the cells of a battery string; and when used in
conjunction with resistance measurements of the battery’s external connections, can
prove continuity. Also some methods of taking internal ohmic measurements, by their
very nature, can prove the continuity of a battery string without having to use the
results of resistance measurements of the external connections.
•
Specific gravity tests could infer continuity because without continuity there could be no
charging occurring; and if there is no charging, then specific gravity will go down below
acceptable levels over time.
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No matter how the electrical continuity of a battery set is verified, it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1-4 to insure that the
station dc supply has a path that can provide the required current to the Protection System at
all times.
W hen should I check the station batteries to see if they have sufficient energy to
perform as m anufactured?
The answer to this question depends on the type of battery (valve-regulated lead-acid, vented
lead-acid, or nickel-cadmium) and the maintenance activity chosen.
For example, if you have a valve-regulated lead-acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every six months. While this interval might seem to be quite short, keep in mind that the sixmonth interval is important for VRLA batteries; this interval provides an accumulation of data
that better shows when a VRLA battery is incapable of performing as manufactured.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every three calendar years.
How is a baseline established for cell/ unit internal ohm ic m easurem ents?
Establishment of cell/unit internal ohmic baseline measurements should be completed when
lead-acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are
most indicative of the station battery’s ability to perform as manufactured, they should be
made at some point in time after the installation to allow the cell chemistry to stabilize after
the initial freshening charge. An accepted industry practice for establishing baseline values is
after six-months of installation, with the battery fully charged and in service. However, it is
recommended that each owner, when establishing a baseline, should consult the battery
manufacturer for specific instructions on establishing an ohmic baseline for their product, if
available.
When internal ohmic measurements are taken, the same make/model test equipment should
be used to establish the baseline and used for the future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement
used by different manufacturer’s equipment. Keep in mind that one manufacturer’s
“Conductance” test equipment does not produce similar results as another manufacturer’s
“Conductance” test equipment, even though both manufacturers have produced “Ohmic” test
equipment. Therefore, for meaningful results to an established baseline, the same
make/modelof instrument should be used.
For all new installations of valve-regulated lead-acid (VRLA) batteries and vented lead-acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to
be used to determine the ability of the station battery to perform as manufactured, the
establishment of the baseline, as described above, should be followed at the time of installation
to insure the most accurate trending of the cell/unit. However, often for older VRLA batteries,
the owners of the station batteries have not established a baseline at installation. Also for
owners of VLA batteries who want to establish a maintenance activity which requires trending
of measured ohmic values to a baseline, there was typically no baseline established at
installation of the station battery to trend to.
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To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also, several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However, it is important that when using battery
manufacturer-supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment). Although many
manufacturers may have provided baseline values, which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
W hy determ ine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be
a very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged, the battery is available to deliver its existing capacity. As a
battery is discharged, its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
W hat is State of Charge and how can it be determ ined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged, the battery is
available to deliver its existing capacity. As a battery is discharged, its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For vented lead-acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the
battery discharges, the active electrolyte, sulfuric acid, is consumed and the concentration of
the sulfuric acid in water is reduced. This, in turn, reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can,
therefore, be used as an indication of the state of charge of the battery. Hydrometer readings
may not tell the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA
battery. If measured right after charging, you might see high specific gravity readings at the top
of the cell, even though it is much less at the bottom. Conversely, if taken shortly after adding
water to the cell, the specific gravity readings near the top of the cell will be lower than those
at the bottom.
Nickel-cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and valve-regulated lead-acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
PRC-005-2 Supplementary Reference and FAQ – October 2012
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readings. For these two types of batteries, and for VLA batteries also, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by taking
voltage and current readings at the battery terminals. The methods employed to obtain
accurate readings vary for the different battery types. Manufacturers’ information and IEEE
guidelines can be consulted for specifics; (see IEEE 1106 Annex B for Nickel Cadmium batteries,
IEEE 1188 Annex A for VRLA batteries and IEEE 450 for VLA batteries.
W hy determ ine the Connection R esistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery,
a very high resistance can cause severe damage. The maintenance requirement to verify
battery terminal connection resistance in Table 1-4 is established to verify that the integrity of
all battery electrical connections is acceptable. This verification includes cell-to-cell (intercell)
and external circuit terminations. Your method of checking for acceptable values of intercell
and terminal connection resistance could be by individual readings, or a combination of the
two. There are test methods presently that can read post termination resistances and
resistance values between external posts. There are also test methods presently available that
take a combination reading of the post termination connection resistance plus the intercell
resistance value plus the post termination connection resistance value. Either of the two
methods, or any other method, that can show if the adequacy of connections at the battery
posts is acceptable.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen, not to exceed the
maximum maintenance interval of Table 1-4. Trending of the interval measurements to the
baseline measurements will identify any degradation in the battery connections. When the
connection resistance values exceed the acceptance criteria for the connection, the connection
is typically disassembled, cleaned, reassembled and measurements taken to verify that the
measurements are adequate when compared to the baseline readings.
W hat conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1-4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to
the electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal colors (which
are an indicator of sulfation or possible copper contamination) and abnormal conditions such as
cracked grids. The visual inspection could look for symptoms of hydration that would indicate
that the battery has been left in a completely discharged state for a prolonged period. Besides
looking at the plates for signs of aging, all internal connections, such as the bus bar connection
to each plate, and the connections to all posts of the battery need to be visually inspected for
abnormalities. In a complete visual inspection for the condition of the cell the cell plates,
separators and sediment space of each cell must be looked at for signs of deterioration. An
inspection of the station battery’s cell condition also includes looking at all terminal posts and
cell-to-cell electric connections to ensure they are corrosion free. The case of the battery
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containing the cell, or cells, must be inspected for cracks and electrolyte leaks through cracks
and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1-4 by a Performance-Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery, nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval
of Table 1-4.
W hy is it necessary to verify the battery string can perform as m anufactured? I
only care that the battery can trip the breaker, w hich m eans that the battery can
perform as designed. I oversize m y batteries so that even if the battery cannot
perform as m anufactured, it can still trip m y breakers.
The fundamental answer to this question revolves around the concept of battery performance
“as designed” vs. battery performance “as manufactured.” The purpose of the various sections
of Table 1-4 of this standard is to establish requirements for the Protection System owner to
maintain the batteries, to ensure they will operate the equipment when there is an incident
that requires dc power, and ensure the batteries will continue to provide adequate service until
at least the next maintenance interval. To meet these goals, the correct battery has to be
properly selected to meet the design parameters, and the battery has to deliver the power it
was manufactured to provide.
When testing batteries, it may be difficult to determine the original design (i.e., load profile) of
the dc system. This standard is not intended as a design document, and requirements relating
to design are, therefore, not included.
Where the dc load profile is known, the best way to determine if the system will operate as
designed is to conduct a service test on the battery. However, a service test alone might not
fully determine if the battery is healthy. A battery with 50% capacity may be able to pass a
service test, but the battery would be in a serious state of deterioration and could fail at some
point in the near future.
To ensure that the battery will meet the required load profile and continue to meet the load
profile until the next maintenance interval, the installed battery must be sized correctly (i.e., a
correct design), and it must be in a good state of health. Since the design of the dc system is
not within the scope of the standard, the only consistent and reliable method to ensure that
the battery is in a good state of health is to confirm that it can perform as manufactured. If the
battery can perform as manufactured and it has been designed properly, the system should
operate properly until the next maintenance interval.
How do I verify the battery string can perform as m anufactured?
Optimally, actual battery performance should be verified against the manufacturer’s rating
curves. The best practice for evaluating battery performance is via a performance test.
However, due to both logistical and system reliability concerns, some Protection System
owners prefer other methods to determine if a battery can perform as manufactured. There
are several battery parameters that can be evaluated to determine if a battery can perform as
manufactured. Ohmic measurements and float current are two examples of parameters that
have been reported to assist in determining if a battery string can perform as manufactured.
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The evaluation of battery parameters in determining battery health is a complex issue, and is
not an exact science. This standard gives the user an opportunity to utilize other measured
parameters to determine if the battery can perform as manufactured. It is the responsibility of
the Protection System owner, however, to maintain a documented process that demonstrates
the chosen parameter(s) and associated methodology used to determine if the battery string
can perform as manufactured.
Whatever parameters are used to evaluate the battery (ohmic measurements, float current,
float voltages, temperature, specific gravity, performance test, or combination thereof), the
goal is to determine the value of the measurement (or the percentage change) at which the
battery fails to perform as manufactured, or the point where the battery is deteriorating so
rapidly that it will not perform as manufactured before the next maintenance interval.
This necessitates the need for establishing and documenting a baseline. A baseline may be
required of every individual cell, a particular battery installation, or a specific make, model, or
size of a cell. Given a consistent cell manufacturing process, it may be possible to establish a
baseline number for the cell (make/model/type) and, therefore, a subsequent baseline for
every installation would not be necessary. However, future installations of the same battery
types should be spot-checked to ensure that your baseline remains applicable.
Consistent testing methods by trained personnel are essential. Moreover, it is essential that
these technicians utilize the same make/model of ohmic test equipment each time readings are
taken in order to establish a meaningful and accurate trendline against the established
baseline. The type of probe and its location (post, connector, etc) for the reading need to be the
same for each subsequent test. The room temperature should be recorded with the readings
for each test as well. Care should be taken to consider any factors that might lead a trending
program to become invalid.
Float current along with other measureable parameters can be used in lieu of or in concert with
ohmic measurement testing to measure the ability of a battery to perform as manufactured.
The key to using any of these measurement parameters is to establish a baseline and the point
where the reading indicates that the battery will not perform as manufactured.
The establishment of a baseline may be different for various types of cells and for different
types of installations. In some cases, it may be possible to obtain a baseline number from the
battery manufacturer, although it is much more likely that the baseline will have to be
established after the installation is complete. To some degree, the battery may still be
“forming” after installation; consequently, determining a stable baseline may not be possible
until several months after the battery has been in service.
The most important part of this process is to determine the point where the ohmic reading (or
other measured parameter(s)) indicates that the battery cannot perform as manufactured.
That point could be an absolute number, an absolute change, or a percentage change of an
established baseline.
Since there are no universally-accepted repositories of this information, the Protection System
owner will have to determine the value/percentage where the battery cannot perform as
manufactured (heretofore referred to as a failed cell). This is the most difficult and important
part of the entire process.
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To determine the point where the battery fails to perform as manufactured, it is helpful to have
a history of a battery type, if the data includes the parameter(s) used to evaluate the battery's
ability to perform as manufactured against the actual demonstrated performance/capacity of a
battery/cell.
For example, when an ohmic reading has been recorded that the user suspects is indicating a
failed cell, a performance test of that cell (or string) should be conducted in order to
prove/quantify that the cell has failed. Through this process, the user needs to determine the
ohmic value at which the performance of the cell has dropped below 80% of the manufactured,
rated performance. It is likely that there may be a variation in ohmic readings that indicates a
failed cell (possibly significant). It is prudent to use the most conservative values to determine
the point at which the cell should be marked for replacement. Periodically, the user should
demonstrate that an “adequate” ohmic reading equates to an adequate battery performance
(>80% of capacity).
Similarly, acceptance criteria for "good" and "failed" cells should be established for other
parameters such as float current, specific gravity, etc., if used to determine the ability of a
battery to function as designed.
W hat happens if I change the m ake/ m odel of ohm ic test equipm ent after the
battery has been installed for a period of tim e?
If a user decides to switch testers, either voluntarily or because the equipment is not
supported/sold any longer, the user may have to establish a new base line and new parameters
that indicate when the battery no longer performs as manufactured. The user always has a
choice to perform a capacity test in lieu of establishing new parameters.
W hat are som e of the differences betw een lead-acid and nickel-cadm ium batteries?
There is a marked difference in the aging process of lead acid and nickel-cadmium station
batteries. The difference in the aging process of these two types of batteries is chiefly due to
the electrochemical process of the battery type. Aging and eventual failure of lead acid
batteries is due to expansion and corrosion of the positive grid structure, loss of positive plate
active material, and loss of capacity caused by physical changes in the active material of the
positive plates. In contrast, the primary failure of nickel-cadmium batteries is due to the
gradual linear aging of the active materials in the plates. The electrolyte of a nickel-cadmium
battery only facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued corrosion of the
positive plate and grid structure throughout its operational life while a nickel-cadmium battery
does not.
Changes to the properties of a lead acid battery when periodically measured and trended to a
baseline, can indicate aging of the grid structure, positive plate deterioration, or changes in the
active materials in the plate.
Because of the clear differences in the aging process of lead acid and nickel-cadmium batteries,
there are no significantly measurable properties of the nickel-cadmium battery that can be
measured at a periodic interval and trended to determine aging. For this reason, Table 1-4(c)
(Protection System Station dc supply Using nickel-cadmium [NiCad] Batteries) only specifies one
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minimum maintenance activity and associated maximum maintenance interval necessary to
verify that the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance against the station battery baseline. This
maintenance activity is to conduct a performance or modified performance capacity test of the
entire battery bank.
W hy in Table 1-4 of PR C-005-2 is there a m aintenance activity to inspect the
structural intergrity of the battery rack?
The purpose of this inspection is to verify that the battery rack is correctly installed and has no
deterioration that could weaken its structural integrity.
Because the battery rack is specifically manufactured for the battery that is mounted on it,
weakening of its structural members by rust or corrosion can physically jeopardize the battery.
W hat is required to com ply w ith the “Unintentional dc Grounds” requirem ent?
In most cases, the first ground that appears on a battery is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously, a “check-off” of some sort will
have to be devised by the inspecting entity to document that a check is routinely done for
Unintentional DC Grounds because of the possible consequences to the Protection System.
W here the standard refers to “all cells,” is it sufficient to have a docum entation
m ethod that refers to “all cells,” or do w e need to have separate docum entation for
every cell? For ex am ple, do I need 60 individual docum ented check-offs for good
electrolyte level, or w ould a single check-off per bank be sufficient?
A single check-off per battery bank is sufficient for documentation, as long as the single checkoff attests to checking all cells/units.
Does this standard refer to Station batteries or all batteries; for ex am ple,
Com m unications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC-005-2 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point, the corrective actions can be initiated.
W hat are cell/ unit internal ohm ic m easurem ents?
With the introduction of Valve-Regulated Lead-Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead-Acid (VLA)
batteries were unable to be used on this new type of lead-acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells
and periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The
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inductive reactance in the current path through the battery is so minuscule when compared to
the huge capacitive reactance of the cells that it is often ignored in most circuit models of the
battery cell. Taking the basic model of a battery cell manufacturers of battery test equipment
have developed and marketed testing devices to take measurements of the current path to
detect degradation in the internal path through the cell.
In the battery industry, these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac
conductance, ac impedance, and dc resistance. They are defined by the test equipment
providers and IEEE and refer to the method of taking ohmic measurements of a lead acid
battery. For example, in one manufacturer’s ac conductance equipment measurements are
taken by applying a voltage of a known frequency and amplitude across a cell or battery unit
and observing the ac current flow it produces in response to the voltage. A manufacturer of an
ac impedance meter measures ac current of a known frequency and amplitude that is passed
through the whole battery string and determines the impedances of each cell or unit by
measuring the resultant ac voltage drop across them. On the other hand, dc resistance of a cell
is measured by a third manufacturer’s equipment by applying a dc load across the cell or unit
and measuring the step change in both the voltage and current to calculate the internal dc
resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices, there were no standards developed or used to mandate the test signals
used in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of
measurement devices. This diversity in test signals coupled with the three different types of
ohmic measurements techniques (impedance conductance and resistance) make it impossible
to always get the same ohmic measurement for a cell with different ohmic measurement
devices. However, IEEE has recognized the great value for choosing one device for ohmic
measurement, no matter who makes it or the method to calculate the ohmic measurement.
The only caution given by IEEE and the battery manufacturers is that when trending the cells of
a lead acid station battery consistent ohmic measurement devices should be used to establish
the baseline measurement and to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need
for taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a baseline and
trending it over time says, “…depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary…” (IEEE std 1188-2005, C.4 page 18).
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries.
The standard also discusses the need to look for significant changes in the ohmic
measurements, the caution that measurement data will differ with each type of model of
instrument used, and lists a number of factors that affect ohmic measurements.
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At the beginning of the 21st century, EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity, but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity,” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as manufactured. By evaluation of the
trending of the ohmic measurements over time, the owner could track the performance of the
individual components of the station battery and determine if a total station battery or
components of it required capacity testing, removal, replacement or in many instances
replacement of the entire station battery. By taking this condition based approach these
owners have eliminated having to perform capacity testing at prescribed intervals to determine
if a battery needs to be replaced and are still able to effectively determine if a station battery
can perform as manufactured.
M y VR LA batteries have m ultiple-cells w ithin an individual battery jar (or unit); how
am I ex pected to com ply w ith the cell-to-cell ohm ic m easurem ent requirem ents on
these units that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1-4. In cases where individual cells in a multi-cell unit are inaccessible, an ohmic measurement
of the entire unit may be made.
I have a concern about m y batteries being used to support additional aux iliary loads
beyond m y protection control system s in a generation station. Is ohm ic
m easurem ent testing sufficient for m y needs?
While this standard is focused on addressing requirements for Protection Systems, if batteries
are used to service other load requirements beyond that of Protection Systems (e.g. pumps,
valves, inverter loads), the functional entity may consider additional testing to confirm that the
capacity of the battery is sufficient to support all loads.
W hy verify voltage?
There are two required maintenance activities associated with verification of dc voltages in
Table 1-4. These two required activities are to verify station dc supply voltage and float voltage
of the battery charger, and have different maximum maintenance intervals. Both of these
voltage verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove
that the charger has not been lost or is not malfunctioning; a reading taken from the battery
charger panel meter or even SCADA values of the dc voltage could be some of the ways that
one could satisfy the requirements. Low battery voltage below float voltage indicates that the
battery may be on discharge and, if not corrected, the station battery could discharge down to
some extremely low value that will not operate the Protection System. High voltage, close to or
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above the maximum allowable dc voltage for equipment connected to the station dc supply
indicates the battery charger may be malfunctioning by producing high dc voltage levels on the
Protection System. If corrective actions are not taken to bring the high voltage down, the dc
power supplies and other electronic devices connected to the station dc supply may be
damaged. The maintenance activity of verifying the float voltage of the battery charger is not
to prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits. As
above, there are many ways that this requirement can be met.
W hy check for the electrolyte level?
In vented lead-acid (VLA) and nickel-cadmium (NiCad) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1-4. Because
the electrolyte level in valve-regulated lead-acid (VRLA) batteries cannot be observed, there is
no maintenance activity listed in Table 1-4 of the standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCad station battery is a condition requiring
correction. Typically, the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCad) by adding distilled or other approved-quality water to the
cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to
check the electrolyte level. In many of the modern station batteries, the jar containing the
electrolyte is so large with the band between the high and low electrolyte level so wide that
normal evaporation which would require periodic watering of all cells takes several years to
occur. However, because loss of electrolyte due to cracks in the jar, overcharging of the station
battery, or other unforeseen events can cause rapid loss of electrolyte; the shorter maximum
maintenance intervals for checking the electrolyte level are required. A low level of electrolyte
in a VLA battery cell which exposes the tops of the plates can cause the exposed portion of the
plates to accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
W hat are the param eters that can be evaluated in Tables 1-4(a) and 1-4(b)?
The most common parameter that is periodically trended and evaluated by industry today to
verify that the station battery can perform as manufactured is internal ohmic cell/unit
measurements.
In the mid 1990s, several large and small utilities began developing maintenance and testing
programs for Protection System station batteries using a condition based maintenance
approach of trending internal ohmic measurements to each station battery cell’s baseline
value. Battery owners use the data collected from this maintenance activity to determine (1)
when a station battery requires a capacity test (instead of performing a capacity test on a
predetermined, prescribed interval), (2) when an individual cell or battery unit should be
replaced, or (3) based on the analysis of the trended data, if the station battery should be
replaced without performing a capacity test.
Other examples of measurable parameters that can be periodically trended and evaluated for
lead acid batteries are cell voltage, float current, connection resistance. However, periodically
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trending and evaluating cell/unit Ohmic measurements are the most common battery/cell
parameters that are evaluated by industry to verify a lead acid battery string can perform as
manufactured.
W hy does it appear that there are tw o m aintenance activities in Table 1-4(b) (for
VR LA batteries) that appear to be the sam e activity and have the sam e m ax im um
m aintenance interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for valve-regulated lead-acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1-4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health
of the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for vented lead-acid (VLA) due to some unique failure modes for VRLA batteries. Some
of the potential problems that VRLA batteries are susceptible to that do not affect VLA batteries
are thermal runaway, cell dry-out, and cell reversal when one cell has a very low capacity.
The other similar activity listed in Table 1-4(b) is “…verify that the station battery can perform
as manufactured by evaluating the measured cell/unit measurements indicative of battery
performance (e.g internal ohmic values) against the station battery baseline.” This activity
allows an owner the option to choose between this activity with its much shorter maximum
maintenance interval or the longer maximum maintenance interval for the maintenance activity
to “Verify that the station battery can perform as manufactured by conducting a performance
or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. Trending against the baseline of VRLA cells in a battery string is
essential to determine the approximate state of health of the battery. Ohmic measurement
testing may be used as the mechanism for measuring the battery cells. If all the cells in the
string exhibit a consistent trend line and that trend line has not risen above a specific deviation
(e.g. 30%) over baseline for impedance tests or below baseline for conductance tests, then a
judgment can be made that the battery is still in a reasonably good state of health and able to
‘perform as manufactured.’ It is essential that the specific deviation mentioned above is based
on data (test or otherwise) that correlates the ohmic readings for a specific battery/tester
combination to the health of the battery. This is the intent of the “perform as manufactured
six-month test” at Row 4 on Table 1-4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1-4b. In order to detect a cell in thermal runaway,
you need not necessarily have a formal trending program. When a single cell/unit changes
significantly or significantly varies from the other cells (e.g. a doubling of resistance/impedance
or a 50% decrease in conductance), there is a high probability that the cell/unit/string needs to
be replaced as soon as possible. In other words, if the battery is 10 years old and all the cells
have approached a significant change in ohmic values over baseline, then you have a battery
which is approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the battery is five
years old and you have one cell that has a markedly different ohmic reading than all the other
cells, then you need to be worried that this cell is susceptible to thermal runaway. If the float
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(charging) current has risen significantly and the ohmic measurement has increased/decreased
as described above then concern of catastrophic failure should trigger attention for corrective
action.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this
does not eliminate the need to be concerned about thermal runaway – the entity still needs to
do the six-month readings and look for cells which are outliers in the string but they need not
trend results against the factory/as new baseline. Some entities will not mind the extra
administrative burden of having the ongoing trending program against baseline - others would
rather just do the capacity test and not have to trend the data against baseline. Nonetheless,
all entities must look for ohmic outliers on a six-month basis.
It is possible to accomplish both tasks listed (trend testing for capability and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of
watching the trend from baselines and watching for the oblique cell measurement.
In table 1-4(f) (Exclusions for Protection System Station dc Supply M onitoring
Devices and System s), m ust all com ponent attributes listed in the table be m et
before an ex clusion can be granted for a m aintenance activity?
Table 1-4(f) was created by the drafting team to allow Protection System dc supply owners to
obtain exclusions from periodic maintenance activities by using monitoring devices. The basis
of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous selfmonitoring. For failure of the microprocessor device used in dc supply monitoring, the self
checking routine in the microprocessor must generate an alarm which will be reported within
24 hours of device failure to a location where corrective action can be initiated.
Table 1-4(f) lists 8 component attributes along with a specific periodic maintenance activity
associated with each of the 8 attributes listed. If an owner of a station dc supply wants to be
excluded from periodically performing one of the 8 maintenance activities listed in table 1-4(f),
the owner must have evidence that the monitoring and alarming component attributes
associated with the excluded maintenance activity are met by the self checking microprocessor
based device with the specific component attribute listed in the table 1-4(f).
For example if an owner of a VLA station battery does not want to “verify station dc supply
voltage” every “4 calendar months” (see table 1-4(a)), the owner can install a monitoring and
alarming device “with high and low voltage monitoring and alarming of the battery charger
voltage to detect charger overvoltage and charger failure” and “no periodic verification of
station dc supply voltage is required” (see table 1-4(f) first row). However, if for the same
Protection System discussed above, the owner does not install “electrolyte level monitoring
and alarming in every cell” and “unintentional dc ground monitoring and alarming” (see second
and third rows of table 1-4(f)), the owner will have to “inspect electrolyte level and for
unintentional grounds” every “4 calendar months” (see table 1-4(a)).
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications-assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested. Besides the trip output and wiring to the trip coil(s), there is
also a communications medium that must be maintained. Newer technologies now exist that
achieve communications-assisted tripping without the conventional wiring practices of older
technology. For example, older technologies may have included Frequency Shift Key methods.
This technology requires that guard and trip levels be maintained. The actual tripping path(s) to
the trip coil(s) may be tested as a parallel trip path within the dc control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals. The requirements apply to the communicated signal
needed for the proper operation of the protective relay trip logic or scheme. Therefore, this
standard is applied to equipment used to convey both trip signals (permissive or direct) and
block signals.
It was the intent of this standard to require that a test be performed on any communicationsassisted trip scheme, regardless of the vintage of technology. The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit
interrupting devices.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
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15.5.1 Frequently Asked Questions:
W hat are som e exam ples of m echanism s to check com m unications equipm ent
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on-site integrity checking to be performed at least every four months
during a substation visit. Some examples are, but not limited to:
•
On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check-back test from one terminal.
•
Systems which use frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss-of-guard indication or alarm. For frequency-shift power-line carrier systems, the
guard signal level meter can also be checked.
•
Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
•
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms
that can be monitored remotely. Some examples are, but not limited to:
•
On-off power-line carrier systems can be shown to be operational by automated
periodic power-line carrier check-back tests with remote alarming of failures.
•
Systems which use a frequency-shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored
with a loss-of-guard alarm or low signal level alarm.
•
Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
•
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
•
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
•
In many communications systems signal quality measurements, including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
•
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
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W hat is needed for the four-m onth inspection of com m unications-assisted trip
schem e equipm ent?
The four-month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms; check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
Does a fiber optic I/ O schem e used for breaker tripping or control w ithin a station,
for ex am ple - transm itting a trip signal or control logic betw een the control house
and the breaker control cabinet, constitute a com m unications system ?
This equipment is presently classified as being part of the Protection System control circuitry
and tested per the portions of Table 1 applicable to “Protection System Control Circuitry”,
rather than those portions of the table applicable to communications equipment.
W hat is m eant by “Channel” and “Com m unications System s” in Table 1-2?
The transmission of logic or data from a relay in one station to a relay in another station for use
in a pilot relay scheme will require a communications system of some sort. Typical relay
communications systems use fiber optics, leased audio channels, power line carrier, and
microwave. The overall communications system includes the channel and the associated
communications equipment.
This standard refers to the “channel” as the medium between the transmitters and receivers in
the relay panels such as a leased audio or digital communications circuit, power line and power
line carrier auxiliary equipment, and fiber. The dividing line between the channel and the
associated communications equipment is different for each type of media.
Examples of the Channel:
•
Power Line Carrier (PLC) - The PLC channel starts and ends at the PLC transmitter and
receiver output unless there is an internal hybrid. The channel includes the external
hybrids, tuners, wave traps and the power line itself.
•
Microwave –The channel includes the microwave multiplexers, radios, antennae and
associated auxiliary equipment. The audio tone and digital transmitters and receivers in
the relay panel are the associated communications equipment.
•
Digital/Audio Circuit – The channel includes the equipment within and between the
substations. The associated communications equipment includes the relay panel
transmitters and receivers and the interface equipment in the relays.
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•
Fiber Optic – The channel starts at the fiber optic connectors on the fiber distribution
panel at the local station and goes to the fiber optic distribution panel at the remote
substation. The jumpers that connect the relaying equipment to the fiber distribution
panel and any optical-electrical signal format converters are the associated
communications equipment
Figure 1-2, A-1 and A-2 at the end of this document show good examples of the
communications channel and the associated communications equipment.
In Table 1-2, the M aintenance Activities section of the Protective System
Com m unications Equipm ent and Channels refers to the quality of the channel
m eeting “perform ance criteria.” W hat is m eant by perform ance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally,
an alarm will be indicated. For unmonitored systems, this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each Protection System
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following
are some examples of Protection System communications channel performance measuring:
•
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
•
An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a Fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check-back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes
this signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
•
Pilot wire relay systems use a hardwire communications circuit to communicate
between the local and remote ends of the protective zone. This circuit is monitored by
circulating a dc current between the relay systems. A typical level may be 1 mA. If the
level drops below the setting of the alarm monitor, the system will indicate an alarm.
•
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme
commonly used on transmission lines. The protective relays communicate current
magnitude and phase information over the communications path to determine if the
Fault is located in the protective zone. Quantities such as digital packet loss, bit error
rate and channel delay are monitored to determine the quality of the channel. These
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limits are determined and set during relay commissioning. Once set, any channel quality
problems that fall outside the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so Protection System channel monitoring
can be performed.
How is the perform ance criteria of Protection System com m unications equipm ent
involved in the m aintenance program ?
An entity determines the acceptable performance criteria, depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre-determined performance criteria for that system, then these results should be
investigated and resolved.
How do I verify the A/ D converters of m icroprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot, and, thus, make it easier to read
the Tables 1-1 through 1-5. The alarms need to arrive at a site wherein a corrective action can
be initiated. This could be a control room, operations center, etc. The alarming mechanism can
be a standard alarming system or an auto-polling system; the only requirement is that the
alarm be brought to the action-site within 24 hours. This effectively makes manned-stations
equivalent to monitored stations. The alarm of a monitored point (for example a monitored
trip path with a lamp) in a manned-station now makes that monitored point eligible for
monitored status. Obviously, these same rules apply to a non-manned-station, which is that if
the monitored point has an alarm that is auto-reported to the operations center (for example)
within 24 hours, then it too is considered monitored.
15.6.1 Frequently Asked Questions:
W hy are there activities defined for varying degrees of m onitoring a Protection
System com ponent w hen that level of technology m ay not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this
provision makes the standard technology neutral. The Standard Drafting Team wants to avoid
the need to revise the standard in a few years to accommodate technology advances that may
be coming to the industry.
Does a fail-safe “form b” contact that is alarm ed to a 24/ 7 operation center classify
as an alarm path w ith m onitoring?
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If the fail-safe “form-b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center, then this can be classified as an alarm path with monitoring.
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)
Distributed UFLS and distributed UVLS systems have their maintenance activities documented
in Table 3 due to their distributed nature allowing reduced maintenance activities and extended
maximum maintenance intervals. Relays have the same maintenance activities and intervals as
Table 1-1. Voltage and current-sensing devices have the same maintenance activity and
interval as Table 1-3. DC systems need only have their voltage read at the relay every 12 years.
Control circuits have the following maintenance activities every 12 years:
•
Verify the trip path between the relay and lock-out and/or auxiliary tripping device(s).
•
Verify operation of any lock-out and/or auxiliary tripping device(s) used in the trip
circuit.
•
No verification of trip path required between the lock-out (and/or auxiliary tripping
device) and the non-BES interrupting device.
•
No verification of trip path required between the relay and trip coil for circuits that have
no lock-out and/or auxiliary tripping device(s).
•
No verification of trip coil required.
No maintenance activity is required for associated communication systems for distributed UFLS
and distributed UVLS schemes.
Non-BES interrupting devices that participate in a distributed UFLS or distributed UVLS scheme
are excluded from the tripping requirement, and part of the control circuit test requirement;
however, the part of the trip path control circuitry between the Load-Shed relay and lock-out or
auxiliary tripping relay must be tested at least once every 12 years. In the case where there is
no lock-out or auxiliary tripping relay used in a distributed UFLS or UVLS scheme which is not
part of the BES, there is no control circuit test requirement. There are many circuit interrupting
devices in the distribution system that will be operating for any given under-frequency event
that requires tripping for that event. A failure in the tripping action of a single distributed
system circuit breaker (or non-BES equipment interruption device) will be far less significant
than, for example, any single transmission Protection System failure, such as a failure of a bus
differential lock-out relay. While many failures of these distributed system circuit breakers (or
non-BES equipment interruption device) could add up to be significant, it is also believed that
many circuit breakers are operated often on just Fault clearing duty; and, therefore, these
circuit breakers are operated at least as frequently as any requirements that appear in this
standard.
There are times when a Protection System component will be used on a BES device, as well as a
non-BES device, such as a battery bank that serves both a BES circuit breaker and a non-BES
interrupting device used for UFLS. In such a case, the battery bank (or other Protection System
component) will be subject to the Tables of the standard because it is used for the BES.
15.7.1 Frequently Asked Questions:
The standard reaches further into the distribution system than w e w ould like for
UFLS and UVLS
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While UFLS and UVLS equipment are located on the distribution network, their job is to protect
the Bulk Electric System. This is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines bulk power system as: “(A) facilities and control
Systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof).” That definition, then, is limited by a later statement which adds the term
bulk power system “…does not include facilities used in the local distribution of electric
energy.” Also, Section 215 also covers users, owners, and operators of bulk power Facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage
instability for BES reliability) are not “used in the local distribution of electric energy,” despite
their location on local distribution networks. Further, if UFLS/UVLS Facilities were not covered
by the reliability standards, then in order to protect the integrity of the BES during underfrequency or under-voltage events, that Load would have to be shed at the Transmission bus to
ensure the Load-generation balance and voltage stability is maintained on the BES.
1 5 .8 Examples of Evidence of Compliance
To comply with the requirements of this standard, an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team
recognizes that there are concurrent evidence requirements of other NERC standards that
could, at times, fulfill evidence requirements of this Standard.
15.8.1 Frequently Asked Questions:
W hat form s of evidence are acceptable?
Acceptable forms of evidence, as relevant for the requirement being documented include, but
are not limited to:
• Process documents or plans
• Data (such as relay settings sheets, photos, SCADA, and test records)
• Database lists, records and/or screen shots that demonstrate compliance information
• Prints, diagrams and/or schematics
• Maintenance records
• Logs (operator, substation, and other types of log)
• Inspection forms
• Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
• Check-off forms (paper or electronic)
• Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
If I replace a failed Protection System com ponent w ith another com ponent, w hat
testing do I need to perform on the new com ponent?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show com pliance for PR C-016 (“Special Protection System
M isoperation”). Can I also use it to show com pliance for this Standard, PR C-005-2?
PRC-005-2 Supplementary Reference and FAQ – October 2012
91
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus, the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC-016 could work for the activity tracking requirements
under this PRC-005-2.
I m aintain Disturbance records w hich show Protection System operations. Can I
use these records to show com pliance?
These records can be concurrently utilized as dc trip path verifications, to the degree that they
demonstrate the proper function of that dc trip path.
I m aintain test reports on som e of m y Protection System com ponents. Can I use
these test reports to show that I have verified a m aintenance activity?
Yes.
PRC-005-2 Supplementary Reference and FAQ – October 2012
92
Re fe re n ce s
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power Engineering
Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3
of Power System Relaying Committee of IEEE Power Engineering Society, December
2006.
7. “Proposed Statistical Performance Measures for Microprocessor-Based
Transmission-Line Protective Relays, Part I - Explanation of the Statistics, and Part II Collection and Uses of Data,” Working Group D5 of Power System Relaying
Committee of IEEE Power Engineering Society, May 1995; Papers 96WM 016-6
PWRD and 96WM 127-1 PWRD, 1996 IEEE Power Engineering Society Winter
Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
10. “Battery Performance Monitoring by Internal Ohmic Measurements” EPRI
Application Guidelines for Stationary Batteries TR- 108826 Final Report, December
1997.
11. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of ValveRegulated Lead-Acid (VRLA) Batteries for Stationary Applications,” IEEE Power
Engineering Society Std 1188 – 2005.
12. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead-Acid Batteries for Stationary Applications,” IEEE Power & Engineering Society
Std 45-2010.
13. “IEEE Recommended Practice for Installation design and Installation of Vented LeadAcid Batteries for Stationary Applications,” IEEE Std 484 – 2002.
14. “Stationary Battery Monitoring by Internal Ohmic Measurements,” EPRI Technical
Report, 1002925 Final Report, December 2002.
15. “Stationary Battery Guide: Design Application, and Maintenance” EPRI Revision 2 of
TR-100248, 1006757, August 2002.
PRC-005-2 Supplementary Reference and FAQ – October 2012
93
PSMT SDT References
16. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
17. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore,
2005
18. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
PRC-005-2 Supplementary Reference and FAQ – October 2012
94
Fig u re s
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC-005-2 Supplementary Reference and FAQ – October 2012
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Figure 2: Typical Generation System
Note: Figure 2 may show elements that are not included within PRC-005-2, and also
may not be all-inclusive; see the Applicability section of the standard for specifics.
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC-005-2 Supplementary Reference and FAQ – October 2012
96
Figure 1 & 2 Legend – components of Protection Systems
Number in
Figure
component of
Protection System
Includes
Excludes
Devices that use non-electrical
methods of operation including
thermal, pressure, gas accumulation,
and vibration. Any ancillary
equipment not specified in the
definition of Protection Systems.
Control and/or monitoring equipment
that is not a part of the automatic
tripping action of the Protection
System
1
Protective relays
which respond to
electrical quantities
All protective relays that use
current and/or voltage inputs
from current & voltage sensors
and that trip the 86, 94 or trip
coil.
2
Voltage and current
sensing devices
providing inputs to
protective relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that
are not a part of the Protection
System, including sync-check systems,
metering systems and data acquisition
systems.
Control circuitry
associated with
protective functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber-optic systems that
carry a trip signal as well as hardwired systems that carry trip
current.
Closing circuits, SCADA circuits, other
devices in control scheme not passing
trip current
4
Station dc supply
Batteries and battery chargers
and any control power system
which has the function of
supplying power to the
protective relays, associated trip
circuits and trip coils.
Any power supplies that are not used
to power protective relays or their
associated trip circuits and trip coils.
5
Communications
systems necessary
for correct operation
of protective
functions
Tele-protection equipment used
to convey specific information, in
the form of analog or digital
signals, necessary for the correct
operation of protective functions.
Any communications equipment that
is not used to convey information
necessary for the correct operation of
protective functions.
3
Additional information can be found in References
PRC-005-2 Supplementary Reference and FAQ – October 2012
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Ap p e n d ix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A-1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two-terminal pilot protection scheme to protect for line Faults, and to avoid overtripping for Faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report
the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of
other relays, meters, or DFRs. The other readings may be from redundant relaying or
measurement systems or they may be derived from values in other protection zones.
Comparison with other such readings to within required relaying accuracy verifies voltage &
current sensing devices, wiring, and analog signal input processing of the relays. One
effective way to do this is to utilize the relay metered values directly in SCADA, where they
can be compared with other references or state estimator values.
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98
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the Protection
System, so each carrier set has a connected or integrated automatic checkback test unit.
The automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation
or noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision have
been verified by internal monitoring. However, the trip circuit is actually energized by the
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contacts of a small telephone-type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a Fault.
3. The check-back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying
circuit or the carrier receiver output state. These connections include microprocessor I/O
ports, electronic driver circuits, wiring, and sometimes telephone-type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but
this does not confirm that the state change indication is correct when the breaker or switch
opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally-occurring Faults are
demonstrations of operation that reset the time interval clock for testing of each breaker
tripped in this way. If Faults do not occur, manual tripping of the breaker through the relay trip
output via data communications to the relay microprocessor meets the requirement for
periodic testing.
PRC-005 does not address breaker maintenance, and its Protection System test requirements
can be met by energizing the trip circuit in a test mode (breaker disconnected) through the
relay microprocessor. This can be done via a front-panel button command to the relay logic, or
application of a simulated Fault with a relay test set. However, utilities have found that
breakers often show problems during Protection System tests. It is recommended that
Protection System verification include periodic testing of the actual tripping of connected
circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring Faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
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Ap p e n d ix B
Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Al McMeekin
NERC
Merle Ashton
Tri-State G&T
Michael Palusso
Southern California Edison
Bob Bentert
Florida Power & Light Company
Mark Peterson
Great River Energy
Forrest Brock
Western Farmers Electric Cooperative
John Schecter
American Electric Power
Aaron Feathers
Pacific Gas and Electric Company
William D. Shultz
Southern Company Generation
Sam Francis
Oncor Electric Delivery
Eric A. Udren
Quanta Technology
Carol Gerou
Midwest Reliability Organization
Scott Vaughan
City of Roseville Electric Department
Russell C. Hardison
Tennessee Valley Authority
Matthew Westrich
American Transmission Company
David Harper
NRG Texas Maintenance Services
Philip B. Winston
Southern Company Transmission
James M. Kinney
FirstEnergy Corporation
David Youngblood
Luminant Power
Mark Lucas
ComEd
John A. Zipp
ITC Holdings
Kristina Marriott
ENOSERV
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101
Exhibit F
Technical Justification for Maintenance Intervals
Technical Basis for Maintenance Intervals in
Tables 1, 2, & 3 of PRC-005-2
General
The relay manufacturers bulletin recommendations on test intervals for legacy electromechanical
protective relays tended to run anywhere from 6 months to two years. Since these relays were made up
of moving parts and discrete components the manufacturers were conservative in their maintenance
recommendations; in lieu of performance based statistics. As utilities obtained maintenance performance
information, the test intervals expanded with the realization the components were reliable, and that
excessive maintenance can negatively affect reliability.
Most utilities developed their own maintenance practices based on the relay application/design, local
climate, experience with relay types, test equipment type, budgets and reliability experience. The entity
maintenance practices varied as each company had different factors influencing their intervals.
Through professional organizations and benchmarking involvement, utilities tried to incorporate best
practices while minimizing maintenance expenses. Papers and studies have been published over the
decades, identifying failure trends, maintenance practices, and maintenance intervals. Due to the wide
variations of the influencing factors it became difficult to come up with a standard test interval.
Protective relay application/design has a large influence on the test interval. The same relay used in a
different scheme at a different voltage may have a different test interval requirement. The setting
practices of the system protection group could also provide different requirements. Each entity’s
influencing factors would be different such that testing practices would vary, but would produce the
similar power system reliability.
An IEEE Power System Relay Committee report, “A Survey of Relaying Test Practices”, written by working
group 11 of the Power System Relay Committee of the IEEE in January 2002, did an excellent job of
identifying many of the influencing factors and reporting the different entity test intervals. In the 1991
version of the survey and report the average test interval for Electro-Mechanical (EM) Transmission relays
was around 2 years. When the survey was repeated in 2001, the average test intervals for EM
transmission relays had been extended to around three to five years. Non EM Transmission relays were
tested at a 2 year average in 1991 where in 2001 the average for non EM relays was 5 years. Of course
there were wide variations in test intervals depending on voltage and schemes. A PJM publication “PJM
RELAY SUBCOMMITTEE-RELAY TESTING AND MAINTENANCE PRACTICES” document published in August
2006 by the PEA Relay Subcommittee recommended a 4 year interval for EM relays.
Many entity Protection System maintenance programs have grace periods built into them so the
scheduled interval may be 4 years but allowances were given for workload and outage availability. It is
acceptable to allow a slightly longer interval, not to exceed grace periods, in these cases.
In the late 1980’s and early 1990’s the new digital (microprocessor based) relays initiated changes in
testing philosophies. The previous generations of electro-mechanical and solid state relays required
testing and calibration to determine relay health. Microprocessor relays have self check and monitoring
capabilities that alarm for relay failure. When properly monitored, this attribute significantly reduces the
level of physical involvement in determining the relays’ health.
Protection System Maintenance Standards
In the PRC-005-1 standard approved in 2007, utilities were required to provide a basis for their Protection
System test intervals in their Protective System Maintenance Plans (PSMP) and to provide evidence that
they met their PSMPs. Many entities built grace periods into their programs to allow for interval
extensions for extenuating circumstances.
The new version, PRC-005-2, provides minimum maintenance activities and maximum equipment test
intervals and a mechanism to use performance based maintenance to more conclusively adjust
maintenance intervals. Entity programs which contain grace periods cannot exceed the maximum
intervals in PRC-005-2.
The PRC-005-2 Standard Drafting Team based its maximum test interval recommendations for the various
classes of protective relays in the System Protection and Control Task Force (SPCTF) white paper
“Protection System Maintenance” dated September 13, 2007 and on the collective experience from the
entities on the drafting team. The SPCTF recommended a 5 year interval for BES unmonitored
electromechanical relays but allowed some grace periods for extenuating conditions. The PRC-005-2
drafting team modified the interval to 6 years to align with power plant outage scheduling without any
grace period. The maintenance intervals proposed by the PRC-005-2 drafting team are not significantly
different than industry averages when grace periods and outage scheduling are considered.
The drafting team incorporated the ability of new technologies to allow the industry to significantly
extend the maintenance intervals by utilizing the monitoring capability of microprocessor based
components. When proper monitoring is applied, the protective system maintenance personnel will be
notified immediately when a protective relay or instrument transformer fails. PRC005-2 allows a 12 year
interval on relays that are properly monitored since these devices will alarm for a failure when they have
a problem as opposed to unmonitored relays experiencing an unidentified failure. Advanced monitoring
techniques also allow other equipment intervals to be extended as detailed in the tables in the standard.
The entities will have to document the applied monitoring techniques to utilize the longer test intervals.
The drafting team believes that the application of new monitoring techniques (even with the longer test
intervals) will provide better reliability than strictly time-based intervals used in the past.
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Page 2 of 25
TBM Interval Feedback
PRC-005-2 allows the entity to choose an interval for the time-based maintenance program that will be
the best fit depending on the applicable influencing factors, and that will be less than the specified
maximums. Feedback to determine if these intervals and requirements are effective will be provided
through the analysis of the protective system Misoperations required in PRC-004. Investigations to
determine the cause of the Misoperation could indicate that relay maintenance program changes are
required.
The newly proposed PBM in appendix A of PRC-005-2 and in Requirement R2 will provide feedback to the
managers of the Protection System Maintenance Program on the effectiveness of the maintenance
intervals. It also provides a mechanism for adjusting the intervals if acceptable testing performance is not
achieved. This type of maintenance program should provide maximum protection system performance as
well as the most efficient use of resources.
The drafting team believes that the intervals provided in PRC-005-2 are in line with average industry
practices and will allow the industry to extend maintenance intervals using modern monitoring methods.
These intervals will also maximize the relay system performance providing acceptable BES reliability.
Condition Based Maintenance
In developing the maximum time intervals for PRC-005-2 the drafting team considered many influencing
factors. These included, but were not limited to:
1. The components of a Protection System
2. The common failure modes of the components of a Protection System
3. The many methods of detecting failures in Protection System components
4. The maintenance approaches in use by entities throughout North America
5. The need to proactively approach maintenance as opposed to running to failure and reacting
6. The need for minimizing manual hands-on activities
7. The need for maximizing complete Protection System integrity
8. A business need to coordinate maintenance activities with the biggest capital driver (generators)
9. A business need to have scheduling management abilities
10. Available technology
A review of legacy traditional proactive maintenance programs shows that time-based maintenance
(TBM) is simply not replaceable. However, PBM is nothing more than a TBM with the added responsibility
of statistical analysis to take advantage of potential time savings in the maintenance program. Another
modification of the TBM is the condition-based maintenance program.
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A condition-based maintenance (CBM) program consists of methods to constantly monitor the condition,
or health, of the protection system components and send an alarm to a central location where action can
be initiated. Personnel will be dispatched to make repairs as a result of the alarm. Condition-based
maintenance is a proactive approach for protection system maintenance. The drafting team included CBM
in PRC-005-2 to allow entities to take advantage of this type of maintenance methodology. Traditionally,
a device was known to be good only at the time of its last test. With CBM some devices are tested many
times in a second. Thus if a device was only good at the time of its last test and its last test was a second
ago then the condition of the device can be ascertained at any time. CBM maximizes testing, maximizes
complete Protection System integrity and minimizes outages caused by human performance errors.
Detailed Interval Discussions:
Table 1-1 (Protective Relays)
Component Attributes:
Any unmonitored protective relay not having all the monitoring attributes specified in Table 2
Maximum Maintenance Interval: 6 calendar years
Maintenance Activity: For all unmonitored relays:
• Verify that settings are as specified
For non-microprocessor relays:
• Test and, if necessary calibrate
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System.
• Verify acceptable measurement of power system input values.
The 6 calendar year activities are a “Cal-Check” of the various legacy or unmonitored microprocessorbased relays (and repair as needed). The microprocessor based equipment requires little or no
maintenance. The maintenance activities require that the failure modes be checked on the equipment;
this is stated in such a manner as to capture all varieties of equipment presently in use. While some
equipment will require test equipment to manage the activities, other equipment can be routinely
verified, without the traditional relay testing equipment. The 6 year interval was determined from the
need for routine performance testing (in the absence of monitoring). 5 years was chosen as a starting
point as outlined in the SPCTF White Paper. The interval chosen for the standard, by mandate, has to be
an absolute measurable limit thus no “grace periods” are allowed within the standard itself. For
scheduling management, unforeseen events, natural disasters and no grace periods a final interval of 6
calendar years was chosen. 6 years also works well as a base interval when coordinating with any
individual registered generator as there may be generator outage schedules that approach but do not
exceed 6 years. Any relay scheme that exists within a generator should then be able to be tested with the
outage schedule.
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The activities prescribed for non-microprocessor based relays are, essentially, calibrating which is a
common practice of protective relay owners.
The activities prescribed for unmonitored microprocessor relays are a verification of settings and verify
the inputs and outputs of the relays; note that the settings verification of legacy relays is inherent in the
calibration activity.
Component Attributes:
Monitored microprocessor protective relay with the following:
•
Internal self-diagnosis and alarming (see Table 2).
•
Voltage and/or current waveform sampling three or more times per power cycle, and conversion of
samples to numeric values for measurement calculations by microprocessor electronics.
•
Alarming for power supply failure (see Table 2).
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify:
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to proper functioning of
the Protection System.
• Acceptable measurement of power system input values.
Relay equipment with these attributes provides condition-based maintenance on many of the sections of
the device. The 12 calendar year activities are to ensure that the device conveys the alarm from its origin
to the location where corrective action can be initiated; that the power system input values are correctly
measured by the relay and that the needed inputs and outputs are still functional. The maintenance
activities are focused on the necessary tests that are not otherwise covered with internal self-diagnostics.
Aside from the components that do not have internal self-diagnostics, this technology utilizes condition
based maintenance (CBM) principles on many of its components. CBM maximizes testing, maximizes
complete Protection System integrity and minimizes outages caused by human performance errors.
Component Attributes:
Monitored microprocessor protective relay with preceding row attributes and the following:
•
Ac measurements are continuously verified by comparison to an independent ac measurement
source, with alarming for excessive error (See Table 2).
•
Some or all binary or status inputs and control outputs are monitored by a process that continuously
demonstrates ability to perform as designed, with alarming for failure (See Table 2).
•
Alarming for change of settings (See Table 2).
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Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify only the unmonitored relay inputs and outputs that are essential to proper
functioning of the Protection System.
This Maintenance Activity includes verification that the device conveys the alarm from its origin to the
location where corrective action can be initiated. This equipment is configured to verify the sections of
the relay that measure the power system values. This equipment routinely verifies all equipment through
CBM except the inputs and outputs.
Table 1-2 (Communications Systems)
Component Attributes:
Any unmonitored communications system necessary for correct operation of protective functions, and
not having all the monitoring attributes of a category below.
Maximum Maintenance Interval: 4 calendar months
Maintenance Activity: Verify that the communications system is functional.
The interval of 4 calendar months was determined from the need for routine station visits (in the absence
of monitoring). The interval, by mandate, has to be an absolute measurable limit thus no “grace periods”
are allowed within the standard itself. In the standards development process, it was determined that
quarterly intervals for station visits were the predominant practice. To allow for flexibility of scheduling,
unforeseen events, natural disasters and no grace periods a final interval of 4 calendar months was
chosen.
Maximum Maintenance Interval: 6 calendar years
Maintenance Activity Verify
• That the communication system meets performance criteria pertinent to the
communications technology applied (e.g. signal level, reflected power, or data error
rate).
• Operation of communication system inputs and outputs that are essential to proper
functioning of the Protection System.
The 6 calendar year activities are a “Cal-Check” of the various systems (and repair as needed). This solidstate and/or microprocessor based equipment requires little or no maintenance. The maintenance
activities require that the failure mode be checked on the equipment; this is stated in such a manner as to
capture all varieties of equipment presently in use. While some equipment will require test equipment to
manage the activities, other equipment can be routinely verified, without the traditional RF test
equipment. With solid-state performance in Protection System equipment there is no indication by
manufacturer or drafting team SME experience that shorter intervals (1-3 years) are required. The 6 year
interval was determined from the need for routine performance testing (in the absence of monitoring). 5
years was chosen as a starting point to stay in line with similar technology in protective relays and the
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starting point as outlined in the SPCTF White Paper. A noticeable inclusion is that the original SPCTF
acknowledged that systems and emergent events routinely require that “grace periods” should be
allowed. The interval chosen for the standard, by mandate, has to be an absolute measurable limit thus
no “grace periods” are allowed within the standard itself. For scheduling management, unforeseen
events, natural disasters and no grace periods a final interval of 6 calendar years was chosen. 6 years also
works well as a base interval when coordinating with any individual registered generator as there may be
generator outage schedules that approach but do not exceed 6 years. Any comm.-assisted trip scheme
that exists within a generator should then be able to be tested with the outage schedule.
Component Attributes:
Any communications system with continuous monitoring or periodic automated testing for the presence
of the channel function, and alarming for loss of function (See Table 2).
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify
• That the communication system meets performance criteria pertinent to the
communications technology applied (e.g. signal level, reflected power, or data error
rate).
• Operation of communication system inputs and outputs that are essential to proper
functioning of the Protection System.
The 12 calendar year activity is to ensure that the monitoring device conveys the alarm from its origin to
the location where corrective action can be initiated. Since this technology is the same technology
utilized for microprocessor based relays, then all of the efficiencies realized apply to this equipment as
well. CBM maximizes testing, maximizes complete Protection System integrity and minimizes outages
caused by human performance errors.
Component Attributes:
Any communications system with all of the following:
•
Continuous monitoring or periodic automated testing for the performance of the channel using
criteria pertinent to the communications technology applied (e.g. signal level, reflected power, or data
error rate, and alarming for excessive performance degradation). (See Table 2)
•
Some or all binary or status inputs and control outputs are monitored by a process that continuously
demonstrates ability to perform as designed, with alarming for failure (See Table 2).
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify only the unmonitored communications system inputs and outputs that are
essential to proper functioning of the Protection System
The 12 calendar year activity is to ensure that the monitoring device conveys the alarm from its origin to
the location where corrective action can be initiated. Since this technology is the same technology
utilized for microprocessor based relays, then all of the efficiencies realized apply to this equipment as
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well. CBM maximizes testing, maximizes complete Protection System integrity and minimizes outages
caused by human performance errors.
Table 1-3 (Voltage and Current Sensing Devices)
Component Attributes:
Any voltage and current sensing devices not having monitoring attributes of the category below.
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify that current and voltage signal values are provided to the protective relays.
The 12 calendar year activities are measurement activities (and repair as needed) and in many cases can
be eliminated by advanced comparison techniques, software and communications.
The time interval is chosen specifically to coincide with every other test of an unmonitored relay and
every test of a monitored relay.
The activity specified implicitly verifies more than voltages, currents and ratios as there is more to the
circuit than just the instrument transformer (or other voltage and current sensing device). The expected
product life cycle of wound voltage and current transformers is known to be far in excess of 40 years, well
above the specified time interval. The verification of the values provided to the protective relays also
brings wiring into the verification process. While there are product degradation failure modes that occur
in cabling and wiring, it is a well-known phenomenon that most cable degradation occurs because of high
voltage stress. High voltage-stressed, direct-buried cable is typically expected to last at least 15 years. The
cables and wires used in these Protection System applications are not stressed with high voltage.
Following prudent installation techniques, associated protection system cabling and wiring life expectancy
is known to be far in excess of 40-50 years.
The activity performed at every-other unmonitored relay calibration is intended to recur much more
often than any predicted cable degradation problem while at the same time this interval will minimize
human interaction with the voltage and current sources. The history of Protection System maintenance
has found that minimizing human interaction will minimize mistakes that manifest themselves as
inadvertent trips and otherwise broken equipment. Shock hazards from voltage and current sources are a
large concern of the industry and are also minimized with the purposeful approach used with the applied
maximum time interval between breaking into the voltage and current paths.
The activity, when used with a monitored relay test, can be extremely useful in a rapid diagnosis of the
complete Protection System package. A state of the art microprocessor relay can produce an output of
the status of the relay, the battery bank float voltage, the continuity of the trip path through the trip coil,
the status of any connected comm.-assisted trip equipment and a display of the values of voltage and
current provided to the relay.
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A properly applied microprocessor relay within a substation might have a display of volts, amps, phase
angles, Watts, VARs, Volt-Amps as well as other programmed output values. All of the programmed
output values can be utilized as possible troubleshooting tools.
As the industry is moving towards a BES with a very high percentage of microprocessor relays this
advanced functionality will be widespread.
The maximum time interval requirement of PRC-005-2 is measurable because there are no grace periods
allowed. It becomes a de-facto time interval of less than 12 years simply because an entity will have to
guarantee that the 12 years is not exceeded. Therefore the activity will be scheduled and completed
before the time interval has run its course.
Thus the time interval works well with the base of 6 years; the work can be coordinated with typical
generator outage schedules; it is less than the expected product degradation of the devices encompassed
within the activity; it reduces human interaction which can negatively affect reliability through conductor
manipulation, and the time interval has been set at a level that will still allow scheduling management
even in the event of such things as natural disasters that can take substantial resources (and time) from
which to recover.
Component Attribute:
Voltage and Current Sensing devices connected to microprocessor relays with AC measurements are
continuously verified by comparison of sensing input value as measured by the microprocessor relay to an
independent ac measurement source, with alarming for unacceptable error or failure.
Maximum Maintenance Interval: No periodic maintenance specified
Maintenance Activity: None
This activity and time interval are specified only in the event that an automated system has been
instituted; furthermore that system must be able to alarm if the “alarming” system failed (fail-safe). There
are “check-sum” systems available and already operational in the field. These systems, when coupled with
comparison software, calculations or algorithms can perform all of the comparison techniques outlined
previously and alarm when a circuit falls out of tolerance. Since such comparisons are automated, the
calculations can occur many times per minute. Therefore, as with any “condition-based” system, there is
actually far more maintenance activities being performed in any given day than typically performed in a
time-based program. The circuit is more secure and there is never a need for human interaction until the
alarm comes in; at which time repairs can be initiated – further reducing human interaction which can
negatively affect reliability through conductor manipulation.
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Table 1-4(a) (VLA Batteries)
Component Attribute:
Protection System Station dc supply using Vented Lead-Acid (VLA) batteries not having monitoring
attributes of Table 1-4(f) (Table 1-4(a)).
Maximum Maintenance Interval: 4 calendar months
Maintenance Activity: Verify
• Station dc supply voltage
Inspect
• Electrolyte level
• For unintentional grounds
The interval of 4 calendar months was determined from the need for routine station visits (in the absence
of monitoring). The interval, by mandate, has to be an absolute measurable limit thus no “grace periods”
are allowed within the standard itself. In the standards development process, it was determined that
quarterly intervals for station visits were the predominant practice for these maintenance activities. To
allow for flexibility of scheduling, unforeseen events, natural disasters and no grace periods a final interval
of 4 calendar months was chosen.
Maximum Maintenance Interval: 18 Calendar Months
Maintenance Activity: Verify
• Float voltage of battery charger.
• Battery continuity.
• Battery terminal connection resistance.
• Battery intercell or unit-to-unit connection resistance.
• That the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance (e.g. internal ohmic values or float
current) against the station battery baseline.
Inspect
• Cell condition of all individual battery cells where cells are visible – or measure
battery cell/unit internal ohmic values where the cells are not visible.
• Physical condition of battery rack.
The interval of 18 calendar months was determined from the need for scheduled annual station visits for
VLA battery maintenance (in the absence of monitoring). The interval, by mandate, has to be an absolute
measurable limit thus no “grace periods” are allowed within the standard itself.
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These “annual” inspections and verifications are listed in the IEEE recommended practice for VLA
batteries (IEEE 450). To allow for flexibility of scheduling, unforeseen events, natural disasters and no
grace periods a final interval of 18 calendar months was chosen.
Maximum Maintenance Interval: 6 calendar years
Maintenance Activity: Verify that the station battery can perform as manufactured by conducting a
performance or modified performance capacity test of the entire battery bank.
The interval of 6 calendar years was determined from the need for scheduled performance or modified
performance capacity testing at 25% of the expected battery life listed in the IEEE recommended practice
for VLA batteries (IEEE 450). 5 years is the predominant industry interval for this practice. The interval, by
mandate, has to be an absolute measurable limit thus no “grace periods” are allowed within the standard
itself. To allow for flexibility of scheduling, unforeseen events, natural disasters and no grace periods a
final interval of 6 calendar years was chosen.
Table 1-4(b) (VRLA Batteries)
Component Attribute:
Protection System Station dc supply with Valve Regulated Lead-Acid (VRLA) batteries not having
monitoring attributes of Table 1-4(f).
Maximum Maintenance Interval: 4 calendar months
Maintenance Activity: Verify
• Station dc supply voltage
Inspect
• For unintentional grounds
The interval of 4 calendar months was determined from the need for routine station visits (in the absence
of monitoring). The interval, by mandate, has to be an absolute measurable limit thus no “grace periods”
are allowed within the standard itself. In the standards development process, it was determined that
quarterly intervals for station visits were the predominant practice for these maintenance activities. To
allow for flexibility of scheduling, unforeseen events, natural disasters and no grace periods a final interval
of 4 calendar months was chosen.
Maximum Maintenance Interval: 6 calendar months
Maintenance Activity: Inspect
• Condition of all individual units by measuring battery cell/unit internal ohmic values.
Verify
• That the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance (e.g. internal ohmic values or float
current) against the station battery baseline
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The interval of 6 calendar months was determined from the need for scheduled quarterly station visits for
VRLA battery maintenance (in the absence of monitoring). The interval, by mandate, has to be an
absolute measurable limit thus no “grace periods” are allowed within the standard itself. This “quarterly”
inspection and verification is listed in the IEEE recommended practice for VRLA batteries (IEEE 1188). To
allow for flexibility of scheduling, unforeseen events, natural disasters and no grace periods a final interval
of 6 calendar months was chosen.
Maximum Maintenance Interval: 18 calendar months
Maintenance Activity: Verify
• Float voltage of battery charger.
• Verify Battery continuity.
• Verify Battery terminal connection resistance.
• Verify Battery intercell or unit-to-unit connection resistance.
Inspect
• Physical condition of battery rack.
The interval of 18 calendar months was determined from the need for scheduled annual station visits for
VRLA battery maintenance (in the absence of monitoring). The interval, by mandate, has to be an absolute
measurable limit thus no “grace periods” are allowed within the standard itself.
These “annual” inspections and verifications are listed in the IEEE recommended practice for VRLA
batteries (IEEE 1188). To allow for flexibility of scheduling, unforeseen events, natural disasters and no
grace periods a final interval of 18 calendar months was chosen.
Maximum Maintenance Interval: 3 calendar years
Maintenance Activity: Verify that the station battery can perform as manufactured by conducting a
performance or modified performance capacity test of the entire battery bank.
The interval of 3 calendar years was determined from the need for the “two years” performance or
modified performance capacity testing schedule listed in the IEEE recommended practice for VRLA
batteries (IEEE 1188). The interval, by mandate, has to be an absolute measurable limit thus no “grace
periods” are allowed within the standard itself. To allow for flexibility of scheduling, unforeseen events,
natural disasters and no grace periods a final interval of 3 calendar years was chosen.
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Table 1-4(c) (NiCad Batteries)
Component Attribute:
Protection System Station dc supply Nickel-Cadmium (NiCad) batteries not having monitoring attributes of
Table 1-4(f) (Table 1-4(c)).
Maximum Maintenance Interval: 4 calendar months
Maintenance Activity: Verify
• Station dc supply voltage
Inspect
• Electrolyte level
• For unintentional grounds
The interval of 4 calendar months was determined from the need for routine station visits (in the absence
of monitoring). The interval, by mandate, has to be an absolute measurable limit thus no “grace periods”
are allowed within the standard itself. In the standards development process, it was determined that
quarterly intervals for station visits were the predominant practice for these maintenance activities. To
allow for flexibility of scheduling, unforeseen events, natural disasters and no grace periods a final interval
of 4 calendar months was chosen.
Maximum Maintenance Interval: 18 calendar months
Maintenance Activity: Verify
• Float voltage of battery charger.
• Battery continuity.
• Battery terminal connection resistance.
• Battery intercell or unit-to-unit connection resistance.
Inspect
• Cell condition of all individual battery cells.
• Inspect Physical condition of battery rack.
The interval of 18 calendar months was determined from the need for scheduled annual station visits for
NiCad battery maintenance (in the absence of monitoring). The interval, by mandate, has to be an
absolute measurable limit thus no “grace periods” are allowed within the standard itself. These “annual”
inspections and verifications are listed in the IEEE recommended practice for NiCad batteries (IEEE 1106).
To allow for flexibility of scheduling, unforeseen events, natural disasters and no grace periods a final
interval of 18 calendar months was chosen.
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Maximum Maintenance Interval: 6 calendar years
Maintenance Activity: Verify that the station battery can perform as manufactured by conducting a
performance or modified performance capacity test of the entire battery bank.
The interval of 6 calendar years was determined from the need for the “five-year” performance or
modified performance capacity testing schedule listed in the IEEE recommended practice for NiCad
batteries (IEEE 1106). The interval, by mandate, has to be an absolute measurable limit thus no “grace
periods” are allowed within the standard itself. To allow for flexibility of scheduling, unforeseen events,
natural disasters and no grace periods a final interval of 6 calendar years was chosen.
Table 1-4(d) (Non Battery Based Energy Storage)
Component Attribute:
Any Protection System station dc supply not using a battery and not having monitoring attributes of Table
1-4(f).
Maximum Maintenance Interval: 4 calendar months
Maintenance Activity: Verify
• Station dc supply voltage
Inspect
• For unintentional grounds
The interval of 4 calendar months was determined from the need for routine station visits (in the absence
of monitoring). The interval, by mandate, has to be an absolute measurable limit thus no “grace periods”
are allowed within the standard itself. In the standards development process, it was determined that
quarterly intervals for station visits were the predominant practice for these maintenance activities. To
allow for flexibility of scheduling, unforeseen events, natural disasters and no grace periods a final interval
of 4 calendar months was chosen.
Maximum Maintenance Interval: 18 calendar months
Maintenance Activity: Inspect condition of non-battery based dc supply.
The interval of 18 calendar months was determined from the need for a scheduled annual station visits to
determine the condition of the non-battery based energy storage device used in the station dc supply (in
the absence of monitoring). The interval, by mandate, has to be an absolute measurable limit thus no
“grace periods” are allowed within the standard itself. To allow for flexibility of scheduling, unforeseen
events, natural disasters and no grace periods a final interval of 18 calendar months was chosen.
Maximum Maintenance Interval: 6 calendar years
Maintenance Activity: Verify that the dc supply can perform as manufactured when ac power is not
present.
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The interval of 6 calendar years was determined from the need for a scheduled maintenance interval of
the stored energy part of a dc supply that does not use a battery. A 5 year interval was suggested by
industry to match the VLA battery interval. The interval, by mandate, has to be an absolute measurable
limit thus no “grace periods” are allowed within the standard itself. To allow for flexibility of scheduling,
unforeseen events, natural disasters and no grace periods a final interval of 6 calendar years was chosen.
Table 1-4(e) (SPS, UFLS and UVLS Batteries for non-BES Interrupting Devices)
Component Attribute:
Any Protection System dc supply used for tripping only non-BES interrupting devices as part of a SPS, nondistributed UFLS, or non-distributed UVLS system and not having monitoring attributes of Table 1-4(f).
Maximum Maintenance Interval: When control circuits are verified (See Table 1-5)
Maintenance Activity: Verify Station dc supply voltage.
The maintenance interval for this maintenance activity (verifying that there is dc supply voltage) is due to
the distributed nature of these components and has also been chosen specifically to coincide with
maintenance activities 12 calendar years maximum maintenance interval for monitored microprocessor
protective relays, voltage and/or current sensing devices, control circuitry, and electromechanical lockout
and/or tripping auxiliary devices listed in table 3 (Maintenance Activities and Intervals for distributed UFLS
and distributed UVLS Systems). Failure of a single component does not have significant impact to the BES
to warrant further maintenance activities for the dc supply. These components are routinely operated in
normal operations and maintenance activities for distribution systems and as such it is only required to
verify that voltage is present when the control circuits are verified.
Table 1-4(f) (Exclusions for Protection System station dc supply monitoring devices and
systems)
Table 1-4(f) was created by the drafting team to allow Protection System dc supply owners to obtain
exclusions from periodic maintenance activities by using monitoring devices. The basis of the exclusions
granted in the table is that the monitoring devices must incorporate the monitoring capability of
microprocessor based components which perform continuous self-monitoring. For failure of the
microprocessor device used in dc supply monitoring, the self checking routine in the microprocessor must
generate an alarm which will be reported within 24 hours of device failure to a location where corrective
action can be initiated.
Table 1-4(f) lists 8 component attributes along with a specific periodic maintenance activity associated
with each of the 8 attributes listed. If an owner of a station dc supply wants to be excluded from
periodically performing one of the 8 maintenance activities listed in table 1-4(f), the owner must have
evidence that the monitoring and alarming component attributes associated with the excluded
maintenance activity are met by the self checking microprocessor based device with the specific
component attribute listed in the table 1-4(f).
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By taking advantage of the exclusions offered in table 1-4(f) a Protection System owner can establish a
proactive condition-based maintenance (CBM) program for most of the maintenance activities listed for
station batteries and chargers used in his Protection System dc supplies.
Table 1-5 (Control Circuitry Associated With Protective Functions)
Component Attribute:
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating devices (regardless of any
monitoring of the control circuitry)
Maximum Maintenance Interval: 6 calendar years
Maintenance Activity: Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device.
The interval of 6 calendar years to determine that each trip coil can operate the circuit breaker,
interrupting device or mitigating device is based on the requirement to electrically operate the
mechanism. This requirement is in place because some of these devices share attributes and failure
modes of electromechanical relays. Many mechanical devices sometimes need to be exercised to ensure
that the mechanism will be ready when called upon to operate. Industry anecdotal evidence has
demonstrated that, even though some manufacturers’ products have very low failure rates, there are
others still in use that have known failure modes and are sometimes involved in notable failure events.
Until such time as the poor quality, legacy equipment is gone from the installed Protection Systems, it is
believed there will continue to be failure of some of these products.
This 6 calendar years time interval was chosen to be at the base interval with the unmonitored relays,
includes sufficient time within the interval to account for scheduling management needs, but has no
allowed grace period and is therefore measurable.
Component Attribute:
Electromechanical lockout devices which are directly in a trip path from the protective relay to the
interrupting device trip coil (regardless of any monitoring of the control circuitry).
Maximum Maintenance Interval: 6 calendar years
Maintenance Activity: Verify electrical operation of electromechanical lockout devices.
The interval of 6 calendar years to determine electrical operation of electromechanical lockout devices is
based on the requirement to electrically operate the mechanism. This requirement is in place because
some of these devices share attributes and failure modes of electromechanical relays. Many mechanical
devices sometimes need to be exercised to ensure that the mechanism will be ready when called upon to
operate. Industry anecdotal evidence has demonstrated that, even though some manufacturers’
products have very low failure rates, there are others still in use that have known failure modes and are
sometimes involved in notable failure events. Until such time as the poor quality, legacy equipment is
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gone from the installed Protection Systems, it is believed there will continue to be failure of some of these
products.
This 6 calendar years time interval was chosen to be at the base interval with the unmonitored relays,
includes sufficient time within the interval to account for scheduling management needs, but has no
allowed grace period and is therefore measurable.
Component Attribute:
Unmonitored control circuitry associated with SPS.
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity Verify all paths of the control circuits essential for proper operation of the SPS.
The interval of 12 calendar years to confirm all paths of control circuits essential for operation of a SPS is
based on the assertion that while there are product degradation failure modes that occur in control
cabling and panel and circuit breaker wiring, it is a well-known phenomenon that most cable degradation
occurs because of high voltage stress. High voltage-stressed, direct-buried cable is typically expected to
last at least 15 years. The cables and wires used in these Protection System applications are not stressed
with high voltage. Following prudent installation techniques, associated protection system cabling and
wiring life expectancy is known to be far in excess of 40-50 years. The activity performed at every-other
unmonitored relay calibration is intended to recur much more often than any predicted panel wiring and
control cable degradation problem while at the same time minimize human interaction with the trip
voltages present. The history of Protection System maintenance has found that minimizing human
interaction will minimize mistakes that manifest themselves as inadvertent trips and otherwise broken
equipment. In many cases circuits can be removed from service to minimize technician-caused real-time
system trips. However, there are many cases where required testing on circuitry must take place on
circuits that cannot be removed from service; one case in point is a line stays in service but only one
circuit breaker of two on a ring can be taken out for testing. Many of the trip circuits remain active even
as a technician conducts the required testing. Additionally almost all aspects of Protection System control
circuitry is continuously monitored by the connected battery charger. Abnormal control circuitry
condition can be indentified through battery maintenance monitoring activities or alarming features
incorporated in battery chargers.
A balance must be reached between making tests upon circuitry to make a reliable system and testing so
often that technician-caused trips make the system unreliable. The drafting team believes that such a
balance can be found at this time interval, although there remain some that are concerned that auxiliary
tripping relays and lock-out relays may still be actuated too often (for tests) for the overall security of the
BES.
Auxiliary control relays that are not lock-out relays usually have less impact to the system for failure to
trip than a lock-out relay. Aux-relays are simpler in construction and share fewer failure modes than a
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legacy lock-out relay. The way that auxiliary control relays are typically wired into circuitry would, in many
cases, require de-terminating wires which increases the risk of human performance errors.
This 12 calendar years time interval includes sufficient time within the interval to account for scheduling
management needs beyond potential unforeseen events, but has no allowed grace period and is
therefore measurable. This time interval fits well with any known typical registered generation outage
schedule.
Component Attribute:
Unmonitored control circuitry associated with protective functions inclusive of all auxiliary relays.
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify all paths of the trip circuits inclusive of all auxiliary relays through the trip
coil(s) of the circuit breakers or other interrupting devices.
The interval of 12 calendar years to authenticate all paths of the trip circuits (including all auxiliary relays)
is based on the premise that while there are product degradation failure modes that occur in control
cabling and panel and circuit breaker wiring, it is a well-known phenomenon that most cable degradation
occurs because of high voltage stress. High voltage-stressed, direct-buried cable is typically expected to
last at least 15 years. The cables and wires used in these Protection System applications are not stressed
with high voltage. Following prudent installation techniques, associated protection system cabling and
wiring life expectancy is known to be far in excess of 40-50 years. The activity performed at every-other
unmonitored relay calibration is intended to recur much more often than any predicted panel wiring and
control cable degradation problem while at the same time minimize human interaction with the trip
voltages present. The history of Protection System maintenance has found that minimizing human
interaction will minimize mistakes that manifest themselves as inadvertent trips and otherwise broken
equipment. In many cases circuits can be removed from service to minimize technician-caused real-time
system trips. However, there are many cases where required testing on circuitry must take place on
circuits that cannot be removed from service; one case in point is a line stays in service but only one
circuit breaker of two on a ring can be taken out for testing. Many of the trip circuits remain active even
as a technician conducts the required testing. Additionally almost all aspects of Protection System control
circuitry is continuously monitored by the connected battery charger. Abnormal control circuitry
condition can be indentified through battery maintenance monitoring activities or alarming features
incorporated in battery chargers.
A balance must be reached between making tests upon circuitry to make a reliable system and testing so
often that technician-caused trips make the system unreliable. The drafting team believes that such a
balance can be found at this time interval, although there remain some that are concerned that auxiliary
tripping relays and lock-out relays may still be actuated too often (for tests) for the overall security of the
BES.
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Auxiliary control relays that are not lock-out relays usually have less impact to the system for failure to
trip than a lock-out relay. Aux-relays are simpler in construction and share fewer failure modes than a
legacy lock-out relay. The way that auxiliary control relays are typically wired into circuitry would, in many
cases, require de-terminating wires which increases the risk of human performance errors.
This 12 calendar years time interval includes sufficient time within the interval to account for scheduling
management needs beyond potential unforeseen events, but has no allowed grace period and is
therefore measurable. This time interval fits well with any known typical registered generation outage
schedule.
Component Attribute:
Control circuitry associated with protective functions and/or SPS whose integrity is monitored and
alarmed (See Table 2).
Maximum Maintenance Interval: No periodic maintenance specified
Maintenance Activity: None.
This activity is one that is simply monitoring the control circuitry that otherwise puts the BES at risk with
human interaction and inadvertent trips during the manual activity process. When the circuitry is
continuously monitored, the monitoring devices produce results comparable to hours of manual testing
without exposing the BES to an increased risk of human performance error and minimizing personnel
safety risks to various arc-flash hazards. Continuous monitoring of equipment results in an alarm as soon
as problems occur. Condition-based monitoring maximizes testing, maximizes complete Protection
System integrity and minimizes outages caused by human performance errors.
Table 2 (Alarming Paths and Monitoring)
Component Attribute:
Any alarm path through which alarms in Tables 1-1 through 1-5 and Table 3 are conveyed from the alarm
origin to the location where corrective action can be initiated, and not having all the attributes of the
“Alarm Path with monitoring” category below.
Alarms are reported within 24 hours of detection to a location where corrective action can be initiated.
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify that the alarm path conveys alarm signals to a location where corrective
action can be initiated.
The 12 calendar year activity is to ensure that the monitoring device conveys the alarm from its origin to
the location where corrective action can be initiated. The time interval is chosen specifically to coincide
with every test of a monitored relay, communication system with monitoring or periodic automated
testing, voltage and current sensing devices, and unmonitored control circuitry.
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Component Attribute:
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours for failure of any portion
of the alarming path from the alarm origin to the location where corrective action can be initiated.
Maximum Maintenance Interval: No periodic maintenance specified
Maintenance Activity: None.
No periodic maintenance is required because the communication path from the monitoring device to the
location where corrective action is initiated is monitored by a microprocessor system that is self-checking
and annunciates whenever any portion of the communication path is not working or encounters
problems. Since this technology is the same technology utilized for microprocessor based relays, then all
of the efficiencies realized apply to this equipment as well. CBM maximizes testing of the alarm path,
maximizes complete Protection System integrity and minimizes outages caused by human performance
errors.
Table 3 (Maintenance Activities and Intervals for distributed UFLS and distributed UVLS
Systems)
Component Attribute:
Any unmonitored protective relay not having all the monitoring attributes of a category below.
Maximum Maintenance Interval: 6 calendar years
Maintenance Activity: Verify that settings are as specified
For non-microprocessor relays:
• Test and, if necessary calibrate
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System. Verify acceptable measurement of power
system input values.
The 6 calendar year activities are a “Cal-Check” of the various legacy or unmonitored microprocessorbased relays (and repair as needed). The microprocessor based equipment requires little or no
maintenance. The maintenance activities require that the failure modes be checked on the equipment;
this is stated in such a manner as to capture all varieties of equipment presently in use. While some
equipment will require test equipment to manage the activities, other equipment can be routinely
verified, without the traditional relay testing equipment. The 6 year interval was determined from the
need for routine performance testing (in the absence of monitoring). 5 years was chosen as a starting
point as outlined in the SPCTF White Paper. The interval chosen for the standard, by mandate, has to be
an absolute measurable limit thus no “grace periods” are allowed within the standard itself. For
scheduling management, unforeseen events, natural disasters and no grace periods a final interval of 6
calendar years was chosen. 6 years also works well as a base interval when coordinating with any
10/10/2012
Page 20 of 25
individual registered generator as there may be generator outage schedules that approach but do not
exceed 6 years.
Component Attribute:
Monitored microprocessor protective relay with the following:
•
Internal self diagnosis and alarming (See Table 2).
•
Voltage and/or current waveform sampling three or more times per power cycle, and conversion of
samples to numeric values for measurement calculations by microprocessor electronics.
•
Alarming for power supply failure (See Table 2).
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify:
• Settings are as specified.
•
Operation of the relay inputs and outputs that are essential to proper functioning
of the Protection System.
•
Acceptable measurement of power system input values
Relay equipment with these attributes provides condition-based maintenance on many of the sections of
the device. The 12 calendar year activities are to ensure that the device conveys the alarm from its origin
to the location where corrective action can be initiated; that the power system input values are correctly
measured by the relay and that the needed inputs and outputs are still functional. The maintenance
activities are focused on the necessary tests that are not otherwise covered with internal self-diagnostics.
Aside from the components that do not have internal self-diagnostics, this technology utilizes condition
based maintenance (CBM) principles on many of its components. CBM maximizes testing, maximizes
complete Protection System integrity and minimizes outages caused by human performance errors.
Component Attribute:
Monitored microprocessor protective relay with preceding row attributes and the following:
•
Ac measurements are continuously verified by comparison to an independent ac measurement
source, with alarming for excessive error (See Table 2).
•
Some or all binary or status inputs and control outputs are monitored by a process that continuously
demonstrates ability to perform as designed, with alarming for failure (See Table 2).
•
Alarming for change of settings (See Table 2).
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify only the unmonitored relay inputs and outputs that are essential to proper
functioning of the Protection System.
10/10/2012
Page 21 of 25
This Maintenance Activity includes verification that the device conveys the alarm from its origin to the
location where corrective action can be initiated. This equipment is configured to verify the sections of
the relay that measure the power system values. This equipment routinely verifies all equipment through
CBM except the inputs and outputs.
Component Attribute:
Voltage and/or current sensing devices associated with UFLS or UVLS systems.
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify that current and/or voltage signal values are provided to the protective
relays.
The 12 calendar year activities are measurement activities (and repair as needed) and in many cases can
be eliminated by advanced comparison techniques, software and communications.
The time interval is chosen specifically to coincide with every other test of an unmonitored relay and
every test of a monitored relay.
The activity specified implicitly verifies more than voltages, currents and ratios as there is more to the
circuit than just the instrument transformer (or other voltage and current sensing device). The expected
product life cycle of wound voltage and current transformers is known to be far in excess of 40 years, well
above the specified time interval. The verification of the values provided to the protective relays also
brings wiring into the verification process. While there are product degradation failure modes that occur
in cabling and wiring, it is a well-known phenomenon that most cable degradation occurs because of high
voltage stress. High voltage-stressed, direct-buried cable is typically expected to last at least 15 years. The
cables and wires used in these Protection System applications are not stressed with high voltage.
Following prudent installation techniques, associated protection system cabling and wiring life expectancy
is known to be far in excess of 40-50 years.
The activity performed at every-other unmonitored relay calibration is intended to recur much more
often than any predicted cable degradation problem while at the same time this interval will minimize
human interaction with the voltage and current sources. The history of Protection System maintenance
has found that minimizing human interaction will minimize mistakes that manifest themselves as
inadvertent trips and otherwise broken equipment. Shock hazards from voltage and current sources are a
large concern of the industry and are also minimized with the purposeful approach used with the applied
maximum time interval between breaking into the voltage and current paths.
The activity, when used with a monitored relay test, can be extremely useful in a rapid diagnosis of the
complete Protection System package. A state of the art microprocessor relay can produce an output of
the status of the relay, the battery bank float voltage, the continuity of the trip path through the trip coil,
10/10/2012
Page 22 of 25
the status of any connected comm.-assisted trip equipment and a display of the values of voltage and
current provided to the relay.
A properly applied microprocessor relay within a substation might have a display of volts, amps, phase
angles, Watts, VARs, Volt-Amps as well as other programmed output values. All of the programmed
output values can be utilized as possible troubleshooting tools.
As the industry is moving towards a BES with a very high percentage of microprocessor relays this
advanced functionality will be widespread.
The maximum time interval requirement of PRC-005-2 is measurable because there are no grace periods
allowed. It becomes a de-facto time interval of less than 12 years simply because an entity will have to
guarantee that the 12 years is not exceeded. Therefore the activity will be scheduled and completed
before the time interval has run its course.
Component Attribute:
Protection System dc supply for tripping non-BES interrupting devices used only for a UFLS or UVLS
system
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify Protection System dc supply voltage.
The maintenance activity for component attribute (verifying that there is dc supply voltage) is due to the
distributed nature of these components. Failure of a single component does not have significant impact
to the BES to warrant further maintenance activities for the dc supply. These components are routinely
operated in normal operations and maintenance activities for distribution systems and as such it is only
required to verify that voltage is present when the other maintenance activities for distributed UFLS and
UVLS systems are conducted.
The 12 calendar interval for verifying dc supply voltage was chosen specifically to coincide with
maintenance activities for monitored microprocessor protective relays, voltage and/or current sensing
devices, control circuitry, and electromechanical lockout and/or tripping auxiliary devices.
Component Attribute:
Control circuitry between the UFLS or UVLS relays and electromechanical lockout and/or tripping auxiliary
devices (excludes non-BES interrupting device trip coils).
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify the path from the relay to the lockout and/or tripping auxiliary relay
(including essential supervisory logic).
10/10/2012
Page 23 of 25
The interval of 12 calendar years to authenticate the path from the relay to the lockout and/or tripping
auxiliary relay is based on the premise that while there are product degradation failure modes that occur
in control cabling panel and circuit breaker wiring, it is a well-known phenomenon that most cable
degradation occurs because of high voltage stress. High voltage-stressed, direct-buried cable is typically
expected to last at least 15 years. However the 12 calendar interval was chosen to coincide specifically
with activities for monitored microprocessor protective relays, voltage and/or current sensing devices,
and Protection System dc supply for UFLS or UVLS systems.
Failure of a single component does not have significant impact to the BES to warrant further maintenance
activities for the control circuitry between the UFLS or UVLS relays and the lockout or tripping auxiliary
devices. These components are routinely operated in normal operations and maintenance activities for
distribution systems and as such it is only required to verify the path from the UFLS or UVLS relay to the
lockout or tripping auxiliary relay.
Component Attribute:
Electromechanical lockout and/or tripping auxiliary devices associated only with UFLS or UVLS systems
(excludes non-BES interrupting device trip coils).
Maximum Maintenance Interval: 12 calendar years
Maintenance Activity: Verify electrical operation of electromechanical lockout and/or tripping auxiliary
devices.
Because failure of a single electromechanical lockout and/or tripping auxiliary device component used in
UFLS or UVLS system does not have significant impact to the BES to warrant the shorter 6 calendar
maintenance interval as other Protection Systems, the 12 calendar interval was chosen. Also the 12
calendar interval to verify operation of electromechanical lockout and/or tripping auxiliary devices was
chosen to coincide specifically with activities for monitored microprocessor protective relays, voltage
and/or current sensing devices, Protection System dc supply and control circuitry for UFLS or UVLS
systems.
Component Attribute:
Control circuitry between the electromechanical lockout and/or tripping auxiliary devices and the non-BES
interrupting devices in UFLS or UVLS systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting devices (excludes non-BES
interrupting device trip coils).
Maximum Maintenance Interval: No periodic maintenance specified
Maintenance Activity: None
No periodic maintenance interval or maintenance activity is required for this UFLS or UVLS distributed
system. Failure of a single control circuit with the component attribute stated above does not have
significant impact to the BES to warrant a maintenance activity at a maximum maintenance interval.
10/10/2012
Page 24 of 25
Component Attribute:
Trip coils of non-BES interrupting devices in UFLS or UVLS systems
Maximum Maintenance Interval: No periodic maintenance specified
Maintenance Activity: None
No periodic maintenance interval or maintenance activity is required for trip coils of non-BES interrupting
devices in UFLS or UVLS systems because failure of a single trip coil does not have a significant impact to
the BES and these components are routinely operated in normal operations and maintenance activities
for distribution systems that the UFLS or UVLS protective relays actuate.
10/10/2012
Page 25 of 25
Exhibit G
Mapping Document
Project 2007-17 Protection System Maintenance
and Testing Mapping Document
Mapping Document Showing Translation of PRC-005-1b – Transmission and Generation Protection
System Maintenance and Testing, PRC-008-0- Implementation and Documentation of Underfrequency
Load Shedding Equipment Maintenance Program, PRC-011-0 – Undervoltage Load Shedding System
Maintenance and Testing, and PRC-017-0 - Special Protection System Maintenance and Testing into
PRC-005-2 – Protection System Maintenance.
Standard: PRC-005-1b - Transmission and Generation Protection System Maintenance and Testing
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
Or Comment
R1. Each Transmission Owner, Generator
R1. Each Transmission Owner
PRC-005-2, R1
Owner, and Distribution Provider shall
and any Distribution Provider
and PRC-005-2,
establish a Protection System Maintenance
that owns a transmission
R2
Program (PSMP) for its Protection Systems
Protection System and each
identified in Section 4.2.
Generator Owner that owns a
generation Protection System
shall have Protection System
maintenance and testing
program for Protection
Systems that affect the
reliability of the BES. The
program shall include:
R1.1. Maintenance and testing
intervals and their basis.
R1.2. Summary of
maintenance and testing
procedures.
PRC-005-2,
Tables 1-1
through 1-5,
Table 2, and
Table 3.
The PSMP shall:
1.1. Identify which maintenance method
(time-based, performance-based per
PRC-005 Attachment A, or a
combination) is used to address each
Protection System Component Type.
All batteries associated with the
station dc supply Component Type of
a Protection System shall be included
in a time-based program as described
in Table 1-4 and Table 3.
1.2. Include the applicable monitored
Component attributes applied to each
Protection System Component Type
consistent with the maintenance
intervals specified in Tables 1-1
through 1-5, Table 2, and Table 3
where monitoring is used to extend
the maintenance intervals beyond
Standard: PRC-005-1b - Transmission and Generation Protection System Maintenance and Testing
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
Or Comment
those specified for unmonitored
Protection System Components.
R2. Each Transmission Owner, Generator
Owner, and Distribution Provider that uses
performance-based maintenance intervals
in its PSMP shall follow the procedure
established in PRC-005 Attachment A to
establish and maintain its performancebased intervals.
See PRC-005-2 Tables 1-1 through 1-5, Table 2,
and Table 3. The Tables establish prescribed
maximum intervals and minimum maintenance
activities, and, as such, the entity no longer needs
to establish the basis for their intervals.
R2. Each Transmission Owner
and any Distribution Provider
that owns a transmission
Protection System and each
Generator Owner that owns a
generation Protection System
shall provide documentation
of its Protection System
maintenance and testing
program and the
implementation of that
program to its Regional
Reliability Organization on
request (within 30 calendar
days). The documentation of
the program implementation
shall include:
R2.1. Evidence Protection
System devices were
maintained and tested within
PRC-005-2, R3
PRC-005-2, R4,
R3. Each Transmission Owner, Generator Owner,
and Distribution Provider that utilizes timebased maintenance programs shall maintain
PRC-005-2, M3,
its Protection System Components that are
PRC-005-2, M4
included within the time-based maintenance
NERC Compliance
program in accordance with the minimum
Monitoring
maintenance activities and maximum
Enforcement
maintenance intervals prescribed within
Program
Tables 1-1 through 1-5, Table 2, and Table 3.
Data Retention
R4. Each Transmission Owner, Generator Owner,
1.3
and Distribution Provider that utilizes
performance-based maintenance programs
in accordance with Requirement R2 shall
implement and follow its PSMP for its
Protection System Components that are
included within the performance-based
program.
The legacy requirement that the entity provide
the program results to the RRO and NERC on
Project 2007-17 Protection System Maintenance and Testing
Mapping Document | October 2012
2
Standard: PRC-005-1b - Transmission and Generation Protection System Maintenance and Testing
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
Or Comment
the defined intervals.
request is addressed in the NERC Compliance
Monitoring Enforcement Program.
R2.2. Date each Protection
System device was last
tested/maintained.
M3. Each Transmission Owner, Generator
Owner, and Distribution Provider that
utilizes time-based maintenance programs
shall have evidence that it has maintained
its Protection System Components included
within its time-based program in
accordance with Requirement R3. The
evidence may include but is not limited to
dated maintenance records, dated
maintenance summaries, dated check-off
lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator
Owner, and Distribution Provider that
utilizes a performance-based maintenance
program in accordance with Requirement
R2 shall have evidence that it has
implemented the Protection System
Maintenance Program for the Protection
System Components included in its
performance-based program in accordance
with Requirement R4. The evidence may
include but is not limited to dated
maintenance records, dated maintenance
summaries, dated check-off lists, dated
inspection records, or dated work orders.
1.3 Data Retention
For Requirement R2, Requirement R3,
Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and
Distribution Provider shall each keep
documentation of the two most recent
Project 2007-17 Protection System Maintenance and Testing
Mapping Document | October 2012
3
Standard: PRC-005-1b - Transmission and Generation Protection System Maintenance and Testing
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
Or Comment
performances of each distinct maintenance
activity for the Protection System Components,
or all performances of each distinct maintenance
activity for the Protection System Component
since the previous scheduled audit date,
whichever is longer.
Project 2007-17 Protection System Maintenance and Testing
Mapping Document | October 2012
4
Standard: PRC-008-0 - Implementation and Documentation of Underfrequency Load Shedding
Equipment Maintenance Program
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
or Comments
See mapping of Requirements R1 and R2 for PRCR1. The Transmission Owner
PRC-005-2, R1,
005-1 above.
and Distribution Provider with R2, R3, R4, and
a UFLS program (as required
by its Regional Reliability
Organization) shall have a UFLS
equipment maintenance and
testing program in place. This
UFLS equipment maintenance
and testing program shall
include UFLS equipment
identification, the schedule for
UFLS equipment testing, and
the schedule for UFLS
equipment maintenance.
Applicability
4.2.2
R2. The Transmission Owner
and Distribution Provider with
a UFLS program (as required
by its Regional Reliability
Organization) shall implement
its UFLS equipment
maintenance and testing
program and shall provide
UFLS maintenance and testing
program results to its Regional
Reliability Organization and
NERC on request (within 30
calendar days).
PRC-005-2, R3,
PRC-002, R4
Tables 1-1 – 1-5,
Table 2, and
Table 3
4.2 Facilities
4.2.2 Protection Systems used for
Underfrequency load-shedding systems installed
per ERO Underfrequency load-shedding
requirements.
See PRC-005-2 Tables 1-1 through 1-5, Table 2,
and Table 3. The Tables establish prescribed
maximum intervals and minimum maintenance
activities, and, as such, the entity no longer needs
to establish the basis for their intervals.
See mapping of Requirements R1 and R2 for PRC005-1 above.
PRC-005-2, M3,
and PRC-005-2
M4
The legacy requirement that the entity provide
the program results to the RRO and NERC on
request is addressed in the NERC Compliance
NERC Compliance Monitoring Enforcement Program.
Monitoring
Enforcement
Program
Project 2007-17 Protection System Maintenance and Testing
Mapping Document | October 2012
5
Standard: PRC-011-0 - Undervoltage Load Shedding System Maintenance and Testing
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
or Comments
PRC-005-2, R1,
See mapping of Requirements R1, and R2 for
R1. The Transmission Owner
PRC-005-1 above.
and Distribution Provider that PRC-005-2, R2,
PRC-005-2,
R3,
owns a UVLS system shall have
PRC-005-2, R4,
4.2 Facilities
a UVLS equipment
PRC-005-2 M3,
4.2.3 Protection Systems used for undervoltage
maintenance and testing
PRC-005-2,
M4,
load-shedding systems installed to prevent
program in place. This
and PRC-005-2
system voltage collapse or voltage instability for
program shall include:
Applicability
BES reliability.
R1.1. The UVLS system
4.2.3
identification which shall
See PRC-005-2 Tables 1-1 through 1-5, Table 2,
include but is not limited to:
and Table 3. The Tables establish prescribed
Tables
1-1
–
1-5,
maximum intervals and minimum maintenance
R1.1.1. Relays.
Table 2, and
activities, and, as such, the entity no longer needs
R1.1.2. Instrument
Table 3
to establish the basis for their intervals.
transformers.
R1.1.3. Communications
systems, where appropriate.
R1.1.4. Batteries.
R1.2. Documentation of
maintenance and testing
intervals and their basis.
R1.3. Summary of testing
procedure.
R1.4. Schedule for system
testing.
Data Retention
1.3
1.3 Data Retention
For Requirement R2, Requirement R3,
Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and
Distribution Provider shall each keep
documentation of the two most recent
performances of each distinct maintenance
activity for the Protection System Components,
or all performances of each distinct maintenance
activity for the Protection System Component
since the previous scheduled audit date,
whichever is longer.
R1.5. Schedule for system
maintenance.
R1.6. Date last
tested/maintained.
R2. The Transmission Owner
and Distribution Provider that
owns a UVLS system shall
provide documentation of its
NERC Compliance The legacy requirement that the entity provide
Monitoring
the program results to the RRO and NERC on
Enforcement
request is addressed in the NERC Compliance
Project 2007-17 Protection System Maintenance and Testing
Mapping Document | October 2012
6
Standard: PRC-011-0 - Undervoltage Load Shedding System Maintenance and Testing
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
or Comments
UVLS equipment maintenance Program
Monitoring Enforcement Program
and testing program and the
implementation of that UVLS
equipment maintenance and
testing program to its Regional
Reliability Organization and
NERC on request (within 30
calendar days).
Project 2007-17 Protection System Maintenance and Testing
Mapping Document | October 2012
7
Standard: PRC-017-0 - Special Protection System Maintenance and Testing
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
or Comments
R1. The Transmission Owner,
PRC-005-2, R1,
See mapping of Requirements R1, and R2 for
Generator Owner, and
PRC-005-2, R2,
PRC-005-1 above.
Distribution Provider that
PRC-005-2, R3,
owns an SPS shall have a
PRC-005-2, R4,
4.2 Facilities
system maintenance and
PRC-005-2 M3,
4.2.4 Protection Systems installed as a Special
testing program(s) in place.
PRC-005-2, M4,
Protection System (SPS) for BES reliability.
The program(s) shall include:
and PRC-005-2
Applicability
See PRC-005-2 Tables 1-1 through 1-5 and Table
R1.1. SPS identification shall
4.2.4
2. The Tables establish prescribed maximum
include but is not limited to:
intervals and minimum maintenance activities,
R1.1.1. Relays.
and, as such, the entity no longer needs to
Tables
1-1
–
1-5,
establish the basis for their intervals.
R1.1.2. Instrument
and
Table
2
transformers.
1.3 Data Retention
R1.1.3. Communications
For Requirement R2, Requirement R3,
systems, where appropriate.
Data Retention
Requirement R4, and Requirement R5, the
1.3
Transmission Owner, Generator Owner, and
R1.1.4. Batteries.
Distribution Provider shall each keep
R1.2. Documentation of
documentation of the two most recent
maintenance and testing
performances of each distinct maintenance
intervals and their basis.
activity for the Protection System Components,
R1.3. Summary of testing
or all performances of each distinct maintenance
procedure.
activity for the Protection System Component
since the previous scheduled audit date,
R1.4. Schedule for system
whichever is longer.
testing.
R1.5. Schedule for system
maintenance.
R1.6. Date last
tested/maintained.
Project 2007-17 Protection System Maintenance and Testing
Mapping Document | October 2012
8
Standard: PRC-017-0 - Special Protection System Maintenance and Testing
Requirement in Approved
Translation to
Proposed Language in PRC-005-2 – Protection
Standard
New Standard or
System Maintenance
Other Action
Or Comment
R1. The legacy requirement that the entity
R2. The Transmission Owner,
NERC Compliance
provide the program results to the RRO
Generator Owner, and
Monitoring
and NERC on request is addressed in
Distribution Provider that
Enforcement
the NERC Compliance Monitoring
owns an SPS shall provide
Program
Enforcement Program
documentation of the program
and its implementation to the
appropriate Regional
Reliability Organizations and
NERC on request (within 30
calendar days).
Project 2007-17 Protection System Maintenance and Testing
Mapping Document | October 2012
9
Exhibit H
Consideration of Comments for Proposed Reliability Standard PRC-005-2
Project 2007-17
Protection System Maintenance and Testing
Related Files
Status:
PRC-005-2 will be presented to the NERC Board of Trustees for adoption in November 2012
and if adopted, filed with regulators for approval.
Purpose/Industry Need:
The purpose of standard PRC-005 should remain “To ensure all transmission and
generation Protection Systems affecting the reliability of the Bulk Electric System
(BES) are maintained and tested.”
In Order 693, the Federal Energy Regulatory Commission directed that changes be
made to these standards.
These standards should be consolidated into a single standard to reduce the costs of
compliance and a number of technical short comings in these standards should be
corrected to provide reliable performance when responding to abnormal system
conditions.
Draft
Action
Dates
Results
10/15/12 10/24/12
(closed)
Summary>>
Draft 4
Standard PRC-0052
Clean | Redline to
Last Posting
Implementation
Plan
Clean
Recirculation
Ballot
Info>>
Vote>>
Supporting
Materials:
Definition of
Protection System
Supplemental
Ballot Results>>
Consideration
of Comments
Reference & FAQ
Clean | Redline to
Last Posting
Technical
Justification
Clean | Redline
Mapping
Document
Clean
Table of Issues and
Directives
VRF and VSL
Justification
Clean | Redline
Last Approved
Versions of
Standards to be
Retired:
PRC-005-1.1b
PRC-008-0
PRC-011-0
PRC-017-0
Draft 4
Standard PRC-0052
Clean | Redline to
Last Posting
Implementation
Plan
Clean | Redline to
Last Posting
Supporting
Materials:
Unofficial
Comment Form
(Word)
Definition of
Protection System
(Updated 8/16/12)
Successive
Ballot
Updated
Info>>
08/17/12 08/27/12
(closed)
Summary>>
Ballot Results>>
Info>>
Vote>>
Supplemental
Reference & FAQ
Clean | Redline to
Last Posting
Technical
Justification
Clean | Redline
Mapping
Document
Clean | Redline to
Last Posting
Table of Issues and
Directives
VRF and VSL
Justification
Clean | Redline
Comment
Period
Info>>
07/27/12 08/27/12
(closed)
Comments
Received>>
06/18/12 -
Summary>>
Submit
Comments>>
Last Approved
Versions of
Standards to be
Retired:
PRC-005-1.1b
PRC-008-0
PRC-011-0
PRC-017-0
Draft 3
Successive
Consideration of
Comments(18)
Ballot
Standard PRC-0052
Clean | Redline to
Last Posting
06/27/12
(closed)
Updated
Info>>
Ballot Results>>
Non-binding
Poll Results>>
Info>>
Implementation
Plan
Clean | Redline to
Last Posting
Supporting
Materials:
Definition of
Protection System
IEEE Stationary
Battery Committee
NERC Task Force
Report and SDT
Response
For Information:
Draft SAR for
Phase 2 of Project
2007-17
Supplemental
Reference & FAQ
Clean | Redline to
Last Posting
Technical
Justification
Clean | Redline
Mapping
Document
Clean | Redline to
Last Posting
Table of Issues and
Directives
Formal
Comment
Period
Info>>
Submit
Comments>>
05/29/12 06/27/12
(closed)
Comments
Received>>
Consideration of
Comments(17)
VRF and VSL
Justification
Clean | Redline
Unofficial
Comment Form
(Word)
Last Approved
Versions of
Standards to be
Retired:
PRC-005-1
PRC-008-0
PRC-011-0
PRC-017-0
Draft 2
Standard PRC-0052
Clean | Redline to
Last Posting
Implementation
Plan
Clean | Redline to
Last Posting
Successive
Ballot and
Non-binding
Poll
Updated
Info>>
Vote>>
SAR
Clean | Redline to
Last Posting
Formal
Comment
Period
Supporting
Materials:
Definition of
Protection System
Updated
Info>>
Info>>
Supplemental
Reference & FAQ
Clean | Redline to
Last Posting
03/19/12 03/28/12
(closed)
Submit
Comments>>
02/28/12 03/28/12
(closed)
Full Record>>
Non-binding
Poll Results>>
Comments
Received>>
Consideration of
Comments(16)
Technical
Justification
Mapping
Document
Table of Issues and
Directives
VRF and VSL
Justification
Unofficial
Comment Form
Last Approved
Versions of
Standards to be
Retired:
PRC-005-1
PRC-008-0
PRC-011-0
PRC-017-0
Nomination
Period
Drafting Team
Nominations
Info>>
09/01/11 09/23/11
(closed)
Submit
Nomination>>
Standard PRC-0052
Clean |Redline to
Recirc Ballot
Implementation
Plan
Clean | Redline to
Recirc Ballot
Initial Ballot
and NonBinding Poll
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After PRC-005-2 failed to reach ballot pool approval in the recirculation ballot that
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Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
The Protection System Maintenance and Testing SAR requesters thank all commenters who
submitted comments on the first draft of SAR. This SAR was posted for a 30-day public
comment period from June 11 through July 10, 2007. The requesters asked stakeholders to
provide feedback on the standard through a special SAR Comment Form. There were 18 sets of
comments, including comments from 85 different people from more than 50 companies
representing 8 of the 10 Industry Segments as shown in the table on the following pages.
The SAR drafting team made no changes to the SAR based on stakeholder comments.
Based on the comments received, the drafting team is recommending that the Standards
Committee authorize moving the SAR forward to the standard drafting stage of the standards
development process.
In this “Consideration of Comments” document stakeholder comments have been organized so
that it is easier to see the responses associated with each question. All comments received on
the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal
is to give every comment serious consideration in this process! If you feel there has been an
error or omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060
or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
1.
Anita Lee (G6)
AESO
2.
Jay Farrington
(G2)
Alabama Electric Coop.,
Inc.
3.
Ken Goldsmith
(G5)
ALT
4.
Robert
Rauschenbach
(G2)
Ameren
9
5.
Thad Kness
American Electric Power
(AEP)
9
6.
Dave Rudolph
(G4)
BEPC
7.
Dean Bender
Bonneville Power
Administration (BPA)
8.
Brent Kingsford
(G6)
CAISO
9.
Alan Gale
City of Tallahassee
(FRCC)
10.
Glen McCartney
(G4)
Constellation Energy
9
11.
Michael Gildea
(G4)
Constellation Energy
9
12.
Nancy C. Denton
Consumers Energy
Company
13.
Greg Rowland
Duke Energy
14.
Tom Seeley (G2)
E. ON-U.S.
9
15.
Charlie Fink (G2)
Entergy
9
16.
Jammie Lee (G2)
Entergy
9
17.
Steve Myers (G6)
ERCOT
9
9
9
9
9
9
9
9
9
9
9
9
9
9
18.
Doug Hohlbaugh
(G7)
FirstEnergy Corp. (FE)
9
19.
Craig Boyle (G7)
Transm. Substa.
9
Page 2 of 19
9
9
9
July 26, 2007
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
Maintenance (FE)
20.
Ken Ddresner (G7)
Fossil Generation (FE)
9
21.
Bill Duge (G7)
Nuclear Generation (FE)
9
22.
Dave Powell (G7)
Transm. Planning &
Protection (FE)
9
23.
Jeff Mackauer(G7)
Transm. Planning &
Protection (FE)
9
24.
Eric Senkowizc
FRCC
25.
Phil Winston (G3)
Georgia Power Company
26.
Steve Waldrep
(G2)
Georgia Power Company
9
27.
Phil Winston (G2)
Georgia Power Company
9
28.
Hong-Ming Shuh
(G2)
Georgia Transmission
Corp.
9
29.
Neal Jones (G2)
Georgia Transmission
Corp.
9
30.
David Kiguel (G4)
Hydro One Networks
9
31.
Ron Falsetti (I)
(G6)
IESO
9
32.
Matt Goldberg
(G6)
ISO- New England
9
33.
Kathleen Goodman
(G4)
ISO-New England
9
34.
William Shemley
(G4)
ISO-New England
9
35.
Eric Ruskamp (G4)
LES
36.
Donald Nelson
(G4)
MADPC
37.
Tony Clark
Manitoba Hydro
38.
Tom Mielnik (G4)
MEC
9
39.
Robert Coish (G5)
MHEB
9
40.
Joe Knight (G5)
Midwest Reliability
Organization
9
41.
Mike Brytowski
(G4)
Midwest Reliability
Organization
9
42.
Terry Bilke (G5)
MISO
9
43.
William Phillips
(G6)
MISO
44.
Carol Gerou (G5)
Minnesota Power (MP)
45.
Ernesto Paon (G2)
Municipal Electric
Authority of GA
9
46.
Michael Shiavone
(G4)
National Grid US
9
9
9
9
9
9
9
9
9
9
Page 3 of 19
9
July 26, 2007
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
47.
Greg Campoli (G4)
New York ISO
48.
Ralph Rufrano
(G4)
New York Power
Authority
9
49.
Murale Gopinathan
(G4)
Northeast Utilities
9
50.
Guy V. Zito (G4)
NPCC
9
51.
Al Adamson (G4)
NY State Reliability
Council
9
52.
Jim Castle (G6)
NYISO
53.
Richard Kafka
(G8)
Pepco Holdings, Inc.
54.
Alicia Daugherty
(G6)
PJM
55.
Jerry Blackley
(G2)
Progress Energy
Carolinas
56.
Phil Riley (G1)
PSC of South Carolina
9
57.
Mignon L. Clyburn
(G1)
PSC of South Carolina
9
58.
Elizabeth B.
Fleming (G1)
PSC of South Carolina
9
59.
G. O’Neal
Hamilton (G1)
PSC of South Carolina
9
60.
John E. Howard
(G1)
PSC of South Carolina
9
61.
Randy Mitchell
(G1)
PSC of South Carolina
9
62.
C. Robert Moseley
(G1)
PSC of South Carolina
9
63.
David A. Wright
(G1)
PSC of South Carolina
9
64.
Mike Gentry
Salt River Project (SRP)
9
65.
Bridget Coffman
(G2)
SC Public Service
Authority
9
66.
Pat Huntley (G2)
SERC Reliability Corp.
67.
Roman Carter
(G3)
So. Company
Transmission
9
68.
Marc Butts (G3)
So. Company
Transmission
9
69.
JT Wood (G3)
So. Company
Transmission
9
70.
Jim Busbin (G3)
So. Company
Transmission
9
71.
Marion Frick (G2)
South Carolina Electric &
Gas Co.
9
9
9
Page 4 of 19
9
9
July 26, 2007
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
72.
Charles Yeung
(G6)
Southwest Power Pool
73.
E. William Riley
Southwest Transmission
Co., Inc.
9
74.
Tom D. Spence
Southwest Transmission
Co., Inc.
9
75.
George Pitts (G2)
Tennessee Valley
Authority
9
76.
Meyer Kao (G2)
Tennessee Valley
Authority
9
77.
Ron Falsetti (G4)
(G6)
The IESO
78.
Roger Champagne
(G4)(I)
TransÉnergie HydroQuébec (HQTE)
79.
Jim Haigh (G4)
WAPA
9
80.
Neal Balu (G5)
WPS
9
81.
Pam Oreschnick
(G4)
XEL
9
82.
Carl Kinsley (G8)
Delmarva Power & Light
9
83.
Alvin Depew (G8)
Potomac Electric Power
Company
9
84.
Evan Sage (G8)
Potomac Electric Power
Company
9
9
9
I – Indicates that individual comments were submitted in addition to comments submitted as part of a
group
G1 – Public Service Commission of South Carolina (PSC SC)
G2 – SERC EC Protection & Control Subcommittee (SERC EC PCS)
G3 – Southern Company Transmission
G4 – NPCC CP9 Reliability Standards Working Group (NPCC CP9 RSWG)
G5 – MRO Members (MRO)
G6 – IRC Standards Review Committee (IRC)
G7 – FirstEnergy Corp. (FE)
G8 – Pepco Holdings, Inc.
Page 5 of 19
July 26, 2007
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
Index to Questions, Comments, and Responses
1.
Do you agree that there is a reliability-related need to improve the requirements in this
standard?.............................................................................................................. 7
2.
Do you agree with the proposed scope of this SAR?..................................................... 9
3.
Do you agree with the applicability of the proposed SAR (Transmission Owners, Generator
Owners and Distribution Providers - Distribution Providers may own the devices that must
be tested and maintained)? ....................................................................................12
4.
If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area. ..................................14
5.
If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us. .................................................................15
6.
If you have any other comments on this SAR that you haven’t provided above, please
provide them here. ................................................................................................16
Page 6 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
1. Do you agree that there is a reliability-related need to improve the requirements in this standard?
Summary Consideration: Most commentators indicated they do believe there is a reliability-related need to improve the
requirements in this set of standards.
Question #1
Commenter
AEP
Yes
No
Comment
has not had an event, due to deficiencies in protection maintenance, in it's long
; AEP
existence that jeopardized the reliability or availability of Bulk Power transfers. Simply
combining multiple standards into one, does nothing for improving reliability.
Response: The proposed changes will improve clarity which should benefit reliability. While AEP may have an excellent
record of maintenance, the existing standards are quite vague and allow an entity that performs maintenance once every 100
years to be fully compliant.
Manitoba Hydro
There is a need to better define and explain the terms "maintenance" and "testing" as
; they
relate to this standard. Also a tighter definition as to which systems are considered
to affect the BES is required. The need to improve the standard is driven by the
administration of the standard rather than reliability.
Response: As envisioned, the SDT will work with stake holders to define the terms ‘maintenance’ and ‘testing.’
The SAR DT disagrees that the standard changes are driven by “administration”. The existing requirements are vague enough
to allow an entity to perform maintenance once every 100 years and still be compliant.
SWTC
This SAR proposes to revise several standards to eliminate ambiguities and to provide
;
requirements that are measurable. In addition, the SPCTF report “Assessment of PRC005-1 – Transmission and Generation Protection System Maintenance and Testing; with
implications for PRC-008-0, PRC-011-0, and PRC-017-0” indicates the need to
differentiate between the different technologies used and insure the standard applies to
all in the appropriate way (i.e. electro-mechanicals, microprocessor-based, solid-state).
Southwest Transmission Cooperative, Inc. also recognizes this deficit in the existing
standards.
Response: The SAR DT agrees and appreciates your support.
SERC EC PCS
Consolidation of the maintenance and testing standards is appropriate. Separate
;
definitions for maintenance and testing are needed.
Response: The SAR DT agrees and appreciates your support.
FRCC
Centralizing System Protection equipment maintenance and testing requirements in a
;
single standard will add clarity, minimize synchronization issues across standards, help
provide consistent terminology and improve understanding of system protection
standards.
Response: The SAR DT agrees and appreciates your support.
Page 7 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #1
Commenter
PSC SC
BPA
Consumers Energy
IESO
SRP
SOCO Transmission
NPCC CP9 RSWG
MRO
IRC
FirstEnergy
HQT
Pepco Holdings
Duke Energy
Yes
No
Comment
;
;
;
;
;
;
;
;
;
;
;
;
;
Page 8 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
2. Do you agree with the proposed scope of this SAR?
Summary Consideration: Some entities objected to the use of ‘maximum allowable intervals,’ however, FERC has ordered
that maximum allowable intervals be developed. No changes to the SAR were made in response to these comments.
Question #2
Commenter
AEP
Yes
No
;
Comment
On the surface, the premise of reducing costs and improving efficiencies by combining
multiple standards sounds excellent. Having to only keep up with one standard instead of
four will not generate significant savings due to the fact that the maintenance will still
have to be performed. But what lies hidden, is the fact that prescribed maximum
allowable maintenance intervals will result from the revisions. They may require more
frequent testing to be performed. Is there evidence that increasing the interval
frequency results in a measurable increase in reliability and availability? Development of
prescribed maximum intervals that are vastly different than the utility's existing
practices may actual increase their O&M costs and reduce efficiencies.
The function of the protective system needs to be taken into account. The purpose of
the line protection is very different than the purpose of UFLS/UVLS and SPS's. The UFLS
program is there as the last line of defense against a decaying system after all other
measures have failed. The combination of all the different relaying systems places them
on equal ground. Shouldn't the reliability and dependability for one be more important
than the others?
Response: In order to develop a measurable standard and conform to the direction from FERC regarding allowable
maintenance intervals, the SDT, working with stakeholders, will develop requirements for maximum allowable maintenance
intervals for protection systems.
Combining these 4 standards into 1 does not preclude the SDT from developing different criteria for different types of
protection systems. Your concerns regarding the different purposes of protection systems and your question regarding
varying importance of different protection systems will be forwarded to the SDT.
Manitoba Hydro
We disagree that there is a need to change the standard to include more specificity for
; maintenance
and test procedures. We also disagree with mandating minimum
maintenance intervals for protection system equipment.
Response: FERC has directed NERC as the ERO to specify maximum allowable maintenance intervals.
Duke Energy
PRC-005, 008, 011 and 017 into one new standard does not seem to be the
; Combining
best approach. Duke Energy does not have UVLS systems or Special Protection
Systems. Furthermore, Duke Energy's Underfrequency Load Shedding system is on the
transmission system in the Carolinas, but on the distribution system in the Midwest.
Page 9 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #2
Commenter
Yes
No
Comment
Combining these standards would likely create confusion and compliance issues for us
and others as well. Also, combining the standards is unlikely to result in simplification,
as different requirements associated with the different protection systems could have
different Violation Risk Factors and levels of non-compliance, which would necessitate
keeping them separate in the combined standard, which would defeat the purpose of
combining them in the first place.
Response: Combining these 4 standards into 1 does not preclude the SDT from developing different criteria for different
types of protection systems (concerns about different voltage levels remain regardless if there is one standard or more than
one).
SWTC
Since most protection schemes are maintained and tested in a similar manner regardless
;
of scheme type, we agree that combining the (4) PRC standards related to maintenance
and testing of different types of systems into one standard will create a that is more
streamlined and less burdensome standard with easily understood measurable
compliance elements.
The most exciting part of the proposed modifications is the inclusion of condition-based
and performance-based maintenance and testing and not just time-based criteria.
Presently Southwest Transmission Cooperative, Inc. uses this type of maintenance and
testing criteria (maintenance data server) which is the current system protection
industry technology.
Response: Thank you for your support.
FirstEnergy
Bullet #5 of the "Detailed Description" on page SAR-2 indicates the following:
;
"Applicable to all four standards — The requirements of the existing standards, as
stated, support time-based maintenance and testing, and should be expanded to
include condition-based and performance-based maintenance and testing. The
requirements for maintenance and testing procedures need to have more specificity
to insure that the stated intent of the standards is met to support review by the
compliance monitor."
FE supports the scope of the SAR to consider adding the ability for condition-based and
performance-based testing, as suggested by the System Protection and Control Task
Force. Additionally, the SDT should consider the need to perform some level of
preventative maintenance on a periodic basis at an established maximum interval length,
that would vary per the equipment being maintained. The interval established would be
based on established guidelines from vendors, EPRI, industry experts, etc.
Page 10 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #2
Commenter
Yes No
Comment
Response: Thank you- The SDT will develop maximum allowable maintenance intervals for protection systems, working with
stakeholders.
FRCC
of subject matter experts (NERC SPCTF) along with the NERC Planning Committee
; ; Use
review of the assessment is an effective and efficient way to supplement project SARs
and provides critical input at the front-end of the standards process.
Attachment A is described as the SPCTF assessment, but attachment A to the SAR is the
SPCTF roster. The assessment referenced in the scope of the SAR should include "Draft
1.0" if the full assessment is not included as part of the SAR.
Response: The attachments and supporting material references will be posted.
PSC SC
;
SERC EC PCS
BPA
Consumers Energy
IESO
SRP
SOCO Transmission
NPCC CP9 RSWG
MRO
IRC
HQT
Pepco Holdings
;
;
;
;
;
;
;
;
;
;
;
Page 11 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
3. Do you agree with the applicability of the proposed SAR (Transmission Owners, Generator Owners and Distribution
Providers - Distribution Providers may own the devices that must be tested and maintained)?
Summary Consideration: Based on comments received no changes were made to the SAR
Question #3
Commenter
Yes No
Comment
FRCC
This question may be better addressed as the standards are integrated.
Response: The SAR DT is obligated to address the applicability,
MRO
Order 693 in both paragraph 1466 and in footnote 384, indicates that in some
; FERC
areas of the country, Load Serving Entities (LSE) and Transmission Operators (TOP) may
individually or jointly own and operate a protection system. Thus, these additional
entities should be subject to the resulting consolidated standard. The MRO believes that
the following caveat should be added to the LSE where it is listed as an Applicable Entity,
(where operation of the protection system can affect the Bulk Electric System).
2. The MRO requests that the SDT review whether or not the Reliability Coordinator
(RC) should be added to the list of Applicable Entities given their wide area view-for
example, the RC may need to be involved in determining which protection systems below
100kV will affect the BES.
Response: FERC Order 693 in both paragraph 1466 and in footnote 384 reiterates IESO-NE comments on the NOPPR. The
FERC directive was to consider this comment. According to the NERC Functional Model, Load-serving Entities, Transmission
Operators and Reliability Coordinators are not owners of protection systems – and the entity responsible for maintenance is
the facility owner.
NPCC CP9 RSWG
requirement needs to specifically address what protection systems need to comply
; ; Each
HQT
with the standard - i.e. a generator not connected to the BPS with under frequency trip
relay should only be subject to under frequency relay maintenance requirements.
Response: Your comment will be referred to the SDT for consideration when convened.
FirstEnergy
The inclusion of the Distribution Provider is generally needed for UFLS and UVLS relays.
;
The confusion that previously existed in PRC-005 by including the DP entity should be
mitigated by the proposed consolidation of the four maintenance standards.
Response: Thank you for your comment.
PSC SC
;
SERC EC PCS
AEP
BPA
;
;
;
Page 12 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #3
Commenter
Consumers Energy
IESO
SRP
SOCO Transmission
SWTC
IRC
Pepco Holdings
Duke Energy
Yes
No
Comment
;
;
;
;
;
;
;
;
Page 13 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
4. If you know of a Regional Variance that should be developed as part of this SAR, please identify that for us. If not,
please explain in the comment area.
Summary Consideration: No regional variances were identified by the commentators
Question #4
Commenter
NPCC CP9 RSWG
Regional
Variance
None
Comment
Certain unavoidable delays like the inability to schedule outages for reliability reasons or
labor disputes, or force-majeure conditions could affect testing period requirements.
These factors should be considered and certain latitude, with the "appropriate
approvals", needs to be provided for delays in the testing process.
Response: This is a compliance issue not a regional variance – The compliance enforcement program does give the
compliance monitor latitude to consider extenuating circumstances.
PSC SC
N/A
SERC EC PCS
None
AEP
None
BPA
No known
regional
variance.
Consumers Energy
N/A
SWTC
N/A
Not aware of any Regional Variance requirements.
MRO
None
FirstEnergy
Not aware of any.
HQT
None
Page 14 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
5. If you are aware of a Business Practice that needs to be developed to support the proposed SAR, please identify that for
us.
Summary Consideration: No needs for development of Business Practices were identified by the commentators.
Question #5
Commenter
AEP
Business
Practice
Possibly
Comment
AEP and other utilities, with many years of experience serving customers and supporting
the electric grid, have voluntarily integrated maintenance and testing programs into the
core of their work practices and processes. AEP fully supports improvements if they
truly foster reliability and availability benefits to bulk power transfers. More Standards,
Requirements and Business Practices are not always better. If Standards create burdens
on a utility's physical resources and budgets, then some mechanism must be available to
allow for the needed changes.
Response: Please monitor the work of the SDT and advise the team if added burdens are created by any of the proposed
requirement and advise the team of the need for any business practice or other mechanism necessary to support the
proposed requirements.
PSC SC
N/A
SERC EC PCS
None
Consumers Energy
N/A
SWTC
N/A
Not aware of any Business Practice needs.
NPCC CP9 RSWG
None that
we know
of.
MRO
None
IRC
None
FirstEnergy
Not aware of any.
HQT
None that we know of.
Page 15 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
6. If you have any other comments on this SAR that you haven’t provided above, please provide them here.
Question #6
Commenter
Comment
SERC EC PCS
The SERC EC PCS supports the work of the NERC SPCTF in their assessments of these standards.
Response: Thank you for your support
AEP
The standard should not use the term Bulk Electric System, but should instead specify a voltage
threshold for impacts to bulk system transfers - specifically; 'Facilities operated 200 kV and above
and Regionally-defined, Operationally Significant facilities operated greater than 100 kV, but less
than 199 kV'. The term 'affects' also needs to be clarified. Inclusion of all facilities greater than 100
kV does not benefit the reliability of national bulk power transfers. For example, the loss or
misoperation of a 138 kV line serving a localized load center would not be detrimental to bulk power
transfers multiple busses away.
Response: Your comment will be referred to the drafting team when convened for consideration when drafting the standard.
BPA
In the "Detailed Description" section of the SAR, it states:
"Part of the stated purpose in PRC-017 is: “To ensure that maintenance and testing programs are
developed and misoperations are analyzed and corrected.” The phrase “and misoperations are
analyzed and corrected” is not clearly appropriate in a maintenance and testing standard. That is the
purpose is more appropriate in PRC-003 and PRC-004, which relate to the analysis and mitigation of
protection system misoperations. Analysis of correct operations or misoperations may be an integral
part of condition-based maintenance processes, but need not be mandated in a maintenance
standard."
The analysis of SPS misoperations is handled in PRC-016 (SPS Misoperations) and PRC 012 (SPS
review Procedure) not in PRC-003 or PRC-004. Therefore, if the phrase is removed from PRC-017, it
does not need to be added to PRC-003 or PRC-004.
Response: We agree. Please see the purpose statement as stated in the SAR.
SOCO Transmission
In the SAR you state "The revised PRC-005 standard should address the issues raised in the FERC
Order 693". With the exception of mentioning the consolidation of the standards into one standard,
the SAR drafting team didn't provide readers with the exact language from FERC that would be useful
to know with respect to PRC-005 in the directive below:
The Commission directs the ERO to develop a modification to PRC-005-1 through the Reliability
Standards development process that includes a requirement that maintenance and testing of a
protection system must be carried out within a maximum allowable interval that is appropriate to the
type of the protection system and its impact on the reliability of the Bulk-Power System. We further
direct the ERO to consider FirstEnergy’s and ISO-NE’s suggestion to combine PRC-005-1, PRC-008-0,
Page 16 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #6
Commenter
Comment
PRC-011-0 and PRC-017-0 into a single Reliability Standard through the Reliability Standards
development process.
Response: The SAR DT Agrees – the SAR DT will make sure that all appropriate documents are included in its next posting
of the SAR.
MRO
1. The MRO commends NERC and the SDT for taking steps to remove some of the redundancy that
currently exists among many of the standards today. The consolidation of the protection system
maintenance and testing standards is a good first step.
2. The MRO requests that the following be considered during the initial drafting of the Requirements
for this new protection and maintenance standard. A minimum set of evidence to be included in a
maintenance and testing program should be established in the measures for R1.2.
3. In the SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0, the clarification
for R2 states that documentation is available to its Regional Reliability Organization and NERC during
audits or upon request within 30 days but paragraph 1545 of FERC Order 693 states "be routinely
provided to the ERO or Regional Entity and not only when it is requested." The MRO believes that the
FERC request would be satisfied if the standard were to state: "the applicable entities shall provide
testing records to the Regional Entity on a periodic basis e.g. (annually).
4. In the event that the SAR DT does not become the SDT, the MRO requests that these comments
be forwarded on to the group that will do tha actual drafting of the Standard.
Response: The SAR DT will forward your comments to the SDT for consideration as required by the process
IRC
1. The SRC (IESO) commends NERC, the SDT and the SPCTF for providing clarity and for efforts to
IESO
reduce the costs of compliance.
2 In the Standard PRC-008-0, Generation Owners were not included in the applicable entities.
Generation Owners may have underfrequency tripping devices for protection of their units. It would
be appropriate to include these devices for maintenance and testing requirements also.
3. Further, there is need to specify which types of relays will be covered by the new standard. The
SAR Team needs to focus on better defining the Generator Protection Schemes ("GPS") that are
critical to bulk power system operation, as distinct from generator operation. For example, a single
generating unit may experience contingency events that would not result in any significant adverse
impacts outside the local area in which the single generating unit is located. As a result, there
remains a need to subject those GPSs that are important to the Bulk Power System, such as
generator underfrequency trip settings, to the maintenance testing intervals to be derived in these
standards.
4. Certain unavoidable delays like the inability to schedule outages for reliability reasons, labor
Page 17 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #6
Commenter
Comment
disputes, or force-majeure conditions could affect testing period requirements. These factors should
be considered and certain latitude needs to be provided for delays in the testing process.
5. However, the SAR team needs to also consider, as part of its scope, assurance that the asset
owner has taken all appropriate steps to assure that required outages are appropriately planned and
can be reasonably accommodated and approved by the TOP or RC.
Response:
1.Thank you
2. Generator owners are included in the SAR
3. This comment will be forwarded to the SDT
4. The compliance enforcement program does give the compliance monitor latitude to consider extenuating circumstances.
5. There are other standards that require coordination of comments
FRCC
There are many standards being addressed (Disturbance Monitoring, System Protection Coordination,
Reliability Coordination, along with Regional standard developments). As these standards are
integrated into PRC-005, the existing and new terminology should be consistently applied in all
system protection standards (with respect to defined terms). Where terms are undefined or being
revised, the drafting team should carefully consider the terms used to ensure coordination of revised
or new definitions with other Reliability standards or flag conflicts within the implementation plan.
Response: Thank you for your comment, your observation will be forwarded to the SDT for consideration.
NPCC CP9 RSWG
Due consideration should be given to potential difficulties in obtaining required outages. System
HQT
reliability concerns may preclude performing maintenance at the intervals required. Certain
unavoidable delays like the inability to schedule outages for reliability reasons, labor disputes, or
force-majeure conditions could affect testing period requirements. These factors should be considered
and certain latitude needs to be provided, with "appropriate" approvals, for delays in the testing
process.
There is need to specify which types of relays will be covered by the new standard. The SAR Team
needs to focus on better defining the Generator Protection Schemes (“GPS”) that would be subject to
this Standard – i.e., what subset of GPS are critical to bulk power system operation, as distinct from
generator operation. For example, typically there is no single generating unit that would, if a
contingency event occurs on that generating unit, result in significant adverse impacts outside of the
local area in which the single generating unit is located. As a result, if these NERC Standards are to
apply to all NERC-registered Generators, only a subset of the GPS need to be subjected to the
maintenance testing intervals.
Response: 1. The compliance enforcement program does give the compliance monitor latitude to consider extenuating
circumstances.
Page 18 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #6
Commenter
Comment
2 Your second comment will be forwarded to the SDT for consideration
Manitoba Hydro
Manitoba Hydro takes exception to the prescriptive nature of the proposed changes to the
maintenance procedures and maintenance intervals. The type of maintenance performed and the
minimum maintenance intervals should be determined by the utility within the operating context of
the protection system. There is no need for the standard to reflect the inherent difference between
various protection system technologies as the utility would account for differences within their stated
maintenance practices.
Response: The proposed changes will improve clarity which should benefit reliability. While Manitoba Hydro may have an
excellent record of maintenance, the existing standards are quite vague and allow an entity that performs maintenance once
every 100 years to be fully compliant.
Pepco Holdings
This SAR will bring needed coherence to what are now several related standards.
Response: Thank you
SRP
None.
PSC SC
N/A
Consumers Energy
None.
SWTC
N/A
FirstEnergy
None.
Page 19 of 19
July 26, 2007
Consideration of Comments on Draft Standard Version 1 Protection System
Maintenance and Testing — Project 2007-17
The Protection System Maintenance and Testing SDT thanks all commenters who submitted
comments on PRC-005-2 — Protection System Maintenance standard. This standard was
posted for a 45-day public comment period from July 24, 2009 through September 8, 2009.
Stakeholders were asked to provide feedback on the Standard through a special electronic
comment form. There were 57 sets of comments, including comments from more than 130
different people from over 75 companies representing all of the 10 Industry Segments as
shown in the table on the following pages.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
The SDT proposed to change the name of the draft standard from “Protection System
Maintenance and Testing” to “Protection System Maintenance”, and to include testing as one
component of “Protection System Maintenance Program”, which will be a defined term. The
majority of stakeholders agreed with both the change in the name of the draft standard and
with the definition of Protection System Maintenance Program. Only two respondents
disagreed and their comments were addressed. Hence, the draft standard will now be
referred to as “Protection System Maintenance.”
Stakeholders generally disagreed with the minimum maintenance activities as well as the
maximum allowable intervals included in Tables 1a, 1b, and 1c in the draft standard. As a
result, the SDT made extensive changes to the standard and tables regarding the
maintenance activities, and made minor changes relative to the associated maintenance
intervals.
A majority of the respondents agreed with the general approaches regarding conditionbased and performance based maintenance programs but provided suggestions on
improving the clarity of the provisions within the tables and expressed concerns about
perceived administrative issues in establishing the programs. The SDT responded by
revising the tables to improve clarity and addressing the administrative concerns in its
responses to comments.
Stakeholders expressed appreciation for the “Supplementary Reference Document” and the
“Frequently-asked Questions” (FAQs) document. In its responses to the comments, the SDT
explained the relationship between the Standard and the two documents. Additionally, the
SDT addressed many of the comments in Questions 1-5 by developing additional FAQ
content, and referring the respondents to the FAQs document.
Most stakeholders were unaware of any conflicts between the proposed standard and any
business practices; however, a few commented that conflicts possibly existed with existing
business practices or with other organizations such as the Nuclear Regulatory Commission.
The SDT provided clarifying explanations to illustrate that conflicts are not actually present.
Stakeholders made numerous comments and suggestions resulting in substantial changes to
the draft Standard, the Supplemental Reference Document, the FAQs, and minor changes to
the draft Implementation Plan.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Index to Questions, Comments, and Responses
1.
The SDT proposes to change the name of the draft standard from “Protection System
Maintenance and Testing” to “Protection System Maintenance”, and to include testing
as one component of “Protection System Maintenance Program”, which will be a
defined term. Do you agree? If not, please explain in the comment area. ................ 11
2.
Within Table 1a, Table 1b, and Table 1c, the draft standard establishes specific
minimum maintenance activities for the various types of devices defined within the
definition of “Protection System”. Do you agree with these minimum maintenance
activities? If not, please explain in the comment area. ........................................... 18
3.
Within Table 1a, the draft standard establishes maximum allowable maintenance
intervals for the various types of devices defined within the definition of “Protection
System”, where nothing is known about the in-service condition of the devices. Do you
agree with these intervals? If not, please explain in the comment area. ................... 58
4.
Within Tables 1b and 1c, the draft standard establishes parameters for condition-based
maintenance, where the condition of the devices is known by means of monitoring
within the substation or plant and the condition is reported. Do you agree with this
approach? If not, please explain in the comment area. ........................................... 84
5.
Within PRC-005 Attachment A, the draft standard establishes parameters for
performance-based maintenance, where the historical performance of the devices is
known and analyzed to support adjustment of the maximum intervals. Do you agree
with this approach? If not, please explain in the comment area. .............................. 94
6.
The SDT has provided a “Supplementary Reference Document” to provide supporting
discussion for the Requirements within the standard. Do you have any comments on
the Supplementary Reference Document? Please explain in the comment area. ...... 102
7.
The SDT has provided a “Frequently-asked Questions” document to address anticipated
questions relative to the standard. Do you have any comments on the FAQ? Please
explain in the comment area. ............................................................................ 115
8.
If you are aware of any conflicts between the proposed standard and any regulatory
function, rule, order, tariff, rate schedule, legislative requirement, or agreement please
identify the conflict here. .................................................................................. 129
9.
If you are aware of the need for a regional variance or business practice that we should
consider with this project, please identify it here. ................................................ 135
10. If you have any other comments on this standard that you have not already provided in
response to the prior questions, please provide them here.................................... 140
June 3, 2010
2
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Group
Joe Spencer - SERC
staff
Additional Member
3
4
5
6
7
8
9
SERC Protection and Controls Sub-committee
(PCS)
Additional Organization
Ameren Services Co.
SERC
1, 3, 5
2. Rick Conner
E.ON Services Inc.
SERC
1, 3, 5, 6
3. Charles Fink
Entergy
SERC
1, 3, 5, 6
4. Phil Winston
Georgia Power Co.
SERC
1, 3, 5
5. Steve Waldrep
Georgia Power Co.
SERC
1, 3, 5
6. Jay Farrington
PowerSouth Energy Coop.
SERC
1, 3, 5, 6
7. Jerry Blackley
Progress Energy Carolinas
SERC
1, 3, 5, 6
8. Marion Frick
South Carolina Electric and Gas Co. SERC
1, 3, 5, 6
9. Bridget Coffman
South Carolina Public Service Auth. SERC
1, 3, 5, 6
10. George Pitts
TVA
SERC
1, 9, 3, 5
11. Ron Broocks
Va.Electric and Power Co.
SERC
1, 3, 5
12. Joe Spencer
SERC Reliability Corp
SERC
10
10
X
Region Segment Selection
1. Paul Nauert
June 3, 2010
2
3
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
2.
Group
Rick Shackleford
Green Country Energy LLC
2
3
4
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Danny Parish
SPP
5
2. Ron Zane
SPP
5
3. Dennis Bradley
SPP
5
4. Mike Anderson
SPP
5
5. Greg Froehling
SPP
5
3.
Group
Guy Zito
Additional Member
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1. Ralph Rufrano
New York Power Authority
NPCC 5
2. Alan Adamson
New York State Reliability Council, LLC
NPCC 10
3. Gregory Campoli
New York Independent System Operator
NPCC 2
4. Roger Champagne
Hydro-Quebec TransEnergie
NPCC 2
5. Kurtis Chong
Independent Electricity System Operator
NPCC 2
6. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
7. Manuel Couto
National Grid
NPCC 1
8. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
9. Brian D. Evans-Mongeon Utility Services
NPCC 8
10. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
11. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
12. Kathleen Goodman
ISO - New England
NPCC 2
13. David Kiguel
Hydro One Networks Inc.
NPCC 1
14. Michael R. Lombardi
Northeast Utilities
NPCC 1
15. Greg Mason
Dynegy Generation
NPCC 5
16. Bruce Metruck
New York Power Authority
NPCC 6
17. Chris Orzel
FPL Energy/NextEra Energy
NPCC 5
18. Robert Pellegrini
The United Illuminating Company
NPCC 1
June 3, 2010
X
4
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
19. Michael Schiavone
National Grid
20. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
21. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
22. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
23. Randy MacDonald
New Brunswick System Operator
NPCC 2
4.
Group
Jalal Babik
2
3
4
5
6
7
8
9
NPCC 1
Electric Market Policy
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Louis Slade
SERC
2. Mike Garton
6
NPCC 5
3. John Loftis
Electric Transmission
SERC
1
4. Ron Broocks
Electric Transmission
SERC
1
5.
Group
Richard Kafka
Pepco Holdings Inc. - Affiliates
Additional Member Additional Organization Region Segment Selection
1. Carlton Bradshaw
Atlantic City Electric
RFC
1
2. Ken Lehberger
Atlantic City Electric
RFC
1
3. Randal Coleman
Delmarva Power & Light
RFC
1
4. Guy Eberwein
Delmarva Power & Light
RFC
1
5. Walt Blackwell
Potomac Electric Power Co RFC
1
6.
Group
David A Szulczewski
Detroit Edison
X
X
X
Additional Member Additional Organization Region Segment Selection
1. David A Szulczewski Detroit Edison
RFC
2. Raju J Vengalil
RFC
June 3, 2010
Detroit Edison
5
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
7.
Group
Kenneth D. Brown
Public Service Enterprise Group Companies
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Scott Slickers
PSEG Power Connecticut NPCC
2. Clint Bogan
PSEG Fossil LLC
ERCOT 5
3. James Hebson
PSEG ER&T LLC
RFC
6
4. James Hubertus
PSE&G
RFC
1, 3
8.
Group
Denise Koehn
Additional Member
5
Bonneville Power Administration
Additional Organization
Region Segment Selection
1. Dean Bender
SPC Technical Svcs
2. Mason Bibles
Sub Maint and HV Engineering WECC 1
3. Laura Demory
PSC Technical Svcs
9.
Group
Sam Ciccone
WECC 1
WECC 1
FirstEnergy
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hohlbaugh
FE
RFC
2. Jim Kinney
FE
RFC
3. Eric Schock
FE
RFC
4. Allen Morinec
FE
RFC
5. Ken Dresner
FE
RFC
6. Bill Duge
FE
RFC
7. Art Buanno
FE
RFC
8. Brian Orians
FE
RFC
9. Jim Detweiler
FE
RFC
10. Ken Bunting
FE
RFC
10.
Group
Carol Gerou
Additional Member
June 3, 2010
MRO NERC Standards Review Subcommittee
Additional Organization
X
Region Segment Selection
6
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
1. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
2. Neal Balu
WPS Corporation
MRO
3, 4, 5, 6
3. Terry Bilke
Midwest ISO Inc.
MRO
2
4. Ken Goldsmith
Alliant Energy
MRO
4
5. Jodi Jenson
Western Area Power Administration MRO
1, 6
6. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
7. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
8. Alice Murdock
Xcel Energy
MRO
1, 3, 5, 6
9. Scott Nickels
Rochester Public Utilties
MRO
4
10. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
11. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
11.
Group
Deborah Schaneman
Additional Member
Platte River Power Authority Maintenance
Group
Additional Organization
2
3
4
5
X
X
X
7
8
9
Region Segment Selection
1. Scott Rowley
Platte River Power Authority WECC 7
2. Gary Whittenberg
Platte River Power Authority WECC 7
12.
Individual
James Starling
SCE&G
X
X
X
13.
Individual
Rick Koch
Nebraska Public Power District
X
X
X
14.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
15.
Individual
Kristina Loudermilk
ENOSERV
16.
Individual
Wade Davis
Otter Tail Power
17.
Individual
Alison Mackellar
Exelon Generation Company, LLC - Exelon
Nuclear
June 3, 2010
6
X
X
X
X
X
7
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
18.
Individual
Benjamin Church
NextEra Energy Resources
19.
Individual
Scott Berry
Indiana Municipal Power Agency
20.
Individual
John E. Emrich
Indianapolis Power & Light Co.
X
21.
Individual
Glenn Hargrave
CPS Energy
X
22.
Individual
Darryl Curtis
Oncor Electric Delivery
X
23.
Individual
Sandra Shaffer
PacifiCorp
X
24.
Individual
Armin Klusman
CenterPoint Energy
X
25.
Individual
Howard Gugel
Progress Energy
26.
Individual
John Moraski
BGE
27.
Individual
Dale Fredrickson
Wisconsin Electric
28.
Individual
Frank Gaffney
Florida Municipal Power Agency, and its
Member Cities as follows: New Smyrna
Beach; City of Vero Beach; and Lakeland
Electric
X
29.
Individual
Russell C Hardison
TVA
X
30.
Individual
Kirit Shah
Ameren
X
31.
Individual
Huntis Dittmar
Lower Colorado River Authority
X
32.
Individual
Brandy A. Dunn
Western Area Power Administration
X
June 3, 2010
2
3
4
5
6
7
8
9
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
8
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
33.
Individual
Robert Casey
Operations and Maintenance
X
34.
Individual
Hugh Francis
Southern Company
X
35.
Individual
Daniel J. Hansen
RRI Energy
36.
Individual
Silvia Parada-Mitchell
Transmission Owner
37.
Individual
Greg Mason
Dynegy
38.
Individual
Michael Ayotte
ITC Holdings
X
39.
Individual
Robert Waugh
Ohio Valley Electric Corp.
X
40.
Individual
Brent Ingebrigtson
E.ON U.S.
X
41.
Individual
Danny Ee
Austin Energy
X
42.
Individual
John Alberts
Wolverine Power Supply Cooperative, Inc.
43.
Individual
Willy Haffecke
44.
Individual
45.
2
3
4
X
5
7
8
9
X
X
X
X
X
X
X
X
X
X
X
City Utilities of Springfield, MO
X
X
X
Charles J. Jensen
JEA
X
X
X
Individual
Greg Rowland
Duke Energy
X
X
X
46.
Individual
Bob Thomas
Illinois Municipal Electric Agency
47.
Individual
Scott Barfield-McGinnis
Georgia System Operations Corporation
X
X
48.
Individual
Jianmei Chai
Consumers Energy Company
X
X
49.
Individual
Vladimir Stanisic
Ontario Power Generation
June 3, 2010
6
X
X
X
X
X
X
9
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
5
6
X
X
X
X
X
X
X
50.
Individual
James H. Sorrels, Jr.
AEP
X
51.
Individual
Jason Shaver
American Transmission Company
X
52.
Individual
Edward Davis
Entergy Services, Inc
X
X
53.
Individual
W. Guttormson
Saskatchewan Power Corporation
X
X
54.
Individual
Alice Murdock
Xcel Energy
X
X
55.
Individual
Martin Bauer
US Bureau of Reclamation
June 3, 2010
4
X
7
8
9
X
10
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
1. The SDT proposes to change the name of the draft standard from “Protection System Maintenance and Testing”
to “Protection System Maintenance”, and to include testing as one component of “Protection System
Maintenance Program”, which will be a defined term. Do you agree? If not, please explain in the comment
area.
Summary Consideration: The majority of the respondents agreed with both the change in the name of the draft standard
and with the definition of Protection System Maintenance Program. Some comments were offered, most of which were
answered by explanation of the rationale of the SDT.
Organization
Yes or No
US Bureau of Reclamation
No
Question 1 Comment
1. The alteration of the program to include testing as a component does not add value to system reliability.
The existing requirement can only be completed with procedures that some of the elements listed under
the program. The proposed program is far too restrictive in the manner in which it requires specific
actions and thereby excludes others.
2. The program element for monitoring is listed; however, the monitoring is intended to be used through an
electronic subsystem and does not allow for observations by experienced technical staff.
3. Testing is listed; however, the definition is limited to the application of signals and precludes other
procedures.
4. Further, the definition of Protection System proposed is a nested definition which tends to expand the
number of devices covered (any device that has voltage and current sensing inputs) irrespective of their
impact on the BPS.
Response: The SDT thanks you for your comments.
1. Maintenance includes a number of actions, one of which is testing; inspections, etc are also part of maintenance. One option is to separately
identify each type of activity, another is to combine the types of activities within the overall Maintenance activity and address the specific activity
type where relevant. As for including some activities and excluding others, the listed activities are contemplated as minimum activities and do not
preclude an entity from performing additional activities.
2. If a facility is attended, the observation of locally-alarmed conditions by on-site personnel, within the time intervals expressed in the monitoring
attributes, can satisfy these requirements. Adequate documentation should be available that the facility is indeed attended, and that the on-site
personnel observe the related items. See FAQ V-1-D (page 30)
3. Nothing is precluded; minimum activities are specified, and entities may use additional approaches.
4. This concern is addressed by the applicability of the standard, where the applicability is limited to “Protection Systems that are applied on, or are
June 3, 2010
11
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 1 Comment
designed to provide protection for the BES”.
Wolverine Power Supply
Cooperative, Inc.
No
Wolverine Power has concern about the level of "prescription" in this standard draft. The intent of the
standards is to define what, not how. This draft gets unnecessarily prescriptive in our opinion, particularly in
the table
Response: The SDT thanks you for your comments. The SDT believes that the level of prescription within the standard is necessary to satisfy the
guidance in FERC Order 693, and also to address observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC005-1 is excessively general. FERC Order 672 also specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined
the minimum activities necessary to implement an effective PSMP.
AEP
Yes
American Transmission
Company
Yes
Austin Energy
Yes
Bonneville Power Administration
Yes
City Utilities of Springfield, MO
Yes
Consumers Energy Company
Yes
CPS Energy
Yes
Detroit Edison
Yes
Duke Energy
Yes
Dynegy
Yes
ENOSERV
Yes
Entergy Services, Inc
Yes
June 3, 2010
12
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Florida Municipal Power Agency,
and its Member Cities
Yes
Georgia System Operations
Corporation
Yes
Green Country Energy LLC
Yes
Illinois Municipal Electric Agency
Yes
Indiana Municipal Power Agency
Yes
Indianapolis Power & Light Co.
Yes
ITC Holdings
Yes
Lower Colorado River Authority
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NextEra Energy Resources
Yes
Northeast Power Coordinating
Council
Yes
Ohio Valley Electric Corp.
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
June 3, 2010
Question 1 Comment
13
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Otter Tail Power
Yes
PacifiCorp
Yes
Pepco Holdings Inc.
Yes
Platte River Power Authority
Maintenance Group
Yes
Progress Energy
Yes
Public Service Enterprise Group
Companies
Yes
RRI Energy
Yes
Southern Company
Yes
Transmission Owner
Yes
TVA
Yes
Western Area Power
Administration
Yes
Wisconsin Electric
Yes
Xcel Energy
Yes
FirstEnergy
Yes
June 3, 2010
Question 1 Comment
Although we agree with the change in the title of the standard, as well as the proposed definition of
"Protection System Maintenance Program", we feel that the definition could be clarified. With regard to
"Restoration", which at present is described as "The actions to restore proper operation of malfunctioning
components", it may be helpful to add examples of acceptable actions to restore operations, such as
calibration, repair, replacement, etc.
14
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 1 Comment
Response: The SDT appreciates your support and comments. An FAQ document is included that addresses your comment related to an example of
acceptable operations to restore operations. See FAQ II-2-B. (page 5)
JEA
Yes
Generally agree; however, some suggestions for possible changes:
1) change "associated communication systems necessary for correct operation of protective devices" to
"protective relays",
2) add a PSMP glossary definition for an acceptable type of monitored alarm, either to the proposed "PSMP
monitor" or another definition for "PSMP monitored and alarmed." The SDT did a good job of making the
overall Protection System definition clearer.
Response: The SDT appreciates your support and comments.
1) “Protective relays” is too specific a term here; it excludes applications such as logic-based direct transfer trip that provides protective functions.
2) The SDT disagrees that the proposed definition is necessary. Guidance on this issue is included in the FAQ. See FAQ V-1-A (page 28)
MRO NERC Standards Review
Subcommittee
Yes
N/A
Exelon Generation Company,
LLC
Yes
None
Saskatchewan Power
Corporation
Yes
Saskatchewan would like clarification of what the expectations and rationale are for including Restoration in
the PSMP. The other terms listed under the PSMP definition represent what we would consider as typical
relay maintenance activities. We would typically consider Restoration as an Operational activity. The existing
NERC standards seem to treat this as an Operator concern addressed in PRC-001 R2.1 and R2.2 (The
Operator shall take corrective action as soon as possible). If Restoration is included in PRC-005 doesn't
PRC-001 have to be modified as well to remove these references? Saskatchewan would also like
clarification on the term upkeep. Is the standard prescriptive and mandate the application of the latest
firmware upgrades within a defined period, or is it flexible and can upgrades be applied as the utility deems
necessary?
Response FAQ II-2-B (page 5) explains that restoration is the “corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction” and provides extensive discussion contrasting “restoration” in this context from
“restoration” in a system operations context. Examples are also discussed. Note that the word, ‘restoration’ is capitalized in the definition, but this
capitalization is for consistent format by capitalizing the first letter of each word in each bulleted phrase – the word was not capitalized to show that
June 3, 2010
15
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 1 Comment
the term is using the approved definition of ‘Restoration.’
SCE&G
Yes
The SDT is to be commended for developing a clear and well documented draft. Overall it provides a
balanced view of Protection System Maintenance, and good justification for its maximum intervals.
Response: The SDT appreciates your support.
Ameren
Yes
1. We commend the SDT for developing such a clear and well documented first draft. It generally provides a
well reasoned and balanced view of Protection System Maintenance, and good justification for its maximum
intervals. Our existing M&T Program has and continues to yield a very reliable BES with mostly similar
intervals, though some are longer and others shorter. We strongly support the almost all of the applicability
revision, which clarifies the boundary of NERC maintenance and testing oversight.
2. We question the addition of UFLS station DC Supply, auxiliary relays, and Generating facility systemconnected station service transformers. Have these components been a significant source of problems
leading to cascading outages?
3. The SDT also modifies the Protection System definition, mostly clarifying the boundaries. We generally
agree except that we recommend adding “fault” before “interrupting devices”.
Response:
1. The SDT appreciates your support and comments.
2. The standard is not focused only on causes of “cascading outages”; it is focused on “Protection Systems that are applied on, or are designed to
provide protection for the BES” and on maintenance of the UFLS systems. The components addressed in the comment are all part of the BES, or the
UFLS. As for the DC supply to the UFLS, it is a component that is necessary for the UFLS to function properly. FAQ II-4-D (page 11) discusses what
auxiliary tripping relays are actually included, and FAQ III-2-A (page 20) provides a discussion of station service (auxiliary) transformers and their
inclusion in this standard.
3. The “Interrupting devices” is a term that addresses the actions of UFLS, UVLS, and SPS, as well as the actions to clear faults.
Electric Market Policy
Yes
We commend the SDT for developing such a clear and well documented first draft. In general, it provides a
well reasoned and balanced view of Protection System Maintenance.
Response: The SDT appreciates your support.
SERC (PCS)
June 3, 2010
Yes
We commend the SDT for developing such a clear and well documented first draft. It generally provides a
well reasoned and balanced view of Protection System Maintenance, and good justification for its maximum
16
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 1 Comment
intervals.
Response: The SDT appreciates your support
AECI
Yes
Puget Sound Energy
Yes
June 3, 2010
17
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
2. Within Table 1a, Table 1b, and Table 1c, the draft standard establishes specific minimum maintenance activities
for the various types of devices defined within the definition of “Protection System”. Do you agree with these
minimum maintenance activities? If not, please explain in the comment area.
Summary Consideration: Most of the respondents disagreed with the minimum maintenance activities to some degree or
another. The disagreement ranged over the full spectrum of activities specified in the Tables, resulting in numerous changes to
the standard in response to comments.
Organization
Yes or No
ITC Holdings
No
Question 2 Comment
1. (FAQ 3C) What is the technical justification for omitting insulation testing of the wiring for DC control,
potential and current circuits between the station-yard equipment and the relay schemes? We feel this
wiring is susceptible to transients which, over time, may compromise the insulation, and therefore should
be tested.
2. 2. Table 1a (Page 6) Improve wording. Suggestion: “Verify proper functioning of the current and voltage
circuits from the voltage and current sensing devices to the protective relay inputs”
3. On Page 6: The red light monitors trip circuit not only trip coil. With only one circuit going to three parallel
single-pole trip coils a red light will not detect a single open trip coil. Is a station inspection that verifies
the red light is “on” an acceptable activity?
4. On Page 9: The 3 month communications maintenance activities should say that the channel needs to be
checked. For example: initiate a manual checkback test of the carrier system.
5. On Page 10: Not clear on level 2 monitoring attributes for protective relay component description. As
written it notes two separate requirements which are ambiguous. We assume that all monitoring noted is
required (internal self diagnosis and waveform sampling)?
6. On Page7: The standard should note that battery testing must include all batteries that are used in
protective relay systems (for example pilot wire batteries).
Response: The SDT thanks you for your comments.
1. The SDT does not believe that insulation testing needs to be included within the minimum required maintenance activities; the SDT is not aware of a
body of evidence that suggests that these tests should be included as a requirement. The proposed standard does not prevent an entity from
including such tests in its program if its experience indicates that such testing is needed.
2. The SDT has modified the standard in consideration of your suggestion and the suggestions of others as shown:
June 3, 2010
18
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
Verify proper functioning of the current and voltage circuit signals necessary for Protection System operation from the voltage and current sensing devices to
the protective relays.
3. The SDT has modified the standard to remove the requirement cited in this comment as shown below:
4. The SDT has modified the standard in consideration of your suggestion as shown below:
Verify that the Protection System communications system is functional.
See FAQ II-6-B for suggestions related to methodology.
5. Yes. For level 2 monitoring, all attributes must be satisfied. The SDT has modified the standard to clarify as shown below:
Includes:
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures.
•
Input voltage or current waveform sampling three or more times per power cycle
•
Conversion of samples to numeric values for measurement calculations by microprocessor electronics that are also performing self diagnosis and
alarming.
6. The proper functioning of such batteries will be addressed by the verification and monitoring of the communications system, and by addressing
maintenance correctable issues related to the communications system.
Green Country Energy LLC
No
1) Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) also The maintenance
activity causes excessive breaker operation, and the intrusive nature increases the risk of subsequent
misoperations on operating units. System configuration of many plants will require an extensive interruption of
total plant production to complete the test.
2) Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS systems only) The maintenance activity
causes excessive breaker operation, and the intrusive nature increases the risk of subsequent misoperations
on operating units. System configuration of many plants will require an extensive interruption of total plant
production to complete the test.
Response: The SDT thanks you for your comments.
1. The overall Protection System Control Circuitry can be addressed in segments, as long as all portions are verified or tested as required.
Depending on the arrangement of the DC control circuit, it may be necessary to only trip the breaker itself once. See FAQ II-4-E. (page 11)
2. The overall Protection System Control Circuitry can be addressed in segments, as long as all portions are verified or tested as required.
June 3, 2010
19
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
Depending on the arrangement of the DC control circuit, it may be necessary to only trip the breaker itself once. See FAQ II-4-E. (page 11)
Public Service Enterprise Group
Companies
No
1) Table 1a Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only). Currently, we test
our UFLS relays on a 2 year maintenance interval. We test the relays and associated DC circuitry up to the
DC lockout relays. It would require extraordinary effort to trip the breakers directly when performing these
tests. Usually, each UFLS relay will trip several feeder breakers. This requirement states that we need to
check the trip coil for each of those breakers each time we perform relay maintenance. This will add an
unreasonable amount of time and effort to reliably switch out several 4kV or 13kV feeders every time we
perform UFLS maintenance. For UFLS and UVLS schemes, we feel the requirement for DC control testing
should not go past the lockout relay. The standard says to perform trip checks at the same time as UF
maintenance. We test the relays on a 2 year interval right now. It is unreasonable to perform trip checks this
often. The trip checks should follow a 6 year span (or longer) just like the BES equipment.
2) Table 1a DC supply. The 18 month inspection requires a measurement of specific gravity and
temperature. We believe that if a battery owner opts to perform an 18 month ohmic value test, this combined
with the cell voltage readings and continuity tests will give a good indication of battery health. We do not feel
that the measurement of specific gravity is required in conjunction with the tests performed above.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment as shown below:
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits, including all electromechanical trip and
auxiliary contacts essential to proper functioning of the Protection System, except that verification does not require actual tripping of circuit breakers or
interrupting devices.
See FAQ II-8-D (page 19) for a discussion on this.
2. The SDT has modified the standard in consideration of your comment and this has been deleted.
Wisconsin Electric
No
1. Page 7 Station DC Supply (Batteries): The activity to verify proper electrolyte level should only apply to
unstaffed (unmanned) stations; checking battery electrolyte levels is routinely done in generating stations,
which are staffed with personnel continuously (24 x 7). In addition, the three activities listed here with a 3
month interval for batteries (electrolyte, voltage, grounds) should NOT require documentation for compliance
purposes. It should be sufficient that these routine and recurring activities (every 3 months) are identified in
the Maintenance Plan. Otherwise the administrative burden to provide documentation will become excessive
and counterproductive to assuring BES reliability.
2. Page 7 Station DC Supply (Batteries): The 18 month interval includes an activity to verify the battery
charger equalize voltage. This activity is normally done only when the bank is load tested. Therefore the
June 3, 2010
20
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
activity to verify equalize voltage of a charger should have a 6 year interval along with the other battery
charger activities to verify full rated current and current-limiting.
3. Page 9 Communications Equipment: Similar to #1 above, the activity to verify monitoring and alarms
should NOT require documentation in order to demonstrate compliance. Having these routine 3 month
activities in the Maintenance Plan is sufficient. This needs to be clarified in the standard. Also, this
requirement should be re-worded to refer to generating stations also, not just substations.
4. Page 11 Station DC Supply (Batteries): Like #1 above, the similar requirement in Table 1b for verifying
battery electrolyte levels should be revised to indicate that documentation is NOT required.
5. Page 6 Prot System Control Circuitry: Like #1 above, the 3 month activity to verify continuity of breaker
trip circuits is fine, but there should be no requirement to document the readings or observations; it is
sufficient that this activity be addressed in the Maintenance Plan, especially for staffed generating stations.
6. Page 6 Prot System Control Circuitry: For the 6 year activity to "perform a functional trip test...": is this a
requirement to actually trip the circuit breaker ? If yes, this should be stated clearly in the Maintenance
Activity description.
7. We are concerned that the Maintenance Activities are not appropriate for certain equipment. The RFC
definition of Bulk Electric System includes any protection equipment that can trip a BES facility independent of
voltage level. As an LSE, this includes distribution-level equipment that was not designed to the same level of
redundancy as Transmission equipment. Complying with the requirements for control circuitry functional
testing and current sensing device testing will actually decrease system reliability since this often cannot be
accomplished without requiring outages to major distribution system components and/or temporarily breaking
protection circuits. We propose that this type of testing on distribution systems which fall under the definition
of BES Protection Systems should be addressed separately from the rest of the BES Protection Systems in
this standard. The intervals and/or maintenance activities should reflect the differences in how these
distribution protection systems are designed and operated.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment. The revised standard requires the responsible entity to “check” the
following every 3 calendar months:
• Electrolyte level (excluding valve-regulated lead acid batteries)
• Station dc supply voltage
• Unintentional grounds
2. The SDT has modified the standard in consideration of your comments regarding DC supply and the reference to “equalize voltages” has been
June 3, 2010
21
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
removed
3. The word “substation” has been removed from this requirement. Documentation of completion of required maintenance activities will likely be
necessary to demonstrate compliance.
4. The SDT has modified the standard in consideration of your comments to require checking of electrolyte levels, instead of verification.
Documentation of completion of required maintenance activities will likely be necessary to demonstrate compliance.
5. The SDT has modified the standard to remove the requirement cited in your comment.
6. Yes. The intent here is that the entire dc control circuit, including the breaker trip coil, be exercised. This was changed to read as follows:
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits, including all electromechanical trip and
auxiliary contacts essential to proper functioning of the Protection System.
7. As established in 4.2.1, this standard applies to all Protection Systems that are “Protection Systems that are applied on, or are designed to provide
protection for the BES”.
Exelon Generation Company,
LLC
No
1. Minimum maintenance activities should be on a yearly multiplier verses a monthly multiplier. Nuclear
generating stations are typically on an 18-month or 24-month refueling cycle. The draft standard does not
take into consideration a nuclear generators refueling cycle. Specifically, most Boiling Water Reactors
(BWRs) are on a 24-month refueling cycle and may run continuously between refueling outages. Performing
maintenance on-line puts the generating unit at risk without any commensurate increase in reliability to the
bulk electric system.
2. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's
refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing
of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing
programs.
3. Activities that begin with "verify" should be modified to "Validate…are/is within acceptable limits. Initiate
corrective actions as required." For example, some levels of DC grounds are acceptable based on circuit
design and component installation. Troubleshooting or ground isolation may increase the risk to the system
depending on ground magnitude and conditions.
4. Please provide clarification on "verify that no dc supply grounds are present" most stations have some level
of ground current. Should this be interpreted to be a measure of resistance or current values? Suggest
rewording to say "Check and record unintentional battery grounds"
5. "Verify Station Battery Chargers provides the correct float and equalize voltage" should be deleted.
Equalizing a battery is a maintenance function and should only be performed as needed. Suggest rewording
June 3, 2010
22
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
to say "Check and record charger output current and voltage."
6. Activities associated with Battery Charger performance should be deleted. The ability of the Battery
Charger to maintain the battery at full charge state is verified by checking proper "float voltage." The ability to
provide full rated current only affects the ability to recharge a battery AFTER an event has occurred.
7. In Table 1a does the requirement to "verify proper electrolyte level" refer to all batteries or only a sampling?
Current practice is to use the "pilot cell" as the monitoring cell as this cell is usually the least healthy of the
battery bank from a specific gravity and/or voltage standpoint. If the pilot cell continues to degrade then the
other batteries will be monitored more often. Suggest rewording to "Check electrolyte level."
8. In Table 1a the 18-month requirement to measure that the specific gravity and temperature of each cell is
within tolerance is "where applicable" what does "where applicable" mean?
9. For the Station dc supply (battery is not used) 18-month interval should this be interpreted that it is just the
battery charger with no attached battery? Or a dc supply system that does not contain a battery?
10. Table 1a Station dc supply 18-month interval to verify cell-to-cell and terminal connection resistance is
within "tolerance" should be revised to say "tolerance or acceptable limits."
11. Table 1a Station dc supply (that has as a component valve regulated lead-acid batteries) should provide
an additional optional activity for "Total replacement of battery at an interval of four (4) years" in lieu of not
conducting performance or service capacity test at maximum maintenance interval.
Response: The SDT thanks you for your comments.
1. The activities that are on an interval less than one calendar year are all “inspection” type activities, rather than “testing” activities. The SDT
requests more specificity as to your concerns.
2. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8.4 of the Supplementary Reference Document
(page 13) and FAQ IV-2-D (page 23) for a discussion on this issue.
3. The SDT has modified the standard and Frequently Asked Questions document (See FAQ II-5-I, page 15) in consideration of your comments about
dc grounds.
4. The SDT has modified the standard and Frequently Asked Questions document (See FAQ II-5-I, page 15) in consideration of your comments about
June 3, 2010
23
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
no dc supply grounds being present. The language in the standard was changed to: Check for unintentional grounds
5. The SDT has modified the standard in consideration of your comments – the phrase, “equalize voltages,” was deleted
6. The performance of the battery charger is critical to the performance of the protection system. The SDT has modified the standard to simplify the
requirements related to maintenance of the battery charger.
7. The SDT has modified the standard in consideration of your comments. The Maintenance Activity related to electrolyte level of batteries has been
changed from “verify proper” to “check” electrolyte levels. This Maintenance Activity refers to every individual cell in a non-VLRA station battery,
similar to recommendations in the relevant IEEE Standards.
8. The SDT has modified the standard in consideration of your comments. The requirement to measure that the specific gravity and temperature of
each cell is within tolerance is "where applicable" has been deleted.
9. The FAQ II-5-A (page 12) addresses your question concerning “Station dc supply (battery is not used)” by explaining that “a Station dc supply where
a battery is not used” is a situation where another energy storage technology besides a battery is used prevent loss of the station dc supply when ac
power to the station dc supply is lost.
10. The SDT has modified the standard in consideration of your comments regarding cell-to-cell and terminal connection resistance – the phrase,
“within tolerance” was deleted – and the requirement was subdivided to clarify that the entity must “verify battery terminal connection resistance and
verify battery cell-to-cell connection resistance.”
11. The SDT believes that the maintenance activities specified in Table 1a for VRLA batteries are necessary to assure that the station battery will
perform reliably and that replacement of the battery every four years in lieu of such testing would not provide such assurance. The SDT is providing
the option of either capacity testing (every three years) or measuring individual cell/unit ohmic values (every three months) and trending the test
results against the station battery’s baseline to allow entities to choose which of these activities best address their facilities. Total replacement of a
VRLA battery with a properly-performing new battery, 3 calendar years after installation of the original battery, is in compliance with Table 1a of this
standard. See FAQ IV-2-A (page 22) & IV-2-B (page 23) for a discussion about commissioning tests and how they relate to establishing a baseline.
US Bureau of Reclamation
No
1. The basis for developing the maintenance intervals was adequately explained. It is understood that FERC
would like uniform intervals; the intervals do not recognize the tremendous variation in installation and
equipment and possibly manufacturer recommendation. Point in fact is the interval for listed for
electromechanical relays. Some of these relays must be calibrated every year or three years on the outside.
Relays that have a history of stable performance based on consistently good test results.
2. The intervals for battery maintenance are not reasonable. The capacity testing at 3 years is higher than
the 5 year which battery manufactures require.
Response: The SDT thanks you for your comments.
1. The proposed standard does not prevent an entity from including such tests in their program if their experience has indicated that such testing is
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
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Question 2 Comment
needed.
2. The 3-year capacity test is specifically for Valve Regulated Lead-Acid batteries (VRLA); Vented Lead-Acid batteries require a 6-year capacity test.
Due to the failure mode and designed service life of Valve Regulated Lead-Acid (VRLA) batteries compared to a Vented Lead-Acid batteries, the SDT
believes that extending capacity testing of a VRLA battery beyond the maximum maintenance interval of 3 calendar years in Table 1a cannot be
justified regardless of what the battery manufacturers recommend.
MRO NERC Standards Review
Subcommittee
No
A. In the tables, the term “verification” should be switched with “check”.
B. The verification activities include testing for “specific gravity” in batteries. Since “impedance testing” will
give you the same results or similar results; revise the tables to reflect this, as well.
C. Another question deals with the table title verbiage. Table 1a and 1c are labeled as Protection Systems,
while Table 1b is Protection System Components. One could interpret table 1c as saying that if any one
component of the protection system in question is not in compliance with level 3 monitoring stipulations, then
every component must be degraded to level 2 monitoring as so forth. This needs to be clarified.
D. Some activities, such as complete functional testing, could lead to reduced levels of reliability, because [1]
it requires removing elements of the transmission system from service and [2] it requires performing tests that
are inherently prone to human errors. The MRO NSRS does not believe the perceived benefits justify the
anticipated costs.
E. In the tables, under Table 1a and Protection system communications equipment and channels, a technical
justification should be provided to show that performance and quality channel testing would result in the
reduction of regional disturbances and blackouts. Quality and performance testing is subjective. Subjective
tests are inherently poor compliance measures. The requirements to measure, document, store, and prove
channel quality data is a poor use of limited compliance resources.
F. In the tables, under Table 1a and Station DC supply (and anywhere else), equalize (battery) voltages
should be eliminated. Equalizing battery voltages reduces battery life and do not provide a significant gain in
overall system reliability to offset the loss of battery life.
G. In the tables, under Table 1a and Station DC supply (and anywhere else), delete the reference to
measuring the fluid temperature of “each cell”. A technical basis should be demonstrated that shows why
individual cell fluid temperature measurement would reduce the occurrence of regional disturbances. If fluid
temperature measurement remains in the standard, a single fluid temperature measurement per battery bank
should be sufficient to demonstrate that the battery bank was performing within normal parameters. The
compliance burden to add fluid temperature measurements for each cell is unwarranted and reduces
compliance personnel resources that could be utilized on more important reliability activities.
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Response: The SDT thanks you for your comments.
A. The SDT has modified the tables in consideration of your comments regarding “verification” vs. “checking”.
B. The SDT has modified the standard in consideration of your comments – the term, “specific gravity” is not used in the revised standard
C. The SDT has modified Tables 1a and 1c in consideration of your comments. The subheading of Table 1a and 1c were modified, replacing,
“Systems” with “System Components.”
D. To minimize system impact of such maintenance and possible errors, the maintenance necessarily should be scheduled at a time that minimizes the
risks.
E. Many utilities have long history that emphasizes that maintenance of communications systems is critical to assuring the proper performance of
these systems. The intervals were determined based on the experiences of SDT and NERC System Protection and Task Force members. Additionally,
this standard is not focused only on avoiding regional disturbances or blackouts, but instead on overall Protection System reliability. See
Supplementary Reference Document, Section 15.5 (page 23) and FAQ II-6-D (page 17).
F. The SDT has modified the standard in consideration of your comments. The requirement to “equalize battery voltages” was removed from the
revised standard.
G. The SDT has modified the standard in consideration of your comments and all references to measuring “temperature” have been removed from the
revised standard.
CenterPoint Energy
No
a. CenterPoint Energy believes the approach taken by the SDT is overly prescriptive and too complex to be
practically implemented. The inflexible minimum “maintenance activities” approach fails to recognize the
harmful effects of over-maintenance and precludes the ability of entities to tailor their maintenance program
based on their configurations and operating experience. In particular, the loss of maintenance flexibility
embodied in this approach would have perverse consequences for entities with redundant systems. Entities
with redundant systems have less need for maintenance of individual components (due to redundancy) yet
have twice the maintenance requirements under the minimum “maintenance activities” approach. For
example, Table 1A calls for performing a specific gravity test on “each cell” of vented lead-acid batteries.
CenterPoint Energy believes such a requirement is dubious for entities that do not have redundant batteries,
and absurd for entities that do. CenterPoint Energy has installed redundant batteries in most locations and
has had an excellent operating history with batteries by using a combination of internal resistance testing and
specific gravity testing of a single “pilot cell”. This practice, combined with DC system alarming capability, has
worked well.
b. CenterPoint Energy is opposed to approving a standard that imposes unnecessary burden and reliability
risk by imposing an overly prescriptive approach that in many cases would “fix” non-existent problems. To
clarify this last point, CenterPoint Energy is not asserting that maintenance problems do not exist. However,
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requiring all entities to modify their practices to conform to the inflexible approach embodied in this proposal,
regardless of how existing practices are working, is not an appropriate solution. Among other things,
requiring entities to modify practices that are working well to conform to the rigid requirements proposed
herein carries the downside risk that the revised practices, made solely to comply with the rigid requirements,
degrade reliability performance.
c. Arguably, an entity could possibly return to its existing practices, if those practices are working well, by
navigating through the complex set of options and supporting documentation that the SDT has crafted in this
proposal. However, most entities have an army of substation technicians with various ranges of experience
to perform maintenance on protection systems and other substation components. It is unrealistic to expect
most entities making a good faith effort to comply with this proposal to have a full understanding throughout
the entire organization of all the nuances crafted into this complex proposal.
d. For the reasons outlined above, CenterPoint Energy does not agree with the proposal to specify minimum
maintenance activities. However, if the majority of industry commenters agree with the SDT’s proposal,
CenterPoint Energy has concerns about some of the proposed tasks. For Protection System control circuitry
(trip circuits), Table 1A calls for performing a complete functional trip test. The “Frequently-asked Questions”
document states that this “may be an overall test that verifies the operation of the entire trip scheme at once,
or it may be several tests of the various portions that make up the entire trip scheme”. Such a requirement
creates its own set of reliability risks, especially when monitoring already mitigates risks. CenterPoint Energy
is concerned with this standard promoting an overall functional trip test for transmission protection systems.
This type of testing can negatively impact reliability with the outages that are required and by exposing the
electric system to incorrect tripping. CenterPoint Energy views overall functional trip testing as a
commissioning task, not a preventive maintenance task. CenterPoint Energy performs such testing on new
stations and whenever expansion or modification of existing stations dictates such testing. Overall,
CenterPoint Energy recommends minimizing, to the extent possible, maintenance activities that disturb the
protection system; that is, placing the protection system in an abnormal state in order to perform a test.
e. For Protection System control circuitry (breaker trip coils only), Table 1A calls for verifying the continuity of
the trip circuit every 3 months. CenterPoint Energy is not sure what would be the expected task to meet this
requirement (it is not addressed in the “Frequently-asked Questions” document).
Response: The SDT thanks you for your comments.
a) The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. Regardless of the level of redundancy provided, all components addressed by this
standard must be maintained in accordance with the requirements of the standard. The SDT has therefore defined the minimum activities necessary to
implement an effective PSMP. The SDT has modified the standard in consideration of your comments concerning performing a specific gravity test
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
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and the revised standard does not require a specific gravity test.
b) ) The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The opportunities in R3 provide additional flexibilities for entities which desire
them.
c) For those entities which wish the least complex approach, a pure time-based program, using R1, R2, and R4, with Table 1a provides the simplest
approach to meeting this standard.
d) The SDT believes that functional trip testing is a key component of an effective PSMP.
e) See the Supplemental Reference Document, Section 15.3 (page 22) for a discussion on this topic.
NextEra Energy Resources
No
a. Tables 1a, 1b & 1c should offer as an alternative, measuring battery float voltages and float currents in lieu
of measuring specific gravities as described in Annex A4 of IEEE Std 450-2002.
b. Inspection of CVT gaps, MOVs and gas tubes should be added to the communications equipment time
based maintenance tables. Failure of the CVT protective devices may cause failure of the Protection System.
c. Maintenance Activities for UVLS or UFLS station dc supplies shows “Verify proper voltage of dc supply”.
Does this imply that, except for voltage readings of the dc supply, distribution battery banks are not
maintained?
d. Why does the Maintenance Activities for UVLS or UFLS relays state that verification does not require
actual tripping of circuit breakers?
e. Please clarify the Maintenance Activities for Voltage and Current Sensing Devices. Must voltage, current
and their respective phase angles be measured at each discrete electromechanical relay?
f. NextEra Energy concurs with other entities comments concerning this question: This entity believes the
approach taken by the SDT is overly prescriptive and too complex to be practically implemented. The
inflexible “minimum maintenance activities” approach fails to recognize the harmful effects of overmaintenance and precludes the ability of entities to tailor their maintenance program based on their
configurations and operating experience. In particular, the loss of maintenance flexibility embodied in this
approach would have perverse consequences for entities with redundant systems. Entities with redundant
systems have less need for maintenance of individual components (due to redundancy) yet have twice the
maintenance requirements under the “minimum maintenance activities” approach. For example, Table 1A
calls for performing a specific gravity test on “each cell” of lead acid batteries. Our company believes such a
requirement is dubious for entities that do not have redundant batteries, and absurd for entities that do. We
have installed redundant batteries in most locations and have had an excellent operating history with batteries
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by using a combination of internal resistance testing and specific gravity testing of a single “pilot cell”. This
practice, combined with DC system alarming capability, has worked well. We are opposed to approving a
standard that imposes unnecessary burden and reliability risk by imposing an overly prescriptive approach
that in many cases would “fix” non-existent problems. To clarify this last point, we are not asserting that
maintenance problems do not exist. However, requiring all entities to modify their practices to conform to the
inflexible approach embodied in this proposal, regardless of how existing practices are working, is not an
appropriate solution. Among other things, requiring entities to modify practices that are working well to
conform to the rigid requirements proposed herein carries the downside risk that the revised practices, made
solely to comply with the rigid requirements, degrade reliability performance. Arguably, an entity could
possibly return to its existing practices, if those practices are working well, by navigating through the complex
set of options and supporting documentation that the SDT has crafted in this proposal. However, like many
entities, we have an army of substation technicians with various ranges of experience to perform maintenance
on protective systems and other substation components. It is unrealistic to expect most entities making a
good faith effort to comply with this proposal to have a full understanding throughout the entire organization of
all the nuances crafted into this complex proposal. For the reasons outlined above, we do not agree with the
proposal to specify minimum maintenance activities. However, if the majority of industry commenters agree
with the SDT’s proposal, we have concerns about some of the proposed minimum tasks. For Protection
System control circuitry (trip circuits), Table 1A calls for performing a complete functional trip test. The
“Frequently-asked Questions” document states that this “may be an overall test that verifies the operation of
the entire trip scheme at once, or it may be several tests of the various portions that make up the entire trip
scheme”. Such a requirement creates its own set of reliability risks, especially when monitoring already
mitigates risks. We are concerned with this standard promoting an overall functional trip test for transmission
Protection Systems. This type of testing can negatively impact reliability with the outages that are required
and by exposing the electric system to incorrect tripping. Our company views overall functional trip testing as
a commissioning task, not a preventive maintenance task. We perform such testing on new stations and
whenever expansion or modification of existing stations dictates such testing.
Response: The SDT thanks you for your comments.
a. The SDT has modified the standard in consideration of your comments. All references to measuring specific gravities have been removed from the
revised standard – and for Table 1a for station dc supply, the language was revised to require, “Verify float voltage of battery charger.”
b. Power line carrier channels are made up of many components that must be maintained on a periodic basis. This standard indicates that adequate
maintenance and testing must be done to keep the performance of the channel at a level that meets the requirements of the relay system. The
determination of specific maintenance activities is the responsibility of the Entity.
c. This standard limits the maintenance requirements of distribution system batteries to those used for UVLS and UFLS and constrains those
requirements to verification of proper voltage. If “distribution system” batteries are used for any other BES Protection System applications, they must
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be maintained according to the other requirements of this standard.
d. The SDT believes that the UFLS scheme is predominantly based within the distribution sector. As such, there are many circuit interrupting devices
that will be operating for any given under-frequency event that require tripping for that event. A failure in the tripping-action of a single distribution
breaker will be far less significant than, for example, any single Transmission Protection System failure such as a failure of a Bus Differential Lock-Out
Relay. While many failures of these distribution breakers could add up to be significant, distribution breakers are operated often on just fault clearing
duty and therefore the distribution circuit breakers are operated at least as frequently as any requirements that might have appeared in the standard.
e. The requirement is that the proper voltage, current, and phase angle must be delivered to each respective relay. The standard does not prescribe
methodology. See FAQ II-3-A (page 8) for further discussion.
f. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. Regardless of the level of redundancy provided, all components addressed by this
standard must be maintained in accordance with the requirements of the standard. The SDT has therefore defined the minimum activities necessary to
implement an effective PSMP. The SDT has modified the standard in consideration of your comments concerning specific gravity testing.
E.ON U.S.
No
1. Capacity or AC impedance only needs to be done to determine service life and therefore periodic testing of
station DC supply does not seem necessary or prudent.
2. If a company checks overall battery bank voltages quarterly then periodic testing of the battery bank
charger should not be required.
Response: The SDT thanks you for your comments.
1. Capacity or Internal Ohmic testing must be periodically performed at the Maximum Maintenance Intervals in Table 1 to verify that a lead acid
battery can perform as designed. Periodic testing to ensure that a battery can perform as designed is necessary to ensure that a battery is capable
of being a dc source to the station dc loads when required. If a battery fails to perform as designed during test before its designed service life is
reached it must be replaced regardless of how many years of service are left on its warranty or its engineered service life.
2. Proper functioning of the battery charger is critical to proper performance of the DC supply. The SDT has modified the standard to simplify the
battery charger maintenance requirements.
City Utilities of Springfield, MO
June 3, 2010
No
1. CU has concern over the battery charger testing requirements. Per the charger manufacturers
recommendations there is no reason to test the chargers as proposed in PRC-005-2. It is their opinion
that the chargers are self diagnostic and do not require these tests (full load current and current limiting
tests). The charger O&M manuals do not even provide instructions for such tests as optional. Therefore,
CU takes exception to this requirement and suggests that battery chargers be maintained and tested in
accordance with manufacturer’s recommendations.
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2. Additionally, CU is concerned with the wording in Table 1a concerning Protection system communication
equipment and channels. We are unsure what the maintenance activity actually means. If this is an
unmonitored system, how can you verify the condition of the communication system? Is the standard
referring to local monitoring such as enunciators? Please provide clarification.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comments. If the battery charger is self diagnostic, it may qualify for Table 1b or Table
1c.
2. FAQ II-6-A (page 16) provides an extensive discussion about various methods to test communications systems.
Florida Municipal Power Agency,
and its Member Cities
No
1. FMPA does not believe that maintenance of each UFLS / UFLS systems are as important as
maintenance of BES protection systems. The fundamental reason is that delayed or uncleared faults on
the BES can cause system “instability, uncontrolled separation, and cascading outages”; therefore, BES
protection systems are very important; however, if a small percentage of UFLS / UVLS relays mis-operate
as a result of a frequency or voltage event, the impact of the mis-operation is much smaller, if even
measurable. As a result, FMPA believes that the emphasis of the maintenance activities ought to be
placed on those systems that can have the most impact on what the standards are all about, as Section
215(a)(4) of the Federal Power Act says, “avoiding instability, uncontrolled separation, and cascading
outages”. As a result, FMPA believes that full functional testing, while important for BES protection
systems, is not necessary for UFLS and UVLS systems (Table 1a, page 6 and Table 1b, page 11).
Because most UFLS / UVLS are on radial distribution feeders, such testing will cause outages to
customers fed on radial distribution circuits and transmission lines without sufficient cause, in other words,
the maintenance itself will reduce the reliability the customer experiences. In addition, distribution tripping
circuits are more regularly exercised by distribution faults than are transmission tripping circuits; therefore,
full functional testing of distribution tripping circuits is far less valuable than testing trip circuits of
transmission elements which are exercised less frequently due to actual system events.
2. FMPA is confused with the wording of Table 1a, page 6, row 3 that talks about breaker trip coils. In the
“Type of Component” column, the subject says “Breaker Trip Coils Only (except for UFLS or UVLS)”, yet
the maintenance activity described states “Verify the continuity of the breaker trip circuit including trip
coil”. These two statements are inconsistent because the first statement limits the applicability to just the
trip coil and the second statement goes beyond the trip coil. And, FMPA believes the second statement
should only apply to the trip coil, e.g., the second statement should say: “Verify the continuity of the trip
coil”. In addition, the parenthetical is confusing, is it meant to say that the continuity of the trip coil only
needs to be verified when the breaker operates during the 3 month interval, or that the intended continuity
check is from the relay contacts through the trip coil, and not from the relay contacts back to the
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batteries?
3. FMPA is also confused concerning station DC supply testing. There are multiple rows in Table 1a
concerning various types of testing for various types of batteries and chargers that do not exclude UVLS
and UFLS, yet on page 8, on the bottom row, the row is exclusive to UVLS and UFLS yet overlaps other
rows discussing station DC supply testing. Is it intended that the other rows that are silent as to what they
apply to exclude UVLS and UFLS? FMPA believes that should be the case. The same comment applies
to Table 1b.
4. FMPA also has concern over the battery charger testing requirements. Per the charger manufacturers
recommendations there is no reason to test the chargers as proposed in PRC-005-2. It is their opinion
that the chargers are self diagnostic and do not require these tests (full load current and current limiting
tests). The charger O&M manuals do not even provide instructions for such tests as optional. Therefore,
FMPA takes exception to this requirement and suggests that battery chargers be maintained and tested in
accordance with manufacturer’s recommendations
Response: The SDT thanks you for your comments.
1. The SDT believes that UFLS and UVLS maintenance needs to be prescriptive for the following reasons:
a. PRC-008-0 and PRC-011-0 today require maintenance of UFLS and UVLS equipment.
b. FERC Order 693 directs NERC to develop maximum allowable intervals for UFLS and UVLS equipment, and recommends combining PRC-0051, PRC-008-0, PRC-011-0, and PRC-017-0.
The objectives are not constrained to limiting “instability, uncontrolled separation, and cascading outages”, but instead address overall Protection
System reliability. The standard has, however, been modified to remove the requirement that the breakers actually be tripped for UFLS and UVLS
functional trip testing.
2. The SDT has modified the standard to remove the requirement cited in your comments.
3. The SDT has modified the standard to clarify that the only DC Supply requirement relevant to UVLS and UFLS is to verify the DC supply voltage in
consideration of your comments.
4. The SDT has modified the standard in consideration of your comments. If the battery charger is self diagnostic, it may qualify for Table 1b or
Table 1c.
Indiana Municipal Power Agency
June 3, 2010
No
IMPA does not agree with the battery charger testing requirements. Per the battery charger manual, the
manufacturer sets the current limit at the factory, and it only needs to be adjusted if a lower current limit is
desired. The manufacturer gives directions on how to lower the current limiter, and the directions seem to be
for this purpose only (not for the sole purpose of performing a current limiter test). The manufacturer also
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does not give directions on how to perform a full load current test and does not give any recommendation to
the user that such test is needed. IMPA believes that both of these maintenance items are not needed to
maintain the battery charger and that only the manufacturer's recommendations on maintenance and testing
need to be followed.
Response: The SDT thanks you for your comments. The performance of the battery charger is critical to the performance of the protection system.
The SDT has modified the standard to simplify the requirements related to maintenance of the battery charger.
FirstEnergy
No
In general we agree with the maintenance activities, except for the specific gravity and temperature testing
included in the "Station dc Supply (that has as a component any type of battery)" of the tables 1a and 1b. We
only perform this testing at nuclear facilities for insurance requirements. In transmission substation
applications it has been eliminated due to the variability of results due to recharging/equalizing, water
addition, temperature correction requirements, etc. In the Supplementary reference, section 15.4 Batteries
and DC Supplies, third paragraph, the SDT indicates these tests are recommended in IEEE 450-2002 to
ensure that there are no open circuits in the battery string. This is essentially a continuity check of the battery
string. In the fourth paragraph, the SDT states that "continuity" was introduced into the standard to allow the
owner to choose how to verify continuity of a battery set by various methods, and not to limit the owner to the
two methods recommended in the IEEE standards."The SDT in Table 1a, the Maintenance Activity "Verify
continuity and cell integrity of the entire battery", and in Table 1b, the Maintenance Activity "Verify electrical
continuity of the entire battery". Based on the information in the Supplementary reference, the owner has to
choose a method to verify continuity and the measurement of specific gravity and cell temperatures could be
the selected method, however it should not be a required maintenance activity as shown in Tables 1a and 1b.
Response: The SDT thanks you for your comments and has modified the standard in consideration of your comments. All references to specific
gravity and temperature testing have been removed from the revised standard.
Ohio Valley Electric Corp.
No
1. In general, all maintenance activities that are verifications of proper function imply that problems found
must be resolved within the maximum interval. For some activities, that is an unreasonable expectation.
A temporary resolution may reliably correct an adverse situation but may not address the original
verification requirement within the maximum interval.
2. Routine substation inspections should not fall under NERC standards. The documentation for quarterly
inspections would be oppressive. It is unreasonable to require there to be no DC grounds. All DC
grounds do not rise to the level of a reliability concern. In some cases, attempting to resolve a relatively
minor DC problem may rise to the level of negatively affecting reliability.
3. The value of capacity testing battery banks and chargers in the context of a protection system reliability
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standard is questionable.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard to clarify that corrective actions must be initiated, but intentionally does not identify when they need to be
completed, largely for the reasons you cite. See FAQ II-2-I (page 7) for a discussion on this.
2. The SDT believes that certain verification activities must be performed on a periodic basis via visual inspection. The standard and Frequently
Asked Questions document (See FAQ II-5-I, page 15) have been modified in consideration of your comment concerning locating and removal of a dc
ground. References to dc grounds have been revised to “unintentional dc grounds.”
3. The SDT believes that the ability of the battery to provide required tripping current is CRITICAL to the reliability of the Protection System; else, the
Protection System is unable to react properly when required. Similarly, the SDT believes that the ability of the charger to properly charge the battery is
critical to sustain the battery capability.
AEP
No
In the process of performing maintenance, some protection systems may need to be taken out of service on
in-service equipment (bus differential protection for example) where redundant protection systems do not
exist. This action seems counter to NERC recommendations, presenting a scenario for expanding outages
during a simultaneous fault. Would the implementation plan include time for the additions of redundant
protection systems? Comments expanded in question 10 response.
Response: The SDT thanks you for your comments. To minimize system impact of maintenance, the maintenance necessarily should be scheduled at
a time that minimizes the risks. The implementation plan addresses the development of acceptable PSMPs.
RRI Energy
June 3, 2010
No
1. It is recommended to change the wording of the Maintenance Activities to the activity itself, not the resolved
state of the maintenance correctable issue (i.e. “For microprocessor relay, check for proper operation of the
A/D converters” instead of “For microprocessor relays, verify proper functioning of the A/D converters”). The
wording of the standard effectively sets the end date for the correction of maintenance identified issues. In
other words, maintenance has not taken place until all maintenance correctible issues have been completely
resolved. The wording in the standard have set non-compliance “traps” for those performing the maintenance
but have not completed correctable issues for legitimate reasons which may not be allowed by the noexception approach of the standard. For example, rewording of the Battery Supply 3 month activities are
recommended as follows: “Check for proper electrolyte level. Check for proper voltage. Check for dc supply
grounds.” As inspection activities, any issue not corrected during the interval should become a maintenance
correctible issue. For generating stations, the judgments to locate and remove a ground are based upon
criteria not accounted for in the requirements of this standard. An activity to locate and clear a ground
requires the judgment of station maintenance and operational management depending upon the operating
conditions of the unit and the level of the ground (solid or high-resistance).Inspections (3 month requirement
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activities) although good practices, should not be standard requirements.
2. The practice of verifying the continuity of breaker trip circuits does not belong as an auditable NERC
standard requirement; it becomes more of a documentation requirement rather than a reliability improvement.
Otherwise, it will ultimately require the expending of resources in an unproductive manner primarily on the
development, storage, and production of excessive records for compliance purposes. The elimination of this
requirement is recommended.
3. For Table 1a Protection System Control Circuitry - rewording is suggested as follows: “Perform functional
trip tests of Protection System trip circuits, including auxiliary relays essential to the proper functioning of the
Protection System.” The requirement, as presently worded “that includes all sections of the Protection
System,” is overly prescriptive and will create non-compliances for miniscule oversights, given the very large
scope of components in protection systems that are spread out far and wide in a system. The requirement
opens the door, allowing the compliance process itself to be punitive in nature. When pursued to the extreme
under audit conditions, this requirement will be very difficult to demonstrate on a large scale.
4. For Table 1a Station dc supply: The ability of a battery charger to correctly supply equalize voltage to a
battery has no direct correlation to reliability of the BES and does not belong in this standard. The objective is
that the battery get an equalize charge when it needs it, not the maintenance of the equalize function of a
battery charger. How the battery gets equalized is not important to this standard, especially since a battery
and the equalize source are usually disconnected from the protection system during the process.
5. For Table 1a Station dc supply: The use of the term “in tolerance,” for the measurement of specific gravity,
is an inconsistency in stating the standard requirements. There are multiple activities that will necessitate the
measurement of a quantity “in tolerance” whether it is battery charger output, individual cell voltages,
connection resistances, or internal ohmic values. The suggested rewording is as follows: “Measure the
specific gravity and temperature of each cell.”
6. For Table 1a Station dc supply: Referring to the requirement to “verify that the station battery can perform
as designed” very little of a generating station battery sizing is related to BES protection. Verification of a
generating station to design conditions is outside the scope of BES protection and does not belong in this
standard. Nearly all protection system operations operate without reliance upon the battery to do so, and the
separation of the generating unit from the BES will take place within cycles, if called upon to do so. The
remainder of the battery duty cycle is outside the scope of BES protection.
Response: The SDT thanks you for your comments.
The station dc supply 3 month activities section of table 1a has been reworded in consideration of your comment as shown below:
Check:
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Question 2 Comment
•
Electrolyte level (excluding valve-regulated lead acid batteries)
•
Station dc supply voltage
•
For unintentional grounds
Also FAQ II-5-I (page 15) has been modified in consideration of your comment concerning location and removal of dc grounds on a generating
station. The following was added to the FAQs:
In most cases, the first ground that appears on a battery pole is not a problem. It is the unintentional ground that appears on the opposite pole that
becomes problematic. Even then many systems are designed to operate favorably under some unintentional DC ground situations. It is up to the owner
of the Protection System to determine if corrective actions are needed on unintentional DC grounds. The standard merely requires that a check be made
for the existence of Unintentional DC Grounds. Obviously a “check-off” of some sort will have to be devised to demonstrate that a check is routinely
done for Unintentional DC Grounds.
Additionally, the Maintenance Activities in Table 1a, Table 1b, and Table 1c have been generally revised as you suggest, to present the activity rather
that the resolved state.
2. The SDT has modified the standard to clarify that this requirement is actually monitoring the trip coil. The SDT believes that verification of breaker
trip coil continuity is a vital component of the Protection System performance, and that they must be maintained as specified in the Standard.
3. The SDT believes that proper functioning of all trip circuit paths is a vital component of the Protection System performance, and that they must be
maintained as specified in the Standard.
4. The SDT has modified the standard in consideration of your comment and the requirement to equalize voltages has been removed from the revised
standard
5. The SDT has modified the standard in consideration of your comment and the comments from others, the reference to measuring specific gravity
and temperature has been removed
6. Thank you for your comments concerning verification that the station battery can perform as designed. Although the SDT agrees with you that
very little of a generation station battery sizing is related to BES protection, the majority of a generation station battery duty cycle is for safely
operating the station when the other elements of a station dc supply are unavailable and that some Protection System operations can operate
using the other elements of the station dc supply besides the station battery. The SDT believes that the station dc supply is such an integral part
of the Protection System of a generating station that, at a minimum, it must be maintained using the Maintenance Activities and Maximum
Maintenance Intervals of Table 1. It is important to note that the station battery must still be able to perform its vital Protection System functions
even if it is simultaneously supplying dc for its myriad of other applications. The required activities include “verify that the station battery can
perform as designed.”
Indianapolis Power & Light Co.
June 3, 2010
No
1. Many preventive maintenance programs have testing tolerances which are tighter than the manufacturer’s
tolerances. This practice is used to force an action prior to falling outside of the manufacture’s tolerances and
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accounts for slight variations in test equipment and environment. Maintenance correctable issues should not
be reportable unless the test failure falls outside of the manufacturer’s published tolerances.
2. In tables 1a through 1c the “Type of Component” columns in each table do not have consistent listings from
one 1a to 1b to 1c. The type of component should be identified consistently in each table. By doing so this
would eliminate confusion in moving from one table to the other.
3. The maintenance activities for some types of components specifies how (i.e. Test and calibrate the relays.
with simulated electrical inputs) while other maintenance activities do not specify how. The maintenance
activities should either all be specific or all be generic.
4. For Station dc Supply (that has as a component any type of battery) the maintenance activity of “verify that
no dc supply grounds are present” there is a problem of tolerance. It is impossible to have “no dc supply
grounds present”. There has to be some tolerance given here such as a voltage measurement from each
battery terminal to ground +- 15 volts of nominal for example.
5. For the type of component of “Protection System Control Circuitry (trip circuits) (UFLS/UVLS Systems
only), the maintenance activity requires a complete functional trip test” of the Protection System. This
suggests that a breaker trip test is required at each maintenance interval. This requires tripping breakers that
supply customers. It is impossible to trip each individual distribution feeder without forcing an outage on
some customers as when there are no other usable circuits to tie the load off to. A failure to trip of a single
distribution circuit in the overall scheme of a UVLS or UFLS scheme would have little effect on the BES. Trip
testing BES breakers and verifying correct operation of breaker auxiliary contacts could become very difficult
to accomplish since opening a breaker on a line might adversely affect the BES. ISOs may prohibit such an
activity at any time. Allowances should be made for BES circuit breakers that can not be operated for such
reasons if documented sufficiently.
Response: The SDT thanks you for your comments.
1. The tolerances, per Note 1 to Table 1a, Table 1b, and Table 1c, are defined by the entity according to their application considerations as related to
the component. The standard has been revised to exclude minor issues that can be corrected during the on-site maintenance activities from
“maintenance correctible issues”.
2. The variations in the “Type of Component” are a result of the varying maintenance activities that are necessary as there are higher levels of
component monitoring. If the “Type of Component” was made consistent among all three tables, there would be additional confusion, because
many of the “Types of Component” in Tables 1b and 1c would indicate that no maintenance activities are required.
3. Generic activity descriptions have been used except where specific activities are necessary.
4. The standard and Frequently Asked Questions document (See FAQ II-5-I, page 15) have been modified in consideration of your comment regarding
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dc grounds. References to dc grounds have been revised to “unintentional dc grounds.”
5. We agree. The minimum activities have been revised in the standard to not require tripping of the breakers for this table entry.
Platte River Power Authority
Maintenance Group
No
Minimum maintenance activities should be based on categorization of relays and defined maintenance
actions system by system using historical and definitively known data entity by entity. By establishing specific
minimum maintenance activities you risk entities changing currently effective maintenance programs to
programs that match minimum maintenance activities to meet requirements in the standard which could be
less effective for their system.
Response: The SDT thanks you for your comments. As for including some activities and excluding others, the listed activities are contemplated as
minimum activities and do not preclude an entity from performing additional activities. Your use of historical and definitively known data may be
applicable to a Performance-Based maintenance program (R3) for some of your activities.
PacifiCorp
No
No comment.
Duke Energy
No
Our comments are limited to activities in Table 1a.
1. ” Protective Relays “ okay
2. ” Voltage and Current Sensing Devices Inputs to Protective Relays “ Proper functioning should be verified
at commissioning, and then anytime thereafter if changes are made in a PT or CT circuit. Additional periodic
checks may be warranted as suggested in Table 1A; however no additional checking should be required
where circuit configuration will inherently detect problems with a PT or CT. For example, PTs & CTs that are
monitored through EMS or microprocessor relays will be alarmed when they are out of specification.
3. “Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS) “Need more
clarity on exactly what this activity is expected to include. In some cases we have a red light on a control
panel monitoring the circuit path to the trip coil. In locations where there is not a red light, verifying the
continuity of the breaker trip circuit including the trip coil will be complicated. There is no straightforward way
to do it without potentially impacting reliability, and we would have to consider modifying these installations to
include a red light.
4.” Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) “Need more clarity on
exactly what the activity is. We believe testing one output all the way to the coil is sufficient to prove the trip
path. The activity states that “all auxiliary contacts” must be tested. We propose that all protection control
circuitry should be tested at initial commissioning, and then again if any changes are made. Ongoing routine
testing is complicated and could pose reliability challenges to the BES. As stated on page 8 of the System
Maintenance Supplementary Reference document: “Excessive maintenance can actually decrease the
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reliability of the component or system. It is not unusual to cause failure of a component by removing it from
service and restoring it. The improper application of test signals may cause failure of a component. For
example, in electromechanical over current relays, test currents have been known to destroy convolution
springs. In addition, maintenance usually takes the component out of service, during which time it is not able
to perform its function. Cutout switch failures, or failure to restore switch position, commonly lead to protection
failures.
5.” Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only) Need additional clarity on
exactly what the test includes. “Complete functional trip test” should not include tripping the breaker.
Proving the output of the relay should be sufficient. Systems that have all load shed on distribution circuits
should require that trip output be confirmed but should not be required through to the trip coil due to
constraints in tying distribution load.
6. Station dc supply (that has as a component any type of battery) Under the 3 month interval activities, we
disagree with the wording of the activity Verify that no dc supply grounds are present. The activity should
instead read “Check for dc supply grounds and if any are found, initiate action to repair.
7. Station dc supply (that has as a component any type of battery) Under the 18 month interval activities, what
is meant by “Verify continuity and cell integrity of the entire battery”? Also what is required to “Inspect the
structural integrity of the battery rack”? The “Supplementary Reference Document” and “Frequently asked
Questions” document should be made part of the standard to provide clarity to the requirements.
8. Station dc supply (that has as a component Valve Regulated Lead-Acid batteries) Need more clarity on
exactly what is required for a “performance or service capacity test of the entire battery bank”. The
“Supplementary Reference Document” and “Frequently asked Questions” document should be made part of
the standard to provide clarity to the requirement.
9. Station dc supply (that has as a component Vented Lead-Acid batteries) Need more clarity on exactly what
is required for a “performance, service, or modified performance capacity test of the entire battery bank”. The
“Supplementary Reference Document” and “Frequently asked Questions” document should be made part of
the standard to provide clarity to the requirement.
10.” Protection system communication equipment and channels Need additional clarity on exactly what is
required for the substation inspection. What is required for power-line carrier systems?
11. UVLS and UFLS relays that comprise a protection scheme distributed over the power system Need more
clarity regarding the meaning of “distributed over the power system”.
Response: The SDT thanks you for your comments.
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1. Thank you.
2. Your example describes attributes applicable to Table 1c, and which would not require periodic maintenance. If monitoring, as you’ve described,
is not present, periodic verification is necessary as described in Table 1a.
3. You are correct. This area of each of the Tables has been extensively revised in response to comments. FAQ II-4-C (page 10) explains that this
“may be via targeted maintenance activities or by documented operation of these devices for other purposes such as fault clearing” and Section
15.3 of the Supplementary Reference (page 22) provides discussion on this.
4. If only one path is tested, this provides no assurance that other paths will perform properly. The cited reference on Page 8 of the Supplementary
Reference Document is focused on effective maintenance intervals, not on performing maintenances. There are methods of performing functional
testing without injecting damaging test currents.
5. The requirement has been modified to provide more clarity, and has been modified to remove the requirement to actually trip the breaker.
6. The SDT has modified the standard in consideration of your comment – it now reads, “Check for unintentional grounds.”
7. The SDT has modified the standard in consideration of your comment on cell integrity of the entire battery. Also, the Protection System
Maintenance Frequently Asked Questions document (FAQ II-5-H, page 15) that accompanied the standard for this comment period addresses your
question about the battery rack in Station dc Supply section. According to the NERC Standard Development Procedure, a standard is to contain
only the prescriptive requirements; supporting discussion is to be in a separate document.
8. Methodologies regarding performance and service capacity tests for VLRA batteries are explained in detail in various available references.
According to the NERC Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to
be in a separate document.
9. Your comment is in the nature of a “how to”, not a requirement, and therefore the SDT believes it belongs in the supporting discussion. According
to the NERC Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to be in a
separate document.
10. FAQ II-6-A (page 16) presents a variety of methods to maintain Protection System communication equipment.
11. This refers to the common practice of applying UFLS on the distribution system, with each UFLS individually tripping a relatively low value of load.
Therefore, the program is implemented via a large number of relays, and the failure of any individual relay to perform properly will have a minimal
effect on the effectiveness of the UFLS program. There are some UVLS systems that are applied similarly.
Progress Energy
No
Progress Energy does not agree with the activity “Verify that the battery charger can perform as designed by
testing that the charger will provide full rated current and will properly current-limit.” We are unclear how this
test should be performed.
Response: The SDT thanks you for your comments. The SDT has modified the standard in consideration of your comment. The component
description was changed to: Station dc supply (which do not use a station battery) And the maintenance activity was changed to: Verify that the dc
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supply can perform as designed when the ac power from the grid is not present.
Xcel Energy
No
Regarding battery chargers, does the SDT propose that OEM-type tests be performed to validate the rated
full current output and current limiting capabilities? It has been proposed that simply turning off the charger
and allowing the batteries to drain for a period of several hours, then returning the charger to service will
validate these items. It is not clear that an auditor would come to the same conclusion, since it appears open
to interpretation. Please modify to make this clear. If an entity has an over-sized battery charger, they can
(and should) only test to the max capacity of the battery bank. Suggest changing “full rated current” to
“designed charging rate”.
Response: The SDT thanks you for your comments. The SDT has modified the standard in consideration of your comment. The component description
was changed to: Station dc supply (which do not use a station battery) And the maintenance activity was changed to: Verify that the dc supply can perform as
designed when the ac power from the grid is not present.
Austin Energy
No
See item # 10 Comments
No
Station DC supply - (Maintenance Activity) As a company we do not think that measuring specific gravity and
temperature of each cell is necessary. There is a better test that we use with the Bite Impedance Test. We
have had good success with the impedance test for determining the batteries condition. See article
(Impedance Testing Is The Coming Thing For Substation Battery Maintenance)written in Transmission &
Distribution 11/1991 by Richard Kelleher, Test & Maintenance Specialist, Northeast Utilities.
Response: See #10 Response
Otter Tail Power
Response: The SDT thanks you for your comments regarding DC supply. Changes have been made to the standard in consideration of your
comments. The requirement to measure specific gravity and temperature of each cell has been deleted.
Detroit Edison
No
1. Suggest that under “Maintenance Activities” for “Protective Relays” add the following: Verify proper
functioning of the microprocessor relay external logic inputs (carrier block, etc.)
2. We recommend not requiring specific gravity and temperature readings for batteries. We have found from
experience that the time and difficulty to obtain specific gravity readings are not justified. We have found that
utilizing visual inspections, voltage and internal/intercell resistance readings gives a good picture of the health
of the battery. We use specific gravity readings on occasion for troubleshooting purposes.
3. It is recommended that the sections about verifying battery charger performance be eliminated if there are
low voltage alarms that go to a monitored location.
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4. We recommend changing the maximum maintenance interval for DC supplies with no battery from 18
months to 3 years. If there is no battery, you do not have the risk of failure of chemical processes and such
that would require an interval as short as 18 months.
Response: Thank you for your comments
1. The SDT has modified the standard in consideration of your comment. The revised activity reads as follows: For microprocessor relays, check the
relay inputs and outputs that are essential to proper functioning of the Protection System
2. Thank you for your comments regarding DC supply. The SDT has modified the standard in consideration of your comment. The requirement to
measure specific gravity and temperature of each cell has been deleted.
3. Changes have been made to the standard in consideration of your comments regarding verifying battery charger performance. The only
requirement relative to battery chargers in the latest draft of the standard (see Table 1a, pg 14) is to verify the float voltage.
4. The SDT disagrees; the 18-month interval includes several items that can be verified only by physical inspection; that are independent of chemical
processes, and that affect the ability of the dc supply to perform properly.
SCE&G
No
1. Table 1a Level 1 Monitoring has a requirement to “Verify the continuity of the breaker trip circuit including
trip coil” at least every 3 months. This is interpreted to be applicable to both the low-side generator output
breaker and the high-side breaker for the GSU. The generator output breaker has 3 separate trip coils (one
for each pole) that are connected in a parallel configuration and there is no means available to verify
continuity of each of these coils INDIVIDUALLY in this arrangement. Is the intent of this requirement to have
each trip signal parallel leg verified every three months even though the trip contacts are normally open
(these circuits are functionally checked during LOR Functional Verification)?
2. Also, is the Red Indication Light (RIL), which includes the trip coil in the power circuit, adequate for
verification (note that the breaker does not include the parallel legs that contain the tripping sensor contacts)?
3. Also, more clarification is needed on the section “Verify proper functioning of the current and voltage circuit
inputs from the voltage and current sensing devices to the protective relays” under “Voltage and Current
Sensing Devices Inputs to Protective Relays.” How would this be done if no redundancy is available for crosschecking voltage and current sources?
4. In certain situations, “verify proper functioning” is not clear enough. Documentation of verification consistent
with the entities procedures should be adequate to indicate compliance.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard to remove the requirement cited in your comment.
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2. The SDT has modified the standard to remove the requirement cited in your comment.
3. The Supplementary Reference Document, Section 15.2 (page 21) and FAQ II-3 (page 8) provides several discussions on this item.
4. Documentation of verification consistent with your procedures is sufficient to “verify proper functioning”
Dynegy
No
Table 1a requires entities to "verify the continuity of the breaker trip circuit including trip coil..." The term
"verify" needs clarification. For example, we believe verifying red and green" lights during routine inspection
should be sufficient. On the other hand, actual testing is not feasible and is risky to reliability.
Response: The SDT thanks you for your comment, and has modified the standard to remove the requirement cited in your comment.
Nebraska Public Power District
No
1. Table 1a, for Protective Relays identifies the following Maintenance Activities: Test and calibrate the relays
(other than microprocessor relays) with simulated electrical inputs. Verify proper functioning of the relay trip
outputs. What is the difference between these two requirements? They appear to be practically equivalent.
2. Tables 1a & 1b, for Station DC supply identify the following Maintenance Activity: Measure that specific
gravity and temperature of each cell is within tolerance (where applicable). What is the advantage of testing
the SG in every cell compared to using a pilot cell as representative sample of the entire bank? NPPD has
not experienced any problems using a pilot cell compared to testing every individual cell. Typically, if the SG
is low the cell voltage will be low, which is detected by the voltage test. This seems to be an excessive
requirement and does increase personnel exposure to hazardous fluid. What unique information is provided
by this test that other tests do not provide?
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment. The activity to “verify proper functioning of the relay trip outputs was
changed to: Verify that settings are as specified.
2. The SDT thanks you for your comments regarding DC supply and has made changes to the standard in consideration of your comments. The
requirement to measure specific gravity and temperature of each cell has been deleted.
ENOSERV
No
1. Table 1A, protective relays for 6 calendar years, Testing and calibrating the relays other than
microprocessors relays with simulated electrical inputs... does that mean that micro processor relays do not
need to be checked?
2. Verify proper function of the relay trip outputs... Does this involve both electro AND micro processors?
Then when mentioning the verifying microprocessor relays, does that include the trip output.
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Response: The SDT thanks you for your comments.
1. Yes. The SDT has modified the standard for clarity. The maintenance activities for microprocessor relays were changed to read as follows:
For microprocessor relays, check the relay inputs and outputs that are essential to proper functioning of the Protection System.
For microprocessor relays, verify acceptable measurement of power system input values.
2. Yes. The SDT has modified the standard for clarity. The language for microprocessor relays was changed as noted in response to your first
comment; the following modification addresses all protective relays: Verify that settings are as specified.
Southern Company
No
1. Tables 1a and 1b require entities to verify the proper operation of voltage and current inputs to sensing
devices on a 12 year interval. The Protection System Supplementary Reference (Draft 1), in section 15.2,
describes several methods that may be used for such verification efforts. In order to perform this type of
verification the circuit in question would need to be in operation. This verification introduces a possible unit trip
due to the need to connect test equipment to live potential and current circuits at each relay, which has the
potential to trip the circuit under test. This could result in the loss of critical transmission lines or generating
units. The System Maintenance Supplementary Reference also allows saturation tests or circuit
commissioning tests to satisfy this requirement; however, these types of tests require the circuit in question to
be removed from service. For generating plants, removing the circuit from service requires that the station be
shut down. We do not feel that the value obtained from this requirement is equal to the risk or maintenance
burden associated with it. Such testing and verification should not be required periodically, but only if new
instrument transformers, cabling or protective devices are installed or if the instrument transformers are
replaced.
2. Table 1b: Protection System Control Circuitry (Trip Coils and Auxiliary Relays) “ Experience has shown
that electrically operating partially monitored breaker trip coils, auxiliary relays, and lockout relays every 6
years is not warranted. This testing introduces risk from a human error perspective as well as from additional
switching and clearances required. We recommend eliminating this maintenance requirement.
3. Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS Systems Only) - Table 1b includes the
statement "Verification does not require actual tripping of circuit breakers or interrupting devices." This
statement should be included in Table 1a.
4. In Table 1a “Station DC Supply (that has as a component any type of battery), we recommend changing
the maximum maintenance interval from 3 months to 6 months as described below.
5. “Verify Proper Electrolyte Level “3 Months - The 3 months interval for verifying proper electrolyte level is
excessive for current battery designs that are properly maintained. The interval in which the electrolyte must
be replenished is affected by many factors. These include temperature, float voltage, grid material, age of the
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battery, flame arrester design, frequency of equalization, and electrolyte volume in the battery jar.
Manufacturers are aware that their customers want to extend the interval in which their batteries require water
and this has lead to jar designs that have a wide min-max band with a high volume of electrolyte to allow for
extended watering intervals. Understanding all the factors and proper maintenance will extend watering
intervals. A battery should go a year or more between watering intervals and some as many as 3 years.
Being conservative the Southern Company Substation Maintenance Standards require that we check the
electrolyte level twice yearly. Experience has shown this has worked well. We propose that the “3 Months”
interval be changed to “6 months”.
6.”Verify proper voltage of the station battery “3 Months - Being conservative, the Southern Company
Substation Maintenance Standards require that we check the station battery voltage twice yearly. Experience
has shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”.
7.” Verify that no dc supply grounds are present “3 Months Being conservative, the Southern Company
Substation Maintenance Standards require that we check for dc supply grounds twice yearly. Experience has
shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”.
8. Measurement of Specific Gravity 18 Months- The measurement of specific gravity and temperature every
18 months is not necessary as a regular part of maintenance. Specific gravity can provide information as to
the health of a cell; however, taking specific gravity readings is a messy process no matter how careful you
are and will result in acid being dripped on top of the battery jars as the hydrometer is moved from cell to cell.
Should a drop of acid end up on an external connection, it will result in corrosion and problems later. Voltage
reading of cells can be substituted for specific gravity readings under normal conditions. Specific gravity is
equal to the cell voltage minus 0.85. A cell with low voltage will have a low specific gravity. If cell voltage
becomes a problem that cannot be addressed through equalization then specific gravity readings are justified
as a follow-up test. Since measurement of specific gravity could lead to problems and reading cell voltage is
a viable alternative, we propose that it be removed from the battery maintenance activities.
9. Verify Cell to Cell and Terminal Connection Resistance 18 Months - Clarification is needed on the expected
method for verifying cell to cell and terminal connection resistance. This could easily be interpreted as
requiring the use of an ohmic value (impedance/conductive/resistance) test device. If this is the case then
basically it eliminates the need for the activity to “Verify that the substation battery can perform as designed
by performing a capacity test every 6-Calendar Years or performing an ohmic value test every 18 Months”,
because the practical thing to do is go ahead and perform the ohmic value test while you have your device
connected to the battery.
10. In table 1a and 1 b - Station dc supply (that has as a component -Vented Lead-Acid batteries). Verify that
the Substation Battery can Perform as Designed 6 Calendar Years/18 Months - Southern Company
Transmission has approximately 570 batteries that are covered by this proposed standard. These batteries
currently have ohmic value testing performed every “4 Years” as required by the Southern Company
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Substation Maintenance Standards. The “4 Years” interval has been utilized for over 10 years and has not
experienced a failure of any of the 570 batteries to perform as designed Having to perform ohmic value
testing on an “18 Months” interval will significantly increase our costs and manpower requirements with no
anticipated improvement in reliability. We propose that the “18 Months” interval for ohmic value testing be
changed to “4 Calendar Years”. This proposal also applies to verifying cell to cell and terminal connection
resistance if an ohmic value test device is required as discussed above.
11. In table 1a and 1b Station dc supply (that uses a battery and charger). Verify that the Battery Charger can
Perform as Designed 6 Calendar Years - Clarification is needed on an acceptable method for verifying that
the battery charger can perform as designed by testing that the charger will provide full rated current and will
properly current limit, especially the part about “will properly current limit”.
12. On Table 1b Station DC Supply (that has a component any type of battery) we recommend changing the
maximum maintenance interval from 3 months to 6 months as described below “ Verify Proper Electrolyte
Level “ 3 Months - The 3 months interval for verifying proper electrolyte level is excessive for current battery
designs that are properly maintained. The interval in which the electrolyte must be replenished is affected by
many factors. These include temperature, float voltage, grid material, age of the battery, flame arrester
design, frequency of equalization, and electrolyte volume in the battery jar. Manufacturers are aware that
their customers want to extend the interval in which their batteries require water and this has lead to jar
designs that have a wide min-max band with a high volume of electrolyte to allow for extended watering
intervals. Understanding all the factors and proper maintenance will extend watering intervals. A battery
should go a year or more between watering intervals and some as many as 3 years. Being conservative the
Southern Company Substation Maintenance Standards require that we check the electrolyte level twice
yearly. Experience has shown this has worked well. We propose that the “3 Months” interval be changed to
“6 months”.
13. We recommend removing the “Detection and alarming of dc grounds” monitoring attribute. Note that this
applies to every “Station dc supply” section where it is listed. .Experience has shown that there have been no
significant problems discovered via alarms that would not have been discovered by 6 month inspection
cycles. We propose to add “verify no dc grounds are present” as a maintenance activity on a 6 months
inspection cycle. Experience has shown that there have been no significant problems discovered via alarms
that would not have been discovered by 6 month inspection cycles.
14. Table 1a, p. 7, Station dc supply, 3 month interval: need to add “unintentional” to the sentence “Verify
that no dc supply grounds are present.” Because most dc systems have ground detection systems which
place an intentional ground on the battery. “No grounds” is not practical and is unacceptable since most dc
systems have some high resistance ground paths. Some criteria should be established to determine the
acceptable ground resistance on a dc system.
15. Table 1a, p. 8: For the vented, lead-acid battery, there is no basis for the 18 month activity option
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(internal ohmic value measurement) in place of the 6 year performance test.
16. The activities for trip checks for Level 1A and Level 1B should be the same. Currently, they read: Level
1a: Perform a complete functional trip test that includes all sections of the Protection System trip circuit,
including all auxiliary contacts essential to proper functioning of the Protection System. Level 1b: Verify that
each breaker trip coil, each auxiliary relay, and each lockout relay is electrically operated within this time
interval. The Level 1a text is adequate for 1b also.
17. Table 1c, p 16: Monitoring of single or parallel trip circuits is not practical where multiple normally open
contacts are in series to trip. Monitoring of the trip coils is practical and useful. How would one monitor
several normally open contacts which are in series to trip a breaker?
18. Table 1c, p. 15, 16, 19: The use of “continuous” under “Maximum Maintenance Interval” in Table 1c
should be changed to “N/A” and the Maintenance Activity should be “NONE”.
19. Verification of the various monitoring (automated notification) systems is not specified anywhere in the
requirements. This, too, should be required.
Response: The SDT thanks you for your comments.
1. The SDT believes that proper functioning of the sensing devices is a vital component of the Protection System performance, and that they must be
maintained as specified in the Standard. To minimize system impact of such maintenance and possible errors, the maintenance necessarily should be
scheduled at a time that minimizes the risks.
2. The SDT believes that proper functioning of the Protection System Control Circuitry is a vital component of the Protection System performance and
those must be maintained as specified in the standard. To minimize system impact of such maintenance and possible errors, the maintenance
necessarily should be scheduled at a time that minimizes the risks
3. The SDT has modified the standard in consideration of your comment. The following was added to Table 1a:
Type of Component - Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS Systems Only)
Maximum Maintenance Interval - 6 Calendar Years
Maintenance Activity - Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits, including all
electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System, except .that verification does not require actual
tripping of circuit breakers or interrupting devices.
4. Please see responses 5, 6 and 7 (below) for discussion regarding your concern about extending the Maximum Maintenance Intervals for an extra 3
months on activities related the station dc supply.
5. The SDT agrees that a healthy modern lead acid battery can go for extended periods of time beyond 3 months without requiring watering. However,
checking cell electrolyte level not only indicates the need for battery watering, it is an indication of an individual cell’s health and needs to remain at
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the Maximum Maintenance Interval of 3 months. To avoid the confusion that the Maintenance Activity listed in Table 1 was to water the battery at the
specified 3 month interval, the Drafting Team has changed the wording of the Maintenance Activity from “verify proper” to “check” electrolyte level.
6. Thank you for your comment to extend the Maximum Maintenance Interval for checking the station dc supply voltage. The SDT believes that
extending the Maximum Maintenance Interval beyond that listed in Table 1 would compromise the performance of the station dc supply.
7. Due to the consequences of unintentional grounds to the station dc control system, the SDT feels that extension of the Maintenance Intervals
beyond the 3 month interval is not prudent. See FAQ IV-2-F (Page 23).
8. Changes have been made to the standard in consideration of your comments regarding specific gravity testing, and the revised standard does not
include a requirement to perform this maintenance activity.
9. Thank you for your comments concerning performance of ohmic measurement at the same time that connection resistance is measured. As you
suggested, these two measurements could be taken at the same time to meet the requirements of their respective Maintenance Activities.
10. Thank you for your comments concerning evaluating internal ohmic values and measurement of battery connection resistance for Vented Lead-Acid
(VLA) batteries. As noted in your comment an owner has two different Maintenance Activities with associated different Maximum Maintenance Intervals
to choose from in verifying that the VLA station battery can perform as designed.
FAQ II-5-F (page 14) and II-5-G (page 14) provides an explanation of why there are two different intervals for these Maintenance Activities is given.
Because trending is an important element of ohmic measurement evaluation, the SDT believes that extending the Maximum Maintenance Interval listed
in Table 1 for evaluating internal ohmic values to four years as suggested would not provide the necessary information for proper evaluation of the
ability of the station battery to perform as designed.
Concerning verifying cell to cell and terminal connection resistance as part of inspecting the battery, various technical references on Lead-Acid
battery maintenance talk about how and why this Maintenance Activity should be performed at the Maximum Maintenance Interval listed in Table 1.
The SDT believes that to extend this inspection activity for the connections of a Lead-Acid battery beyond the Maximum Maintenance Interval would
compromise the performance of the station dc supply.
11. The SDT has modified the standard in consideration of your comment regarding battery charger performance. The only remaining maintenance
activity relevant to the battery charger is to verify the float voltage.
12. The SDT agrees that a healthy modern lead acid battery can go for extended periods of time beyond 3 months without requiring watering.
However, checking cell electrolyte level not only indicates the need for battery watering, it is an indication of an individual cell’s health and needs to
remain at the Maximum Maintenance Interval of 3 months. To avoid the confusion that the Maintenance Activity listed in table 1 was to water the
battery at the specified 3 month interval, the Drafting Team has changed the wording of the Maintenance Activity from “verify proper” to “check”
electrolyte level.
13. Thank you for your comments concerning the monitoring attribute for unintentional dc grounds on the station dc supply. Due to the consequences
of unintentional grounds to the station dc control system (see FAQ II-5-I, page 15), the SDT feels that monitoring for them is an important part of an
effective condition based maintenance program and should be an option available for those who want to perform condition based maintenance. Also
because the threat to the dc system and the BES that unintentional dc grounds create, the SDT feels that extension of the Maintenance Intervals for
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checking for unintentional dc grounds beyond the 3 month interval is not prudent. See FAQ IV-2-F (page 23).
14. The SDT has modified the standard in consideration of your comment regarding dc grounds – the word, “unintentional” was added as proposed.
15. The SDT thanks you for your comment concerning ohmic value measurements. The FAQ II-5-F (page14) includes an explanation for the basis of
this activity. The SDT believes that this Maintenance Activity is a viable alternative that a Vented Lead-Acid battery owner can perform at the Maximum
Maintenance Interval of Table 1 in place of conducting a performance, modified performance or service capacity test.
16. For Table 1b, much of the DC control circuit is, by definition, being monitored; therefore, the only requirement is that the electromechanical devices
be exercised.
17. With the detail provided in your comment, it appears to the SDT that you would not be able to use Table 1c in this example.
18. “Continuous” is intended to clarify that the maintenance is being performed continuously via the monitoring system and the Activities portion of
the table is intended to state those activities that are being performed by the monitoring system.
19. This verification is established within the “General Description” at the top of Table 1c as generic criteria to use this table.
Transmission Owner
No
a. Tables 1a, 1b & 1c should offer as an alternative, measuring battery float voltages and float currents in lieu
of measuring specific gravities as described in Annex A4 of IEEE Std 450-2002.
b. Inspection of CVT gaps, MOVs and gas tubes should be added to the communications equipment time
based maintenance tables. Failure of the CVT protective devices may cause failure of the Protection System.
c. Maintenance Activities for UVLS or UFLS station dc supplies shows “Verify proper voltage of dc supply”.
Does this imply that, except for voltage readings of the dc supply, distribution battery banks are not
maintained?
d. Why does the Maintenance Activities for UVLS or UFLS relays state that verification does not require
actual tripping of circuit breakers?
e. Please clarify the Maintenance Activities for Voltage and Current Sensing Devices. Must voltage, current
and their respective phase angles be measured at each discrete electromechanical relay?
Response: The SDT thanks you for your comments.
a. The SDT has modified the standard in consideration of your comment regarding dc supply. All references to measuring specific gravities have been
removed from the revised standard – and for Table 1a for station dc supply, the language was revised to require, “Verify float voltage of battery
charger.”
b. Power line carrier channels are made up of many components that must be maintained on a periodic basis. This standard indicates that adequate
maintenance and testing must be done to keep the performance of the channel at a level that meets the requirements of the relay system. The
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determination of specific maintenance activities is the responsibility of the Entity.
c. This standard limits the maintenance requirements of distribution system batteries to those used for UVLS and UFLS and constrains those
requirements to verification of proper voltage. If “distribution system” batteries are used for any other BES Protection System applications, they must
be maintained according to the other requirements of this standard.
d. The SDT believes that the UFLS scheme is predominantly based within the distribution sector. As such, there are many circuit interrupting devices
that will be operating for any given under-frequency event that requires tripping for that event. A failure in the tripping-action of a single distribution
breaker will be far less significant than, for example, any single Transmission Protection System failure such as a failure of a Bus Differential Lock-Out
Relay. While many failures of these distribution breakers could add up to be significant, it is also believed that distribution breakers are operated often
on just fault clearing duty and therefore the distribution circuit breakers are operated at least as frequently as any requirements that might have
appeared in the standard.
e. Not exactly. The requirement is that the entity must verify that proper voltage, current, and phase angle is delivered to the relays. The standard does
not prescribe methodology. See FAQ II-3-A (page 8) and the Supplementary Reference Document, Section 15.2 (page 21) for a discussion on this
topic.
Pepco Holdings Inc.
No
1. Tables 1a, 1b and 1c all require measuring specific gravity and temperature of battery cells. This invasive
test provides no information regarding battery health that cannot be obtained from cell impedance testing.
Recommend requiring cell impedance OR specific gravity & cell temperature testing.
2. Tables 1a, 1b and 1c all require testing the battery charger every 6 years to verify that it can provide full
rated current and will properly current limit. In order to perform this (unnecessary) test the battery would be
subjected to a deep discharge. Whatever benefits may be derived from this test are dwarfed by the negative
effect on the battery. Recommend removing this requirement.
Response: The SDT thanks you for your comments.
1. The SDT has made changes in consideration of your comments regarding measuring of specific gravity and temperature of battery cells and
removed this maintenance activity from the revised standard.
2. The SDT has modified the standard in consideration of your comments regarding battery charger performance. All maintenance activities relating to
the battery charger were removed except for verification of the float voltage.
Illinois Municipal Electric Agency
No
1. The Illinois Municipal Electric Agency (IMEA) is concerned the minimum maintenance activities may be too
prescriptive for transmission subsystems that essentially operate radially.
2. Please see comment under Question 7.
3. Also, IMEA supports comments submitted by Florida Municipal Power Agency regarding applicability to
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UFLS systems.
Response: The SDT thanks you for your comments.
1. This standard applies Protection Systems that that are applied on, or are designed to provide protection for the BES. The SDT believes that the level
of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address observations from the Compliance
Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also specifies that NERC Standards should
be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to implement an effective PSMP.
2. Please see our response to your comments under Question 7.
3. The SDT has responded to the FMPA comments regarding UFLS systems.
Consumers Energy Company
No
1. The second sentence in Note 1 on page 20 should be changed to “A calibration failure is when the relay is
inoperable and cannot be brought within acceptable parameters.”
2. Note 2 should be changed to “Microprocessor relays typically are specified by manufacturers as not
requiring calibration. The integrity of the digital inputs and outputs will be verified by applying the inputs and
verifying proper response of the relay. The A/D converter must be verified by inputting test values and
determining if the relay measurements are correct.”
Response: The SDT thanks you for your comments.
1. The standard establishes a calibration failure to be any condition where the relay is found to be out of tolerance, whether or not it can be restored
to acceptable parameters. The condition described is a calibration failure that is also a “maintenance correctable issue” as established in
revisions to R4 and the resulting footnote, and requires more extensive action to resolve.
2. Note 2 has been removed and the relevant requirements added to the Tables themselves. There are methods, other than inputting test values, to
verify the A/D converter.
American Transmission
Company
No
1. The Standard should focus on identifying the types of components to be tested but should not identify the
specific maintenance activities that must be performed. Entities should be allowed the flexibility to develop
and implement the appropriate maintenance activities necessary for each identified component.
2. ATC is also concerned with the expressed identification of maintenance intervals. We do not believe that
the standard should identify specific maintenance intervals but that it should require entities to identify their
maintenance intervals appropriate for their system. If the team continues to pursue specific maintenance
intervals it will be establishing the industries practices.
3. Specific Concern: The standard identifies that entities should perform complete functional testing as part of
its maintenance activities, but we are concerned that this could lead to reduced levels of reliability, because it
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requires entities to remove elements from service and then requires entities to perform tests that are
inherently prone to human errors. We believe that the perceived benefits do not match the anticipated costs
or improve system reliability.
Response: The SDT thanks you for your comments. As you are probably aware, protection systems have contributed to most major events, indicating
a need to provide greater “defense in depth” to the body of standards. While many facility owners do have effective protective system maintenance
programs, some do not – which puts the grid at risk.
1. Specific activities are defined where necessary to implement an effective PSMP, and has provided for flexibility where there are multiple methods
that will be effective.
2. FERC Order 693 expressly directs NERC to develop maximum maintenance intervals.
3. The SDT believes that complete functional testing is a vital component of the Protection System performance, and must be performed as specified
in the standard. To minimize system impact of such maintenance and possible errors, the maintenance necessarily should be scheduled at a time
that minimizes the risks.
Wolverine Power Supply
Cooperative, Inc.
No
The tables are too prescriptive - The standards should state what, not how.
Response: The SDT thanks you for your comments. The SDT believes that the level of prescription within the standard is necessary to satisfy the
guidance in FERC Order 693, and also to address observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC005-1 is excessively general. FERC Order 672 also specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined
the minimum activities necessary to implement an effective PSMP.
Northeast Power Coordinating
Council
No
1. We agree there is a need for minimum maintenance activities; however, the standard does not clearly
define the differences between Table 1a, 1b, and 1c. It is recommended that the drafting team develop
definitions for the equipment listed in these tables. For example, Table 1a equipment consists of mechanical
and solid state equipment without monitoring capability, Table 1b consists of mechanical and solid state
equipment with monitoring capability, and Table 1c consists of equipment capable of self monitoring.
2. In addition, all battery, charger and power supply maintenance activities should be removed from Table 1a,
1b, and 1c, and summarized in a separate Table (i.e. Table 2). Tables 1a and 1b for 'Station dc supply (that
has as a component any type of battery) and Table 1c for 'Station dc Supply (any battery technology) for an
18 Month 'Maximum Maintenance Interval' identifies the need to 'Measure that the specific gravity and
temperature of each cell is within tolerance (where applicable).'
3. Following industry best practices, we would recommend using the MBRITE diagnostic test. MBRITE
testing provides more information than a specific gravity test while reducing the risk of injury to testing
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personnel.
4. In Table 1a, the Type of Component “Protection system communications equipment and channels.” has a 3
month “Maximum Maintenance Interval”. Clarification needs to be provided as to how an unmonitored (do not
have self-monitoring alarms) will be tested.
5. Table 1a refers to “Unmonitored Protection Systems”. The “6 Calendar Years” “Maximum Maintenance
Interval” “Maintenance Activities” is excessive.
Response: The SDT thanks you for your comments.
1. The component differences between Table 1a, Table 1b, and Table 1c are described in the header to the Tables and in the specific monitoring
attributes for the specific component types. Please see the decision trees near the end of the FAQ document (pages 33-37).
2. The SDT believes that the Station DC Supply component should be addressed with the other components, and has simplified the Tables in
consideration of your comments.
3. The DC Supply component has been modified, and no longer specifically requires specific gravity testing.
4. See FAQ II-6-B (page 16) for a discussion of a number of methods to test the communications systems.
5. Your comment is unclear, and the SDT is unsure how to respond. The SDT believes that the level of prescription within the standard is necessary
to satisfy the guidance in FERC Order 693, and also to address observations from the Compliance Monitoring entities (the Regional Entities and
NERC) that PRC-005-1 is excessively general. FERC Order 672 also specifies that NERC Standards should be clear and unambiguous. The SDT
has therefore defined the minimum activities and maximum intervals necessary to implement an effective PSMP. Some entities may feel that they
need to maintain Protection System components more frequently.
Lower Colorado River Authority
No
We agree with all stated intervals except for the maximum stated interval of 6 years for Protection System
Control Circuitry (Trip Coils and Auxiliary Relays) in tables 1b and 1c. What was the intent of separating this
interval out from the Protection System Control Circuitry (Trip Circuits), which is 12 years for monitored
components? Monitoring of the trip coils should be enough to justify a maximum interval of 12 years. As
stated these requirements will put an undue financial and resource burden on utilities that have updated their
protective relay systems with state-of “the art components and monitoring. In addition to the expense and
effort of scheduling the additional maintenance, the additional validation of lockouts and auxiliary relays,
separate from the full function testing could lead to additional human errors and accidental tripping of circuits
while testing. We believe there should be one stated activity “Protection System Control Circuitry and have a
maximum interval of 12 years for monitored systems.
Response: The SDT thanks you for your comments.
Monitoring of the coil of these devices does not assure that the device will mechanically operate properly. Electromechanical devices such as lockout
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relays and auxiliary relays must be exercised periodically to assure proper operation. The monitoring systems cannot perform this. See
Supplementary Reference Document Section 15.3 (page 22).
Ameren
No
We agree with the vast majority of them, listed below are our few concerns, questions, and pleas for
clarification.
1) We disagree with doing specific gravity and temperature of every cell in the 18 month test because the
other tests being done are already comprehensive.
2) FAQ 3B p 29 digital relay A/D verification should include simply comparing digital relay displayed metered
values to another metered source.
3) FAQ 3A p6 Change “prove that” to “verify”. For single CT or VT, this can be challenging and some
measure of reasonableness in determining an expected value comparable to the measured value must be
acceptable.
4) FAQ 1B p17 Combining evidence forms of “Process documentation or plans” and “Data” or “screen shots”
shows compliance. Please add an example or verbiage to clarify that a field technician’s (or operator)
recorded check-off combined with a company’s process is sufficient evidence. Otherwise documentation
alone could consume considerable field personnel time.
5) FAQ p2 Add FAQ to clarify “verify settings”. If EM relays are included, explain that minor tap or time dial
differences of the order of relay tolerances are acceptable. For digital relays state that software compare
functions are a sufficient means to “verify settings.”
6) Omit Table 1b row 3 because row 4 actually applies to Monitoring Level 2 Trip Circuits. Row 3 already
appears in Table 1a, and repeating it in Table 1b is confusing.
7) FAQ 4D p 7 then defines auxiliary relays as device 86 and 94. Does device number nomenclature or
function determine and restrict inclusion?
8) Please state that “a location where action can be taken for alarmed failures” would include a dispatch
center or control room. From there the custodial authority would be called out to take action.
9) Please explain the expansion from station battery to station DC supply, specifically the addition of the
charger, an AC to DC device.
10. The charger load test up to its current limiter would add a significant amount of work with little known
benefit.
11. Have charger problems been a significant cause of cascading outages?
12) We oppose your expansion of Station DC Supply to UFLS (the last row on page 8.) PRC-008-0 is
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restricted to UFLS equipment. UFLS is often applied in distribution substations to trip feeders directly serving
load. Your scope expansion has the potential to greatly increase the number of substation DC Supplies
covered by NERC standards. ,. While we agree that UFLS is BES applicable, and those substations are
included in our overall maintenance program, this expansion to NERC scrutiny is not warranted. Have there
been UF events in which a material amount of load was not shed because of DC problems? UFLS is spread
out amongst many distribution stations, and even if a couple did fail to trip in an underfrequency event, it
would have little effect.
13) FAQ 2 p 17 expands the scope at Generating Facilities so that system connected station auxiliary
transformers would be included. We oppose this expansion as these are radially served loads, and they often
do not result in generation loss. Even if they did, the BES can readily tolerate the loss of a single generator.
Response: The SDT thanks you for your comments.
1. All references to specific gravity and temperature testing have been removed from the revised standard.
2. The FAQ has been revised and reorganized in response to many industry comments; see FAQ II-3 (all subsections – pages 8-10) for a discussion of
this topic.
3. The FAQ has been revised and reorganized in response to many industry comments; see FAQ II-3 (all subsections – pages 8-10) for a discussion of
this topic.
4. The FAQ has been revised and reorganized in response to many industry comments; see FAQ IV-1-B (page 21)
5. See FAQ II-2-D & II-2-E(pages 6-7).
6. Table 1a and Table 1b each stand alone; use the table that is relevant to the level of monitoring that is implemented.
7. The SDT modified the FAQ to remove references to the IEEE device numbers (page 11) except when essential to respond to the question.
Regardless of how the device is described by internal entity nomenclature, the function of the device determines whether it is included within the
standard.
8. Your suggestion is properly considered as an example. See FAQ V-1-A (page 28).
9. The SDT believes that the charger is an integral portion of the Station DC supply; thus it has been added. The SDT has modified the standard to
simplify the requirements related to maintenance of the battery charger.
10. The SDT modified the standard in consideration of your comment. All maintenance activities pertaining to battery chargers have been removed
except verification of the float voltage.
11. The standard addresses overall Protection System reliability, not only those issues that may cause cascading outages.
12. The SDT believes that verification of the DC supply voltage to the UFLS is not burdensome. The SDT has modified the standard to clarify that the
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only DC Supply requirement relevant to UFLS is to verify the DC supply voltage.
13. Station service transformers are essential to starting the plant during grid recovery. The FAQ clarifies why these elements are included. The
standard addresses overall Protection System reliability, not only those issues that may cause extreme outages.
Manitoba Hydro
No
1. What documentation or evidence is required to prove that the Protection System Control Circuitry has been
maintained every three months, if just a visual inspection of the breaker control trip circuit RED panel light has
been completed, to verify continuity of breaker trip coil?
2. How do we handle breakers with dual trip coils and only one RED light for trip coil continuity?
3. What do the terms DISTRIBUTED and CENTRALIZED with respect to UFLS mean?
4. In Table 1C under the heading "Maximum Maintenance Interval” some of the entries are stated as being
"Continuous". In the case of other maintenance activities the descriptor for Maintenance Interval indentifies
the maximum period of time that may elapse before action must be taken. "Continuous" implies continuous
action; however, in reality continuous monitoring enables no maintenance action to be taken until such time
as trends indicate the need to do so. Therefore we recommend that where the maintenance interval is stated
as "Continuous" it should be changed to read "Never" or "Not Applicable".
5. The Table 1A requirement of 3 months for Protection System Control Circuitry (Breaker Trip Coil Only)
(except for UFLS or UVLS) should be omitted as it is not realistic. Recommend following the Table 1B
requirement of 6 years (Trip testing) for this. Does 27 undervoltage monitoring of this circuit qualify as self
monitoring?
Response: The SDT thanks you for your comments.
1. The requirement to which you refer has been removed. See FAQ IV-1-B (page 21) for a general discussion of documentation.
2. The SDT has modified the standard to remove the requirement cited in your comment.
3. See FAQ II-7-C (page 18) and FAQ II-8-E (page 19A).
4. Continuous” is intended to clarify that the maintenance is being performed continuously via the monitoring system and the Activities portion of the
table is intended to state those activities that are being performed by the monitoring system.
5. The SDT has removed this requirement.
CPS Energy
No
While I agree for the most part, there are some activities that are unclear.
1. Specifically, the testing of voltage and current sensing devices, some of the trip coil testing, and some of
the communications testing. If the trip coil is now going to be included in the definition of the protective
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system, is the testing defined adequate?
2. The testing of the voltage and current sensing devices is not entirely clear.
Response: The SDT thanks you for your comments.
1. The listed activities are contemplated as minimum activities and do not preclude an entity from performing additional activities.
2. See the Supplementary Reference Document, Section 15.2 (page 21) and FAQ II-3-A (page 19) for a discussion of this topic.
AECI
No
1. Tables 1a and 1b Station DC Supply: Requirement is to measure specific gravity and temperature of
every cell. We believe that this test is unnecessary if voltage and internal resistance are measured. This
test should only be required if other tests indicate a problem, or if the voltage and internal resistance tests
are not performed.
2. Tables 1a and 1b Station DC Supply (Valve Regulated Lead-Acid Batteries): Will a limited discharge test
be acceptable as a “performance or service capacity test” or is full discharge required? We believe a full
discharge test will decrease battery life and suggest that only a limited discharge test be performed.
3. Tables 1a and 1b Station DC Supply (Vented Lead-Acid Batteries): What is the definition of “modified
performance capacity test?”
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment concerning station dc supply and has removed the requirement to measure
specific gravity and temperature of every cell.
2. The SDT does not feel that conducting a performance or service capacity test at the intervals prescribed in the standard will cause any appreciable
decrease in battery life over the service life of the battery. The Protection System owner is responsible for maintaining a station dc supply that can
perform as designed and conducting a performance or service capacity test will verify that a VRLA battery will satisfy the design requirements (battery
duty cycle) of the dc system that a limited discharge test might not verify. If you are concerned that such a test may have implications on battery life,
the standard provides an option to instead measure and trend internal cell/unit ohmic values on a 3-month interval.
3. How to conduct a modified performance test for Vented Lead-Acid Batteries is explained in detail in various available reference books. For Vented
Lead-Acid Batteries, it is a capacity test where the discharge rate(s) are modified to cover every portion of the battery’s duty cycle.
Puget Sound Energy
June 3, 2010
No
For all tables, PSE agrees with the majority of the minimum maintenance activities established. However, the
Station DC supply maintenance activities raise concern. The requirement to test that the charger will provide
full rated current versus output seems to be excessive. In many cases the charger is rated far in excess of
the output needed to perform its function. Also PSE is not aware of a known industry test for these and it is
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not an IEEE recommended standard. Finally, PSE is unclear whether this test would diminish the charger.
Response: The SDT thanks you for your comments. The SDT modified the standard in consideration of your comment regarding battery chargers.
The maintenance activities for battery chargers have been modified to remove all activities except for verification of the float voltage.
SERC (PCS)
Yes
We agree with the majority of the activities. Below is an example where clarification is needed.
1. “Verify proper functioning of the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays” under “Voltage and Current Sensing Devices Inputs to Protective Relays.”
How would this be done if no redundancy is available for cross-checking voltage and current sources?
2. In certain situations, “verify proper functioning” is not clear enough. Documentation of verification consistent
with the entities procedures should be adequate to indicate compliance.
Response: The SDT thanks you for your comments.
1. The standard is prescribing what needs to be done, not how. Please refer to the Supplementary Reference Document Section 15.2 (page 21) and
FAQ II-3-A (page 19) for examples and additional discussion.
2. Documentation of verification consistent with your procedures is sufficient to “verify proper functioning”
TVA
Yes
Add clarifying statement from Table 1b for Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS
Systems Only) to the same section in Table 1a. Statement is “(Verification does not require actual tripping of
circuit breakers or interrupting devices.)"
Response: Thank you for your comment. The SDT has modified the standard in consideration of your comment. The following was added to Table 1a:
Type of Component - Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS Systems Only)
Maximum Maintenance Interval - 6 Calendar Years
Maintenance Activity - Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits, including all
electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System, except .that verification does not require actual
tripping of circuit breakers or interrupting devices.
JEA
Yes
If a communication system relies on a battery system independent of the "station battery", is this
communication system battery under the same requirements as the "station battery"?
Response: Thank you for your comment. The proper functioning of such batteries will be addressed by the verification and monitoring of the
communications system, and by addressing maintenance correctable issues related to maintenance of communication systems. See FAQ II-5-K (page
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
15).
Bonneville Power Administration
Yes
Electric Market Policy
Yes
Entergy Services, Inc
Yes
Georgia System Operations
Corporation
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
Saskatchewan Power
Corporation
Yes
Western Area Power
Administration
Yes
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
3. Within Table 1a, the draft standard establishes maximum allowable maintenance intervals for the various types
of devices defined within the definition of “Protection System”, where nothing is known about the in-service
condition of the devices. Do you agree with these intervals? If not, please explain in the comment area.
Summary Consideration: Most respondents disagreed with the specified maximum allowable intervals to some degree or
another. The disagreements ranged over the full spectrum of activities specified in the Tables, and often corresponded to the
disagreements related to the activities. The intervals within Table 1a were reconsidered (with minor changes – eliminating the
3-month control circuit activity) by the SDT when responding to the comments.
Organization
Yes or No
Green Country Energy LLC
No
Question 3 Comment
1) Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) also The maintenance
activity causes excessive breaker operation, and the intrusive nature increases the risk of subsequent
Misoperations on operating units. System configuration of many plants will require an extensive interruption of
total plant production to complete the test.
2) Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS systems only) The maintenance activity
causes excessive breaker operation, and the intrusive nature increases the risk of subsequent Misoperations
on operating units. System configuration of many plants will require an extensive interruption of total plant
production to complete the test.
Response: The SDT thanks you for your comments.
1. The overall Protection System Control Circuitry can be addressed in segments, as long as all portions are verified or tested as required. Depending
on the arrangement of the DC control circuit, it may be necessary to only trip the breaker itself once. See FAQ II-4-E (page 11).
2. The overall Protection System Control Circuitry can be addressed in segments, as long as all portions are verified or tested as required. Depending
on the arrangement of the DC control circuit, it may be necessary to only trip the breaker itself once. See FAQ II-4-E (page 11).
Public Service Enterprise Group
Companies
No
1) Table 1a Station dc supply (that uses a battery and charger). The 6 year test requires that the charger
perform as designed. PSE&G usually applies redundant battery chargers. PSE&G would like the drafting
team to consider if it is appropriate to not require the 6 year battery charger tests if a battery owner uses
primary and backup battery chargers. PSEG believes that the use of a redundant charger will maintain
reliability at the same level or better level as provided by testing a single charger.
2) For protection system control circuits components (breaker trip coil only), suggest that a sub category with
redundant trip coils be added with longer maintenance interval to allow for the reliability provided by
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Organization
Yes or No
Question 3 Comment
redundancy.
Response: The SDT thanks you for your comments.
1. The performance of the battery charger is critical to the performance of the protection system. The SDT has modified the standard to simplify the
requirements related to maintenance of the battery charger. If condition-based maintenance is applied in accordance with Table 1b, the battery alarms
could automatically (or manually) switch to the redundant charger. Redundancy may also provide more flexibility in addressing issues discovered
during maintenance.
2. Even with redundant equipment, it is essential that all equipment be tested according to the requirements of this standard to ensure proper function
and to support the reliability advantages presented by redundancy. The requirements related to this subject have been extensively modified.
Ameren
No
1) The “zero tolerance” structure proposed combined with the large volume and complexity of Protection
System components forces an entity to shorten their intervals well below maximum. We instead propose a
calendar increment grace period in which a small percentage of carryover components would be tracked and
addressed. For example, up to 10% of all breaker trip coils subject to the 3 month “verify breaker trip coil
continuity” could carry over into the first month of the next period. And for example, up to 5% of an entity’s
communication channel 6 year verifications could carryover into the next year. These carryover components
would be addressed with high priority in that next calendar increment. There are many barriers to 100%
completion or zero tolerance. Barriers include sheer volume, obtaining outages, resource availability,
coordination, and documentation (over ten thousand components in our utility alone; taking a BES outage to
permit maintenance can incur a greater reliability risk than delaying the maintenance; emergent issues such
as major storms impact resource availability; coordination with interconnected neighbors, their resources and
maintenance timing; record keeping errors or oversights; etc. )
2) Alternatively, components with intervals less than a year should be stated in terms of the number of times
annually it should be performed, rather than a short duration interval. The expectation is that they would be
roughly equally spaced throughout the year; for example quarterly instead of 3 months. Comment 1 grace
period would still apply to components with maximum intervals of 1 year or greater.
3) Some of our maintenance intervals are shorter than maximum. Please confirm that documentation is only
to be kept for two of the entity’s intervals, not two of the maximum interval.
4) Please add standard language or FAQ near 2D on p 18 that an entity can validly use an interval with %
tolerance to achieve maintenance goals, as long as the applicable maximum interval is honored.
Response: The SDT thanks you for your comments.
1. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals
would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace
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Organization
Yes or No
Question 3 Comment
period” would not conform to this directive.
2. Simply stating the number of times annually that these devices must be maintained, with a tacit expectation that the maintenance be spaced
throughout the year, does not ensure that they will be tested thusly. To achieve the periodicity of the testing, it is essential that the requirement
specify such periodicity. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the
established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and
allowing for a “grace period” would not conform to this directive.
3. The data retention has been modified in consideration of your comments. The revised language reads as follows:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation of the two most recent performances of each
distinct maintenance activity for the Protection System components, or to the previous on-site audit date, whichever is longer.
4. You may define your program within the parameters expressed within the standard as long as you adhere both to your program and to the Standard.
Exelon Generation Company,
LLC
No
1. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's
refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing
of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing
programs.
2. Table 1a page 6 regarding the 3 Month "Protection System Control Circuitry (Breaker Trip Coil Only)
(except for UFLS or UVLS)" states that the maintenance activity shall verify the continuity of the breaker trip
circuit including the trip coil. There is unclear guidance on how this activity is to be performed, particular on
generator output breakers. Does this activity imply actual trip testing of the breaker itself? If so, performing
this type of activity with the generator on-line puts the unit at risk without any commensurate increase in
reliability to the bulk electric system. If this is the case it is requested that this particular test is extended from
3 months to 24 months to align with nuclear generating units refueling cycle. If not, and this activity is simply
verification of continuity by means of light indication; then please clarify in Table 1a.
Response: The SDT thanks you for your comments.
1. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document
for a discussion on this issue.
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Question 3 Comment
2. The SDT has removed this requirement.
Entergy Services, Inc
No
1. A 3 month interval activity is likely to drive an entity to perform that activity every 2 months in a zero
tolerance, 100% completion, mandatory compliance environment. There should be an allowance for a grace
period on monthly designated activities, for instance a one month grace period, unless the intention is to have
the activity performed more frequently than indicated. Additional guidance is needed on the monthly interval
designations. Is it okay, for instance, to do all four tasks (3 month interval) at one time? Instinctively the
answer should be "no", but if following the "calendar year" allowance, then maybe it is. Are we non-compliant
on a 3 month interval task if we go one single day over the due date? Instinctively the answer should be "no",
but some additional guidance should be provided. For example, the standard might be more understandable if
it indicated that if the interval is "four per year" (or 3 month interval), then it is allowed to perform these tasks
no less than 45 days apart from each other as long as four are done within a calendar year, etc.
2. We believe the 3 month trip coil task activity could actually shorten the life of the trip coil, introduce
unpredictable trip coil failures, and increase the risk of an in-service failure of the trip coil if the verification is
done by tripping the breaker each time. Increasing the risk of failure is counter-productive the intent of the
standard.
Response: The SDT thanks you for your comments.
1. The standard specifies MAXIMUM allowable intervals for the various activities; entities must manage their program however they see fit to adhere to
those intervals. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established
intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for
a “grace period” would not conform to this directive.
2. The SDT has removed this requirement.
MRO NERC Standards Review
Subcommittee
No
A. It looks like for unmonitored systems, breaker trip coils are to be checked for continuity every 3 months.
There is no mention of auxiliary relays. In the partially monitored and fully monitored sections, trip coils and
auxiliary relays are lumped in the same category at 6 calendar years each. What happened to the aux relays
in the unmonitored section? Also, note that the term "trip coils" is used, not "breaker trip coils" in the type of
component category.
B. The maintenance interval for Protection System Control Circuitry (Trip coils and Auxiliary relays) is 6 years,
but the interval for relay output contacts is 12 years when these components are partially monitored. It seems
that these things all have a similar reliability. If commissioning tests are done diligently, the trip DC availability
is continuously monitored and the trip coil itself is continuously monitored, no functional tests should be
needed. The only thing that would be done at PM time would be to ensure that the alarming method is still
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Organization
Yes or No
Question 3 Comment
functional.
Response: The SDT thanks you for your comments.
A. The SDT has removed this requirement.
B. In your discussion (with continuous monitoring of the trip dc and trip coil), you have effectively established most of the monitoring to move to either
Table 1b or even Table 1c. You are encouraged to carefully review the Monitoring Attributes for these higher levels of monitoring; if you satisfy the
attributes, you may be able to further minimize hands-on maintenance.
NextEra Energy Resources
No
a. (i) Protective relays, (ii) Protection Control Circuitry (Trip Circuits) and (iii) Protection System
Communications Equipment and Channels should be changed from 6 calendar years to 8 calendar years.
Based on FPL Group’s experience and Reliability Centered Maintenance (RCM) program, FPL Group has
established an 8 year program and has found that an aggressive 6 year program would not substantially
increase the effectiveness of a preventative maintenance program.
b. Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s lead-calcium
batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past.
c. The maximum maintenance interval for communications equipment should be changed from 3 months to
12 months. Based on FPL Group’s experience and RCM program, FPL Group has established a 12 month
program that is effective.
d. Additionally, NextEra Energy concurs with other entities comments concerning this question: Imposing
inflexible maximum interval requirements has the same basic problems as imposing inflexible minimum task
requirements. The inflexible “maximum interval” approach fails to recognize the harmful effects of overmaintenance and precludes the ability of entities to tailor their maintenance program based on their
configurations and operating experience. The maximum interval approach also has same perverse
consequences for entities with redundant systems as the minimum interval approach.
e. Furthermore, the rigid maximum interval approach embodied herein does not sufficiently take into
consideration common natural disaster situations. Several of the preventive maintenance tasks proposed in
this standard have a maximum interval of 3 months, which is problematic under normal circumstances and
unworkable when routine maintenance activities have a much lower priority than emergency repair and
restoration. An interval as short as this does not provide a sufficient maintenance scheduling horizon to
complete the tasks. The SDT could attempt to address this shortfall by modifying the draft to account for
natural disaster situations. For example, the FERC-approved NERC reliability standard FAC-003 for
Vegetation Management does include such allowances for natural disasters, such as tornados and
hurricanes. However, even if that specific problem is addressed, the fundamental problems created by an
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Yes or No
Question 3 Comment
overly prescriptive maximum interval approach remains.
Response: The SDT thanks you for your comments.
a. The SDT believes that the 6-year maximum allowable intervals, to which you refer, are appropriate. The intervals within the standard are based on
the experience of the SDT and of the NERC System Protection and Control Task Force (SPCTF). The SPCTF also validated these intervals via an
informal survey that represented about 2/3 of the net-energy-for-load within NERC, and by comparison to IEEE surveys. See Supplementary Reference
Document Section 8 (page 9). An entity may implement a Performance Based maintenance program if they wish to apply their experience.
b. The SDT agrees that a healthy modern lead acid battery can go for extended periods of time beyond 3 months without requiring watering. However,
checking cell electrolyte level not only indicates the need for battery watering, it is an indication of an individual cell’s health and needs to remain at
the Maximum Maintenance Interval of 3 months. To avoid the confusion that the Maintenance Activity listed in Table 1 was to water the battery at the
specified 3 month interval, the Drafting Team has changed the wording of the Maintenance Activity from “verify proper” to “check” electrolyte level.
c. The 3 month interval is for inspection of unmonitored equipment. The SDT felt that this is appropriate for carrier channels or for leased audio
channels that have a chance of failure and would result in an overtrip or failure to trip if ignored. It is possible to extend the interval for performance
based systems if the entity has applicable data.
d. FERC Order 693 directs that NERC establish maximum allowable intervals. For entities that wish to establish a performance-based maintenance
program using experience, the standard DOES allow for that.
e. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to implement an
effective PSMP.
CenterPoint Energy
No
a. See CenterPoint Energy’s comments made in response to question 2. Imposing inflexible maximum
interval requirements has the same basic problems as imposing inflexible minimum task requirements. The
inflexible “maximum interval” approach fails to recognize the harmful effects of over-maintenance and
precludes the ability of entities to tailor their maintenance program based on their configurations and
operating experience. The maximum interval approach also has same perverse consequences for entities
with redundant systems as the minimum interval approach.
b. Furthermore, the rigid maximum interval approach embodied herein does not sufficiently take into
consideration common natural disaster situations. Several of the preventive maintenance tasks proposed in
this standard have a maximum interval of 3 months, which is problematic under normal circumstances and
unworkable when routine maintenance activities have a much lower priority than emergency repair and
restoration. An interval as short as this does not provide a sufficient maintenance scheduling horizon to
complete the tasks. The SDT could attempt to address this shortfall by modifying the draft to account for
natural disaster situations. For example, the FERC-approved NERC reliability standard FAC-003 for
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Organization
Yes or No
Question 3 Comment
Vegetation Management does include such allowances for natural disasters, such as tornados and
hurricanes. However, even if that specific problem is addressed, the fundamental problems created by an
overly prescriptive maximum interval approach remains.
Response: The SDT thanks you for your comments.
a. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to implement an
effective PSMP.
b. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document
(page 9) for a discussion on this issue.
FirstEnergy
No
Although we agree with the proposed maintenance intervals, there may be extenuating circumstances beyond
an entity’s control that could delay maintenance on a particular protection system. We ask the SDT to
consider adding a footnote to these intervals that allows a grace period of up to three months when outages
necessary for maintenance must be delayed due to unusual system conditions or other issues where an
outage would be detrimental to the entity's system.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may
need to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. Specifically,
for generation facilities, there would seem to be numerous opportunities within the 6-year or longer intervals to perform the required maintenance
during a scheduled plant outage, and maintenance with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection
than anything else; the SDT believes that this maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be
used to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed
that NERC establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8
of the Supplementary Reference Document (page 9) for a discussion on this issue.
American Transmission
Company
June 3, 2010
No
1. ATC is concerned that the proposed standard would result in entities being required to use outdated
testing techniques and or practices. We believe that the standard should identify the “what” and not the
“how”. The identification of specific testing techniques and/or practices would likely result in entities being
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Yes or No
Question 3 Comment
prevented from implementing improved techniques and/or practices. (The standard would have to be
updated and receive FERC approval before entities could test/implement improved testing techniques
and/or practices.)
2. An example of the standard directing the how is with station batteries. The “specific gravity” test,
proposed in the standard, is being used less or not at all by some registered entities because a more
accurate method that is less intrusive and provides more accurate results has been developed. (This
standard would basically require entities to go backwards in testing practices.)This standard should not
prevent the use of improved techniques and/or practices.
Response: The SDT thanks you for your comments.
1. In consideration for your concern, the Drafting Team has revised Table 1 to identify more of what is required for the station dc supply activities and
eliminated most of the “how to do it”.
2. All references to specific gravity and temperature testing have been removed from the revised standard.
City Utilities of Springfield, MO
No
CU agrees in general with many of the maximum maintenance intervals. However, we disagree with the
necessity to verify the continuity of trip coils every 3 months. We would be interested to know what basis the
committee used to arrive at all intervals. Furthermore, it is our opinion that even if a component is
unmonitored, the interval should not surpass the manufacturer’s recommendations.
Response: The SDT thanks you for your comments and has removed this requirement.
ITC Holdings
No
1. Does the standard require that time or condition based maintenance programs monitor countable events to
identify significant problems in particular relay segments, and then adjust the maintenance interval
accordingly?
2. On page 6: Please clarify the use of “Calendar Year” Our understanding is that if a relay is maintained on
August 31, 2003 on a 6 year interval, it will not be overdue until January 1, 2010. Is this correct??
3. On Page 7: What is the basis for 18 months? We believe 2 calendar years would be more appropriate.
4. On Pages 6, 10: What is the basis of the 6 calendar year interval for functional trip tests? We request that
this be changed to a 10 calendar year interval. We follow a 10 calendar year interval that has proven to be
satisfactory. Decreasing the interval to 6 calendar years will result in a major increase in our maintenance
expenses without a corresponding increase in reliability.
5. On Page 9: If it is being verified ok every 3 months, what is the basis of the 6 calendar year interval for
Communication equipment? ITC communications systems are partially monitored and therefore required to
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Yes or No
Question 3 Comment
perform this testing every 12 years. However, ITC would like to know the basis of the 6 year interval for
informational purposes.
6. On pages 6, 8, 11, 13, 14 and 19: The maximum maintenance interval (when the associated UVLS or
UFLS system is maintained) should be shown as the actual “6 Calendar Years”.?
7. On Page 1 of Attachment A: Please provide an example in the reference of the proper way of adjusting the
interval based on test results.
8. On Pages 7, 8, 12: It is our understanding that adequate maintenance can be achieved by performing
either one of the two maintenance activities in cases where there is an “or”, is that correct?
9. On Page 14: For the bottom two rows on page 14 we believe there is a typo and it should read “Level 2”
not “Level 1”.
10. On Page 13: Do power line carrier schemes that provide a remote alarm if a daily check back test fails,
meet level 2 monitoring requirements?
11. In Table 1: What is the basis for the 6 year interval for the battery systems? This test would be an
additional test for ITC. We would prefer to perform this additional test with the relay periodic maintenance on
a 10 year interval.
Response: The SDT thanks you for your comments.
1. No, the standard does not require that countable events be analyzed for determination of intervals in time-based or condition-based maintenance
programs. However, excessive poor operation may trigger additional activities as part of a corrective action plan per PRC-004 in response to
Misoperations.
2. Your understanding is incorrect. A maintenance activity last completed in 2003 on a 6-year interval would next need to be maintained sometime in
2009. (See Supplementary Reference Document Section 8.4, page 13)
3. The SDT believes that 18-month is the appropriate interval, based on common industry practice.
4. The SDT believes that 6-years is the appropriate interval, based on common industry practice. For entities that wish to establish a performancebased maintenance program using experience, the standard DOES allow for that.
5. The 6 year interval is mostly driven by the needs of power line carrier channels and the use of analog auxiliary tuning components in the
communications systems. The relay communications systems intervals were based on the experiences of SDT and NERC System Protection
Committee Task Force members.
6. The SDT has modified the standard in consideration of your comment to include the specific intervals for the various components related to
UFLS/UVLS, with the exception of the dc supply. The maintenance for the dc supply for UFLS/UVLS was left related to the maintenance of the
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Yes or No
Question 3 Comment
UVLS/UFLS system because the SDT believed that this activity should be tied to the specific intervals needed for the relays.
7. See FAQ IV-3-H (page 26).
8. You are correct in your statement that the Maintenance Activity of verifying that the station battery can perform as designed can be met by
completing either of the two activities listed in Table 1 in the prescribed Maximum Maintenance Interval.
9. Thank you. You are correct; these table entries have been modified accordingly.
10. Yes. A remote alarm daily auto-check back as you describe satisfies the Level 2 monitoring attributes for channel performance in a power line
carrier system.
11. The SDT believes that extending the Maximum Maintenance Interval for station batteries beyond that listed in Table 1 would degrade the Protection
System by not detecting compromises to the performance of the station dc supply during the extended interval.
Platte River Power Authority
Maintenance Group
No
Electro-mechanical relays are historically out of tolerance well before the 6 year maximum allowable
maintenance intervals defined within table 1a.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may
need to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals.
Florida Municipal Power Agency,
and its Member Cities
No
1. FMPA agrees in general with many of the maximum maintenance intervals; however we have been unable
to determine what basis was used to arrive at the time based intervals provided in the tables. Further
explanation would be appreciated
2. FMPA is concerned with the use of the term “continuous” in Table 1c. As stated, it would seem that, on loss
of communications that would communicate the alarm, thereby causing a loss of “continuous” monitoring and
alarming, the entity who invested in a reliability improving monitoring system would be found non-compliant
with an infinitesimal maintenance period required for “continuous” monitoring. Therefore, FMPA recommends
using “not applicable” or some other term in this column.
Response: The SDT thanks you for your comments.
1. The intervals within the standard are based on the experience of the SDT and of the NERC System Protection and Control Task Force (SPCTF). The
SPCTF also validated these intervals via an informal survey that represented about 2/3 of the net-energy-for-load within NERC, and by comparison to
IEEE surveys. See Supplementary Reference Document Section 8 (page 9).
2. The SDT believes that the maintenance is indeed being done “continuously”. If the alarming method is not functional, you’ve fundamentally
dropped back to Level 1 or Level 2 monitoring, depending on the component.
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Yes or No
E.ON U.S.
No
Question 3 Comment
1. Generally, E.ON U.S. requests that the SDT provide the basis for the proposed changes in maintenance
time lines. E ON U.S.’s existing maintenance intervals are based on actual operating experience. Not having
been provided with the basis for the proposed intervals, the time lines appear arbitrary. E.ON U.S. currently
has an 8-year interval for combustion turbines vs. the 6-year interval provided here. The E.ON U.S. interval is
based on the Company’s experience with this equipment. E.ON U.S. suggests that the SDT provide some
consideration to individual entities historic practices.
2. It is difficult to track “18 months”. Maintenance intervals should be in expressed in number of years.
3. E ON U.S. also does not understand the basis for the 3 months maintenance schedule on breaker trip
coils. Typically, the circuit breaker closed indication is wired through the breaker trip coil. Thus there could
not be a breaker closed indication without a good breaker trip coil. So, this test should be considered
continuous monitoring which may not even require documentation except in case of failure.
Response: The SDT thanks you for your comments.
1. See Supplementary Reference Document, Section 8 (page 9). An entity’s historical practices and results can be used to establish a performancebased maintenance program as described within the standard.
2. The SDT believes that the 18-month interval is appropriate. If you wish, you may do these activities more frequently to aid in your maintenance
tracking, as long as you adhere to the requirements within the standard.
3. If this indication is local (for example, a lamp), 3-month inspections of the lamp state are necessary to satisfy the requirement. If the indication is an
alarm to a location such as a control room, control center, etc, this may satisfy for either Level 2 or Level 3 monitoring as you suggest.
Transmission Owner
No
a. i) Protective relays, ii) Protection Control Circuitry (Trip Circuits) and iii) Protection System Communications
Equipment and Channels should be changed from 6 calendar years to 8 calendar years. Based on FPL’s
experience and Reliability Centered Maintenance (RCM) program, FPL has established an 8 year program
and has found that an aggressive 6 year program would not substantially increase the effectiveness of a
preventative maintenance program.
b. Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s lead-calcium
batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past.
c. The maximum maintenance interval for communications equipment should be changed from 3 months to
12 months. Based on FPL’s experience and RCM program, FPL has established a 12 month program that is
effective.
Response: The SDT thanks you for your comments.
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a. The SDT believes that the 6-year interval is appropriate. An entity may implement a Performance Based maintenance program if they wish to apply
their experience.
b. The SDT agrees that a healthy modern lead acid battery can go for extended periods of time beyond 3 months without requiring watering. However,
checking cell electrolyte level not only indicates the need for battery watering, it is an indication of an individual cell’s health and needs to remain at
the Maximum Maintenance Interval of 3 months. To avoid the confusion that the Maintenance Activity listed in Table 1 was to water the battery at the
specified 3 month interval, the Drafting Team has changed the wording of the Maintenance Activity from “verify proper” to “check” electrolyte level.
c. The 3 month interval is for inspection of unmonitored equipment. The SDT felt that this is appropriate for carrier channels or for leased audio
channels that have a chance of failure and would result in an overtrip or failure to trip if ignored. It is possible to extend the interval for performance
based systems if the entity has applicable data.
Illinois Municipal Electric Agency
No
1. IMEA is concerned the maximum allowable maintenance intervals may be too prescriptive for transmission
subsystems that essentially operate radially.
2. Please see comment under Question 7.
3. Given the magnitude of reliability-related initiatives currently in progress, additional time is needed to
evaluate these intervals, particularly for communications equipment, dc supply, and UFLS relays.
Response: The SDT thanks you for your comments.
1. The intervals are established for Protection Systems on BES components. If you believe that some of your system components are not BES that is
an issue relative to your region’s BES definition.
2. See response to comment under Question 7.
3. An Implementation Plan is provided to allow systematic implementation of these intervals. If you are concerned about the time available to develop
comments on posted drafts, be advised that the posting period is determined according to the NERC Reliability Standards Development Process. The
SDT is providing the maximum comment time available.
PacifiCorp
No
No comment.
Duke Energy
No
1. Our comments are limited to Table 1a. More clarity is needed for many of the Maintenance Activities
before assessing whether or not the intervals are reasonable. But as a general comment we would like to
understand the basis used to develop all of the intervals, and how that basis compares with research done by
the Electric Power Research Institute (EPRI). It is our understanding that NERC did an industry survey of
maintenance intervals and we would like to see the results of that survey as well.
Specific comments:
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2. Protective Relays 6 calendar years is okay.
3. Voltage and Current Sensing Devices Inputs to Protective Relays We question the logic for a 12-year
interval. Proper functioning should be verified at commissioning, and then anytime thereafter if changes are
made in a PT or CT circuit. Additional periodic checks may be warranted as suggested in Table 1A, however
no additional checking should be required where circuit configuration will inherently detect problems with a PT
or CT. For example, PTs & CTs that are monitored through EMS or microprocessor relays will be alarmed
when they are out of specification.
4. Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS) In locations where
the continuity of the circuit is not monitored (via a light in the path or through a microprocessor relay) this
would be a very complicated test, which could impact reliability, especially if done every three months.
5. Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) Need clarity on exactly what
the activity is to include. We believe proving one output all the way to the trip coil is appropriate. Proving
every output and every auxiliary contact, to the trip coil would be unnecessarily invasive and could impact
reliability, even if done every 6 calendar years.
6. Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only) Interval is okay, but we
disagree with tripping the breakers proving the output of the relay should be sufficient. Systems that have all
load shed on distribution circuits should require trip output be confirmed but should not be required through to
the trip coil due to constraints in tying distribution load.
7. Station dc supply (that has as a component any type of battery) 3 month and 18 month intervals are
probably okay, depending on what is required to “verify continuity and cell integrity of the entire battery” and
“inspect the structural integrity of the battery rack”.
8. Station dc supply (that has as a component Valve Regulated Lead-Acid batteries) 3 calendar years and 3
month intervals are probably okay, depending on what is required for the “performance or service capacity
test”.
9. Station dc supply (that has as a component Vented Lead-Acid batteries) 6 calendar year and 18 month
intervals are probably okay, depending on what is required for the “performance, service or modified
performance capacity test”.
10. Protection system communication equipment and channels 3 months and 6 calendar years seem
reasonable, depending upon what is included in the substation inspection, and what is required for power-line
carrier systems.
11. UVLS and UFLS relays that comprise a protection scheme distributed over the power system Can’t
comment on the 6 calendar year interval until we get more clarity regarding the meaning of “distributed over
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Question 3 Comment
the power system”.
Response: The SDT thanks you for your comments.
1. See Supplementary Reference Document, Section 8 (page 9).
2. The SDT thanks you for your support.
3. For unmonitored systems, the SDT believes that the interval specified in Table 1a is appropriate. If alarming is available for anomalies, you may be
able to use Table 1c with continuous monitoring.
4. Table 1a has been modified to remove the activities to which you refer.
5. See Supplementary Reference Document, Section 15.3 (page 22).
6. The requirements relating to Protection System Control Circuitry for UFLS/UVLS only do not require tripping of the breaker.
7. Thank you for agreeing with the Maximum Maintenance intervals associated with the Maintenance Activities. The SDT has modified the standard
concerning the requirement to verify cell integrity (See FAQ II-5-C, page 12), and continuity (See FAQ II-5-D, page 13) and inspecting for the structural
integrity of the battery rack (See FAQ II-5-H, page 15).
8. How to conduct a performance and service capacity test for Valve Regulated Lead-Acid batteries are explained in detail in various available
reference books. One of the options available to the Protection System owner who is responsible for maintaining a station dc supply that can perform
as designed is to conduct a performance or service capacity test within the Maximum Maintenance Interval of Table 1 that will verify that a VRLA
battery will satisfy the design requirements (battery duty cycle) of the dc system.
9. How to conduct a performance service or modified performance capacity test for Vented Lead-Acid Batteries is explained in detail in various
available reference books.
10. These intervals are for power line carrier channels as well as other types of communications channels.
11. See FAQ II-7-C (page 19).
Electric Market Policy
No
Recommend that all Level 1 three-month maintenance intervals be changed to a quarterly based system
where only 4 inspections are required per year. Given a 3 month maximum interval, activities would need to
be scheduled every 2 months, which would result in six inspections per year. Our experience of four
inspections per year has proven to be successful.
Response: The SDT thanks you for your comments. The SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of
the maintenance activities. “Once per calendar quarter” would allow up to a 6-month practical interval, which would not maintain this periodicity. This
DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
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SERC (PCS)
No
Question 3 Comment
Recommend that all Level 1 three-month maintenance intervals be changed from 3 months to quarterly.
Given a 3 month maximum interval an entity would need to schedule these tasks every 2 months. This would
result in six inspections per year. In the experience of many of our utilities, four inspections per year have
proven to be successful.
Response: The SDT thanks you for your comments. The SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of
the maintenance activities. “Once per calendar quarter” would allow up to a 6-month practical interval, which would not maintain this periodicity. This
DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
Indianapolis Power & Light Co.
No
See comments in number 2 above.
Response: The SDT thanks you for your comments. See response to comments in Question 2.
Austin Energy
No
See item # 10 Comments
Response: The SDT thanks you for your comments. See Question #10 Response
Wolverine Power Supply
Cooperative, Inc.
No
See question 2 response
Response: The SDT thanks you for your comments. See Question #2 Response
SCE&G
No
Several maximum maintenance intervals are 3 months. Since this is an absolute maximum period, entities
would need to schedule on a 2 month basis to assure the 3 month maximum is met, i.e., 6 times per year.
We recommend that 3 month periods be increased to 4 months which allows scheduling every 3 months.
Other methods of achieving the same result are to state periodic requirements of quarterly or 4 times per
year.
Response: The SDT thanks you for your comments. The SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of
the maintenance activities. “Once per calendar quarter” or “four times per year” would allow up to a 6-month practical interval, which would not
maintain this periodicity. This DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
Wisconsin Electric
June 3, 2010
No
Similar to comments in #7 above: It is our practice on distribution-level protection systems to utilize a 6 year
interval plus/minus 1 year to accommodate potential scheduling conflicts. This is consistent with other LSE's
relay testing practices as well. Thus the potential 7 year maintenance interval would be a violation of the draft
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requirements. The maintenance intervals in this standard should be increased accordingly for distribution
protection system equipment.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may
need to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. Specifically,
for generation facilities, there would seem to be numerous opportunities within the 6-year or longer intervals to perform the required maintenance
during a scheduled plant outage, and maintenance with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection
than anything else; the SDT believes that this maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be
used to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed
that NERC establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8
of the Supplementary Reference Document for a discussion on this issue.
Pepco Holdings Inc.
No
Table 1a requires verification of the continuity of the breaker trip circuit every three months in the absence of
a trip coil monitor. Recommend maintenance interval to match that for other protection system control
circuitry (6 years).
Response: The SDT thanks you for your comments. The SDT has modified the standard to remove the requirement to which you refer.
Nebraska Public Power District
No
Table 1a, for Station DC supply (that has as a component - Valve Regulated Lead-Acid batteries) establishes
a Maximum Maintenance Interval of 3 Calendar Years for the following Maintenance Activity: Verify that the
station battery can perform as designed by conducting a performance or service capacity test of the entire
battery bank. What is the basis for this interval? NPPD’s experience indicates that a 5 Year interval is
adequate, especially during the early service life of the battery bank, with increasing frequency as the bank
ages.
Response: Thank you for your comment concerning the Maximum Maintenance Interval for Valve Regulated Lead-Acid batteries (VRLA). Due to the
failure mode and designed service life of VRLA batteries compared to a Vented Lead-Acid batteries, the SDT believes that extending capacity testing of
a VRLA battery beyond the maximum maintenance interval of 3 calendar years in Table 1 cannot be justified regardless of what the battery
manufacturers of VRLA batteries recommend. This is especially true in the later periods of service life beyond 3 calendar years as noted by many
utilities requiring total replacement of their VRLA batteries after 4 years of service. It appears that your practices are actually addressing Vented Lead
Acid batteries, rather than Valve Regulated Lead-Acid batteries.
Dynegy
No
The 3 month interval in Table 1a for verification of the continuity of the breaker trip circuit is only feasible if this
verification can be done by inspection versus testing (see Response to Question 2).
Response: The SDT thanks you for your comment and has removed the requirement.
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Southern Company
No
Question 3 Comment
1. The 3 month intervals specified for the trip coil monitoring and communication circuit testing are too
frequent. Our experience is that trip coils rarely burn open and don’t need to be checked this often. If no
monitoring currently exists, manually checking the circuit (until a time where monitoring can be installed) may
inadvertently cause a trip. This adds risk to the reliability. Thus, requiring the trip circuits to be tested every 3
months may reduce the reliability of the BES.
2. Protection System Control Circuitry (Breaker Trip Coil Only) (Except for UFLS or UVLS) In order to reduce
the risk of reducing Bulk Electric System reliability a better time interval for testing un-monitored trip coils
would be 12 months. This may need to be 24 months for Nuclear Generating units.
3. Some allowance for a grace period (beyond the specified intervals) should be considered for all
classifications. Outage schedules are known to change unexpectedly due to unforeseen circumstances. A
grace period tolerance of +25% for specified maintenance intervals less than 12 months and of +1yr for those
intervals specified as greater than 12 months is recommended. Typically at a nuclear plant a grace period is
allowed by plant procedures. This grace period is defined as an additional 25 percent of the original schedule
interval for the task. The grace period is provided as reasonable flexibility to allow for alignment with
surveillance activities and equipment maintenance outages and to better manage the use of station
resources. Some maintenance activities will require an outage to perform the work. Refueling outages are
typically performed on an 18 month or 24 month refueling cycle. However, refueling outages do not always fall
exactly on that interval. It is possible that the duration between one outage to the next may exceed 18 or 24
months. For activities that are required to be complete on a calendar year cycle this should not be an issue
since the outages are normally scheduled several months prior to the end of the year. However, if the interval
is a monthly interval there could be a problem with scheduling the maintenance such that it does not impact
planned maintenance activities, surveillance requirements, and station resources.
4. Tables 1a, 1b and 1c have several instances where inspection and testing of DC circuits or components
has a specified interval of 18 months. At nuclear generating stations, such tests on station battery banks and
associated chargers incur unacceptable risk if performed with the unit on line and a unit outage is required for
this testing. A number of nuclear plants are on two-year shutdown cycles and we request that the 18 month
intervals be changed to two (2) (calendar) year intervals to accommodate this.
5. Protection System Control Circuitry (Breaker Trip Coil Only) (Except for UFLS or UVLS) Based on past
performance, a complete functional test trip every 6 years is not warranted. This complete functional test
introduces additional risk to our maintenance program, not only from a human error perspective, but also from
the additional frequency of switching and outages required. Our experience has shown that 12 years is an
appropriate maximum time interval (rather than 6 years.)
Response: The SDT thanks you for your comments.
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1. The SDT believes that such maintenance of the communications will primarily be performed by inspection monitoring lamps and so forth. The trip
coil requirements to which you refer have been removed.
2. This activity is primarily inspection-based, involving no invasive testing. The stated intervals seem appropriate.
3. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 (page 9) of the Supplementary Reference
Document for a discussion on this issue.
4. All Maintenance Activities listed in Tables 1a, 1b, and 1c related to the station dc supply that have a Maximum Maintenance Interval shorter than two
(2) (calendar) years are necessary inspection, checking or verification activities routinely performed on the station dc supply with it in service and
without posing an unacceptable risk. The Drafting team feels that to extend these activities beyond their Maximum Maintenance Intervals listed in
Table 1 would jeopardize the station dc supply.
5. The SDT believes that the 6-year interval for this activity is appropriate. If you experience supports a longer interval, the standard permits you to
utilize Performance-Based maintenance.
AEP
No
The availability to perform maintenance of many protection systems is dictated by the load or customer that is
connected. Many of these industrial customers, who are outside the jurisdiction of NERC requirements,
operate 24X7 and see the outages required for maintenance as a nuisance and a loss of revenue. How can
the owner be held non-compliant for not meeting the intervals when they may not control the timing?
Comments expanded in question 10 responses.
Response: The SDT thanks you for your comments. This non-compliance would be addressed via contract law; these contracts are described in the
Statement of Compliance Registry.
US Bureau of Reclamation
No
The definition of Protection System components does not add clarity. The standard proposes including
stations service transformers for generation facilities, however, the protection system definition does not
include those elements. The inclusion of station service transformers would only be appropriate if the
protection associated with the transformer results in the tripping of a transmission element.
Response: The SDT thanks you for your comments. The applicability to station service transformers emphasizes the impact of those components on
the operability of the associated generator. They are not themselves Protection System components; however, maintenance of the Protection System
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components on those system elements is required per the Standard. See FAQ III-2-A (page 20).
Ohio Valley Electric Corp.
No
The documentation requirements for the inspection activities with three month intervals are oppressive and
should not be a part of the protection system maintenance standard.
Response: The SDT thanks you for your comments. The SDT disagrees; it is left to the entity to adopt effective methods to document these activities.
CPS Energy
No
1. The first problem that I have is the 3 Months for the Protection system communications equipment and
channels component. My main concern with this interval is that it is so extremely short and I am concerned
that there may not be any rational behind it. What studies, surveys, or statistical data were used to determine
that 3 months is necessary to protect the reliability of the BES? It doesn't make sense that a communications
signal needs to be checked every 3 months but the protective relay that utilizes that scheme needs to be
checked at most only every 6 years.
2. What concerns me the most with the 3 month interval for my company is with on-off power line carrier DCB
schemes? We only have these schemes on tie lines, and it can be difficult to implement a checkback system
with another utility who might utilize different carrier equipment. This type of scheme is also intended to be
inherently insecure and is frequently more or less tested with faults in the system. The SPCTF should do
surveys to determine what is presently done with these type of systems or provide some other rationale for
the communication requirements. It is not totally clear from the documents, but it appears that the only way to
avoid the 3 month check for an on-off power-line carried DCB scheme is to have an automated check back
scheme. Is this correct? Or is alarming from the carrier equipment adequate?
3. My second problem is with the 6 year maximum maintenance interval for the breaker trip coil in tables 1b
and 1c. By having to verify that each breaker trip coil is electrically operated, you might as well perform a
functional test to test the protection system control circuitry. Electrically operating the trip coil tests the
breaker as much as it test the actual trip coil. Also, if you have a primary and secondary trip coil, is it really
necessary to test this often? What studies or statistical data were used to determine that testing the breaker
trip coils every 6 years is necessary to protect the reliability of the BES?
4. My third problem is with the intervals requirements for the UVLS/UFLS systems. Other than testing and
calibration of electromechanical UVLS/UFLS, most other tests probably should require at most 10 years for
these types of systems. These systems don't require the performance level of most other systems as stated
in the supplementary reference. The testing and calibration of electromechanical UFLS should possibly be
even shorter than the 6 year requirement due to problems with drift with these type of relays. What studies,
surveys, or statistical data were used to determine the intervals in related to UFLS/UVLS.?
Response: The SDT thanks you for your comments.
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1. The 3 month intervals are for unmonitored equipment and are based on experience of the relaying industry represented by the SDT, the SPCTF and
review of IEEE PSRC work. Relay communications using power line carrier or leased audio tone circuits are prone to channel failures and are proven
to be less reliable than protective relays.
2. The automated check back systems are common ways to verify the integrity of the relay communication channel. It would only be moved to Level 2
if the check back test is monitored remotely and the tests are run daily. Without check back equipment, it will be necessary to have personnel at both
ends and manually initiate a signal and verify that the remote equipment operates.
3. In the experience of the SDT and the NERC SPCTF, the 6-year interval is appropriate. The SPCTF also conducted an informal survey of entities
representing approximately 2/3 of the NERC net-energy-for-load and a review of IEEE surveys to validate these intervals. See the Supplementary
Reference Document, Section 8 (page 9).
4. In the experience of the SDT and the NERC SPCTF, the 6-year interval is appropriate. The SPCTF also conducted an informal survey of entities
representing approximately 2/3 of the NERC net-energy-for-load and a review of IEEE surveys to validate these intervals. See the Supplementary
Reference Document, Section 8 (page 9). The maintenance of the other Protection System components associated with UFLS/UVLS is specifically
stated to correspond with the intervals for the relays themselves.
Consumers Energy Company
No
1. The interval for Protection System Control Circuitry (breakers trip coil) should be set at 12 years since this
is a scheme test. This test requires testing of the circuit and not just the coil.
2. The interval for Protection System Control Circuitry (trip circuit) should be set at 12 years since this is a
scheme test. The Protection System Control Circuitry (trip circuit) test would require tripping off customers on
radial distribution circuits which is not acceptable.
3. The interval for a station battery service test (lead acid) should be set at 5 years based on NFPA 70B.
Response: The SDT thanks you for your comments.
1. The SDT believes that the intervals indicated in the standard are appropriate. The standard allows the use of Performance-Based maintenance if
your experience supports it.
2. The SDT believes that the intervals indicated in the standard are appropriate. The standard allows the use of Performance-Based maintenance if
your experience supports it. The standard applies only to Protection Systems on BES components as established by your regional BES definition.
3. NFPA 70B is a recommended practice which is voluntary, and is not a standard that establishes any requirements that must be measurable. NERC
standard PRC-005 requirements are loosely aligned with some of the NFPA standards. However, the Maximum Maintenance Intervals required in PRC005-2 were established to be measurable and enforceable. If an owner chooses to perform the Maintenance Activities outlined in Table 1 of the
standard at a lesser interval the owner is free to do so.
RRI Energy
June 3, 2010
No
1. The intervals need to be defined on a calendar quarters or calendar years, especially for intervals listed as
3 months. The demonstration of maintenance on rolling three-month intervals will be an onerous record
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keeping task, particularly when relying upon planning and tracking software that scheduled recurring tasks on
the same day of an interval.
2. Given the magnitude of the number of trip circuits, the requirements set an un-acceptable trap of noncompliance from a record keeping perspective. The resources required to keep and maintain flawless
records are too much to justify the intervals. A non-compliance is the result if the breakers that happen to be
in an open state when the officially “documented” inspection is recorded and is missed by accidental oversight
on follow-up. If the requirement remains, it should be waived for any breaker that is operated during the
defined interval.
Response: The SDT thanks you for your comments.
1. The SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of the maintenance activities. “Once per calendar
quarter” or “four times per year” would allow up to a 6-month practical interval, which would not maintain this periodicity. This DOES permit entities
to use four inspections per year provided that they carefully manage their maintenance activities.
2. The dc control circuit maintenance to which you refer has been removed from the standards. The SDT disagrees that the record keeping is
excessively burdensome; it is left to the entity to adopt effective methods to document these activities.
Progress Energy
No
The rational for microprocessor-based relay intervals is examined, but all others are strictly based on industry
weighted average of survey results. We believe the team should use a more empirical, documented
approach to determining these intervals, as many companies have longer intervals that they currently have
documented for their basis. If these have been accepted as satisfactory in previous audits, why should they
be required to change just to meet an arbitrary number?
Response: The SDT thanks you for your comments. The standard permits entities to use Performance-based maintenance if they have documented
experience which supports doing so.
Northeast Power Coordinating
Council
No
1. We question whether any maintenance activity should be as long as 12 years. Considering the rate of
change in personnel and technology, the working group should reduce the time period by redefining the
requirement if necessary, or eliminate the standard requirement.
2. In addition, the DC components have too many tests at confusing intervals. Confusion will make it difficult
to implement or follow the exact method used.
Response: The SDT thanks you for your comments.
1. In the experience of the SDT and the NERC SPCTF, the intervals within the standard are appropriate. The SPCTF also conducted an informal survey
of entities representing approximately 2/3 of the NERC net-energy-for-load and a review of IEEE surveys to validate these intervals. (See
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Supplementary Reference Document, Section 8.4, page 13)
2. The SDT has modified the standard in consideration of your comments and simplified the maintenance activities associated with dc supplies.
Detroit Edison
No
What is the basis for the three month interval for verifying breaker trip coil continuity? Will the investment
required to facilitate this really result in the presumed expected increased reliability?
Response: The SDT thanks you for your comments and has removed the requirement.
Manitoba Hydro
No
1. When we have redundant digital relay system that would fall under Level 1c category with a 12 year
maintenance cycle, but the Protection System Control Circuitry is non-monitored so it falls under Level 1a,
with a 6 year maintenance cycle. We will have to complete relay maintenance and trip testing every 12 years
and trip testing only every 6 years, therefore we must complete trip testing twice as often as we are doing the
maintenance. We feel that relay maintenance and trip testing should be completed at the same frequency.
2. The Protection System Control Circuitry (Breaker Trip Coil) checks every three months is too excessive.
These circuits are checked during trip testing of the Protection scheme, at the 6 or 12 year interval.
3. If we have a redundant digital relay system, using a IEC61850 communication from the relay to a common
breaker aux trip relay, what level does this system fall under?
Response: The SDT thanks you for your comments.
1. Whether relay systems are redundant are immaterial in determining appropriate maintenance intervals. The SDT believes that the intervals
established in the standard are appropriate. The Tables have been revised extensively; the SDT invites you to review the revised Tables to determine
how they affect your system.
2. The requirement to which you refer has been removed from the Table.
3. Whether relay systems are redundant are immaterial in determining appropriate maintenance intervals. You will need to evaluate all components to
determine applicable maintenance activities; the digital relays MAY fall under Table 1c, but other components may fall under any of the Tables.
Xcel Energy
June 3, 2010
No
Within the tables, several components related to UFLS/UVLS systems have an interval of “when the
associated UVLS or UFLS system is maintained.” Yet, there is no maximum interval established for a UVLS
or UFLS system. We feel this item should be clarified. If the intent of the SDT is to tie the testing to when the
UFLS/UVLS relays are maintained, so that all components are tested at the same time, then this should be
made clear. One possible resolution would be to change the interval to read: “when the associated
UVLS/UFLS relays are maintained”.
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Organization
Yes or No
Question 3 Comment
Response: The SDT thanks you for your comments. The interval for the UVLS or UFLS system relays is established within Table 1a, Table 1b, and
Table 1c. The intent of the SDT is to facilitate concurrent maintenance of all components associated with these systems at a common location.
AECI
No
1. Comments: Table 1a 3 months for protection system coil check out seems extreme. Should be at least 1
year.
2. Same as comment 4 for the communication checkout on page 9.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard to remove the requirement to which you refer.
2. See response to your question 4 comment on communication checkout.
Puget Sound Energy
Yes
PSE appreciates the explanation of calendar provided in the supplementary reference on page 14. Further
clarity would be gained by an example that is not at the end of a calendar year. For example if a relay was
maintained June 15, 2008, would it be due for maintenance again no later than June 30, 2014 or December
31, 2014.
Response: The SDT thanks you for your comments. For your example, the maintenance would have to be completed within 2014.
Bonneville Power Administration
Yes
ENOSERV
Yes
Georgia System Operations
Corporation
Yes
Lower Colorado River Authority
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
June 3, 2010
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Organization
Yes or No
Otter Tail Power
Yes
Saskatchewan Power
Corporation
Yes
TVA
Yes
Western Area Power
Administration
Yes
June 3, 2010
Question 3 Comment
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
4. Within Tables 1b and 1c, the draft standard establishes parameters for condition-based maintenance, where
the condition of the devices is known by means of monitoring within the substation or plant and the condition
is reported. Do you agree with this approach? If not, please explain in the comment area.
Summary Consideration: Most respondents agreed with the general approach regarding condition-based maintenance, many
of them with questions and/or comments. Many of the comments requested clarification of any of a variety of specific
provisions within Tables 1b and 1c, and revisions were made to the Tables to present the information more clearly. The
activities for control circuits and for dc supply were considerably re-worked.
Organization
Yes or No
Green Country Energy LLC
Exelon Generation Company,
LLC
Question 4 Comment
No Preference at this time.
No
1. Please provide more clarification on what constitutes "partially monitoring." For example, is a computer
auxiliary contact alarm count as partial monitoring? Would a common alarm between relays meet the
definition of partial monitoring?
2. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's
refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing
of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing
programs.
3. Table 1b Station dc supply (that has as a component valve regulated lead-acid batteries) should provide an
additional optional activity for "Total replacement of battery at an interval of four (4) years.
4. There seems to be a disconnect between the monitoring attribute and maintenance activity. For example,
the monitoring attribute "Monitoring and alarming of the station dc supply voltage/detection and alarming of dc
grounds" has the maintenance activity "verify that the station battery can perform as designed by conducting
a performance or service capacity test of the entire batter bank. (3 calendar years) or “ Verify that the station
battery can perform as designed by evaluating the measure cell/unit internal ohmic values to station battery
baseline (3 months)." The maintenance activity does not support the monitoring attribute.
5. If an entity has implemented Table 1b and/ or Table 1c, is there an acceptable length of time that the
monitoring equipment can be out of service without falling back to Table 1a requirements?
Response: The SDT thanks you for your comments.
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Organization
Yes or No
Question 4 Comment
1. A common alarm would meet the definition of partially monitored. See FAQ V-3-A (page 38).
2. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document
(page 9) for a discussion on this issue.
3. The SDT believes that total replacement of a VRLA battery set at an interval of four (4) years in lieu of not conducting a capacity test at the maximum
maintenance interval of 3 calendar years, or evaluating the measured cell/unit internal ohmic values to the station battery’s baseline at the maximum
maintenance interval of 3 months would put the owner of the battery set out of compliance with the standard. The SDT believes the three calendar
year Maximum Maintenance Interval for conducting a capacity test (listed in Table 1) cannot be exceeded. If an owner does a total replacement of the
battery within a three calendar year interval from initial installation of a VRLA battery set, the owner will be compliant with the standard. Extending the
time that a VRLA goes beyond the Maximum Maintenance Interval in Table 1 without verification that it can perform as designed is not adequate to
insure that the station battery will perform reliably.
4. The monitoring attributes describe “what you know of the component via the monitoring”, while the activities describe what must be done relative to
the “things you don’t know”. Therefore, it’s expected that the attributes and activities will be dissimilar.
5. The equipment used to monitor the alarms must be returned to service within the shortest Table 1a interval of the monitored components. For
example, if monitoring is used to defer the 3-month Table 1a maintenance activity related to Protection System Control Circuitry, the monitoring
function must be returned to service within 3 months. This has been added to Table 1b and Table 1c as a requirement.
American Transmission
Company
No
1. ATC does not believe that there is a relay, on the market today, that has the ability to fully monitor itself as
described in Table 1c. We believe that Table 1c should be deleted. (Table 1b could cover any device that
has the ability to fully monitor if such a device is developed in the future.) ATC does not believe that NERC
Reliability Standards should be used as an enticement for manufacturers to develop specific devices.
2. Under the “General Description” in Table 1c, there is a reporting requirement identifying a 1 hour window.
(“must be reported within 1 hour or less of the maintenance-correctable issue occurring, to the location where
action can be taken.”) ATC believes that the team needs to define if this action is a phone call or physically
verify the maintenance correctable issue which is occurring.
Response: The SDT thanks you for your comments.
1. Your observation may be accurate at the present time and is not limited to protective relays. The standard was developed with future improvements
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Organization
Yes or No
Question 4 Comment
in technology and practices in mind.
2. This reporting requirement is intended to be by whatever means is available, to a location where resolution of the maintenance-correctable issue
can be initiated.
Duke Energy
No
For utilities like us with large numbers of relays it’s too complicated, which drives us back to Table 1a.
Response: The SDT thanks you for your comments. The standard was written with enough flexibility to allow entities to make the best business
decision for their situation. Some entities may decide that Table 1a is the best fit for their situation.
AEP
No
How would the failure of a SCADA system affect the ability to take advantage of monitoring?
Response: The SDT thanks you for your comments.
It doesn’t, as long as the SCADA system is returned to service within the shortest Table 1a interval of the monitored components. For example, if
monitoring is used to defer the 3 month Table 1a maintenance activity related to Protection System Control Circuitry, the monitoring function must be
returned to service within 3 months. This has been added to Table 1b and Table 1c as a required attribute for the associated type of protection system
component.
Illinois Municipal Electric Agency
No
IMEA supports comments submitted by Florida Municipal Power Agency regarding use of the word “every” in
Table 1c.
Response: The SDT thanks you for your comments. See response to FMPA.
Pepco Holdings Inc.
No
Monitoring and alarming of the station dc supply and detection and alarming of dc grounds are required to
qualify for Level 2 monitoring of battery / dc systems. While the presence of dc ground may affect protection
and control operations, they do not affect any of the systems for which dc ground alarming is listed as a
monitoring criteria. Recommend removing this criterion from the battery & dc system monitoring criteria and
adding it as a maintenance activity, with frequency of testing based on presence of detection / alarming.
Response: The SDT thanks you for your comments. The dc ground alarm may identify a maintenance correctable issue, which must be resolved
according to Requirement R4. The SDT believes that dc ground detection is usually a part of battery maintenance; this is sometimes even included in
the battery charger.
Electric Market Policy
June 3, 2010
No
Recommend that all Level 2 three-month maintenance intervals be changed to a quarterly based system
where only 4 inspections are required per year. Given a 3 month maximum interval, activities would need to
be scheduled every 2 months, which would result in six inspections per year. Our experience of four
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 4 Comment
inspections per year has proven to be successful.
Response: Thank you for your comments .SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of the
maintenance activities. “Once per calendar quarter” or “four times per year” would allow up to a 6-month practical interval, which would not maintain
this periodicity. This DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
SERC (PCS)
No
Recommend that all Level 2 three-month maintenance intervals be changed from 3 months to quarterly.
Given a 3 month maximum interval an entity would need to schedule these tasks every 2 months. This would
result in six inspections per year. In the experience of many of our utilities, four inspections per year have
proven to be successful.
Response: The SDT thanks you for your comments. SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of the
maintenance activities. “Once per calendar quarter” or “four times per year” would allow up to a 6-month practical interval, which would not maintain
this periodicity. This DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
Wolverine Power Supply
Cooperative, Inc.
No
See question 2 response
Response: The SDT thanks you for your comments. See Question 2 response.
SCE&G
No
Several maximum maintenance intervals are 3 months. Since this is an absolute maximum period, entities
would need to schedule on a 2 month basis to assure the 3 month maximum is met, i.e., 6 times per year.
We recommend that 3 month periods be increased to 4 months which allows scheduling every 3 months. An
alternate method of achieving the same result is to state periodic requirements of quarterly or 4 times per
year.
Response: The SDT thanks you for your comments. SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of the
maintenance activities. “Once per calendar quarter” or “four times per year” would allow up to a 6-month practical interval, which would not maintain
this periodicity. This DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
Detroit Edison
No
Table 1b indicates that this (level 2) includes all elements of level 1 monitoring. However, level 1 is constantly
referred to as unmonitored in other places.
Response: The SDT thanks you for your comments and modified Table 1b to address your comment by removing this reference from the header of the
table.
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Organization
Yes or No
Southern Company
No
Question 4 Comment
1. Table 1b should allow self-monitored circuits that are not alarmed but are monitored and logged by
personnel daily or more often. Many plants and substations have personnel that do in person checks of
unmanned control rooms. This is the equivalent of “Protection System components whose alarms are
automatically provided daily (or more frequently) to a location where action can be taken for alarmed failures.”
For example, dc system ground potential lights and dc system volt meters exist on most control room bench
boards or exist in the digital control systems at generating stations. These devices are monitored by
operators in manned control rooms.
2. On Table 1b, Protection System Control Circuitry (Trip Coils and Auxiliary Relays), the monitoring
component calls for “Monitoring and alarming of continuity of trip coil(s).” Clarify that “trip coil(s)” excludes
Breaker Failure Initiate relay coil(s).
3. On Table 1b, Protection System Control Circuitry (Trip Coils and Auxiliary Relays) Experience has shown
that electrically operating fully monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is
not warranted. This testing introduces risk from a human error perspective as well as from additional
switching and clearances required. We recommend eliminating this maintenance requirement from Table
1b.
4. On Table 1c, Protection System Control Circuitry (Trip Coils and Auxiliary Relays) Experience has shown
that electrically operating fully monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is
not warranted. This testing introduces risk from a human error perspective as well as from additional
switching and clearances required. We recommend changing this maximum maintenance interval to 12
years.
5. Component monitoring attributes need to be defined for all components in table 1b and 1c. For example,
the attributes for voltage and current sensing devices could be that "Voltage and current input circuits are
monitored and alarmed".
6. Based on past performance, the requirement to electrically operate trip coils, auxiliary relays, and lockout
relays every 6 years in Table 1b is not warranted. We recommend complete functional testing including
electrical operation of breaker trip coils, auxiliary trip relays, and lockout relays every 12 years in tables 1b
and 1c.
Response: Thank you for your response.
1. The SDT modified the Table 1b header to address your comment by adding “condition or” to the General Description. See FAQ V-1-D (page 30).
2. The SDT has modified the standard to clarify that this monitoring addresses monitoring of the trip circuit(s), rather than the trip coil(s).
3. The SDT believes that it is important that these mechanical devices be periodically (physically) exercised to assure that they will operate properly.
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Organization
Yes or No
Question 4 Comment
4. The SDT believes that the intervals in the table are appropriate. The standard allows entities to utilize Performance-Based maintenance if they have
appropriate documented experience.
5. The tables have been modified to address this issue, except where no relevant monitoring attributes exist.
6. The SDT believes that the intervals in the table are appropriate. The standard allows entities to utilize Performance-Based maintenance if they have
appropriate documented experience.
US Bureau of Reclamation
No
The condition based monitoring only provides for a very narrow process and excludes sound judgment in
determining maintenance intervals. As long as the registered entity establishes parameters by which
variation in the prescribed maintenance intervals are determined, justified variation should be allowed.
Response: The SDT thanks you for your comments. The SDT, in accordance with FERC Order 693, has prescribed maximum allowable maintenance
intervals for unmonitored Protection System components (Table 1a), partially-monitored Protection System components (Table 1b), and fullymonitored Protection System components (Table 1c). For further discussion pertaining to intervals see Supplementary Reference Document, Section
8 (page 9). To allow an entity to use their discretion to extend these intervals, absent adoption of the criteria established for performance-based
maintenance, would be contrary to the direction established by FERC. For further discussion pertaining to performance based maintenance see
Supplementary Reference Section 9.
Austin Energy
Yes
Bonneville Power Administration
Yes
CPS Energy
Yes
Dynegy
Yes
E.ON U.S.
Yes
ENOSERV
Yes
Entergy Services, Inc
Yes
FirstEnergy
Yes
Georgia System Operations
Yes
June 3, 2010
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Organization
Yes or No
Question 4 Comment
Corporation
Indianapolis Power & Light Co.
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NextEra Energy Resources
Yes
Northeast Power Coordinating
Council
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
Otter Tail Power
Yes
PacifiCorp
Yes
Platte River Power Authority
Maintenance Group
Yes
RRI Energy
Yes
Saskatchewan Power
Corporation
Yes
Transmission Owner
Yes
TVA
Yes
June 3, 2010
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Organization
Yes or No
Western Area Power
Administration
Yes
Wisconsin Electric
Yes
Xcel Energy
Yes
MRO NERC Standards Review
Subcommittee
Yes
Question 4 Comment
A. The MRO NSRS agrees with this approach; however, I think most entities will not see the advantage of
condition-based maintenance until they can resolve any gaps in data retention. If an entity was retaining a set
of maintenance records but failed to include all the needed information as specified in this standard so they
would need to adjust their maintenance procedure to collect all information and then they would need to wait
for the entire retention period until they could start using the extended maintenance interval. If an entity had a
collateral set of records which verified the information that lacked in the original maintenance record then
could the entity start using the extended maintenance interval? For example, an entity has records showing
that they have maintained a voltage or current transformer within the prescribed maintenance interval listed in
level 1 monitoring (which is a maximum 12 year maintenance interval). Could this same entity go to level 3
monitoring (which is a continuous maintenance interval) immediately if it can query their SCADA and produce
detailed records indicating the accuracy of the PT or CT for the maintenance records already retained?
B. For lockout relays, if commissioning tests are done diligently, the trip DC availability is continuously
monitored and the trip coil itself is continuously monitored, is it necessary to operate these relays for
functional testing? For breaker failure lockout relays, re-verifying the operation of the coil and all the contacts
could mean taking multiple breakers and line terminals out of service at the same time. Functional trip tests
could cause unintentional tripping of equipment, cause equipment damage and interruption of service to
customers. It's hard to see how the reliability of the BES is significantly improved by doing this test. The
MRO NSRS feels the risk of adverse impact could be greatly reduced by a longer interval such as 12 years.
C. In table 1c, the word “continuous or continuously monitored” is used. Please clarify the “within 1 hour” time
frame takes into account that there may be a communication outage (failover) that will prevent an entity to
“continuously” monitor a device.
Response: The SDT thanks you for your comments.
A. It appears to the SDT that this comment actually is addressing performance-based maintenance, rather than condition-based maintenance. If the
entity has all the necessary records to support immediate moving to a specific level of maintenance, or to performance-based maintenance, there
should be no barrier to such an action.
B. The SDT is not aware of any monitoring system that can verify that these mechanical devices can indeed physically operate properly; thus the
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Organization
Yes or No
Question 4 Comment
interval is established at 6 years. (See Supplementary Reference Document Section 15.4, page 23.)
C. “Continuous monitoring” is an attribute of the Protection System component to produce an indication of state or status; the 1-hour constraint refers
to the communication method used to monitor the indications. The equipment used to monitor the alarms must be returned to service within the
shortest Table 1a interval of the monitored components. For example, if monitoring is used to defer the 3 month Table 1a maintenance activity related to
Protection System Control Circuitry, the monitoring function must be returned to service within 3 months. This has been added to Table 1b and Table 1c
as a required attribute for the associated type of protection system component.
City Utilities of Springfield, MO
Yes
CU agrees with the approach, but, may not agree with the exact wording in the tables. For instance, the use
of the word “every” in table 1c in “Protection System components in which every function required for correct
operation of that component is continuously monitored and verified” may be overstating the level of monitoring
that would realistically enable a Protection System to use table 1c.
Response: The SDT thanks you for your comments. Table 1c establishes that, with the monitoring attributes specified, periodic maintenance may not
be necessary at all. In order to facilitate this, the constraint, “every function required for correct operation of that component is continuously
monitored and verified” must be met. If a component cannot meet this constraint, it must be addressed within either Table 1b or Table 1a, as
appropriate.
Florida Municipal Power Agency,
and its Member Cities
Yes
FMPA agrees with the approach, but, may not agree with the exact wording in the tables. For instance, the
use of the word “every” in table 1c in “Protection System components in which every function required for
correct operation of that component is continuously monitored and verified” may be overstating the level of
monitoring that would realistically enable a Protection System to use table 1c.
Response: The SDT thanks you for your comments. Table 1c establishes that, with the monitoring attributes specified, periodic maintenance may not
be necessary at all. In order to facilitate this, the constraint, “every function required for correct operation of that component is continuously
monitored and verified” must be met. If a component cannot meet this constraint, it must be addressed within either Table 1b or Table 1a, as
appropriate.
JEA
Yes
Is it possible that for coil monitored equipment, such as LOR coils, that they were left out, of this Table
allowing for a longer maintenance interval. Certainly LOR continuous coil monitoring with alarming to a 24
hour 7 day a week manned location, with emergency dispatch, would allow for a longer maintenance interval
for continuously monitored LORs. Suggestion here might be alignment with continuously self-tested,
monitored and alarmed microprocessor relays at 12 years.
Response: The SDT thanks you for your comments. Monitoring of the coil of these devices does not assure that the device will mechanically operate
properly; thus the interval for verification of proper physical operation is established at 6 years similarly to Table 1a and Table 1b. (See Supplementary
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Organization
Yes or No
Question 4 Comment
Reference Document, Section 15.4, page 23.)
ITC Holdings
Yes
We agree with the approach. We have several issues with the details of Maintenance Issues, Interval and
Monitoring Attributes. See previous comments for Questions 2 and 3.
Response: The SDT thanks you for your comments. See response to your comments in Questions 2 and 3.
Ameren
Yes
We agree with the condition-based approach. Our comments in 3 above apply to Tables 1b and 1c as well.
We note that Table 1b Station dc supply intervals are the same as Table 1a. Why doesn’t the monitoring
cause 1b intervals to be longer than 1a?
Response: The SDT thanks you for your comments. The standard (specifically Table 1b) has been modified in consideration of your comment.
Lower Colorado River Authority
Yes
We commend the drafting team for recognizing the advantages of using monitored systems and a conditionbased approach. This approach recognizes the benefits of using newer technologies and will give utilities
added incentive to update their relay systems.
Response: The SDT thanks you for your support.
Puget Sound Energy
June 3, 2010
Yes
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
5. Within PRC-005 Attachment A, the draft standard establishes parameters for performance-based maintenance,
where the historical performance of the devices is known and analyzed to support adjustment of the maximum
intervals. Do you agree with this approach? If not, please explain in the comment area.
Summary Consideration: Many of the respondents agreed with this approach, but comments indicated concern about
perceived administrative difficulties in establishing performance-based maintenance programs. The SDT responded to these
concerns by noting that associated administrative program development is one of the considerations that an entity must
address when contemplating use of such a program.
Organization
Yes or No
Green Country Energy LLC
MRO NERC Standards Review
Subcommittee
Question 5 Comment
N/A does not apply
No
A. The MRO NSRS is concerned that this approach could lead to non-compliance if the company follows this
process and a Compliance Auditor disagrees with the method that was used. An applicable entity should be
protected if they follow the standard appropriately. There should be some assurance of a grace period for
mitigation if this selected approach was not accepted.
B. Please provide the basis for having at least 60, then taking 30 (50%) for testing/maintenance. This may
give an unfair advantage to larger companies rather than being fair across the board. This places an undue
burden on smaller companies by having to team up with other asset owners.
Response: The SDT thanks you for your comments.
A. See Attachment A of standard. The entity has three years to get performance to an acceptable level (under 4% countable events) or get on the
appropriate time-based interval.
B. The requirement for having 60 and testing 30 is based on having a statistically significant number of devices. Please see Section 9.1 (page 16) of
the Supplementary Reference Document for a discussion of the statistical basis. The standard allows smaller entities to share data in order to support
their ability to utilize performance-based maintenance.
CenterPoint Energy
June 3, 2010
No
a. CenterPoint Energy lauds the SDT for recognizing that strict imposition of the maximum interval approach
creates problems which the SDT attempts to correct by allowing performance-based adjustments.
CenterPoint Energy believes the majority of industry commenters will agree with CenterPoint Energy’s
assessment that the maximum interval approach is problematic and should be dropped from the proposal.
However, if the majority of industry commenters agree with the SDT’s approach, then a performance-based
option to correct the problems introduced by the maximum interval requirements should remain.
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Organization
Yes or No
Question 5 Comment
b. CenterPoint Energy answered “No” to question 5 because CenterPoint Energy believes the arduous path of
creating a new set of problems with a rigid approach (maximum interval requirements) and then introducing a
complex set of auditable requirements to provide an option (performance-based maintenance) to mitigate the
harm of the rigid approach is ill-advised and fraught with pitfalls. Stated otherwise, using performance-based
adjustments to correct inappropriate maximum intervals would not be necessary if the inappropriate maximum
intervals were not imposed. CenterPoint Energy believes a better approach is to avoid introducing the new
set of problems that then have to be mitigated by not imposing problematic maximum intervals.
c. Followed to its logical conclusion, using performance-based adjustments to correct inappropriate maximum
intervals is a contorted way of arriving at the philosophy embodied in the current set of standards in which
entities determine the maximum intervals appropriate for their circumstances and performance. CenterPoint
Energy’s concern is that the contortions needed to arrive at the same point, in addition to being unnecessary,
will be difficult for most entities to navigate. An entity making a good faith effort to comply with the
performance-based adjustments will have to navigate through the complexities and nuances of the approach,
as illustrated by the extensive set of documents the SDT has provided in an attempt to explain all the
requirements and nuances. As an entity attempts to manage this hurdle, the entity will likely have to deal with
the reality that the granularity of performance metrics do not exist in most cases to justify to an auditor the
rationale for the adjustments to the inappropriate maximum intervals. For example, CenterPoint Energy has
asserted that it has had good battery performance using existing practices. However, the assertion is
anecdotal. CenterPoint Energy cannot recall any instances where it had a relay misoperation due to battery
failure in over twenty five years. CenterPoint Energy does not attempt to keep performance metrics on events
that historically occur less than four times a century and CenterPoint Energy believes most entities will be in
the same situation.
d. If an entity is somehow able to overcome these hurdles, the entity will almost certainly encounter
skepticism for what will be viewed as an exception to the default requirement embodied in the standard. Even
if an entity can overcome likely skepticism in an audit, the entity will be in a severely disadvantaged situation if
a protection system component for which the maintenance interval has been adjusted, based on the entity’s
good faith effort and reasoned judgment, nevertheless is a contributing factor in a major reliability event
investigation, regardless of whether the maintenance interval adjustment contributed to the failure. No matter
what maintenance intervals are used, protection system components could fail. If the maintenance interval
has been adjusted and if failure occurs, it will likely be unknown whether the interval adjustment was in fact a
contributing factor or whether the failure would have occurred anyway.
e. Faced with this dilemma, in addition to all the other hurdles to overcome in attempting to adjust an
inappropriate maximum interval, the reality is that most entities will accept the inappropriate maximum interval
and over-maintain their protection system components, and introduce a new set of reliability risks from such
over-maintenance. For these reasons, CenterPoint Energy advises against creating a new set of problem by
imposing rigid maximum intervals and then attempting to correct the problems through a performance-based
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Organization
Yes or No
Question 5 Comment
mechanism that in actual practice would likely be illusory.
Response: The SDT thanks you for your comments.
a. FERC order 693 requires that NERC establish maximum time intervals. The criteria for performance-based maintenance are established for entities
that wish to establish other intervals based on concise stated criteria.
b. FERC order 693 requires that NERC establish maximum time intervals. The SDT believes that the established intervals are appropriate. The criteria
for performance-based maintenance are established for entities that wish to establish other intervals based on concise stated criteria.
c. Entities are not required to use PBM, but instead may elect to simply use the intervals established in Table 1a, Table 1b, and/or Table 1c. However, if
an entity keeps the necessary metrics to conform to Attachment 1, it may find opportunities within PBM; however, the SDT has established that
maintenance of station batteries must be performed within a time-based maintenance program.
d. The standard established maximum intervals, minimum maintenance activities, and, for PBM, minimum requirements (and performance). If an entity
is concerned about whether these intervals will yield acceptable performance, it may perform more maintenance, more frequently, than established
within the standard.
e. FERC order 693 requires that NERC establish maximum time intervals. The criteria for performance-based maintenance are established for entities
that wish to establish other intervals based on concise stated criteria, but entities are not required to use PBM.
ITC Holdings
No
Appendix A fixes a 4% level of “countable events”. Is this number the industry average for countable events?
Has the industry average actually been determined? The basis for the 4% requirement noted in Paragraph 5
of Appendix A should be included in the reference document. Also a sample calculation for adjusting the
interval is needed to clarify the requirement.
Response: The SDT thanks you for your comments. We used failure and calibration data from some of the utilities on the drafting team to determine
the 4% level; this value is also determined such that a single countable event on the 30 unit minimum test sample established via the statistical
analysis described in Section 9 of the Supplementary Reference Document (page 15) does not exceed the threshold. See FAQ IV-3-D thru IV-3-F
(pages 25-26) which discusses types of Misoperations and correcting segment performance.
American Transmission
Company
No
ATC agrees with this approach but is concerned that Attachment A does not contain enough language to
support an entity that implements this practice. This attachment needs to clearly state that following your
performance-based maintenance practices satisfies an entity’s compliance obligations. Entities should not be
subject to non-compliance over disagreements with their performance-based maintenance methodology.
Response: The SDT thanks you for your comments. The SDT believes Attachment A does contain enough language to support PBM, and this
language is further supported by technical guidance from Section 9 of the Supplementary Reference Document (page 15). Additionally, R3 of the
standard specifically provides that an entity that follows the requirements detailed in Attachment A is indeed in compliance. The SDT will consider any
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Question 5 Comment
suggested improvements.
E.ON U.S.
No
E.ON U.S. recommends keeping with time-based intervals (and the improvement thereof) and staying clear of
condition-based performance for the generating stations. But that is not meant to preclude other companies
from doing condition-based, if they so prefer.
Response: The SDT thanks you for your comments.
Indianapolis Power & Light Co.
No
Establishing historical performance and keeping the documentation up to date makes this almost useless
Response: The SDT thanks you for your comments. Entities are not required to use PBM.
Florida Municipal Power Agency,
and its Member Cities
No
FMPA believes that the documented process outlined in Attachment A; "Criteria for Performance Based
Protection System Maintenance Program" is biased towards larger entities. The requirement that the
minimum population of 60 individual components of a particular segment is required to make a component
applicable to this program automatically eliminates most of the small or medium sized entities. Further the
need to first test a minimum of 30 individual components in any segment reinforces the same size limitation.
FMPA suggests that the Performance-Based Protection System Maintenance Program allow for regional
shared databases applicable towards meeting the establishment and testing criteria of similar individual
components. This practice will allow for the inclusion of entities of all sizes. This will also provide a greater
format for the discussion of lessons learned and improvements to the testing database on a regional basis.
Response: The SDT thanks you for your comments. The requirement for having 60 and testing 30 is based on having a statistically significant number
of devices. Please see Section 9.1 of the Supplementary Reference Document (page 16) for a discussion of the statistical basis. The standard allows
smaller entities to share data in order to support their ability to utilize performance-based maintenance. See footnote 4 of Attachment A.
Duke Energy
No
For utilities like us with large numbers of relays it’s too complicated, which drives us back to Table 1a.
Response: The SDT thanks you for your comments. Entities are not required to use PBM.
Illinois Municipal Electric Agency
No
IMEA supports comments submitted by Florida Municipal Power Agency that the process outlined in
Attachment A is biased towards larger utilities.
Response: The SDT thanks you for your comments. The requirement for having 60 and testing 30 is based on having a statistically significant number
of devices. Please see Section 9.1 of the Supplementary Reference Document (page 16) for a discussion of the statistical basis. The standard allows
smaller entities to share data in order to support their ability to utilize performance-based maintenance. See footnote 4 of Attachment A.
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Organization
Yes or No
City Utilities of Springfield, MO
No
Question 5 Comment
It appears that Attachment A was written for large utilities. Some allocation needs to be made for utilities with
smaller numbers of components.
Response: The SDT thanks you for your comments. The requirement for having 60 and testing 30 is based on having a statistically significant number
of devices. Please see Section 9.1 of the Supplementary Reference Document (page 16) for a discussion of the statistical basis. The standard allows
smaller entities to share data in order to support their ability to utilize performance-based maintenance. See footnote 4 of Attachment A.
Saskatchewan Power
Corporation
No
Saskatchewan agrees with the approach, but requires clarification in the definition of segment. The definition
uses a population of 60 or more individual components but in the establishment of a PSMP, it only asks for a
population of 30 or more. Which number will be used to define the segment?
Response: The SDT thanks you for your comments. The requirement is that a minimum population of 60 units be present, and that at least 30 units be
tested on time-based maintenance (Table 1a) prior to moving to PBM. A minimum of 30 units tested is also used for ongoing analysis of the PBM
performance, as specified in Attachment A. Please see Section 9.1 of the Supplementary Reference Document (page 16) for a discussion of the
statistical basis.
Austin Energy
No
See item # 10 Comments
No
See question 2 response
Response: See item #10 response.
Wolverine Power Supply
Cooperative, Inc.
Response: See question 2 response.
Northeast Power Coordinating
Council
No
The concept is acceptable, but the requirements to follow in Appendix A seem to be a deterrent from
attempting to use this process. Is the term “common factors” meant to take into account variables at locations
that can affect the components” performance (lightning, water damage, humidity, heat, cold)”
Response: The SDT thanks you for your comments. The SDT has attempted to make Attachment A as straight forward as possible. The term
“common factors” does mean common variables that are expected to affect performance of the component such as lightning, water damage, humidity,
heat and cold. The term also means common variables such as design, manufacture, performance history, etc that are expected to affect performance
of the component.
US Bureau of Reclamation
June 3, 2010
No
The parameters established can only be implemented with documentation that defined in the document but is
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Question 5 Comment
not readily available.
Response: Before utilizing a PBM for their Protection Systems, an entity must develop the supporting documentation via application of a time-based
program (using the Table 1a intervals) in accordance with Attachment A.
CPS Energy
Yes
Detroit Edison
Yes
Dynegy
Yes
Electric Market Policy
Yes
ENOSERV
Yes
Entergy Services, Inc
Yes
Georgia System Operations
Corporation
Yes
Lower Colorado River Authority
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NextEra Energy Resources
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
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Organization
Yes or No
PacifiCorp
Yes
Pepco Holdings Inc.
Yes
Platte River Power Authority
Maintenance Group
Yes
RRI Energy
Yes
SCE&G
Yes
SERC (PCS)
Yes
Southern Company
Yes
Transmission Owner
Yes
Western Area Power
Administration
Yes
Wisconsin Electric
Yes
Xcel Energy
Yes
FirstEnergy
Yes
Question 5 Comment
Although we agree with the parameters of the proposed PBM, we have the following comments:
1. We question the inclusion of Misoperations in countable events as described in footnote 4. Since standard
PRC-004 already requires analysis and mitigation of Protection System Misoperations through a Corrective
Action Plan, entities should not be required to repeat this analysis and mitigation in PRC-005. We ask that the
SDT clarify the requirements to allow a tie between PRC-005 and PRC-004 so as to assure work is not
duplicated.
2. We are not receptive to using this methodology to develop intervals due to the detailed tracking and
analysis that will be required to establish maximum intervals. The approach may suit other utilities and thus,
we are not opposed to the methodology being contained within the standard.
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Question 5 Comment
Response: The SDT thanks you for your comments.
1. PRC-004 should be used to handle reporting of the Misoperation and its corrective action. However, the misoperation should be included as a
countable event required for PBM analysis. The documentation of correction of problems per PRC-004 should also suffice to address resolution of the
corresponding maintenance-correctable issue for PRC-005.
2. Entities are not required to use PBM.
JEA
Yes
Approach appears to be well explained. Only one are of concern and that would be delaying the
advancement of replacement of EM relay systems with microprocessor, if the PBM population were to
decrease below the 60, resulting in not meeting the sample minimum population criteria. Falling below this 60
population sample minimum, might result in an immediate compliance violation.
Response: The SDT thanks you for your comments. The standard is not meant to delay replacement of relays. An entity should do an annual analysis
of it segment size and countable events. As the segment population approaches 60, the entity should transition back to a time-based program per
Table 1a, Table 1b, or 1c, as appropriate, and assure that the remaining components are maintained accordingly.
Exelon Generation Company,
LLC
Yes
None
TVA
Yes
Should allow inclusion of dc systems as well.
Response: The SDT thanks you for your comments. A Station DC supply that does not include batteries may be fit into a PBM. See Section 15 of the
Supplementary Reference Document (page 21) (and FAQ IV-3-G, page 26) for a discussion of why station batteries cannot be included in a PBM.
Ameren
Yes
While we agree with the approach, batteries should be allowed, not excluded.
Response: The SDT thanks you for your comments. See Section 15 of the Supplementary Reference Document (page 21) (and FAQ IV-3-G, page 26)
for a discussion of why station batteries cannot be included in a PBM.
Puget Sound Energy
June 3, 2010
Yes
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6. The SDT has provided a “Supplementary Reference Document” to provide supporting discussion for the
Requirements within the standard. Do you have any comments on the Supplementary Reference Document?
Please explain in the comment area.
Summary Consideration: In general, respondents expressed appreciation for the additional technical discussion included
within this document. The SDT responded to many comments by explaining the relationship between the Standard and the
Reference Document. Several respondents suggested that elements of the extensive discussion be contained within the
standard itself, which is contrary to the guidance within the paradigm for NERC Standards.
Organization
Yes or No
Bonneville Power Administration
Question 6 Comment
Will this document be a part of the standard? Are its explanations the official interpretation of the standard?
Response: The FAQ and the Supplementary Reference Document are provided as references to present detailed discussions about determination of
maintenance intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT
believes that these documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes
that these documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority.
It is the drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference
document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the
Standards Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future
revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the
standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
American Transmission
Company
No
City Utilities of Springfield, MO
No
Detroit Edison
No
Electric Market Policy
No
ENOSERV
No
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Organization
Yes or No
Florida Municipal Power Agency,
and its Member Cities
No
Georgia System Operations
Corporation
No
Illinois Municipal Electric Agency
No
Indianapolis Power & Light Co.
No
JEA
No
Manitoba Hydro
No
Nebraska Public Power District
No
NextEra Energy Resources
No
Northeast Power Coordinating
Council
No
Operations and Maintenance
No
Pepco Holdings Inc.
No
RRI Energy
No
SCE&G
No
SERC (PCS)
No
Transmission Owner
No
TVA
No
June 3, 2010
Question 6 Comment
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Organization
Yes or No
Western Area Power
Administration
No
Wolverine Power Supply
Cooperative, Inc.
No
US Bureau of Reclamation
No
Question 6 Comment
The document will require revisions.
1. Performance based maintenance is establishing a strategy to achieve a desired performance. The document
limits strategy to statistical analysis of failure rates.
2. The document assumes a modern protection system with a high level of monitoring. Facilities which barely
qualify would not have high end monitoring installed.
3. The document also refers to “exercising a circuit breaker through t relay tripping circuits using remote control
capabilities via data communication.” This repeated several times throughout the document as a means of
increasing the TBM. This function, if indeed used, would require maintenance. This function is very dangerous
and could introduce a cyber vulnerability.
Response: The SDT thanks you for your comments.
1. As you say, PBM is an option to achieve a desired performance. The result should be a documented acceptable level of performance, and statistical
analysis of failure rates is required as a minimum method to achieve this level of performance.
2. The standard addresses all generations of equipment with varying levels of monitoring capability, and establishes requirements which address the
equipment with no monitoring capability, as well as facilitating effective use of monitoring capabilities of the equipment that DOES have those
capabilities.
3. Exercising a circuit breaker through the relay tripping circuits via a remote communication method is an available option to those entities that wish to
use it to satisfy maintenance intervals established in the standard, not to increase them; this is presented as an example of how entities may be able to
use remotely performed activities to minimize maintenance requiring station visits. If an entity is concerned about risks presented from remote
maintenance activities, they are not required to use such methods. Issues relating to cyber security are outside the scope of this Standard.
Ontario Power Generation
No
A well prepared and useful document.
Response: The SDT thanks you for your support.
MRO NERC Standards Review
June 3, 2010
No
N/A
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Organization
Yes or No
Question 6 Comment
Subcommittee
Exelon Generation Company,
LLC
No
None
Entergy Services, Inc
No
1. Regarding Section 2.3, Applicability of New Protection System Maintenance Standards, there needs to be
clarification and examples of applicable relaying associated with the language: and that are applied on, or are
designed to provide protection for the BES. For example, is the application of reverse power schemes and
directional overcurrent schemes considered applicable when considering the impact to the protection of the
BES?
2. We agree with the application of the term “calendar” in the PRC-005-2 Protection System Maintenance
Supplementary Reference document. There should be enough flexibility in interval assignments to allow for
annual maintenance planning, scheduling and implementation.
Response: The SDT thanks you for your comments.
1. Please refer to Clause 4 (Applicability) of the standard itself, and to the FAQ document (FAQ III – 2 – A, page 20), for further information on this. It
appears that this comment is focused on generation plants; Clause 4.2.5.1 of the draft standard states, “Protection system components that act to trip
the generator either directly or via generator lockout or auxiliary tripping relays.” This Applicability clause would have to be applied to the specific
instance of concern.
2. The SDT thanks you for your comments.
PacifiCorp
No
Very helpful.
Response: The SDT thanks you for your comments.
Austin Energy
Yes
Ameren
Yes
1) We disagree with the page 22 statement that batteries cannot be a unique population segment of a PBM.
2) What role does the Supplement play in Compliance Monitoring and Enforcement?
Response: The SDT thanks you for your comments.
1. Thank you for your comment concerning your disagreement with the standard Drafting Team that batteries cannot be a unique population segment of
a PBM. In FAQ IV-3-G (page 26) and the Supplementary Reference Document (See Section 15.4, page 23), the Drafting team states why batteries are
excluded from PBM. The Drafting Team still believes, that for the reasons stated in the FAQ, that batteries cannot be a unique population segment of a
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PBM. There was much debate on this topic in the standard drafting process. It is well known that like batteries will behave differently for even slight
variations of outside influences such as temperature, station load, battery charger action, number of duty cycles and even time spent on inventory shelf
before first charge. The manufacturers’ literature all state that you must control outside influences to attain a level of satisfactory performance. To prove
this level of satisfactory performance (and possibly to help detect poor performance from outside influences) you must conduct certain routine tests.
Routine tests are included within the Standard’s tables of maintenance activities.
2. The FAQ and the Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document.
In order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the Standards
Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future revisions to
PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the standard,
and the Standards Committee will have to remain convinced of their accuracy and relevance.
FirstEnergy
Yes
1. Sec. 2.3 (pg. 4) This section appears to be discussing the purpose of the standard and not the applicability.
We suggest changing the title of Sec. 2.3 to "Purpose of New Protection System Maintenance Standard."
Also, in Sec. 2.3 it states: "The applicability language has been changed from the original PRC-005: '... affecting
the reliability of the Bulk Electric System (BES) ...' To the present language: '... and that are applied on, or are
designed to provide protection for the BES.' However, the posted Draft 1 of PRC-005-2 still has the original
Purpose statement. Is the SDT planning to revise the Purpose statement as discussed in Sec. 2.3 of the Ref.
document? It appears that this statement is included in the applicability section 4.2.1 but believe it is more
appropriate as a general purpose statement applying to the whole standard.
2. Sec. 2.4 (pg. 4) Remove the extra word "that" from the second sentence of this section.
3. In the Supplementary reference, section 15.4 Batteries and DC Supplies, third paragraph, the SDT indicates
these tests are recommended in IEEE 450-2002 to ensure that there are no open circuits in the battery string.
This is essentially a continuity check of the battery string. In the fourth paragraph, the SDT states that
"..."continuity" was introduced into the standard to allow the owner to choose how to verify continuity of a battery
set by various methods, and not to limit the owner to the two methods recommended in the IEEE standards."
4. The SDT in Table 1a, the Maintenance Activity "Verify continuity and cell integrity of the entire battery", and in
Table 1b, the Maintenance Activity "Verify electrical continuity of the entire battery". Based on the information in
the Supplementary reference, the owner has to choose a method to verify continuity and the measurement of
specific gravity and cell temperatures could be the selected method, however it should not be a required
maintenance activity as shown in Tables 1a and 1b.
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Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments.
1. This clause of the document DOES specifically discuss the Applicability clause of the Standard; PRC-005-2 Section 4.2.1 states “Protection Systems
that are applied on, or are designed to provide protection for the BES.”
2. The Supplementary Reference Document has been changed in consideration of your comment – the extra “that” has been removed.
3. The standard and FAQ (See FAQ II-5-D, page 13) have been modified in consideration of your comments concerning checking continuity using specific
gravity.
4. Table 1a and Table 1b of the draft standard have been modified to remove requirements relating to measurement of cell temperature and specific
gravity.
CPS Energy
Yes
Adds to the confusion with the standard, FAQ, and Supplemental. The three documents at times describe
things a little differently.
Response: The SDT thanks you for your comments and is aligning the associated documents with changes to the standard.
AEP
Yes
Although helpful in understanding and clarifying intent, the requirements of a standard should be clearly written
so that multiple, lengthy supporting documents are not needed. These supporting documents do not get
recorded into the registry as part of the standard and may or may not be used by auditors during compliance
audits which could lead to different interpretations.
Response: The SDT thanks you for your comments. The FAQ and Supplementary Reference Document are provided as references to present detailed
discussions about determination of maintenance intervals and other useful information regarding establishment of a maintenance program, and do not
have statutory effect. The SDT believes that these documents provide potentially useful information to the entity in developing and sustaining an
effective PRC-005 program, and hopes that these documents will be useful to the entity in establishing support of their program when it is reviewed by
the Compliance Enforcement Authority. It is the drafting team's intent that these documents be posted with the standard when approved similarly to the
CIP FAQ and the PRC-023 reference document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo
industry comment and review, and the Standards Committee must be convinced through that process that the documents align with the standard and are
relevant to the standard. With future revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and
industry comment to remain posted with the standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
CenterPoint Energy
June 3, 2010
Yes
CenterPoint Energy believes the need for an extensive “Supplementary Reference Document”, in addition to 13
pages of tables and an attachment in the standard itself, illustrates that the proposal is too prescriptive and
complex for most entities to practically implement. CenterPoint Energy would prefer the SDT leave the existing
requirements substantially intact or, if most industry commenters prefer the SDT’s approach, that the SDT
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Yes or No
Question 6 Comment
attempt to simplify it.
Response: The SDT thanks you for your comments. The NERC Standard Development Procedure establishes that the standard prescribe requirements,
but avoid “how to” or “why” discussions. The SDT, in accordance with FERC Order 693, has prescribed maximum allowable maintenance intervals for
various Protection System Components, has provided opportunities for entities to use advanced technologies to perform physical maintenance less
frequently, and to use analytical techniques to customize their intervals. At its simplest, an entity could implement a pure time-based program utilizing
Table 1a, and much of the additional explanation in the Supplementary Reference Document would not be needed by that entity.
Public Service Enterprise Group
Companies
Yes
Figure 2 “typical generation system” shows a typical auxiliary medium voltage bus, suggest that a line of
distinction (dotted line) be added to the figure that defines the element connected to the BES (station Aux
Transformer - SAT) and equipment not associated with protection of the SAT be shown as not part of the BESPSMP.
Response: The SDT thanks you for your comments. The figures are provided to help describe the components of the Protection System, and are not
intended to fully describe the boundaries of the BES, the definition of which may vary by Region.
Wisconsin Electric
Yes
How much authority or weight will this document have with Compliance staff? If potential violations of the
standard requirements are alleged by Compliance staff, can this document be cited by an entity when the
document provides clarifying information on the requirements?
Response: The SDT thanks you for your comments. This document is not part of the standard, but is intended to provide the rationale of the SDT, as
well as guidance about how the various requirements might be met. The explanations are not an “official” interpretation of the standard, but may be
useful to determine how to implement various facets of the standard.
Green Country Energy LLC
Yes
Huge help to us!
Response: Thank you for your support.
Platte River Power Authority
Maintenance Group
Yes
1. It isn't clear in the Supplementary Reference Document why lock-out relays (86) are included as a component
of Protection Systems that require a 6 year maximum interval. Historically we haven't experienced any failures
with lock-out relays and feel the risk of causing a system reliability issue by removing it from service and
restoring it far outweighs the benefits of testing it. What, if any evidence, i.e. equipment failure, does the
standard drafting team use to mandate routine testing of 86 devices? Are we fixing something that isn't broke
here?
2. The FERC order directed NERC to submit a modification to PRC-005-1 that includes a requirement that
maintenance and testing of a protection system be carried out within a maximum allowable interval that is
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Organization
Yes or No
Question 6 Comment
appropriate to the type of the protection system and its impact on the reliability of the BPS. It would seem more
appropriate to allow each entity to set their own maximum allowable interval based on studies and historical data
of their specific protection system and impact on the reliability of the BPS opposed to a blanket approach that
covers all systems regardless of their size or system configuration.
Response: The SDT thanks you for your comments.
1. There are events in the industry that point to a failure of an electro-mechanical 86 device failing, and these devices are essential to proper functioning
of the Protection System. PBM principles can be utilized to extend maintenance intervals. (See Supplementary Reference Document, Section 9, page 15.)
2. FERC Order 693 directed that NERC establish maximum maintenance intervals, which does not provide the latitude to continue to allow entities to set
their own intervals. The SDT has, however, added the ability of an entity to follow PBM principles, as you describe, thus adjusting the time intervals
between required hands-on maintenance activity to reflect an entity’s experience.
Progress Energy
Yes
Progress Energy is concerned that separating this document from the standard may lead to issues down the
road. If the desire is to consolidate and clarify existing standards, then the two documents should be merged.
Otherwise the reference document may get lost from the standard, or might get changed without due process, or
might not even be recognized by FERC.
Response: The SDT thanks you for your comments. The FAQ and Supplementary Reference Document are provided as references to present detailed
discussions about determination of maintenance intervals and other useful information regarding establishment of a maintenance program, and do not
have statutory effect. The SDT believes that these documents provide potentially useful information to the entity in developing and sustaining an
effective PRC-005 program, and hopes that these documents will be useful to the entity in establishing support of their program when it is reviewed by
the Compliance Enforcement Authority. It is the drafting team's intent that these documents be posted with the standard when approved similarly to the
CIP FAQ and the PRC-023 reference document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo
industry comment and review, and the Standards Committee must be convinced through that process that the documents align with the standard and are
relevant to the standard. With future revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and
industry comment to remain posted with the standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
Southern Company
Yes
1.Section 15.3 DC Control Circuitry: Although we agree with the premise that auxiliary trip relays and lock-out
relays are similar in nature to EM relays and breakers, we believe that based on past performance, a complete
functional test trip every 6 years is not warranted. This complete functional test introduces additional risk to our
maintenance program not only from a human error perspective but also from the additional frequency of
switching and outages required. Our experience has shown that 12 years is an appropriate maximum time
interval (rather than 6 years.)
2. The Protection System Maintenance Supplementary Reference (Draft 1), section 8.4, states that the intervals
using the term “calendar” are allowed to be completed by the end of the applicable period, not necessarily
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Question 6 Comment
exactly at the interval specified. The only intervals specified in the PRC-005-2 tables are “calendar years” and
“months”. We believe that the “calendar” description should be extended to the “months” designator also to also
provide some maintenance flexibility (i.e. if an inspection were performed March 1st and was on a three month
interval, it would not be required until the end of June). This section should remove the term “calendar” and use
“months” and “years” with an appropriate explanation of the intent of the durations.
Response: The SDT thanks you for your comments.
1. The SDT believes that the intervals within the standard are appropriate. The standard permits the use of Performance-Based maintenance if an entity
has documented experience that supports longer intervals.
2. The standard was modified to append “Calendar” in front of “Months” in the Tables in consideration of your comment.
Dynegy
Yes
Suggest including operational verification (i.e. analysis of protection system operation after a system event) as
an acceptable method of verification.
Response: The SDT thanks you for your comments. Verification through analysis of events is an acceptable method of verification. Section 11 of the
Supplementary Reference Document (page 18) speaks to this topic.
Oncor Electric Delivery
Yes
The “Supplementary Reference Document” provides good technical justification for the various approaches to a
maintenance program (Time Based, Performance Based, and Condition Based) or combinations of these
programs that an owner of a Protection System can follow.
Response: The SDT thanks you for your support.
Xcel Energy
Yes
The information in the supplementary reference document is very helpful and valuable. Yet, it is not clear how
the document would be managed/revised, nor what role it plays in compliance monitoring. There needs to be a
clear understanding if everything in the document is required for compliance, e.g. criteria for monitored systems,
etc.
Additionally, we feel that evidence should be addressed within the supplementary reference document.
Response: The SDT thanks you for your support. The FAQ and Supplementary Reference Document are provided as references to present detailed
discussions about determination of maintenance intervals and other useful information regarding establishment of a maintenance program, and do not
have statutory effect. The SDT believes that these documents provide potentially useful information to the entity in developing and sustaining an
effective PRC-005 program, and hopes that these documents will be useful to the entity in establishing support of their program when it is reviewed by
the Compliance Enforcement Authority. It is the drafting team's intent that these documents be posted with the standard when approved similarly to the
CIP FAQ and the PRC-023 reference document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo
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Organization
Yes or No
Question 6 Comment
industry comment and review, and the Standards Committee must be convinced through that process that the documents align with the standard and are
relevant to the standard. With future revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and
industry comment to remain posted with the standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
The Supplementary Reference Document and FAQ have been updated to include a discussion pertaining to evidence for compliance.
Saskatchewan Power
Corporation
Yes
The supplementary reference document is useful information if properly explained and justified. Are the
suggestions in the reference document to become part of the standard, or simply recommendations of best
practice from industry and serve as a document to reduce the number of interpretations requested?
Response: The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of
maintenance intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT
believes that these documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes
that these documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority.
It is the drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference
document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the
Standards Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future
revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the
standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
Lower Colorado River Authority
Yes
The Supplementary Reference is well written and helpful in explaining the drafting teams thought process.
Response: The SDT thanks you for your support.
Duke Energy
Yes
We strongly believe that this document should be made a part of the standard, either as an Attachment or
worked into the requirements and tables. This will bring clarity to PRC-005 that is needed to get away from all
the past problems that were due to a lack of clarity with the previous PRC-005 standards. Also, all the
explanations and guidance lose force if they are not part of the standard. Auditors will only be bound by the
standard.
Response: The SDT thanks you for your comments. The NERC Standard Development Procedure establishes that the standard prescribe requirements,
but avoid “how to” or “why” discussions. The SDT, in accordance with FERC Order 693, has prescribed maximum allowable maintenance intervals for
various Protection System Components, has provided opportunities for entities to use advanced technologies to perform physical maintenance less
frequently, and to use analytical techniques to customize their intervals. At its simplest, an entity could implement a pure time-based program utilizing
Table 1a, and much of the additional explanation in the Supplementary Reference Document would not be needed by that entity.
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Organization
Yes or No
ITC Holdings
Yes
Question 6 Comment
1. Will clarifications in the Reference Document be enforceable with the standard?
2. For example page 11 of the reference document notes “Voltage & Current Sensing Device circuit input
connections to the protection system relays can be verified by comparison of known values of other sources on
live circuits or by using test currents and voltages on equipment out of service for maintenance.” Can a
maintenance program be confidently established using this or other testing methods included in the reference
document?
3. A condensed definition of “Condition Based Maintenance” as described in Section 6 of the Reference
document should be included in the standard document itself.
Response: The SDT thanks you for your comments.
1. The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document.
In order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the Standards
Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future revisions
to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the
standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
2. The NERC Standard Development Procedure establishes that the standard prescribe requirements, but avoid “how to” or “why” discussions.
3. Condition Based Maintenance is not intended to be a defined term; however, a discussion of the attributes of condition-based maintenance is
captured within the header of Table 1b and Table 1c of the Standard.
E.ON U.S.
June 3, 2010
Yes
1. With reference to Section 8.1., under additional notes is the following bullet:5. Aggregated small entities will
naturally distribute the testing of the population of UFLS/UVLS systems and large entities will usually maintain a
portion of these systems in any given year. Additionally, if relatively small quantities of such systems do not
perform properly, it will not affect the integrity of the overall program. This implies that incorrect performance of a
“relatively small quantity” of UFLS relays is acceptable but with the understanding that it is not optimal. E.ON
U.S. agrees with this statement in principle, in that the UFLS program is spread out across the system, and
there is not a one to one performance expectation as there is with a transmission line or generation protection
system. This calls into question the required intervals for testing of these types of relays, and the performance
expectations in a PBM program. Given the number of relays spread out across the distribution system, the
testing requirements of UFLS relays require longer testing intervals than other bulk transmission system
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Organization
Yes or No
Question 6 Comment
components.
2. 8.2 Is this requirement expected to be retroactive? That is, if the previous retention policy was followed to
the letter, an entity could be fully in compliance based on the previous standard, but not be in compliance if
PRC-005-2 were retroactive.
3. 8.3 And 8.4 This discussion explains how time based maintenance intervals were determined. The
conclusion is based upon surveys of SPCTF members and their existing practices, and seemed to arrive at a
maintenance interval based upon a simple average weighed by the size of the reporting utility. No
consideration appears to have been given to utilities who have successfully operated with longer test and
calibration intervals. In section 5 of the Supplementary Reference it is stated that “excessive maintenance can
actually decrease the reliability of the component or system.” With that in mind, some of the intervals defined in
the table seem too aggressive.
4. With the proposed PRC-005-2, the Drafting Team has effectively shortened the recommendation for UFLS
relays from 10 years to 6 years, with reference to the recommendations of the Protection System Maintenance
Technical Reference. E.ON U.S. believes that this is inconsistent with previous comments in Section 8.1, bullet
5 of the notes.
5. Consistent with the comments above and based on E ON U.S.’s internal testing, calibration and verification
experience, E.ON U.S. recommends maintenance on UFLS relays that comprise a protection scheme
distributed over the power system to be no less than 10 years for Level 1 monitoring and no less than 15 years
for Level 2 monitoring. For a PBM program, require the number of countable events within a segment to be no
more than 10%, not 4% as proposed.
Response: The SDT thanks you for your comments.
1. The SDT believes that the intervals specified in the standard are appropriate.
2. The new standard will be effective according to the dates established within the standard. The Implementation Plan posted with the standard
establishes a path for entities to migrate from their current practices and schedules to those imposed in this standard when approved.
3. Entities that have successful experience with equipment at intervals beyond the Standard’s tables can utilize the Standard’s PBM option.
4. The SDT believes that the intervals specified in the standard are appropriate, and disagrees that the intervals are inconsistent with the cited clause of
the Supplementary Reference Document.
5. Allowing the countable events to be increased to 10% would clearly allow an entity to increase its time interval between testing if there was a failure of
less than 10% of the testing segment. However, SDT contends that would be an unacceptably high rate of mal-performing Protection System
components, and would be detrimental to system reliability. The acceptable failure rate needs to balance between a goal of ultimate reliability and what
could be reasonably expected of a well-performing component population.
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Organization
Yes or No
AECI
No
Puget Sound Energy
Yes
Question 6 Comment
PSE appreciates this document as it provides a lot of further clarity. However, we wonder how this document
might be used during an audit. What is the formal process for the supplementation reference document to be
changed? How will entities be notified?
Response: The SDT thanks you for your support. This document is not part of the standard, but is intended to provide the rationale of the SDT, as well
as guidance about how the various requirements might be met. The explanations are not an “official” interpretation of the standard, but may be useful to
determine how to implement various facets of the standard. The FAQ and Supplementary Reference Document are provided as references to present
detailed discussions about determination of maintenance intervals and other useful information regarding establishment of a maintenance program, and
do not have statutory effect. The SDT believes that these documents provide potentially useful information to the entity in developing and sustaining an
effective PRC-005 program, and hopes that these documents will be useful to the entity in establishing support of their program when it is reviewed by
the Compliance Enforcement Authority. It is the drafting team's intent that these documents be posted with the standard when approved similarly to the
CIP FAQ and the PRC-023 reference document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo
industry comment and review, and the Standards Committee must be convinced through that process that the documents align with the standard and are
relevant to the standard. With future revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and
industry comment to remain posted with the standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
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7. The SDT has provided a “Frequently-asked Questions” document to address anticipated questions relative to
the standard. Do you have any comments on the FAQ? Please explain in the comment area.
Summary Consideration: In general, respondents expressed appreciation for the additional technical discussion included
within this document. The SDT responded to many comments by explaining the relationship between the standard and the FAQ.
Several respondents suggested that elements of the extensive discussion be contained within the standard itself, which is
contrary to the guidance within the paradigm for NERC Standards. Additionally, many of the comments in Questions 1-5 were
addressed by developing additional FAQ content and referring the respondents to the revised FAQ.
Organization
SCE&G
Yes or No
Question 7 Comment
1. The FAQ should be expanded to address the issues raised above with verification of trip circuits as to what is
an acceptable method meeting the intent of the standard.
2.
We also suggest changing “prove” to “verify” on FAQ 3a to be consistent with the wording of the
requirement.
3. Also, for a single bus with one set of bus potential transformers, how does one verify proper functioning of
the potentials? Is a reasonableness criterion adequate?
Response: The SDT thanks you for your comments.
1. The SDT agrees. The FAQ has been modified to address your concerns. (See FAQ II-4-E, page 11.)
2. The SDT agrees. The FAQ has been modified to address your concerns. (See FAQ II-3-A, page 8.)
3. The entity must verify that the protective devices are receiving the expected potential from the potential transformers or equivalent. If the potentials,
both magnitude and phase angle, can be determined to be reasonable, that would suffice. (See FAQ II-3-A, page 8.)
Bonneville Power Administration
Will this document be a part of the standard? Are its explanations the official interpretation of the standard?
Response: The SDT thanks you for your comments.
The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document.
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Organization
Yes or No
City Utilities of Springfield, MO
No
Dynegy
No
Electric Market Policy
No
ENOSERV
No
Florida Municipal Power Agency,
and its Member Cities
No
Georgia System Operations
Corporation
No
Green Country Energy LLC
No
Indianapolis Power & Light Co.
No
Operations and Maintenance
No
Platte River Power Authority
Maintenance Group
No
TVA
No
US Bureau of Reclamation
No
Western Area Power
Administration
No
Wisconsin Electric
No
Wolverine Power Supply
Cooperative, Inc.
No
June 3, 2010
Question 7 Comment
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Organization
Yes or No
E.ON U.S.
No
Question 7 Comment
E.ON U.S. disagrees with commissioning tests not being considered as a baseline for subsequent maintenance
activities. Commissioning tests should be counted as the initial testing in the scheme of a maintenance program
Response: The SDT thanks you for your comments.
As long as the requirements of the standard are met by the commissioning tests, they can “start the clock” for future maintenance testing. The FAQ has
been reworded to clarify this point. (The revised FAQ is IV-2-B, page 23.)
Ontario Power Generation
No
It was a good idea to prepare such a document.
Response: The SDT thanks you for your support.
Pepco Holdings Inc.
No
Item 3.B. (Page 6) claims that a small measurable quantity in 3I0 and 3V0 inputs to relays -may- be evidence that
the circuit is performing properly. This statement is weak at best, and incorrect at worst. A balanced
transmission system may exhibit 3I0 and 3V0 quantities that are not measurable, and those that are measurable
cannot be compared to other readings, since CT/PT error often exceeds system imbalance. Since these inputs
are verified at commissioning, recommend that maintenance verification require ensuring that phase quantities
are as expected and that 3IO and 3VO quantities appear equal to or close to 0.
Response: The SDT thanks you for your comments.
The SDT agrees; See FAQ II-3-B, page 9.
Exelon Generation Company,
LLC
No
None
MRO NERC Standards Review
Subcommittee
No
Overall, the FAQ’s are helpful toward understand what the SDT was thinking. Explanations for questions dealing
with the maintenance activities (e.g., battery testing) indicate an attempt to line up the requirement with IEEE
standards. While it is commendable to attempt alignment reliability standards with other industry standards, it
also begs the question of why requirements that are already covered by other standards should be repeated in
reliability standards. In addition, if the other standards are changed, then they could become inconsistent with or
contradictory to the reliability standard.
Response: The SDT thanks you for your support. The IEEE standards are voluntary standards, and do not establish any requirements, and also are not
measurable. PRC-005 standard requirements are loosely aligned with the IEEE standards and any future minor changes to those IEEE standards would
not significantly alter the correlation between PRC-005 standard requirements for batteries and the IEEE recommendations.
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Organization
Yes or No
American Transmission
Company
No
Question 7 Comment
Overall, the FAQ’s are helpful. Explanations for questions dealing with the maintenance activities (e.g., battery
testing) indicate an attempt to line up the requirement with IEEE standards. While commendable to attempt
alignment with the industry, it is further justification that maintenance activities should not be included in the
standard. Over the long term, technology or IEEE standards could change making the compliance standard
inconsistent.
Response: The SDT thanks you for your support. The IEEE standards are voluntary standards, and do not establish any requirements, and also are not
measurable. PRC-005 standard requirements are loosely aligned with the IEEE standards and any future minor changes to those IEEE standards would
not significantly alter the correlation between PRC-005 standard requirements for batteries and the IEEE recommendations.
PacifiCorp
No
Very helpful.
Response: Thank you for your support.
Austin Energy
Yes
Entergy Services, Inc
Yes
Manitoba Hydro
Yes
Public Service Enterprise Group
Companies
Yes
1) R1 - PRC-005-1 required the protection owner to supply a “basis” for the chosen maintenance intervals. Is it
intended that the new standard will no longer require the protection owners to provide a basis for their intervals
as long as they meet (or better) the published required intervals?
2) Compliance 1.4 Data Retention Needs more clarity. Some items require 12 years maximum maintenance
interval. However, we may perform the same maintenance in 6 years. The requirement for data retention is 2
maintenance intervals. In this example, does this mean 12 years or 24 years? Are we required to maintain
records for the maximum maintenance intervals allowed by the standard or only for the two shorter maintenance
intervals that we actually use?
3) Compliance will need some guidance on to what is required for “proper documentation”. Generally, the relay
technicians will scribe the actual test values for a given tests requiring the application of AC voltage and current.
However, as an example, when performing DC checks (DC aux relay), the technician may simply state that the
aux relay is “OK” without stating the DC coil pickup value in volts. Is this acceptable? Another example may be
when performing battery inspections (i.e., verify proper voltage of station battery, verify that no DC grounds exist,
etc), the inspector may simply indicate/document that the battery is “Ok”. This would indicate that appropriate 3
month inspections (as per table 1a) were completed and found to be within tolerances. Is this acceptable? If
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Organization
Yes or No
Question 7 Comment
specific details are required to be stored on test media (paper test sheets, computer based data storage, etc),
then please make some comments as such.
4) Table 1a DC supply. The 3 month inspection requires “verify that no dc supply grounds are present”. This
needs further clarification. What is the defined “limit” to determine whether we have a DC ground? The detection
methods for determining the presence of a DC ground will vary from indicating light balance to actual DC
ammeters or voltmeters. It is assumed that the intent of this requirement is to ensure that there are no full DC
grounds (dead shorts) in the DC terminals. Please clarify.
5) In the group by type of BES facility descriptions on pages 15 and 16 there is discussion about generation
station auxiliary transformers and associated protection devices. It also cites examples of relays which need not
be included even though they could result in tripping of the generating station. The line of demarcation is not well
defined in the FAQs or in the standard itself. Suggest that verbiage be added that clearly defines the element
(transformer) directly connected to the BES and its associated protection is what is included in the PSMP
requirements, items connected at lower voltage (down stream) are not within the PSMP requirement.
6) On page 15, the sample list of what is included in the standard, suggest that the list be expanded to show what
is not included (a relay that monitors parameters and is used for control/ alarm but not protection); generator
excitation controls that trip an auxiliary exciter. The list of items not included in the PSMP but that could trip the
unit should be further defined and expanded.
Response: The SDT thanks you for your comments.
1. The SDT agrees that no basis is required for level 1 monitoring as detailed in Table 1a. Monitoring attributes will be required to meet Table 1b and
Table 1c requirements. A performance based program will require further documentation; see Attachment A of the standard.
2. The SDT has modified the Data Retention area of the standard to clarify this.
3. The SDT will consider acceptable forms of evidence when developing the Measures. See the FAQ IV-1-B, page 21. Also, see Section 15.6 (page 24) of
the Supplementary Reference Document for a discussion of “evidence”.
4. Table 1a has been modified to address this, and an FAQ (FAQ II-5-I, page 15) has been added to clarify this. The revised language in the standard reads:
Check for unintentional grounds.
5. The SDT agrees; the FAQ has been modified to address your concerns see FAQ III-2-A, page 20.
6. The definition of Protection System states that “Protective relays, associated communication systems necessary for correct operation of protective
devices, voltage and current sensing inputs to protective relays, station DC supply, and DC control circuitry from the station DC supply through the trip
coil(s) of the circuit breakers or other interrupting devices.” Controls and alarms are excluded per the definition.
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Organization
Yes or No
Ameren
Yes
Question 7 Comment
1) We don’t think an Executive Summary is needed.
2) Please include the Supplement’s explanation of A/D verification method from Supplement page 9.
3) What role does the FAQ play in Compliance Monitoring and Enforcement?
4) Refer to question 2 and add our items # 2, 3, 4, 5, 7, and 11 to FAQ.
5) Please add FAQ that provides the NERC Compliance Registry Criteria for Generating Facilities, to clarify
applicability to >20MVA direct BES connection, aggregate >75MVA etc.
6) FAQ 2A p17 states that commissioning is construction, not maintenance. It seems like you’re ignoring the
significant verification, testing, inspection, and calibration activities that occur in commissioning. Should the inservice date be assigned to these components for determining their next maintenance?
7) Refer to question 3 and add our items # 4 to FAQ.
Response: The SDT thanks you for your comments.
1. The SDT thanks you for your input.
2. The SDT agrees; this information was already present in FAQ V-3-B (page 38).
3. The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that
these documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference
document.
4. The SDT agrees; see our response to your comment on Question 2.
5. The NERC Compliance Registry Criteria and Regional BES definitions are themselves requirements upon entities, and need not be explained within the
PRC-005 FAQ.
6. As long as the requirements of the standard are met by the commissioning tests, they can “start the clock” for future maintenance testing. See FAQ
IV-2-B (page 23).
7. The SDT agrees; see our response to your comment on Question 3.
NextEra Energy Resources
June 3, 2010
Yes
a. NextEra Energy believes the need for an extensive “Supplementary Reference Document”, in addition to 13
pages of tables and an attachment in the standard itself, illustrates that the proposal is too prescriptive and
complex for most entities to practically implement. NextEra Energy would prefer the SDT leave the existing
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Organization
Yes or No
Question 7 Comment
requirements substantially intact or, if most industry commenters prefer the SDT’s approach, that the SDT
attempt to simplify it.7. The SDT has provided a “Frequently-asked Questions” document to address anticipated
questions relative to the standard. Do you have any comments on the FAQ? Please explain in the comment
area. 1 Yes 0 No
Comments:
a. An alternative to measuring battery specific gravity is to measure float voltage and float current as described in
Annex A4 of IEEE Std 450-2002.
b. FAQ Page 17 (#1B): It is outside the jurisdiction of the standards development team to determine acceptable
forms of evidence. This should be decided by the Regional Entities.
c. FAQ Page 15 (#1A): This question should not have been included since it is addressing the definition of BES,
which is currently being addressed by another NERC Group.
d. FAQ Page 15 (#2): Although the FAQ is not enforceable, the answer provided may be interpreted as
enforceable. This should be included in the standard and not in the FAQ.
Response: The SDT thanks you for your comments.
The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities and maximum intervals
necessary to implement an effective PSMP.
a. The SDT has modified the standard in consideration of your comment by removing the maintenance activity of measuring specific gravity.
b. Other commenters have requested assistance in determining applicable evidence. The SDT has provided guidance that agrees with entities’ experience
regarding effective evidence during actual audits. See FAQ IV-1-B, page 21 and Supplementary Reference Document, Section 15.6, page 24.
c. Including the definition of the BES in the FAQ is helpful to some entities, and addresses common questions from other commenters; the FAQ states
that the RRO’s may have additional criteria.
d. The FAQ is intended to present examples of applicable devices, and is not intended to be all-inclusive. The requirements are established by the standard
definition of Protection System and the section 4 (“Applicability”).
CPS Energy
Yes
Adds to the confusion with the standard, FAQ, and Supplemental. The three documents at times describe things
a little differently.
Response: The SDT thanks you for your comments, however in the future please be more specific and identify the actual discrepancies so we can
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Organization
Yes or No
Question 7 Comment
improve the documents.
AEP
Yes
Although helpful in understanding and clarifying intent, the requirements of a standard should be clearly written
so that multiple, lengthy supporting documents are not needed. These supporting documents do not get
recorded into the registry as part of the standard and may or may not be used by auditors during compliance
audits which could lead to different interpretations.
Response: The SDT thanks you for your comments. The SDT believes that providing additional references helps clarify the requirements in the standard.
The SDT must address the directives of FERC orders 672 and 693 without being too prescriptive within the standard itself. According to the NERC
Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to be in a separate document.
Transmission Owner
Yes
An alternative to measuring battery specific gravity is to measure float voltage and float current as described in
Annex A4 of IEEE Std 450-2002.
Response: The SDT has modified the standard in consideration of your comment by removing the maintenance activity of measuring specific gravity.
SERC (PCS)
Yes
Change “prove” to “verify” on FAQ 3a (under Voltage and Current Sensing Devise Inputs to Protective Relays) to
be consistent with the wording of the requirement.
Response: The SDT thanks you for your comments. See FAQ II-3-A (page 8) – the word, “prove” was replaced with “verify” as proposed.
Detroit Edison
Yes
Example #1 on page 21 states “A vented lead-acid battery with low voltage alarm connected to SCADA. (level
2)”. However, Table 1b indicates that detection and alarming of dc grounds is also required for level 2.
Response: The SDT thanks you for your comments. The cited example is intended to show a mixture of Level 1 and Level 2 monitored components.
Those components not equipped with Level 2 monitoring must be maintained in accordance with Table 1a. Also, see the Decision Tree at the end of the
FAQ, addressing DC Supply monitoring levels.
ITC Holdings
Yes
1. FAQ page 6 question 3C should be clarified in the standard document itself. What is the technical justification
for omitting insulation testing of the wiring for DC control, potential and current circuits between the station-yard
equipment and the relay schemes? We feel this wiring is susceptible to transients which, over time, may
compromise the insulation, and therefore should be tested.
2. FAQ page 17 question 2A the standard should define when the first maintenance activity is to be performed.
We include our maintenance activities during commissioning, and set the next maintenance due date based on
the testing interval.
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Organization
Yes or No
Question 7 Comment
3. Will clarifications in the FAQs be enforceable with the standard? Can a maintenance program be confidently
established using this or other answers included in the FAQ’s?
Response: The SDT thanks you for your comments.
1. The SDT does not believe that insulation testing needs to be included within the minimum required maintenance activities; the SDT is not aware of a
body of evidence that suggests that these tests should be included as a requirement. The proposed standard does not prevent an entity from including
such tests in its program if their experience has indicated that such testing is needed. Furthermore, requirements for checking for proper current and
voltage at the relays and checking for DC grounds, provides some assurance of cable insulation integrity.
2. As long as the requirements of the standard are met by the commissioning tests, they can “start the clock” for future maintenance testing. See FAQ IV2-B, page 23.
3. The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority.
Nebraska Public Power District
Yes
On page 17, the answers to questions 2B and 2C indicate that there is no allowance or provision to exceed the
Maximum Maintenance Interval under any circumstances, except that natural disasters or other events of force
majeure will receive special consideration when determining sanctions. The rigidity of this performance
requirement could conceivably require equipment to be tested even though it is out of service in order to remain
compliant, adding unnecessary cost and waste to the PSMP of the regulated entities. We believe that a
prescriptive process for deferring testing and maintenance beyond the stated interval would be beneficial to allow
the necessary flexibility to manage the PSMP effectively.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may
need to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. The SDT is
concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals would thus not be
measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace period” would not
conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a discussion on this issue.
Should maintenance be due on equipment that is out-of service for a protracted period, the required maintenance should only be necessary before the
equipment is returned to service. However, you may encounter compliance challenges if you did not complete the maintenance during the scheduled
period, and should be prepared to document the out-of-service period and the subsequent maintenance.
Southern Company
June 3, 2010
Yes
Part of the responses could be more correctly stated: Page 11E, “why is specific gravity testing required” The
specific gravity measurements do not reflect accurate state of charge for lead-calcium batteries. (Float current is
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Organization
Yes or No
Question 7 Comment
a better parameter for this indication)
Response: The SDT thanks you for your comments concerning specific gravity being required. The SDT has modified the standard by removing the
requirement for specific gravity testing.
FirstEnergy
Yes
Pg. 17 (What forms of evidence are acceptable) Although Measures are not yet developed and posted with the
standard, we wanted to point out that the SDT should consider adding these acceptable forms of evidence in the
measures of the standard.
Response: The SDT thanks you for your comments. The SDT will consider identifying acceptable forms of evidence when developing the Measures.
Progress Energy
Yes
Progress Energy is unclear how a new/revised standard can have a 30 page FAQ document associated with it. If
questions need to be addressed, the answers should be incorporated into the existing standard. During this
stage of the draft, all questions should be addressed, not left to the side in an “interpretation” paper.
Response: The SDT thanks you for your comments. The SDT believes that providing additional references helps clarify the requirements in the standard.
The SDT must address the directives of FERC orders 672 and 693 without being too prescriptive within the standard itself. According to the NERC
Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to be in a separate document.
RRI Energy
Yes
Reverse power relays do not belong in the list of devices within the scope of this standard; reverse power is not
used for generator protection or protection of a BES element. Aside from the protection of reverse power for
other non-BES equipment, a generator can operate continuously as a generator, synchronous condenser, or a
synchronous motor. Reverse power relays (or reverse power elements in multi-function relays) is commonly
used as a control function for automatic shut-down purposes, which is not a protective function. Other reverse
power protection, with longer time delays, is provided for turbine protection, which is not within the scope of the
NERC Standards.
Response: The SDT thanks you for your comments. For some power plants, the reverse power relays trip the generation output breaker(s) and thus are in
scope per section 4.2.5.1 of the standard. The list of devices provides examples which may or may not be in scope of the standard depending upon how
they applied.
CenterPoint Energy
Yes
See CenterPoint Energy’s response to question 6. The need for an FAQ document in addition to an extensive
“Supplementary Reference Document” further illustrates the complexity and impracticality of the proposed
standard revisions.
Response: The SDT thanks you for your comments. See the response to your comments on Question 6.
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Organization
Yes or No
Question 7 Comment
The SDT believes that providing additional references helps clarify the requirements in the standard. The SDT must address the directives of FERC
orders 672 and 693 without being too prescriptive within the standard itself. According to the NERC Standard Development Procedure, a standard is to
contain only the prescriptive requirements; supporting discussion is to be in a separate document.
Oncor Electric Delivery
Yes
The FAQ document is an excellent resource document for Protection System Owners to understand why the
maintenance activities listed in the proposed standard were chosen.
Response: The SDT thanks you for your support.
JEA
Yes
The FAQ is a well written document and the team should take pride in its clarity and informative content. One
area that would be good to have further clarification, is if the SDT could provide a current industry product or
example of the "software latches or control algorithms, including trip logic processing implemented as
programming components, such as a microprocessor relay that takes the place of (conventional) discrete
component auxiliary relays or lockout relays that do not have to be routinely tested." Is this a microprocessor
lockout relay (that does not require trip testing?)
Response: The SDT thanks you for your support. The description indeed does reflect a microprocessor relay with imbedded lockout relay functions that
does not require trip testing for the lockout function. However, the breaker trip coil would still need to be tested as otherwise required in the standard.
Because of the NERC Antitrust Policy, the SDT is unable to provide commercial examples.
Northeast Power Coordinating
Council
Yes
The FAQ is helpful in answering many of the obvious questions.
Response: The SDT thanks you for your support.
Saskatchewan Power
Corporation
Yes
The FAQ section is beneficial, but would suggest reviewing it to determine if it can be integrated within the
reference document.
Response: The SDT thanks you for your support. The SDT will, to the degree possible, integrate material from the FAQ into the Supplementary Reference
Document. The SDT additionally believes that there is value in the FAQ that presents the material as questions and answers.
Lower Colorado River Authority
Yes
The Frequently-asked Questions document is very well written and very helpful. The decision trees are a good
addition.
Response: The SDT thanks you for your support.
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Organization
Yes or No
Xcel Energy
Yes
Question 7 Comment
1. The Frequently-asked Questions seem to act as interpretations to the standard. What roll will they play in
determining compliance?
2. On table 1b (page 11) the UFLS and UVLS maintenance activities indicate that tripping of the interrupting
device is not required, but it uses the term “functional trip test”. The FAQ indicates that a “functional trip test”
does require tripping the interrupting device. This conflicts with what is in the table and should be corrected in the
FAQ to reflect that no trip is required.
Response: The SDT thanks you for your comments.
1. The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document.
2. The SDT agrees with your comment. See FAQ II-4-E, page 11.
Illinois Municipal Electric Agency
Yes
Under “Group by Type of BES Facility”, 1. (page 15) “The radial exemption in the BES definition should be
clarified to include transmission subsystems within a single municipality, where the transmission facilities serving
only subsystem load with one transmission source - essentially operate radially. A more practical application of
the radial exemption would address smaller TOs whose system has minimal potential to impact the BES as a
whole.
Response: The SDT thanks you for your comments. The BES is a NERC and Regional defined term, and is outside the scope of this drafting team.
Requests for clarification regarding the BES definition should be referred to your Regional Entity. It isn’t clear to the SDT whether the example you
request is appropriate or accurate.
Duke Energy
Yes
We strongly believe that this document should be made a part of the standard, either as an Attachment or
worked into the requirements and tables. This will bring clarity to PRC-005 that is needed to get away from all
the past problems that were due to a lack of clarity with the previous PRC-005 standards. Also, all the
explanations and guidance lose force if they are not part of the standard. Auditors will only be bound by the
standard.
Response: The SDT thanks you for your comments. The SDT must address the directives of FERC orders 672 and 693 without being too prescriptive
within the standard itself. The SDT feels that providing additional references helps clarify the requirements in the standard and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. According
to the NERC Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to be in a separate
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Organization
Yes or No
Question 7 Comment
document.
AECI
Yes
Group by Type of Maintenance Program:
2. Time-Based Protection System Maintenance (TBM) Programs
A. What does this Maintenance standard say about commissioning?
Commissioning tests are regarded as a construction activity, not a maintenance activity.
COMMENT 1: If we understand the question and answer correctly, we disagree. We believe that the standard
should accept commissioning as the first date for the maintenance testing if the commissioning tests correspond
to the Standard’s TBM testing procedures. Otherwise, maintenance tests on a new substation will be required to
be completed (again) based on the Implementation Plan guidelines for PRC-005-02.
Group by Type of Maintenance Program:
2. Time-Based Protection System Maintenance (TBM) Programs
C. If I am unable to complete the maintenance as required due to a major natural disaster (hurricane,
earthquake, etc.), how will this affect my compliance with this standard.
The NERC Sanction Guidelines provide that the Compliance Monitor will consider extenuating circumstances
when considering any sanctions.
COMMENT 2: We feel that guidelines should be provided for “extenuating circumstances”, specifically
addressing natural disasters.
Response: The SDT thanks you for your comments.
The FAQ will be reworded to clarify that commission tests can be used to establish initial performance of maintenance as long as the requirements
Tables 1a, 1b, & 1c are fulfilled. See FAQ IV-2-B, page 23.
The SDT believes that “extenuating circumstances” are addressed by the NERC Sanction Guidelines, and are therefore a discretionary issue between the
entity and the Compliance Enforcement Authority. Because of the variability in natural disasters and their potential impact on Protection System
maintenance programs, it does not seem practical to develop measurable requirements addressing this issue in the context of this standard. Additionally,
FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive.
Please refer to Section 8 (page 9) of the Supplementary Reference Document for a discussion on this issue.
Puget Sound Energy
June 3, 2010
Yes
PSE appreciates this document as it provides a lot of further clarity. PSE hopes this document will be updated
through by comments and questions provided during the development process. We wonder how this document
might be used in an audit as well. What is the formal process for the supplementation reference document to be
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Yes or No
Question 7 Comment
changed? How will entities be notified?
Response: Thank you for your support.
The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document. In
order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the Standards
Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future revisions to
PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the standard,
and the Standards Committee will have to remain convinced of their accuracy and relevance.
June 3, 2010
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8. If you are aware of any conflicts between the proposed standard and any regulatory function, rule, order,
tariff, rate schedule, legislative requirement, or agreement please identify the conflict here.
Summary Consideration: Most respondents were unaware of any conflicts. Some felt that conflicts existed with existing
business or Regional practices, or with other organizations such as the Nuclear Regulatory Commission. The SDT provided
clarifying explanations to illustrate that conflicts are not actually present.
Organization
ITC Holdings
Question 8 Comment
Comments: We are not aware of any conflicts.
Response: The SDT thanks you for your comments.
MRO NERC Standards Review
Subcommittee
Conflict: Order 672 says that standards should be clear and unambiguous.
Response: The SDT thanks you for your comments. The SDT must address the directives of FERC orders 672 and 693 without being too prescriptive
within the standard itself. The SDT believes that providing additional references helps clarify the requirements in the standard. Also, the SDT believes
that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address observations from the
Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general.
Lower Colorado River Authority
Conflict: Potential conflict with PRC-023 as to which PRS systems are applicable per this standard.
Comments: PRC-005-2 requires compliance for this standard for all non-radial systems over 100 kV; while, PRC-023-1
prescribes it as below: 1. Title: Transmission Relay Loadability2. Number: PRC-023-13. Purpose: Protective relay settings shall
not limit transmission loadability; not interfere with system operators’ ability to take remedial action to protect system reliability
and; be set to reliably detect all fault conditions and protect the electrical network from these faults.4. Applicability: 4.1.
Transmission Owners with load-responsive phase protection systems as described in Attachment A, applied to facilities defined
below:4.1.1 Transmission lines operated at 200 kV and above.4.1.2 Transmission lines operated at 100 kV to 200 kV as
designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System.4.1.3 Transformers with low
voltage terminals connected at 200 kV and above.4.1.4 Transformers with low voltage terminals connected at 100 kV to 200 kV
as designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System.4.2. Generator Owners with
load-responsive phase protection systems as described in Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.4.3.
Distribution Providers with load-responsive phase protection systems as described in Attachment A, applied according to
facilities defined in 4.1.1 through 4.1.4., provided that those facilities have bi-directional flow capabilities.4.4. Planning
Coordinators.
We believe Bulk Electric System (BES) owners resources would be better utilized by focusing on relay systems as defined in
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Organization
Question 8 Comment
the above PRC-023-1 and this would still provide high level of reliability for the BES, since not all facilities operating between
100 200KV are critical to the BES. This would not preclude any utilities from applying this standard to other facilities operating
at the lower voltage range. Why did the drafting team not use the application language sited in the “Protection System
Maintenance - A NERC Technical Reference” which is similar to what is described above from PRC-023-1?
Response: The SDT thanks you for your comments. The Energy Policy Act of 2005, as well as various FERC orders and the NERC Standards
Development Process requires that reliability standards should be applicable to the BES (or, in the case of the Energy Policy Act, the BPS, which is
almost synonymous). In the case of PRC-023-1, cited in the comment, that SDT as well as the NERC Staff was required to carefully explain why this
standard was not specifically applicable to the BES, but instead to a subset of the BES. The 2007-17 SDT has determined that a similar rationale cannot
be effectively determined for PRC-005-2, and thus specified that it should be applicable to the BES. It is noted that this applicability is similar to the
applicability for PRC-005-1.
Exelon Generation Company, LLC
Conflict
1. Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission (NRC). Each licensee
operates in accordance with plant specific Technical Specifications (TSs) issued by the NRC. TS allow for a 25% grace period
may be applied to TS Surveillance Requirements (SRs). Referencing NRC issued NUREGs for Standard Issued Technical
Specifications (NUREG-143 through NUREG-1434) Section 3.0, "Surveillance Requirement (SR) Applicability, SR 3.02 states
the following:" The specified Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval
specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of
the Frequency is met."
2. Battery Charger Testing
2a. All conditions (grounds, voltages etc) should be compared to "acceptable limits" as specified in nuclear station design basis
documents, industry standards or vendor data.
2b. IEEE 450 does not use the word "proper" as utilized in Table 1a (e.g., "record voltage of each cell v/s verify proper voltage
of each individual cell.")
3. The NRC Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness of maintenance to ensure reliable
operation of equipment within the scope of the Rule. Adjustments are made to the PM (preventative maintenance) program
based on equipment performance. The Maintenance Rule program should provide an acceptable level of reliability and
availability for equipment within its scope.
Comments:
4. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's refueling schedule
and emergent conditions that would prevent the safe isolation of equipment and/or testing of function. "Grace" periods align
with currently implemented nuclear generator's maintenance and testing programs.
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Organization
Question 8 Comment
5. The 3-month maximum interval should be extended to include a grace period to ensure that a 25% grace period is included
to align with current nuclear templates that implement NRC TS SRs are documented in the response to Question 8.
Response: The SDT thanks you for your comments.
1. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with
shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance
can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the
established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and
allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a
discussion on this issue.
2a. The SDT agrees that each entity establishes its own “acceptable limits”. In this case, “acceptable limits” would seem to be determined in the
materials cited, and would apply for PRC-005-2.
2b. The SDT agrees. The SDT modified the standard to address your concerns. The revised maintenance activity now reads: Inspect cell condition of
individual battery cells where cells are visible, or measure battery cell/unit internal ohmic values where cells are not visible.
3. The entity must satisfy all applicable requirements (in this case, NERC PRC-005-2 and the NRC 10 CFR 50.65) as they apply to common equipment.
Since the NRC requires monitoring of the effectiveness of the program, you must do so even if this isn’t in the NERC standard.
4. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with
shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance
can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the
established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and
allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a
discussion on this issue.
5. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with
shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance
can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the
established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and
allowing for a “grace period” would not conform to this directive. Please refer to Section 8 (page 9) of the Supplementary Reference Document for a
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Question 8 Comment
discussion on this issue.
City Utilities of Springfield, MO
CU is unaware of any conflicts.
Response: The SDT thanks you for your comments.
Florida Municipal Power Agency,
and its Member Cities
FMPA is not aware of any conflicts
Response: The SDT thanks you for your comments.
Green Country Energy LLC
It would be beneficial to include some administrative (man hour) and cost estimates to comply with this and any future
proposed standards so if major budget impacts could be addressed.
Response: The SDT thanks you for your comments. The SDT is unable to assess the costs of any specific entity to comply with this standard, as the SDT
is not aware of the degree to which that entity’s current program would satisfy the requirements of this standard. Additionally, “man-hours” would vary
widely with the size of the entity.
Operations and Maintenance
No conflicts known.
AEP
No known conflicts.
Duke Energy
None
Electric Market Policy
None
Nebraska Public Power District
None
PacifiCorp
None known.
SERC (PCS)
None known.
Ontario Power Generation
Not aware of any
Georgia System Operations
Not aware of any.
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Organization
Question 8 Comment
Corporation
American Transmission Company
Order 672 says that standards should be clear and unambiguous. This proposed standard is very complex. While the standard
allows entities to select the appropriate maintenance strategy (time based, performance based or conditioned based) for their
system the amount of data and tracking required to demonstrate compliance will be overwhelming.
Response: The SDT thanks you for your comments. At its simplest, using time-based maintenance and Table 1a, the documentation requirements should
not be vastly different than those to prove compliance to PRC-005-1 for a strong compliance program. If more advanced strategies are used,
documentation requirements to demonstrate compliance may very well increase.
The SDT believes that it has clearly and unambiguously defined the minimum activities and maximum intervals necessary to implement an effective
PSMP, and presented advanced strategies for those entities who wish to utilize them.
Indianapolis Power & Light Co.
Performing some of the maintenance activities may cause conflict with regional ISOs and their safe operation of the BES
Response: The SDT thanks you for your comments. To minimize system impact of such maintenance, the maintenance necessarily should be scheduled
at a time that minimizes the risks.
Northeast Power Coordinating
Council
Yes--NPCC Directory #3, NPCC Key Facility Maintenance Tables. All areas must implement changes at the same time.
Response: The SDT thanks you for your comments. PRC-005-2 is a NERC standard and as such it will have its own implementation plan. PRC-005-2
when implemented will be an ERO-wide standard which establishes minimum requirements; to the degree that these requirements are more stringent
than those currently imposed by any individual Regional Entity, the NERC requirements will govern. Any individual Regional Entity can establish MORE
stringent requirements.
Puget Sound Energy
PRC-STD-005
PRC-005-2 requires a Protection System Maintenance Program (PSMP) while PRC-STD-005 requires a Transmission
Maintenance and Inspection Plan (TMIP). Historically the requirements of PRC-005-1 and PRC-STD-005 folded nicely into one
consistent plan. Could the maximum intervals identified in PRC-005-2 be expected or audited against under PRC-STD-005
where it does not indicated that much specificity? PRC-STD-005 requires maintenance of lines and breakers over and above
what PRC-005-2 the expectations relative to breakers should align.
Response: The SDT thanks you for your comments. An entity can be audited to both NERC Reliability Standards and to Regional Standards, provided
that both are mandatory and enforceable. Where applicable, Regional Standards will have more stringent requirements. As for intervals, where different
intervals apply to the same piece of equipment, the more stringent intervals apply. Also, the NERC intervals would apply only to the equipment
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Organization
Question 8 Comment
associated with those intervals within the NERC Standard. If the Regional requirements address equipment not addressed within the NERC Standard,
only the Regional requirements are relevant.
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
9. If you are aware of the need for a regional variance or business practice that we should consider with this
project, please identify it here.
Summary Consideration: A number of respondents suggested that the standard should allow “grace periods” to defer
maintenance because of a variety of expected difficulties in completing the required activities within the established intervals.
The SDT consistently responded that a “grace period” would be contrary to a measurable standard, and that entities should
manage their programs to assure that the required activities are completed on schedule.
Organization
TVA
Regional Variance or
Business Practice
Business Practice
Question 9 Comment
Allow for deferrals to coordinate with generator outages.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may need
to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. Specifically, for
generation facilities, there would seem to be numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a
scheduled plant outage, and maintenance with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything
else; the SDT believes that this maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a
de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish
maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary
Reference Document (page 9) for a discussion on this issue.
Exelon Generation Company,
LLC
Business Practice
Business Practice: Nuclear Electric Insurance Limited (NEIL) variance allowance.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may need
to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. Specifically, for
generation facilities, there would seem to be numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a
scheduled plant outage, and maintenance with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything
else; the SDT believes that this maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a
de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish
maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary
Reference Document (page 9) for a discussion on this issue.
ITC Holdings
June 3, 2010
Comment: We are not aware of any regional variance or business practice that should be considered
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Organization
Regional Variance or
Business Practice
Question 9 Comment
with this project.
Response: The SDT thanks you for your comment.
Green Country Energy LLC
Business Practice
Contractual commitments existing prior to NERC stds make it difficult to comply with some of the
maintenance activities.
Response: The SDT thanks you for your comment. Existing contracts may need to be adjusted to accommodate compliance to NERC standards.
City Utilities of Springfield, MO
CU is not aware of a need for a regional variance.
Response: The SDT thanks you for your comment.
Florida Municipal Power Agency,
and its Member Cities
FMPA is not aware of a need for a regional variance
Response: The SDT thanks you for your comment.
Electric Market Policy
Regional Variance
1. It is our understanding that once Project 2009-17: “Interpretation of PRC-004-1 and PRC-005-1 for
Y-W Electric and Tri-State” is approved, that the definition of a “Transmission Protection System”
would be included within PRC-005-2 or included within the NERC Glossary of Terms. However, the
specific protection that would be considered part of the “Transmission Protection System” would also
depend on the regional definition of the BES.
2. We suggest that the regions develop a supplement that provides further clarification on what
constitutes a “Transmission Protection System” given the regional definition of the BES.
Response: The SDT thanks you for your comments.
1. The 2009-17 interpretation addresses PRC-005-1. The SDT will monitor this interpretation to determine if any changes need to be made to PRC-005-2 in
response to this interpretation. In general, a definition cannot be established via the Interpretation process, but only through the comprehensive Standards
Development process.
2. You should present this concern to your region.
SERC (PCS)
June 3, 2010
Regional Variance
1, It is our understanding that once Project 2009-17: “Interpretation of PRC-004-1 and PRC-005-1 for
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Organization
Regional Variance or
Business Practice
Question 9 Comment
Y-W Electric and Tri-State” is approved, that the definition of a “Transmission Protection System”
would be included within PRC-005-2 or included within the NERC Glossary of Terms. However, the
specific protection that would be considered part of the “Transmission Protection System” would also
depend on the regional definition of the BES.
2. We suggest that the regions develop a supplement that provides further clarification on what
constitutes a “Transmission Protection System” given the regional definition of the BES.
Response: The SDT thanks you for your comments.
1. The 2009-17 interpretation addresses PRC-005-1. The SDT will monitor this interpretation to determine if any changes need to be made to PRC-005-2 in
response to this interpretation. In general, a definition cannot be established via the Interpretation process, but only through the comprehensive Standards
Development process.
2. You should present this concern to your region.
American Transmission
Company
Business Practice
Jointly-owned facilities should be a component of this standard. Comments: ATC shares services at
Substations; consider dividing the services, i.e. batteries and PTs.
Response: The SDT thanks you for your comments. This is a registration issue and it’s not within the scope of the SDT. If a company owns a facility that
meets the applicability section as described in this standard then it is responsible for the maintenance activities as described in this standard.
Ontario Power Generation
Regional Variance
Maintenance activities, and especially intervals, prescribed in NPCC Directory 3 (Maintenance Criteria
for BPS Protection) often differ from those in PRC 005 - 02. We recommend that NPCC aligns
Directory #3 with PRC 005 - 02 as much as possible. Technical justification should be provided for
any variance.
Response: The SDT thanks you for your comments. Any Regional Entity may develop its own requirements, as long as they are not less stringent than the
NERC requirements.
The SDT suggests that the commenter communicate with the NPCC regional staff regarding this concern.
AEP
No none regional or business practice variances known.
Nebraska Public Power District
None
PacifiCorp
None known.
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Question 9 Comment
Georgia System Operations
Corporation
None.
Operations and Maintenance
None.
Northeast Power Coordinating
Council
Not aware of any regional variance or business practice.
Response: The SDT thanks you for your comment.
JEA
Regional Variance
Regional variances in the Bulk Electric System definition as applied across regions allows for PSMP
to vary possibly even for the same region crossing tie lines. Also, accepted maintenance practices by
one region vary from accepted maintenance practices from another region. In the case of lower kV
non-redundant bus lockout protection systems, one region may allow for the protection system to be
taken out of service to perform maintenance, while another region may specifically prohibit this
practice (don't leave energized equipment protected by delayed clearing, etc.)
Response: The SDT thanks you for your comment.
Duke Energy
Regional Variance
Regions with ISO’s and RTO’s - Where the independent system operator (ISO) is not the same
company as the entity doing testing and maintenance, the independent system operator could prevent
the entity from performing scheduled maintenance and testing due to outage request constraints.
There should be no violation in such a situation, and the maintenance and testing just rescheduled.
Response: The SDT thanks you for your comments.
The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. The SDT is concerned that a “grace period”, if permitted, would be used
to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC
establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 (page 9) of the
Supplementary Reference Document for a discussion on this issue.
Wisconsin Electric
June 3, 2010
Regional Variance
See above Question 2, Item 7: There needs to be some recognition that Protection System's applied
on distribution-voltage systems may be included in a regional definition of a BES Protection System.
These systems are not designed or operated in the same way as Transmission or Generation
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Question 9 Comment
Protection Systems. Therefore, it is reasonable that these systems be subject to less rigorous
requirements.
Response: The SDT thanks you for your comments. See our response above to Question #2, item 7.
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10.If you have any other comments on this standard that you have not already provided in response to the prior
questions, please provide them here.
Summary Consideration: This question generated numerous comments and many respondents repeated comments offered
earlier in the document. Several of the respondents objected to the establishment of maximum allowable intervals at all, and
suggested that it should be left to the entities to establish their own intervals; the SDT explained that this would be directly
contrary to FERC directives related to the four current standards which are being addressed within this project. Additional
technical comments covered the full spectrum of the material in the standard and associated reference documents, and resulted
in extensive changes to the standard and in changes to both the Supplementary Reference (mostly to correct inconsistencies)
and to the FAQ (including addition of many additional topics). There was also concern about the documentation necessary to
demonstrate compliance.
Organization
Ameren
Question 10 Comment
1) Documentation could be a monumental task. Although FAQ 1B allows a comprehensive set of forms of documentation, a very
large number of people are involved across this set at most utilities. Producing a particular needle in the haystack may take
longer than an auditor would expect. Inspection forms can be structured to capture abnormal conditions, and thus normal
conditions are not recorded. Some items, like the red light monitoring a trip coil, may only be reported by exception (i.e., “red light
out, replaced bulb” but if the red light is on an operator may not report that).
2) We presume that the SDT would expect transmission facilities to be switched out of service if maintenance would result in
those facilities being unprotected. We think this should be stated or clarified, as there may be entities that still use differential
cutoff switches or other means of disabling protection for testing and have not considered the consequences of a concurrent fault.
Response: The SDT thanks you for your comments.
1. Much of your concern can be addressed within your program by careful design of your maintenance tracking forms and systems. In your example of a
red light, your maintenance can include documentation forms that require completion of either of multiple choices (e.g., OK, Not OK with resolution, etc).
2. This consideration relates to general planning, design, and operational issues, and is outside the scope of this standard. Various other NERC standards
apply.
Public Service Enterprise Group
Companies
June 3, 2010
1) R4 requires all maintenance correctable issues identified as part of a time based maintenance plan to be resolved in that same
maintenance period. This places a burden on some items (for example, 3 month battery inspections) to achieve adequate
resolution for problems that are not an immediate threat. For example, if a battery with a somewhat out of allowable range
specific gravity is found near the end of the maintenance period, scheduling and performing the work to replace the battery could
reasonably extend somewhat beyond the end of maintenance period. PSE&G requests that the drafting team revisit this
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requirement and allow flexibility for corrections to be made within a specified reasonable timeframe when correctible issues are
identified that for practical reasons require extension for work completion beyond the end of the current maintenance interval.
2) Section 4.2.5.5 of the standard should define provide an example that just the transformer connected to the BES is included
and specifically exclude connected equipment beyond the LV terminals.
3) Draft implementation plan for requirements R2, R3 & R4 discusses table 1a as basis, should also address tables 1b and 1c.
Response: The SDT thanks you for your comments.
1. Requirement R4, Part4.3 has been added to the standard in consideration of your comments. It reads as follows:
R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, including identification of the resolution of all
2
maintenance correctable issues as follows: [Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]
4.3
Assure either that the components are within acceptable parameters at the conclusion of the maintenance activities or initiate any necessary
3
activities to correct unresolved maintenance correctable issues .
2. The SDT disagrees with your comment. For example, current transformers on low-voltage transformer bushings or low-voltage breakers, which are
associated with differential relays, must be considered within application of PRC-005-2. See Figure 2 in the Supplemental Reference Document (page 28)
for an illustration.
3. The SDT believes that the implementation period for PRC-005-2 must be kept as brief as possible; until PRC-005-2 is fully implemented, entities will have
to be compliant with PRC-005-2 for those components for which implementation has been completed, and with PRC-005-1 for all other components.
However, entities may need considerable time to become compliant with the more specific requirements of PRC-005-2. An implementation period based on
Table 1a seems to be the best compromise period to achieve this. Additionally, the Implementation Plan does not require that entities adopt the Table 1a
activities and intervals, but instead just refers to the Table 1a components and their intervals for establishment of a phased implementation.
Wisconsin Electric
1. In the definition of a Protection System Maintenance Program, the statement is made that "A maintenance program CAN
include...” with a list of seven attributes following. Is it the intent that the PSMP "SHALL include one or more of the following”?
What is to prevent Compliance staff from concluding that all seven of these attributes MUST be included in the PSMP?
2. The standard should more clearly describe what is meant by "verify..." when used in a Maintenance Activity description. Does
2
A maintenance correctable issue is a failure of a device to operate within design parameters that can not be restored to functional order by repair or calibration
while performing the initial on-site maintenance activity, and that requires follow-up corrective action
3
A maintenance correctable issue is a failure of a device to operate within design parameters that can not be restored to functional order by repair or calibration
while performing the initial on-site maintenance activity and that requires follow-up corrective action.
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this require actual paper or electronic documentation? If so, then this should be explicitly stated in the Maintenance Activity
description. We maintain above that the recurring and routine maintenance activities having a 3 month interval should be revised
to use alternate words such as "Check" or "Observe". For example, "Check the continuity of the breaker trip circuit...", or
"Observe the voltage of the station battery". This activity should not be required to have paper or electronic documentation or
evidence. It should be sufficient to have these activities included in the PSMP.
3. It is stated in the Supplementary Reference that actual event data from fault records may be used to satisfy certain
Maintenance Activities, yet the standard itself does not appear to allow for this. Will such evidence be accepted by Compliance
staff?
Response: The SDT thanks you for your comments.
1. Yes, a PSMP should include one or more of the listed activities for any specific component. The definition is intended to identify the possible attributes
of a PSMP. Only those attributes relevant to a specific program and component need be included in the PSMP for that component. The proposed definition
includes the following phrase, making it clear that the PSMP does not have to include all listed items, “A maintenance program for a specific component includes
one or more of the following activities:”
2. The SDT thanks you for your comments and has modified the standard in consideration of your comments.
3. It is difficult to predict what will be accepted by Compliance staff; the SDT believes that you will need to establish a method to capture the evidentiary
data from fault records (such as what is empirically verified, when, and how) within your maintenance records. See FAQ IV-1-B (page 21), FAQ II-3-B (page
9) and Section 11 (page 18) of the Supplemental Reference Document.
Bonneville Power Administration
1. Tables 1a, 1b, and 1c were cumbersome to use because we found ourselves flipping back and forth to compare the
requirements for the different levels of monitoring. Also, in some cases, the types of components were slightly different between
the tables, which created confusion. We believe that it would be much easier to decipher a single table that listed each type of
component only once and showed the requirements and maintenance intervals for the different levels of monitoring on a single
page. Even if it took an entire page for each component, it would be very useful to see all of the options for that component
without having to flip back and forth between tables.
2. Please clarify the requirements for trip coils. Table 1a has as a component type "breaker trip coil only", with a maximum
maintenance interval of 3 months, while Table 1b has as a component type "trip coils and auxiliary relays". Table 1b say that
there are no monitoring attributes for this component and to use the level 1 intervals, but then gives a maximum maintenance
interval of 6 years, which doesn't agree with the 3 month interval given in Table 1a.
3. The terminology used to describe the secondary currents and voltages provided to the relay is confusing. Under the modified
definition of a protection system, it includes the term "voltage and current sensing inputs to protective relays", and in the tables it
uses the term "current and voltage circuit inputs". These terms, especially the use of the word input, give the impression that the
actual input circuitry of the protective relay is what is being described, but we believe that these terms are really meant to describe
the secondary currents and voltages from the instrument transformers (or other devices). BPA suggests revising the terminology
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to describe the secondary currents and voltages. For example, in the maintenance activities section of the tables, you could say,
"Verify that the secondary current and voltages provided to the relay are correct".
4. There is no mention to what the thresholds are when performing these maintenance activities or what corrective actions must
take place and by when they need to be carried out. Is this something we should expect to see soon?
5. The need to measure the cell/unit internal ohmic value every 18 months can be argued. BPA’s Substation Maintenance crew
performs these measurements once every 24 months and with the Operators monthly inspections, we have been able to
effectively catch any problems before a severe event/failure.
6. Communications: It is not clear specifically what equipment is included in "communications". The test interval of 12 years in
table 1b is too long to verify continued proper operation of transfer trip tone equipment. Monitoring the presence of the channel
does not provide any indication of whether the equipment can initiate a trip. Consequently, a required minimum interval of 12
calendar years is too long and does not do anything to verify proper communications support of the relay scheme. A shorter
interval of 6 years, such as that in table 1a makes more sense from a functionality standpoint.
Response: The SDT thanks you for your comments.
1. The SDT has experimented with various arrangements of the Tables with some input from external parties, and feels that the presentation shown in the
standard is the best way to present this complex information. To the degree possible, the SDT has attempted to make the arrangement of the three tables
as similar as possible to address your concern.
2. The cited sections of Table 1a, Table 1b, and Table 1c have been extensively revised.
3. The SDT modified the standard to address your comments by revising the description of these components within the tables and by modifying the
Protection System definition.
4. Note 1 to Table 1a, Table 1b, and Table 1c specify, “adjustment is required to bring measurement accuracy within parameters established by the asset
owner based on the specific application of the component.” Clause R4.3 has been added to the standard to require that the entity “initiate any necessary
activities to correct unresolved maintenance correctible issue.” Because corrective actions will vary widely in type and scope, it is difficult to specify when
it must take place; simple corrective actions may occur rapidly, but highly involved actions may take an extended period to complete.
5. Thank you for your comments concerning the evaluation of cell/unit internal ohmic values to the station base line at the Maximum Maintenance Interval
in Table 1. Because trending is an important element of ohmic measurement evaluation, the SDT believes that extending the Maximum Maintenance
Interval listed in Table 1 for evaluating internal ohmic values would not provide the necessary information for proper evaluation of the ability of the station
battery to perform as designed.
6. The SDT has defined the minimum activities and the maximum intervals necessary to implement an effective PSMP. Some entities may feel that they
need to maintain Protective System components more frequently.
Exelon Generation Company,
June 3, 2010
1. Battery testing should be added to Table 1c for Station dc supply (that uses a battery and charger)
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LLC
Question 10 Comment
2. Table 1c Condition based maintenance. Consider adding Battery Capacity Test on a 6-year interval regardless of other
condition based maintenance performed.
3. Evaluating the measured cell/unit internal ohmic values to station battery baseline does not provide an evaluation of battery
capacity please explain rational for maintenance activity.
4. If the Table 1a maintenance interval is reached and the entity is unable to perform the maintenance task, is it acceptable to
install temporary external monitoring or other measures to defer the maintenance to Table 1b or Table 1c interval? Is it
acceptable in Table 1b to substitute additional or augmented maintenance activities or operator rounds to extend intervals?
5. Table 1c for equipment with "continuous monitoring" states the maximum maintenance interval of "continuous" this does not
seem correct wording consider revising to state "not required."
6. The NERC standard should be revised to include a specific allowance for a deferral or variances of a maintenance activity
based on a formal technical evaluation. Nuclear generating units allow for deferrals and/or variances on certain equipment based
on emergent conditions that would prevent safe isolation and/or testing of function. It should be noted that any deferrals and/or
variances if justified are to be based on a formal evaluation and not based on work management or resource issues.
7. The maintenance intervals and maintenance activities should be referenced directly to a basis document to ensure guidelines
have a specific technical basis (e.g., IEEE-450).
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comments concerning Table 1c. Within Draft 2 of the standard, testing of the battery is not
required if all performance attributes of the battery are monitored.
2. The SDT has modified the standard in consideration of your comments concerning Table 1c and the need for testing to verify that the battery can
perform as designed.
3. The SDT believes that this Maintenance Activity is a viable alternative that a Vented Lead-Acid or Valve-Regulated Lead Acid battery owner can perform
at the Maximum Maintenance Interval of Table 1 in place of conducting a capacity test. See FAQ II-5-F (page 14) and FAQ II-5-G (page 14).
4. R2 of the standard establishes that the entity “ensure the components to which the condition-based criteria are applied (as specified in Tables 1b or 1c),
possess the necessary monitoring attributes.” It appears irrelevant as to when the monitoring system is installed within the Table 1a monitoring interval,
as long as the monitoring satisfies the attributes established in Table 1b or Table 1c as appropriate. If operator rounds, etc, are performed to the intervals
established within the Table 1b general requirements, address the monitoring attributes specified within the Table, and are appropriately documented, they
meet the requirements. However, it seems to the SDT that any temporary monitoring, etc, will have to be in place BEFORE you are overdue on maintenance
and therefore out of compliance.
5. The Maintenance Activities describe that maintenance is actually being performed continuously via the monitoring system. Stating “continuous” for the
interval provides a valuable link to FERC Order 693, which directs NERC to establish maximum maintenance intervals.
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6. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be numerous
opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with shorter
intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance can be done
on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals
would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace
period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a discussion on this issue.
7. IEEE Standards are voluntary unless they are adopted by an “authority having jurisdiction’, thus the IEEE Standards could be adopted here in their
entirety. However, they would require consistent and continual review by NERC to assure that they are, and continue to be, relevant. The SDT elected
instead to use them as a source of material, and to include the relevant required tests within the NERC Standard.
FirstEnergy
1. BES reclosing schemes were recently questioned in a PRC-005-1 interpretation but there is no mention of reclosing schemes in
the draft standard. This interpretation should be integrated into the requirements of PRC-005-2.
2. Lack of Exception Process - The standard as written does not reflect the fact that any one group, such as a TO performing
maintenance on a BES, does not have full control over when an outage can be taken to perform maintenance activities.
Especially regarding functional testing, where the equipment needs to be exercised resulting in some BES components being deenergized, it can be very difficult in certain parts of the T&D system to obtain the necessary outage to complete these tasks. Even
with proper planning, changes in system conditions and unforeseen equipment problems in other areas can impact the ability to
schedule an equipment outage appropriately. Accordingly, a TO can be penalized for not completing prescribed maintenance
within prescribed limits due to factors outside of their control. This type of scenario has already been experienced where
maintenance activities are scheduled upwards of a year in advance, and then inclement weather or system conditions outside of a
TO’s service territory (e.g. unanticipated generating unit shutdown) prevent the work from taking place.
3. The standard should provide some specific guidance to allow relief for such situations, or that properly incents or even requires
independent system operators (ISOs) and other outside groups to also ensure maintenance is completed within prescribed
intervals. If a TO properly considers factors such as weather (not scheduling critical outage during middle of summer), resource
commitment, schedule (the requested outage window is at least one year before maximum interval is met), time of day
(performing work during afterhours period when load is down) etc. then if outages are still denied, that the TO is not penalized for
being out of compliance as maximum intervals are exceeded. This suggested "exception process" should provide requirements
for all parties involved, both those performing the maintenance as well as those controlling and overseeing the system. There
should be required documentation to prove that the parties on both sides made proper efforts to complete the required
maintenance, as well as discuss conflict resolution.
4. With regard to the phrase "including identification of the resolution of all maintenance correctible issues" in Req. R4, we feel
that this requirement should be a subset of R4 since it is part of the implementation of the PSMP. We suggest removing the
phrase from the main requirement of R4 and creating a new 4.3 as follows:"4.3. For all maintenance programs, identify resolutions
for all encountered maintenance correctible issues and take corrective action within a time period suitable for maintaining reliability
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of the affected protection system."
5. With regard to the proposed modification of "Protection System", we suggest adding the word "devices" after "voltage and
current sensing". This would also match what appears to be the SDT’s intended wording as shown in the Supplementary
Reference Document sec. 2.2. Also, we suggest modifications to the proposed definition to add clarity to the types of
communications system protection and the voltage and current sensing devices. The following is our suggestion for wording of the
definition:"Protective relays, communication systems used in communications aided (or pilot) protection, voltage and current
sensing devices and their secondary circuits to protective relays, station DC supply, and DC control circuitry from the station DC
supply through the trip coil(s) of the circuit breakers or other interrupting devices."
6. Protection System Communication Equipment and Channels - Some power line carrier equipment has automatic testing and
remote alarming and some that does not. For other relay communication schemes (e.g., tone transfer trip ckts), if the circuit
travels over our private communications network (fiber or microwave radio), the communication equipment is remotely
monitored/alarmed. In other cases it is not remote monitored. We ask for clarification as follows: As part of our maintenance
program, we check that signal level, reflected power, and data error rate are all within tolerance at the interface between the end
equipment and the communication link. Our question is: Does this meet the intent of the proposed requirements in PRC-005-2 for
maintenance activities for Protection System Communication Equipment and Channels? Or do the requirements ask for
something beyond this?
7. We suggest combining 4.2.2, 4.2.3 and 4.2.4 to read as a new 4.2.2 "Protection System components which are installed as an
underfrequency load shedding, under voltage load shedding or Special Protection System for BES reliability."
Response: The SDT thanks you for your comments.
1. The SDT is required to include/adopt material from approved interpretations within the standard. In the case of reclosing relays, the referenced
interpretation stated that reclosing relays are NOT included, and the draft standard excludes them.
2. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. The SDT is concerned that a “grace period”, if permitted, would be used
to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC
establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the
Supplementary Reference Document (page 9) for a discussion on this issue.
3. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. The SDT is concerned that a “grace period”, if permitted, would be used
to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC
establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 (page 9) of the
Supplementary Reference Document for a discussion on this issue
4. The SDT has modified the standard in consideration of your comment. Requirement R4, Part 4.3 was added and now reads: Assure either that the
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components are within acceptable parameters at the conclusion of the maintenance activities or initiate any necessary activities to correct unresolved maintenance
4
correctable issues .
5. The SDT believes that your suggestions regarding the Protection System definition may address predominant current technology relatively accurately,
but may be constraining with regards to emerging technologies.
6. If there is remote monitoring of the Channel, then Level 2 requirements indicate a 12 calendar year interval for the tests you describe. If the system is
unmonitored a manual check back or a check of the automated check back is required at a 3 month interval. Unmonitored systems would also have the
signal level, reflected power and data error rate check done on a 6 year interval.
7. The SDT elected to list these components within separate subrequirements in order to maintain linkage to the legacy PRC-008, PRC-011, and PRC-017
standards. Your suggestion may be better adopted in a future revision of this standard (following approval of PRC-005-2).
Dynegy
1. The proposed definition of Protection System needs further clarification. Suggest changing wording around DC supply to read
as follows: "...and DC control circuitry associated with protective devices from the station DC supply".
2. Suggest revising Section 4.2 to separate time based program as its own item under R4.3.
3. Change title on Table 1a to clarify level 1 monitoring as time based.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment. The following phrase was added to the definition: and associated circuitry from the
voltage and current sensing devices
2. R4.1 currently addresses implementation of maintenance programs per Table 1a, Table 1b, and Table 1c as different “flavors” of a time-based program,
depending on the degree of monitoring present for the various components. The SDT feels that this is the correct approach. R4.2 specifically addresses
performance-based maintenance, and does not seem relevant to the text of your comment.
3. The SDT has modified the standard in consideration of your comment and added “Time-based” to the title of Table 1a.
MRO NERC Standards Review
Subcommittee
A. In the applicability section 4.2.5.5, change the statement to say, “Protection systems for BES connected station-service
transformers for generators that are part of the BES.”
B. In the applicability section 4.2.5, change the statement to replace “are part of” with “directly connected to”. The “are part of”
will be left to interpretation. Please indicate the added reliability benefit by collecting this in Table 1a Page 9 protection system
4
A maintenance correctable issue is a failure of a device to operate within design parameters that can not be restored to functional order by repair or calibration
while performing the initial on-site maintenance activity and that requires follow-up corrective action.
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communication equipment and channels.
C. If a breaker failure relay is also being used for sync-check, is it required to verify the voltage inputs since they are used for a
closing function and not a tripping function? It is understood that the current inputs would have to be verified since these are used
for breaker failure tripping.
D. Please clarify requirement R1-1.1, does one have to individually list out each Protection System and its associated
maintenance activities or can the PSMP be a generalized procedure that covers each of the components in all of a utility's
Protection Systems?
E. All references to breakers should be eliminated; thus, eliminate breaker trip coils. Breakers are primarily mechanical in nature
and should be excluded similar to mechanical relay systems such as sudden pressure relays.
F. Clarify that trip coils checks or tests can be verified through alternate means other than physically tripping the coil or potentially
requiring system outages to physically trip a coil. Alternate tests could consist of checking self monitoring relays, continuity lights,
etc. Trip coil tests could require transmission line outages which can be denied by regulatory authorities due to system conditions
beyond an entity’s control. Significant delays of months or longer could occur to obtain a transmission line outage. Further,
potentially requiring transmission line outages for trip coil test could harm BES reliability by increase the number of force
transmission line outages due to testing. System reliability could be significantly negatively impacted anytime testing on trip
circuits is performed due to human errors causing outages or regional disturbances.
G. One item R1.3 (inclusion of batteries) was questioned as why this was specifically called out. It should be part of the definition.
H. Define the term “condition-based”.
I. The format of the tables is poor with 17 line items addressed in each. It is difficult to relate one table to another because they are
not consistent with regard to the type of components. For example table 1a references of components a “breaker trip coil (only)”
and the 1b references “trip coils and auxiliary relays”.
J. R1.1 please add “as they apply to the applicable entity”. As stated now, all three tables must be accomplished.
K. Please add the words “time based maintenance methods” to table 1a for clarity in the heading.
L. Table 1b under general description, last sentence the word “elements” should be replaced with “maintenance activities” which
will provide exactly what is intended.
M. Table 1b, if maintenance activities for level 2 monitoring include level 1 maintenance activities, then redundant activities in
table 2 that are contained in table 1 should be removed (the same for table 3 to table 2 to table 1).
N. If an entity maintenances a protective relay such that it is included in level 2 monitoring (a Condition Based Maintenance
program) and this relay is considered to have a maximum interval of 12 years, does the entity need to also perform the
maintenance activities for level 1 monitoring since the table 1b header indicates, “General Description: Protection System
components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
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alarmed failures. Monitoring includes all elements of level 1 monitoring with additional monitoring attributes as listed below for the
individual type of component”?
Response: The SDT thanks you for your comments.
A. The station-service transformer impacts proper operation of the BES generator, whether the station service transformer is connected to the BES (for
example, at 138 kV) or not (for example, connected at 46 kV). (See FAQ III-2-A, page 20)
B. This suggestion may actually bring a small, non-BES, generator facility that is connected to the BES into scope. For example, if a Region specifies that
any generator greater than 20 MVA connected at 100 kV or above is BES, your suggestion would bring a 10 MVA generator (similarly connected) into scope.
Clause 4.2.5 currently limits applicability to BES generators.
C. No. The maintenance activities for this component have been modified to clarify.
D. The entity may use whatever method it wishes, but the documentation of the program and the implementation of the program needs to be adequate to
satisfy the Compliance Enforcement Authority that the program meets the requirements of the standard. Please be advised that all requirements of the
standard must be met, including that the relevant activities in the Tables are performed.
E. The SDT believes that the breaker trip coils are a vital electrically-operated component of the DC control circuit, and they therefore must be included.
For testing the breaker trip coil, the breaker must be observed to trip; however, such additional testing such as travel recorder, breaker timing, etc need not
be performed to satisfy PRC-005.
F. The SDT considers that the electro-mechanical devices (trip coils, aux relay coils, etc) need to be periodically exercised to assure that they operate
properly. Much of the rest of the control circuit can be verified by monitoring, including continuity of the coils, but this doesn’t assure operating integrity
of these devices. An entity is necessarily obligated to manage its maintenance program to complete the necessary activities on time, and various other
NERC standards address the management of risk related to planned outages.
G. In the Protection System Maintenance – Frequently Asked Questions (FAQ) document (FAQ IV-3-G, page 26.) and Supplementary Reference Document
Section 15.4 (page 23), the Drafting Team explains why batteries are excluded from PBM and the standard should include all batteries associated with a
Protection System in a time-based program.
H. The SDT declines to introduce a defined term for this. Table 1b and Table 1c identify condition-based maintenance to include consideration of the
known condition of the component within condition-based maintenance. The Supplemental Reference Document (Section 6, page 8) and the FAQ (V-3,
page 38 and V-4, page 39) also describe condition-based maintenance considerations.
I. The SDT has modified to Tables to make them more consistent with each other.
J. The SDT has modified the standard in consideration of your comment. The original Pwas replaced with a new Part 1.1 and a new Part 1.3 was added as
shown below,
1.1. Identify all Protection System components.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
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per Requirement 1, Part 1.2.
K. The SDT has modified the standard in consideration of your comment - and added “Time-based” to the title of Table 1a.
L. The SDT has modified the standard in consideration of your comment. The revised language does not use the word, “elements” – it reads: Level 2
monitoring includes all monitoring attributes as listed below for the individual type of component.
M. The SDT disagrees. Repeating the activities in Table 1b or Table 1c allows the entity to not refer back to the previous table.
N. If an entity decides to implement Table 1b for qualified components, the activities in Table 1b supersede the comparable activities in Table 1a.
Requirement R1 has been modified to clarify.
CenterPoint Energy
a. CenterPoint Energy believes the existing maintenance standards are preferable to the approach embodied in this proposal.
However, if most entities agree with the SDT’s approach, CenterPoint Energy recommends deleting Under-Frequency Load
Shedding (UFLS) and Under-Voltage Load Shedding (UVLS) system equipment from the scope of this proposal because the
performance requirements for UVLS and UFLS are substantially different from transmission and generation protection schemes.
Few would argue that protection schemes that clear faults on the Bulk Electric System must be very reliable, much more reliable
than schemes that shed distribution load for under-voltage or under-frequency situations. If an entity plans to shed a
contemplated level of load for a contemplated set of circumstances based upon planning simulations, that plan would translate
into a certain number of distribution feeders that are reasonably predicted to shed a load amount that is reasonably close, but not
exactly equal (unless by chance) to the contemplated amount of load shed. For example, if a certain number of distribution
circuits equals 10% of the entity’s load during one time (such as system peak), that same amount of distribution circuits will almost
certainly equal a different percentage of the entity’s load at other times. So, if hypothetically 100 distribution circuits are armed
with UVLS or UFLS relays set a given trip point, the actual percentage of load that will be shed will vary under different system
conditions. Therefore, if 95 of the distribution circuits actually trip on one occasion and 98 trip on another occasion, the difference
in system performance is immaterial because the exercise is not that precise, especially when planning simulation uncertainties
are also introduced into the picture. For these reasons, CenterPoint Energy believes it is unreasonable to impose a high level of
rigidity into load shedding schemes when the designs of the schemes inherently do not depend on such rigidity. If the SDT
agrees, then the revised standard would not be applicable to Distribution Providers, and 4.1.3 can be deleted.
b. CenterPoint Energy also disagrees with the proposed expansion of the Protection System definition. The present definition
does not include trip coils; and correctly so, as trip coils are part of the circuit breaker. A protection system has correctly
performed its function if it provides tripping voltage up to the breaker’s trip coils. From that point, the breaker can fail to timely
interrupt fault current due to several factors such as a binding mechanism that affects breaker clearing time, a broken pull rod, a
bad insulating medium, or bad trip coils. Local breaker failure protection is installed to address the various possible causes of
circuit breaker failure. Planning standard TPL-001 tables 1C and 1D specifically support the present definition, as Delayed
Clearing is noted as due to “stuck breaker or protection system failure”.
Response: The SDT thanks you for your comments.
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a. The four legacy standards are combined here in response to several suggestions, including from FERC (in Order 693) because of substantial equipment
similarities. For the reasons that you note, the activities specified for UFLS and UVLS protection are somewhat less comprehensive than those for fault
protection.
b. The SDT contends that the trip coil itself is an integral and essential component of the station control circuitry, and it must be assured that the trip coil
operates. The SDT has also been diligent in excluding any facets of the breaker mechanism from consideration, thereby excluding consideration of many
of the failure types listed. Many breaker failure schemes are designed with the presumption that the trip coil is properly initiated, and are more focused on
mechanism failures.
NextEra Energy Resources
a. The level of effort that will be required to be in compliance in accordance to PRC-005-2 is substantial. Also, it will be difficult to
create one maintenance program for all NextEra Energy sites that establishes maintenance intervals based the implementation of
a combination of the three allowable types of maintenance programs (time-based, condition based, and/or performance based
maintenance). As a result, a high risk exists that something will be missed or carried out incorrectly.
b. What is the implementation period? How will the standard be implemented in relation to the entity’s maintenance scheduled in
accordance with existing intervals specified in the current Protection System Maintenance and Testing Procedure that meets the
requirements of PRC-005-1 but will exceed PRC-005-2’s established maximum intervals? Once PRC-005-2 becomes mandatory,
entities should not be required to re-do testing in accordance with the new intervals. Instead, entities should be allowed to
implement the newly established intervals after the last known cycle.
c. Protection System Maintenance Program (PSMP):
(c1) The PSMP definition would be better defined if the first sentence was changed to “An ongoing program by which Protection
System components are kept in working order and where malfunctioning components are restored to working order.”
(c2) Please clarify what is meant by “relevant” under the definition of Upkeep. Should “relevant” be changed to “necessary”?
(c3) The definition of Restoration would also be more explicit if changed to:The actions to return malfunctioning components back
to working order by calibration, repair or replacement.
(c4) Please clarify the definition of Restoration. For example, if a direct transfer trip system has dual channels for extra security
even though only one channel is required to protect the reliability of the BES and one channel fails, must both be restored to be
compliant?
d. Protection System (modification):
(d1) Voltage and current sensing inputs to protective relays” should be changed to “voltage and current sensors for protective
relays.” Voltage and current sensors are components that produce voltage and current inputs to protective relays.
(d2) “Auxiliary relays” should be changed to “auxiliary tripping relays” throughout PRC-005-2, FAQ and the Draft Supplementary
Reference.
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(d3) The word “proper” should be removed from the standard. It is ambiguous and should be replaced with a word or words that
are clear and concise.
e. Additionally, NextEra Energy concurs with the following comments made by other entities:
(e1) PRC-005 Sect B (R2): More clarity needs to be provided. Does this requirement require the utility to document the
capabilities of its various protection components to determine fully and partially monitored protection systems? If so the
requirement for such documentation should be clearly spelled out. Usually each requirement has a measurement (of compliance)
and I'm not clear how this will be done.
(e2) PRC-005 Sect B (R4.1): A “grace period” similar to the NPCC Criteria should be considered in case it is not possible to
obtain necessary outages.
Response: The SDT thanks you for your comments.
a. We agree that the effort may be substantial. However, the effort and compliance risk can be minimized by simply implementing Table 1a, together with R1
and R4.
b. A proposed Implementation Plan was posted with this draft of the standard, and will continue to be posted with future drafts (including ballot drafts when
the standard reaches that stage). Please review the posted Implementation Plan.
c1. The SDT does not believe that the suggested change is substantive, and sees no reason to make it.
c2. Some updates may not affect the operation of the device as applied, and therefore are not relevant. “Necessary” would imply an additional level of
review to determine whether the device would operate properly without the updates, while “relevant” simply implies that the update applies to the function.
c3. The SDT does not believe that the suggested change is substantive, and sees no reason to make it.
c4. The standard establishes that all components need to be fully maintained, and that they will function as designed. The SDT appreciates that some
“restoration” activities may take an extended time to complete, but also contends that restoration to the designed condition is a vital element of
maintenance.
d1. The SDT has modified the standard in consideration of your comments.
d2. “Auxiliary tripping relays” may exclude essential other internal Protection System functions. Therefore, the SDT declines to adopt this suggestion.
d3. “Proper”, “working condition”, “correct”, etc, are all somewhat subjective terms that address the application-specific requirements related to the
specific use. For example, one entity’s design standards may require that an electromechanical relay be within a 2% tolerance of the ideal operating
characteristics, while another may only require that it be within 5%. Each of these is proper, correct, etc, for the application.
e1. The requirement establishes that an entity be able to prove that the specified monitoring attributes are met. There may be many methods of
documenting this – see Section 15.6 of the Supplemental Reference Document (page 24) which was posted with this standard. Measures, etc, will be
included with the next posted draft of the standard.
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e2. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals would
thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace period”
would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document for a discussion on this issue.
City Utilities of Springfield, MO
As proposed, this standard is very long and complex. Additionally, in requirement R1, bullet 1.1 ought to state “For each
component used in each Protection System, include all “applicable” maintenance activities specified in Tables 1a, 1b and 1c”. For
instance, if every component has continuous monitoring, why should the program include 1a and 1b?
Response: The SDT thanks you for your comments. The SDT has modified the standard in consideration of your comments. The original Part 1.1 was
replaced with a new Part 1.1 and a new Part 1.3 was added as shown below,
1.1.
Identify all Protection System components.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
per Requirement 1, Part 1.2.
Austin Energy
Austin Energy is meticulous in adhering to the current maintenance standard and is convinced that its current maintenance and
documentation program is adequate to maintain its reliable electric power system.
1. Austin Energy appreciates the good intentions of the SDT but believes that the approach taken increases complexities to the
maintenance process, introduces unwarranted workload in excessive documentation, is inflexible towards system configuration
and experience, and is over prescriptive in nature. The approach also fails to distinguish the harmful effects of over-maintenance,
increasing reliability risk due to human error and ultimately affecting the overall performance and reliability of the system.
2. Another concerning issue is the addition of the breaker trip coil to the protection system definition. Our position is that the trip
coil should be part of the breaker. The protection system would be considered operating correctly if it provided the output signal
for the trip coil when expected. Hence the trip coil should be excluded from the new protection system definition.
3. Performance based maintenance as specified in the attachment is extremely difficult and cumbersome to navigate. The intricate
requirements are difficult to comprehend and will entrap entities making a good faith effort to comply. We believe this approach
may become burdened with undesirable consequences.
4. Last but not least, Austin Energy believes that under-frequency load shedding (UFLS) and under-voltage load shedding (UVLS)
systems should not be included in the scope of this new proposal. UFLS and UVLS are a wholly different entity as compared to
the Bulk Electric System (BES). Rigidity imposed onto distribution system equipment, operating schemes and performance is
uncalled for and overreaching.
Response: The SDT thanks you for your comments.
1. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
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observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to implement an
effective PSMP. To minimize system impact of such maintenance and possible errors, the maintenance necessarily should be scheduled at a time that
minimizes the risks.
2. The SDT contends that the trip coil itself is an integral and essential component of the station control circuitry and it must be assured that the trip coil
operates. The SDT has also been diligent in excluding any facets of the breaker mechanism from consideration.
3. If an entity considers that a PBM would be difficult to implement, they may choose to implement simple time-based maintenance (Table 1a) and/or
condition-based maintenance (Tables 1b and Table 1c). This option is provided for those who elect to take advantage of the opportunities presented.
4. The four legacy standards are combined here in response to several suggestions, including from FERC Order 693 because of substantial equipment
similarities. The SDT disagrees that the requirements for UFLS and UVLS are “uncalled for and overreaching”, and has specified less stringent
requirements for these devices.
Progress Energy
Comments:
1- Requirement R4 “Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, including
identification of the resolution of all maintenance correctible issues as follows: “ Based on the definition provided (A maintenance
correctable issue is a failure of a device to operate within design parameters that can be restored to functional order by calibration,
repair or replacement.) Pr ogress Energy believes that this will become a potential tracking issue. To maintain all of the data
required to meet this definition can be onerous.
2- The biggest concern with the proposed PRC is that for many entities, the proposed maintenance and intervals will greatly
increase the entities workloads. There are not enough relay technicians available to handle this increased workload across the
country.
3- The Implementation Plan for R2, R3, and R4 identified in the Draft Implementation Plan for PRC-005-02, dated July 21, 2009, is
very reasonable. This plan recognizes that it is unrealistic to expect entities that are presently using intervals that exceed the
maximum allowable intervals to immediately be in compliance with the new intervals. It allows implementation to be implemented
across the maximum allowable interval. This is a reasonable approach for the following reasons:
a. Sufficient resources are not available to perform the additional maintenance proposed on an accelerated basis.
b. It allows the staggering of the PMs so that resource loading can be balanced. Without the ability to stagger the PMs, there
would be an initial “bow-wave” of PMs and future “bow-waves” each time the interval is up.
4- The Implementation Plan for R1 identified in the Draft Implementation Plan for PRC-005-02, dated July 21, 2009, is not
reasonable. The implementation plan requires entities to be 100% compliant three months following approval of the PRC. This is
not a reasonable timeframe given the program changes required, including:
a. A massive effort to review circuit schematics to determine whether equipment meets the definition of partial-monitored or
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unmonitored.
b. Many procedures, basis documents, and job plans will need to be revised or created.
c. The work management tool will have to be modified to reflect the new intervals.
5- PRC-008-1 placed only the relays associated with UFLS in the compliance program. Contrary to PRC-008-1, the draft PRC005-02 places all components (relays, instrument transformers, dc supply, breaker trip paths) in the compliance program. This
forces much of the distribution-level components to be placed in the compliance program.
6- The response to Item 2A of the FAQ Document, page 17, seems to indicate that commissioning test results do not have to be
captured as the initial test record, only the in-service date. Is this a correct interpretation of the response?
7- Table 1a (Unmonitored Protection Systems) seems to indicate that a complete functional trip test must be performed for the
UFLS/UVLS protection system control circuitry. This wording is identical with the wording for the protection system control
circuitry (except UFLS/UVLS) table entry. This implies that UFLS/UVLS functional testing should include tripping of the feeder
breakers for these unmonitored systems. Table 1b (Partially-Monitored Protection Systems) indicates that actual tripping of circuit
breakers is not required under the UFLS/UVLS control circuit functional testing. Is this because trip coil continuity is being
monitored and alarmed under Level 2 Monitoring? Must feeder breakers be tripped during the functional testing if the trip coil
continuity is not monitored and alarmed (unmonitored protection system)?
8- All standards to be retired should be specifically listed in the Implementation Plan.
Response: The SDT thanks you for your comments.
1. Requirement R4.3 has been added to the standard to address some of these concerns. It reads as follows:
R4.
Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, including identification of the resolution of
all maintenance correctable issues as follows:
4.3.
Assure either that the components are within acceptable parameters at the conclusion of the maintenance activities or initiate any
necessary activities to correct unresolved maintenance correctable issues.
2. The SDT understands that workloads may increase. However, with increasing sensitivity to degraded system performance, the increased attention to
Protection System maintenance is critical to BES reliability. NERC’s analysis of major system events reveals that Protection System maintenance is a
contributing factor to many major system problems.
3. The SDT appreciates that you recognize these issues which were central in developing the Implementation Plan.
4. Table 1a provides activities and intervals for components for which Level 2 or Level 3 maintenance cannot be fully justified. Additionally, considerable
time can transpire between successful balloting and regulatory approvals and major elements of the standard will be largely established even well before
balloting. Entities are encouraged to proactively begin making the necessary program adjustments.
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5. PRC-008 currently addresses “UFLS equipment” which is a bit vague. Arguably, the identified components within PRC-005-2 may be regarded as various
portions of “UFLS equipment”. The SDT contends that the indicated activities are necessary, and notes that some of the activities are less stringent than
for other Protection System components.
6. FAQ IV-2-A, page 22) now indicates that commissioning records are one option to establish the start date of maintenance intervals, and to establish the
baseline.
7. The Tables have modified to clarify that actual tripping of the breakers is not required for Protection System control circuitry for UFLS/UVLS only.
8. The SDT agrees. The Implementation Plan will be modified to indicate retirement of the four legacy standards upon the completion of the
Implementation Plan.
Nebraska Public Power District
Definition of Terms:
1. Footnote 2 for R4 defines a "maintenance correctable issue". This should be added to the Definition of Terms section.
2. Sections 4.2.5.4 and 4.2.5.5 inappropriately extend Generator Protection Systems to Station Service Transformers. These are
components necessary for plant operation however they are not part of the generator protection scheme. This conclusion is
supported by the explanations on page 16 of the FAQ.
3. The FAQ states the operation of the listed station auxiliary transforms protective relays would result in the trip of the generating
unit and, as such, would be included in the program. The FAQ goes on to state that relays which trip breakers serving station
auxiliary loads such as pumps, fans, or fuel handling equipment, etc., need not be included in the program even if the loss of
those loads could result in a trip of the generating unit. The FAQ appears to be inconsistent. Station auxiliary transformers are
included because they would result in the trip of the generating unit while other loads such as pumps, fans, etc., are excluded
even if their trip could result in a trip of the generating unit. In my opinion, the station service transformers like pumps, fans, etc.
are components necessary for plant operation but not necessary for generator protection and should therefore be excluded from
PRC-005-2 by removing Sections 4.2.5.4 and 4.2.5.5 from the standard and modifying the FAQ accordingly.
4. R1 (1.1) First sentence: "For each component used in each Protection System..." is ambiguous. The sentence should be
revised to say..."For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, and 1c."
This limits the components to only those identified by the definition of a Protection System.
5. R2 End of sentence: "possess the necessary monitoring attributes." is ambiguous. The sentence should be revised to
say..."possess the monitoring attributes identified in Tables 1b or 1c." This specifically defines which attributes are necessary.
6. R4 I am concerned with including the phrase "including identification of the resolution of all maintenance correctible issues".
Providing evidence of implementation of the PSMP will require the collection and submittal of all work documents that restored a
device to functional order by calibration, repair, or replacement. It is reasonable to assume that appropriate corrective actions
were taken for each specific situation. Identification of the resolution will add a significant documentation burden without adding to
the reliability of the BES. Implementation of the PSMP may be evidenced without including identification of the resolution of all
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maintenance correctible issues. It is interesting to note that nowhere in PRC-005-2 does it state that you have to take corrective
actions to return a component to normal operating conditions. "No action taken" can be the resolution taken by the utility of a
maintenance correctible issue.
Response: The SDT thanks you for your comments.
1. Establishing this term within the “Definition of Terms” would add this to the NERC Glossary. Instead, the SDT believes that this term is relevant only to
this Standard, and that establishing it in the Glossary of Terms rather than simply as a term within this standard would expose entities to potential
compliance exposure by having to refer to the Glossary to implement the standard.
2. Station service transformers are system components and the Protection Systems on those system components must be maintained as indicated in this
standard. (See FAQ III-2-A, page 20)
3. Many of the components (pumps, fans, etc) are redundant, and a plant may be able to withstand loss of one of these. However, the loss of the station
service transformer will result in simultaneous loss of many such elements, and will result in immediate plant shutdown. Also, the station service
transformers may be necessary to achieve an orderly plant shutdown, and the loss of a station service transformer may result in a more abrupt plant
shutdown. Improper Protection System performance due to maintenance issues must not be the cause of such an event. (See FAQ III-2-A, page 20)
4. The SDT has modified the standard in consideration of your comment. The original Part 1.1 was replaced with a new Part 1.1 and a new Part 1.3 was
added as shown below,
1.1. Identify all Protection System components.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
per Requirement 1, Part 1.2.
4. The SDT has modified the standard in consideration of your comment. The requirement was modified to read as follows:
R2.
Each Transmission Owner, Generator Owner, and Distribution Provider that uses condition-based maintenance intervals in its PSMP for
partially or fully monitored Protection Systems shall ensure the components to which the condition-based criteria are applied, possess the
monitoring attributes identified in Tables 1b or 1c.
6. A fundamental tenet of compliance is that “if it’s not documented, it’s not done.” Therefore, the documentation you describe will likely be necessary to
demonstrate compliance. The PSMP definition, the new R4.3, and the General Requirements of each Table all establish that maintenance-correctable
issues need to be resolved. If there is a maintenance-correctable issue, “no action taken” does not seem to be an acceptable response.
Florida Municipal Power Agency,
and its Member Cities
1. Facilities applicability 4.2.2, due to the changes in applicability of the draft PRC-006, ought to refer say something like UFLS
which are installed per requirements of PRC-006 rather than per ERO requirements.
2. In requirement R1, bullet 1.1 ought to state “For each component used in each Protection System, include all “applicable”
maintenance activities specified in Tables 1a, 1b and 1c”. For instance, if every component has continuous monitoring, why
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should the program include 1a and 1b?
Response: The SDT thanks you for your comments.
1. The existing PRC-006 establishes that entities install UFLS in accordance with Regional requirements (which, by extension, are ERO requirements). In
accordance with FERC Order 693, PRC-006 is currently undergoing revision to be a continent-wide standard, in which case it will itself be an ERO
requirement. Clause 4.2.2 applies equally to either situation.
2. Requirement R1has been modified in consideration of your comment. The original Part 1.1 was replaced with a new Part 1.1 and a new Part 1.3 was
added as shown below,
1.1. Identify all Protection System components.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
per Requirement 1, Part 1.2.
American Transmission
Company
1. General Comment: The requirements section of the standard seems acceptable.
2. NOTE: Why does R1.3 identify the inclusion of batteries? We believe that this should be part of the definition.
3. We believe that the team needs to define the term “condition-based”.
4. Does the Protection System definition in PRC-005-2 or interpretation of the standard and the tables line up with other NERC
Standards?
5. The table formats (1a through 1b) are confusing and should be reconsidered. We found is difficult to relate one table to
another. (No consistency in the Type of components)
Response: The SDT thanks you for your comments.
1. The SDT thanks you for your support.
2. R1.3 specifies that batteries can be tested ONLY via TBM. That is the intent of the requirement. In the Protection System Maintenance – Frequently
Asked Questions (FAQ) document (FAQ IV-3-G, page 26.) which accompanied the standard and in the Supplementary Reference Document, Section 15.4
(page 23), the SDT explains why batteries are excluded from PBM and the standard should include all batteries associated with a Protection System in a
time-based program.
3. The SDT declines to introduce a defined term for this. Table 1b and Table 1c identify condition-based maintenance to include consideration of the known
condition of the component within condition-based maintenance. The Supplemental Reference Document, Section 6 (page 8) and the FAQ (V-3, page 38
and V-4, page 39) also describe condition-based maintenance considerations.
4. The SDT was required to investigate all uses of this defined term with NERC standards and assure that these changes are consistent with the other
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applications.
5. The SDT has modified to Tables to make them more consistent with each other.
CPS Energy
Have several comments and questions:
1. I think that the way that the tables are done is confusing. My biggest complaint is that the "breakdown" of the Type of
Component varies between the tables. For example, in tables 1a and 1B, you have Protective Relays, but in table 1c, you have
Protective Relays and Protective Relays with trip contacts. This is a little confusing at times.
2. I also find the UFLS/UVLS requirements confusing as well. It can be confusing to figure out when the UFLS/UVLS has a
separate requirement. Would prefer to see the UVLS/UFLS in separate tables; e.g. 2a, 2b, 2c.
3. SPCTF should provide the basis for how the intervals in table 1 were derived. While the supplemental describes that a survey
of its members with a weighted average was used to determine the maintenance intervals. However, what is not clear is what
exactly was surveyed in terms of components. Was it just relay calibration testing? Functional testing? What about
communications, voltage and current sensing devices, trip coils, etc? Was UVLS and UFLS looked at separately from
transmission? Was generation also considered as well? Why did values change from the SPCTF technical reference "Relay
Maintenance Technical Reference" dated September 13, 2007? For example, UVLS/UFLS testing and calibration went from 10
years to 6 years for un-monitored, communications went from 6 months to 3 months for un-monitored, and instrument transformer
testing went from 7 years to 12 years for un-monitored systems. What is the basis for the intervals?
4. The committee should reconsider the use of the term "A/D converters". The point of the requirement is to assure that the
analog signal from the instrument transformer is correct to the processor. Two problems with just saying "A/D converters". One, it
ignores the digital relay input transformers of microprocessor relays. The SEL-4000 test set can bypass these transformers.
Would using this test set be adequate to test the "A/D converters"? Two, some relays, such as the SEL-311L, perform an A/D
self-test. I do not think that the A/D self-test performs the testing that is being sought by the document.
5. Could a better example of "Calendar Year" be provided? Is it simply the years difference, or should the days be included as
well? In your example in the reference document, you show that December 15, 2008 and December 31, 2014 as meeting the
requirement of 6 calendar years. Would like to see a more exaggerated example. Would an unmonitored protective relay is
calibrated on January 1, 2008 and then again on December 31, 2014 meet the "Maximum Maintenance Interval" of "6 Calendar
Years"?
6. Does the standard address breakers and other switching devices that do not have "trip coils". Magnetic actuated circuit
breakers, reclosers, and possibly other devices do not have trip coils to monitor or test. Do the trip coil testing and requirements
fully take this account? If a breaker does not have a trip coil, is some other type of test required? Does not having a trip coil
prevent extending the Protection System Control Circuitry interval to 12 years?
7. The requirement for testing Voltage and Current Sensing devices should be better thought out as to what is trying to be
accomplished. On page 11 of the reference document, item 6 under "Additional Notes for Table” it states that "phase value and
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phase relationships are both equally important to prove". In both the FAQ document (page 6, 3A) and the reference document
(page 21, 15.2), several methods to verify the voltage and current sensing inputs to the protective relays and satisfy the
requirement are given. However, these methods do not all seem to verify the same thing. Totalizing watts and vars on the bus
verifies that the current transformers are correctly and providing correct signals to the relays, but do not necessarily verify that the
voltage sensing device is necessarily correct if the same PT is used for all relays on the bus. Performing a saturation test on a CT
and a ratio test on the PT does not verify the phase angle relationships, which is stated as important on page 11 of the reference
document. What exactly needs to be accomplished by the Voltage and Current Sensing devices testing? That an analog signal is
getting from the instrument transformer to the device? That the signal is an accurate representation of the measured quantity?
What about frequency for UFLS relays, where voltage magnitude may not be that important? Do CT's need to be verified for
multiple CT grounds? Do the any examples described necessarily find multiple ct grounds?
8. This standard should also address the ramifications of RRO's not allowing for equipment to be removed from service for
testing. Either RRO's should be required to allow outages in some time frame or leeway should be given to entities that cannot
get equipment out for maintenance because RRO's will not grant reasonable outage times for testing and maintenance.
9. Page 13 of the reference document states that the 3-month inspection should include checking that "equipment is free of
alarms, check any metered signal levels, and that power is still applied." What is meant by "metered signal levels"? What does
the term "metered" mean, specifically in terms of an on-off power line carrier scheme?
10. It appears that if a company on a TBM plan has shorter intervals than the maximum allowable of this proposed standard, the
company would not be in violation if they did not meet their own plan but still met the intervals required by this proposed standard.
Is this true? Could this actually reduce reliability of the BES if companies are now allowed to extend intervals to those listed in this
document without any justification?
Response: The SDT thanks you for your comments.
1. The SDT has modified to Tables to make them more consistent with each other.
2. Many of the components of UFLS and UVLS are very similar to other generic Protection System components, with similar maintenance activities. The
SDT has modified the Tables to clarify activities which apply specifically to UFLS and/or UVLS.
3. The SPCTF, in an earlier technical paper, provided descriptions of the derivation of the intervals, but this technical paper was not charged with
developing a measurable standard. The SDT has used this information, as well as consideration of system and generation plant operating constraints,
EPRI reports, IEEE surveys, and experience of SDT members and others, to develop the intervals in the tables. These intervals were also adjusted to
address the SPCTF’s recommendations about grace periods without providing grace periods. The SDT also considered intervals that supported
establishment of systemic maintenance programs.
4. The SDT modified the standard in consideration of your comment. A/D converters are now discussed only in the Monitoring Attributes within Table 1c;
otherwise, the relay must be confirmed to operate properly. However, the SDT did NOT define methodology.
5. Disregard the complete date and just look at the year portion. For a 6 calendar-year interval, if the test date was IN 2004, the next test date must be IN or
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before 2010.
6. Where relevant to the requirements of the standard, any of these devices apply similarly. Many of the alternate technologies mentioned do not seem
relevant to BES Protection Systems, but instead to UFLS and/or UVLS systems. The required maintenance activities for these components do not require
actual test tripping.
7. No single method of verification may be relevant for every imaginable situation. The activities relevant to Voltage and Current Sensing Devices have
been revised in consideration of your comment.
8. Some entities may need to perform certain maintenance activities more frequently to assure that the activities are performed within the required
intervals. Allowing a “grace period” would create a standard that is not measurable. Please refer to Section 8 of the Supplementary Reference Document
(page 9) for a discussion on this issue. Outages must be planned in accordance the Reliability Coordinators (RRO’s, or RE’s, have no role in this) to
support reliable system operation.
9. “Metered signal levels” refer to the communication signal levels which are part of proper communications system function for certain equipment, such
as power-line carrier systems. The SDT is continuing to align the three documents (Standard, Supplemental Reference, and FAQ) to assure consistency.
10. You will be held to compliance with your plan, whatever it is, under R4, but your plan must also adhere to the intervals established by NERC. As long
as you still have elements subject to PRC-005-1, you need to comply with the program established for PRC-005-1. When you have fully implemented PRC005-2, the requirements of PRC-005-1 no longer apply. However, the SDT hopes that entities that feel that a shorter interval is appropriate will continue to
use that interval.
JEA
1. Implementation Plan - Strongly encourage keeping the implementation plan and allow for an extension of the implementation
plan for the time required to fund, design, procure, install and commission redundant protection systems for current non-redundant
lockout systems at the lower kV levels of the BES.
2. Our present and past performance of LOR and auxiliary relays will support a PBM/CBM program that allows for a much longer
time than the six years proposed for EM LOR trip testing. To use a TBM for LORs of six years, may in fact, lower the reliability of
the BES due to the complete outages required, along with the detailed procedures that must be created and rigorously followed to
perform these tests without subsequent load loss on the BES.
Response: The SDT thanks you for your comments.
1. If an entity expects to encounter difficulty in performing the maintenance specified in the standard, the SDT encourages them to begin implementation of
the necessary features to support maintenance while the standard is still in a development or approval stage.
2. The SDT encourages you to begin assembling the documentation necessary to support a PBM for these components such that you may implement that
PBM when the standard becomes effective.
Consumers Energy Company
June 3, 2010
1. In Table 1a for Station dc supply it requires verification that no dc supply grounds are present. DC grounds are common
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occurrences and the activity should be to document if dc grounds are present.
2. Please specify how cell to cell connection resistance is measured.
3. For station dc supply (battery is not used) change “Verify the continuity of all circuit connections that can be affected by wear
and corrosion” to “Inspect all circuit connections that can be affected by wear and corrosion.”
4. Is “metered and monitored” equivalent to “alarming”?
5. If a component failure causes the unit to trip, what is the purpose of testing it? It will always test positive until the point of failure
and that point is identified when the unit trips.
6. In the Facilities Section 4.2.5.4 “station service transformer” should be changed to “unit connected auxiliary transformer” to be
consistent with Figure 2 of the Supplement Reference Document.
7. Facilities Section 4.2.5.5 should also include “System connected auxiliary transformers are excluded when only used for unit
start-up.”
8. There should be an allow variance period (grace period) for the testing intervals.
9. The maximum allowable time periods should be in calendar years, defined as “occurring anytime during the calendar year.”
10. The following statement should be added to Requirement 1.2: “Identification at a program level is permissible if all components
use the same maintenance method.”
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comments concerning dc grounds – the maintenance activity was revised to read, ‘Check for
unintentional grounds.”
2. The IEEE Standards 1188 and 450 have very detailed descriptions of how to measure cell to cell connection resistance using a Micro-Ohm Meter.
3. Upon consideration of your comment, the SDT determined that it is important to both “check the continuity” and to verify the physical condition.
Therefore, the standard has been modified to include both.
4. Not necessarily. “Metered and monitored” are more detailed than “alarming”. Alarms simply report an abnormal condition, while “metered and
monitored” will probably actually report values.
5. In this case, testing of the component should assure that the component functions properly and thus does NOT result in an unintended trip of its system
component, and that it WILL trip when called upon to do so.
6. The SDT contends that “station service transformer” is a more universal description for this component. The Supplemental Reference Document has
been modified for consistency.
7. The SDT contends that “startup transformer” Protection Systems also need to be maintained per PRC-005-2. During startup, these components are
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critical for reliability. On the other hand, maintenance of the Protection Systems on these system elements should be somewhat easier to schedule.
8. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be numerous
opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with shorter
intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance can be done
on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals
would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace
period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a discussion on this issue.
9. All multi-year periods ARE in calendar years. There are other essential shorter intervals, and the SDT does not agree that these can be extended to a
minimum of one calendar year – most of these activities are “inspection” type activities. The SDT does not believe that it is necessary to define this term;
“Calendar year” seems to be a very precise term in itself.
10. To the degree that you can concisely describe your program this way, and demonstrate implementation of your program, it does not seem to the SDT
that this modification to the requirement is necessary.
ITC Holdings
1. In the Definitions of Terms, the Protection System (modification) should include control circuits up to and including the trip coil
of ground switches used in protection schemes.
2. Footnote 2 (Maintenance correctable issue) should be included in the Definition of Terms in the body of the standard.
Response: The SDT thanks you for your comments.
1. To the degree that the ground switch (or, more properly, the Protection System that operates the ground switch) is protecting a BES element, the SDT
classifies the ground switch as an interrupting device.
2. Establishing this term within the “Definition of Terms” would add this to the NERC Glossary. Instead, the SDT believes that this term is relevant only to
this standard, and that establishing it in the Glossary of Terms rather than simply as a term within this standard would expose entities to potential
compliance exposure by having to refer to the Glossary to implement the standard.
Entergy Services, Inc
1. It would be beneficial to also include an explanation or definition of the term “calendar year” in the standard. It is not readily
apparent in the draft standard, especially in light of the new maximum interval requirements, that a task can be performed anytime
between 1/1 and 12/31.
2. Although addressed in the FAQ and Supplement, the terms “Upkeep” and “Restoration” are referenced in the definitions section
of the standard but are not used anywhere else in the document, or with regard to routine activities. They should be eliminated
from the standard unless there are upkeep or restoration requirements.
Response: The SDT thanks you for your comments.
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1. Disregard the complete date and just look at the year portion. For a 6-calendar-year interval, if the test date was IN 2004, the next test date must be IN
2010.
2. While “upkeep” is not used in the standard, the SDT has identified the term as a component of maintenance. “Restoration” is used in R4.3 and within
the header of each Table.
AEP
1. Monitoring and tracking the activities prescribed in the standard seem too complex to manage at a level needed for auditable
compliance. The activities prescribed seem to lean toward conventional protection systems and do not take into account newer
special technology devices (High Voltage DC, Static Var Compensator and Phase Shifting transformer controls) and how there
are to included.
2. R1 1.2 Does the draft standard require a basis for an entities” defined time based maintenance intervals or can an entity just
move directly to the intervals prescribed and use the standard as its basis”
3. R4. This requirement seems to refer to failed equipment and its reporting. This corrective maintenance activity is outside of the
interpreted preventative maintenance theme of the standard and adds another layer of complexity in compliance data retention. It
also implies that a failed piece of equipment or segment could remain failed for the entire maintenance interval.
4a.Tables 1a & 1b. Station dc supply (that has as a component any type of battery) Interval: 18 months - This requirement
incorporates specific gravity testing (where applicable). Although (where applicable) is not defined, it seems it refers to all nonsealed batteries.
4b. For sealed batteries, a more frequent internal ohmic test is prescribed. The same 18 month requirement incorporates ohmic
testing which is essentially equivalent to specific gravity. Specific gravity and measure of internal temperature are invasive tests
which subject personnel to handling acid and subject the battery to damage. If the logic for sealed batteries is to do more frequent
ohmic testing why not allow more frequent ohmic testing as a substitute for specific gravity? We would suggest ohmic testing
every 6 months with any questionable results rechecked using specific gravity. This eliminates excessive intervention into all cells
and gives a validity check on the ohmic testing.
4c.For Ni-Cad the performance service test has no option (6 year intervals). Typically, the Ni-Cad can yield a low voltage
indication; however testing the cells in pairs allows testing and finding bad cells. Why not offer a more frequent ohmic test for the
Ni-Cads?
5. Facilities 4.2.1 and R1. “applied on, or are designed to provide protection for the BES.” This may be in conflict with Regional
Entity (RE) BES definitions. There needs to a clear understanding of what is included and what is not without regional differences.
There should be no responsibilities or requirements of the RE. BES also takes on different meanings depending upon which of
the many standards it is applied. Data Retention 1.4 Data retention for two intervals could mean that records would need to be
kept for 24 years. This seems impractical. Could audit evidence be used in lieu of actual data for long intervals?
6. Tables: Where the interval is in months, the term “calendar” months should be used for clarification.
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7. Table 1a:“verify the continuity of the breaker trip coil”. The SDT assumed that Trip Coil Monitoring (TCM) could be
accomplished by verifying/inspecting red lights. This may be true in most cases, but there are designs that do not incorporate this
type of TCM and the breaker would have to be exercised every 3 months if not operated by natural events unless the scheme gets
replaced. This seems counterproductive to the reliability of the BES. The implementation plan does not take the time required for
upgraded systems into consideration.
8. Table 1a DC Supply, 3 month interval “Verify no dc supply grounds are present.” Does this mean that you are non-compliant if
you have a DC ground? This also needs to be clarified as to the amount of acceptable ground that could be present. Table 1a PS
communications equipment channels 3 month interval: Do the activities imply that only alarms be verified and that no channel
“playback” be performed?
9. If SPR relay or similar auxiliary relay is excluded as a protective relay, then do we not have to verify its tripping contact as part
of the DC system?
10. Table 1a The exclusion of UVLS/UFLS from certain activities is confusing. Does trip coil monitoring not have to be performed
on these systems?
Tables:
11. Since PT and CT devices themselves are not included in the PS definition, then the word “devices” should be removed from
the type of component column describing inputs to the relay.
12. Table 1a. Even though an entity may be on time-based intervals, would a natural occurring fault event reset the maintenance
clock for the protection segment involved?
13. Assessment of Impact of Proposed Modification to the Definition of Protection System: Reclosing and certain auxiliary relays
have been excluded from protection system definition. This new definition would have an impact on other PRC standards that use
this term in its requirements, specifically the Misoperations investigation and reporting standards. These other standards, as
written today, are not clearly written as to the application and assumptions as to what is included in a protection system.
14. Trip coil Monitoring: If the trip coil is actually part of the DC circuitry, then why is there a differing (shorter) interval for this
series connected element?
Response: The SDT thanks you for your comments.
1. The SDT invites additional participation to address such devices.
2. There is no additional basis required for an entity to adopt the maximum allowable intervals established within the standard.
3. The SDT has modified the standard to require that an entity also initiate correction of maintenance-correctable issues. There is no time-period specified
for actually correcting maintenance-correctable issues in recognition of the wide variety of activities that may be represented.
4a. The SDT has modified the standard in consideration of your comments concerning specific gravity not being applicable to non-sealed batteries. The
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maintenance activities no longer include any reference to specific gravity.
4b. The SDT has modified the standard in consideration of your comments concerning specific gravity and internal temperature. The maintenance activity
associated with specific gravity and internal temperature was removed from the revised standard.
4c. Presently there are no other options that are available today to verify that a Ni-Cad battery can perform as designed.
5. NERC standards establish minimum requirements, which can be expanded on by Regional Entities. This standard does NOT place any requirements
upon the Regional Entity. BES is a defined NERC and Regional Entity term which applies uniformly to the various standards. The Records Retention
section has been modified to read as follows:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation of the two most recent performances of each
distinct maintenance activity for the Protection System components, or to the previous on-site audit date, whichever is longer.
6. The SDT has modified the standard in consideration of your comment and the word, “Calendar” was added to clarify that the term “months” means
“calendar months”
7. The SDT has removed the cited requirement.
8. The SDT has modified the standard in consideration of your comments concerning dc grounds (changed to “Check for unintentional grounds” and
compliance FAQ II-5-I, (page 15) explains that the entity is responsible to determine if corrective actions are needed upon detection of unintentional dc
grounds.
9. Yes.
10. The Tables have been modified to better delineate the specific activities related to components associated with UFLS/UVLS relays.
11. The definition has been further modified to add these devices.
12. Only to the degree that the Protection System operation for the natural fault verified the functions and “performed” the activities within the Table. See
FAQ II-4-C, page 10 and Supplementary Reference Document, Section 15.3, page 22.
13. The SDT, in accordance with the NERC Standard Development Procedure, analyzed all other uses of the defined term, “Protection System” within the
NERC standards, and, in a document which was posted with the standard and other associated documents during the comment period, listed all other uses
and concluded that there is no impact on the other uses. Reclosing relays are still not listed in the definition, but auxiliary relays, which previously were
not listed and now are, were implicit in the previous “dc control circuits”.
14. The Tables have been modified to remove this shorter-interval specific activity.
Green Country Energy LLC
None
Georgia System Operations
Corporation
None.
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Operations and Maintenance
None.
ENOSERV
On Table 1A, the maximum time lengths are too long, especially for electro relays. A prime example is when testing a KD relay on
a yearly basis and most of the time needs to be adjusted because of how far off it comes out. Allowing entities to take their time up
to six calendar years may be too long.
Response: The SDT thanks you for your comments. See the Supplementary Reference Document, Section 5.1, page 7.
Xcel Energy
Please clarify if the following are subject to PRC-005-2 requirements:
1) a battery that is in a station where the only BES element is a UFLS scheme
2) batteries used only to support communication elements (microwave houses)
Response: The SDT thanks you for your comments.
1) The SDT has modified the standard to clarify that the only DC Supply maintenance activity relevant to UFLS is to verify the DC supply voltage.
2) The proper functioning of such batteries (communication system) will be addressed by the verification and monitoring of the communications system,
and by addressing maintenance correctable issues related to the communications system. See FAQ II-5-K, page 15.
BGE
1. PRC-005-2R1 1.2
Identify whether each Protection System component is addressed through time-based, conditionbased, performance-based, or a combination of these maintenance methods and identify the associated maintenance interval.
Comment:
The existing standard PRC-005-1 requirement R1.1 says a maintenance program must include the maintenance
and testing intervals and their basis. PRC-005-2 does not have a similar requirement, and the associated FAQ indicates the
standard “establishes the time-basis for a Protection System Maintenance Program to a level of detail not previously required”.
Does PRC-005-2 require evidence to support the basis for a defined maintenance interval, or is the basis now purely defined by
PRC-005-2?
2. R2
Each transmission owner .......shall ensure the components to which condition-based criteria are applied....possess the
necessary monitoring attributes? Comment: Depending on the evidence requirements that are enforced this could be a very large
undertaking offsetting the benefit of extending intervals with CBM. It would be helpful to understand what the drafting team or
other stakeholders would envision as appropriate evidence supporting this requirement.
3. R4 Each transmission owner .......shall implement its PSMP, including the identification of the resolution of all maintenance
correctable issues as follows :4.1 ....within the maximum allowable intervals not to exceed those established in table 1a, 1b, 1c
Comment: It’s inferred that this requirement applies to maintenance correctable issues that are discovered as a consequence of
scheduled maintenance and not as a consequence of monitoring or misoperations. If that inference is incorrect the requirement
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imposes an unequal playing field for the resolution of known correctable issues depending on the monitoring being employed, not
to mention an unreasonably long allowance for the correction of some serious problems. On the other hand, the requirement
imposes an unreasonably short period of time for the resolution of some issues that may be associated with short interval
maintenance/inspection intervals, such as battery grounds.
4. Section D1.4 Data Retention? The Transmission Owner shall...retain documentation for two maintenance intervals....
Comment: Recognizing that in order to achieve compliance PS owners will execute scheduled maintenance on shorter intervals
than the maximum requirement it’s uncertain what this means. Example: Max interval for instrument transformers is 12 years, we
maintain every six. Is the requirement for 24 years of data or 12? It seems like there ought to be an upper limit. 24 years is a very
long time. Table 1a Protection System Control Circuitry (Breaker trip coil only); 3 month maximum interval; verify the
continuity....of the trip circuit.....except for breakers that remain open for the entire maintenance interval. Comments: What’s the
failure-probability justification for this requirement when other similar dc control components have a maximum interval of 6 years?
It seems like the SDT made an assumption that all trip coils are monitored by red lights and could be verified by inspection and
said somewhat arbitrarily, “do it because you can”. “Remaining open for the entire maintenance interval” is a poorly reasoned
effort to arrive at a necessary exception. Even if the red-light-through-the-trip-coil assumption is accurate for a normally open
breaker, it’s unreasonable to demand that an inspection take place if it’s closed at anytime during the interval. The actual time that
its closed might be seconds or a few minutes, but that time would make the exception moot and put the owner out of compliance.
On the subject of three month maximum intervals in general: One can agree that three months is about the right time for some of
these inspections, batteries in particular. However as written, three months and a day is “out of compliance”. More flexibility would
avoid a lot of meaningless “technical fouls”. How about four times a year not more than four months between each...or something
like that.
5. Table 1aStation DC supply (that has as a component any type of battery); verify that no dc supply grounds are present?
Comment: All grounds are not created equal. No guidance for acceptance criteria is given, nor is evaluation/acceptance criteria
explicitly made the responsibility of the battery owner (as it is for relay calibration). Without any guidance the requirement of “no”
grounds is open to unreasonable interpretation (there is always a ground if one considers a high enough resistance) and high
impedance grounds that do not present a risk to the PS will consume effort and attention unnecessarily.
6. Station DC supply (that has as a component any type of battery); Measure to verify that the specific gravity and temperature of
each cell is within tolerance?
Comment: It is not clear that a specific gravity test provides any better data concerning battery health than an impedance test, but
specific gravity testing is a requirement. Can the impedance test be performed as routine maintenance in lieu of a specific gravity
test?
7. General Comment: It is not clear whether Communications batteries should be held to the same testing/maintenance
requirements as the station battery. Communications batteries are in place to supply relatively low power electronic equipment
and do not have to provide energy to trip a breaker. Simple monitoring of the channel may be sufficient to assure battery
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availability, and a less rigorous maintenance plan may be appropriate based on the continuous monitoring and low duty of the
battery.
8. FAQ Group by Monitoring Level A level 2 (partially) monitored Protection System or an individual component of a level 2
monitored Protection System has monitoring and Alarm circuits on the Protection System components. The alarm circuits must
alert a 24-hour staffed operations center.
Comment: The standard Table 1b, General Description for Level 2 monitoring is simply described as Protection System
components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
alarmed features. This appears to be a conflict between the FAQ and the standard. The more stringent requirement of the FAQ,
for the reporting facility to be manned 24 hours per day, could be read to imply a requirement for a specific time to respond to an
alarm. Is there such a requirement? Is there an implied requirement to document the alarm condition and the response time?
Response: The SDT thanks you for your comments.
1. If a time-based or condition-based program is used according to Tables 1a, 1b, and 1c, no additional basis is needed. If the entity elects to use
Performance-based maintenance, the activities in Attachment A must be used to establish the related basis.
2. See FAQ V-1-D, page 22 for a discussion relevant to your comment.
3. The SDT has modified the standard in consideration of your concern concerning the interval of checking for unintentional dc grounds and the ability to
remove the unintentional ground from the dc system. R4 of The SDT has modified the standard to require initiation of the resolution of maintenancecorrectable issues, rather than to identify their resolution. See FAQ II-5-I, page 15.
4. The data retention section has been modified to read as follows: The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for the Protection System components, or to the previous on-site audit date,
whichever is longer.
5. Both the standard and FAQ document have been modified in consideration of your comments concerning dc grounds to specify that it is up to the owner
to determine if corrective actions are needed for unintentional dc grounds. See FAQ II-5-I, page 15.
6. The standard has been revised to remove maintenance activities related to specific gravity.
7. Communication system batteries are not included in the requirements for “Station Batteries”. The entity must ensure proper operation of the relay
communications circuit which would include adequate maintenance of the equipment including the communication system batteries The proper
functioning of such batteries (communication system) will be addressed by the verification and monitoring of the communications system, and by
addressing maintenance correctable issues related to the communications system. (See FAQ II-5-K, page 15.)
8. The FAQ has been modified to remove this apparent additional requirement.
Transmission Owner
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a. The PSMP definition would be better defined if the first sentence was changed to “An ongoing program by which Protection
System components are kept in working order and where malfunctioning components are restored to working order.”
b. Please clarify what is meant by “relevant” under the definition of Upkeep. Should “relevant” be changed to “necessary”?
c. The definition of Restoration would also be more explicit if changed to “The actions to return malfunctioning components back to
working order by calibration, repair or replacement.
d. Please clarify the definition of Restoration. For example, if a direct transfer trip system has dual channels for extra security
even though only one channel is required to protect the reliability of the BES and one channel fails, must both be restored to be
compliant?
e. Protection System (modification) “Voltage and current sensing inputs to protective relays” should be changed to “voltage and
current sensors for protective relays.” Voltage and current sensors are components that produce voltage and current inputs to
protective relays.
f. “Auxiliary relays” should be changed to “auxiliary tripping relays” throughout PRC-005-2, FAQ and the Draft Supplementary
Reference.
g. The word “proper” should be removed from the standard. It is ambiguous and should be replaced with a word or words that are
clear and concise.
Response: The SDT thanks you for your comments.
a. The SDT does not believe that the suggested change is substantive, and sees no reason to make it.
b. Some updates may not affect the operation of the device as applied, and therefore are not relevant. “Necessary” would imply an additional level of
review to determine whether the device would operate properly without the updates, while “relevant” simply implies that the update applies to the function.
c. The SDT does not believe that the suggested change is substantive, and sees no reason to make it.
d. The standard establishes that all components need to be fully maintained, and that they will function as designed. The SDT appreciates that some
“restoration” activities may take an extended time to complete, but also contends that restoration to the designed condition is a vital element of
maintenance.
e. The critical task is to verify that the proper representation of the primary current and voltage signals will get to the protective relays. The “Type of
Protection System Component” has been modified in an effort to clarify.
f. “Auxiliary tripping relays” may exclude essential other internal Protection System functions. Therefore, the SDT declines to adopt this suggestion.
g. “Proper”, “working condition”, “correct”, etc, are all somewhat subjective terms that address the application-specific requirements related to the specific
use. For example, one entity’s design standards may require that an electromechanical relay be within a 2% tolerance of the ideal operating
characteristics, while another may only require that it be within 5%. Each of these is proper, correct, etc, for the application.
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Ohio Valley Electric Corp.
Question 10 Comment
1. R1.2 seems to require owners to establish there own intervals and basis. Compliance with these requirements should be
based on the intervals that are in tables 1a, 1b and 1c.
2. R4 implies that all maintenance correctible issues must be resolved within the Maintenance Activity Intervals. A diligent effort to
restore proper function of a system should not be penalized if it does not fall within the prescribed maintenance interval.
Response: The SDT thanks you for your comments.
The SDT has modified the standard in consideration of your comment. The Parts of Requirement R1 were modified to read as follows:
1.1. Identify all Protection System components.
1.2
Identify whether each Protection System component is addressed through time-based, condition-based, performance-based, or a combination of these
maintenance methods and identify the associated maintenance interval.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
per Requirement 1, Part 1.2.
1.4
Include all batteries associated with a Protection System in a time-based program.
2. The SDT has modified the standard to require INITIATION of resolution, not the actual resolution. The revised footnote reads as follows: A maintenance
correctable issue is a failure of a device to operate within design parameters that can not be restored to functional order by repair or calibration while performing the
initial on-site maintenance activity, and that requires follow-up corrective action.
E.ON U.S.
1. Recently, NERC made an interpretation on PRC-005-1 which stated that battery chargers were not to be included as part of the
standard. This version of the standard seems to be in direct conflict with that interpretation, and for the reasons stated above
E.ON U.S. recommends that battery chargers not be included in the standard. E.ON U.S. believes that capacity or AC impedance
only needs to be done to determine service life, and therefore a periodic testing of station DC supply does not seem necessary or
prudent.
2. Regarding the “Retention of Records”, retaining records of the latest test seems adequate. E.ON U.S. does not understand the
point of retaining records for the past two test results. This is particularly true for equipment for which there are relatively long
testing intervals, for example, 12 years. Retaining result documents from 24 years ago seems unnecessary and impractical.
3. With regard to NERC’s PRC-005-2 Supplementary Reference Section 2.4 on Applicable Relays, E.ON U.S. offers the following
comments:
3.1. This section extends the applicable relay coverage to IEEE type # 86 and IEEE type # 94. Some utilities define their turbine
trip relay as an IEEE type #94. E.ON U.S. interprets that the NERC scope of applicable relays is that the turbine trip relays would
be excluded; however, it would further clarify this exclusion if it were mentioned as an example in the last sentence.
3.2. The Tables in proposed standard PRC-005-2 require additional clarity. E.ON U.S. suggests renaming tables to 1, 2 and 3 to
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match Level 1, 2 and 3 monitoring. The wording and format of text is not consistent between tables.
3.3. The fields in the tables are incoherent. E.ON U.S. interpretation is that intervals and activities for UFLS and UVLS are
different than other relay systems and components, but this is unclear. E.ON U.S. believes a separate table or sections for UFLS
and UVLS would provide more clarity.
4. In section 7 of the Supplementary Reference the SDT refers to the Bulk Power System instead of the Bulk Electric System.
These are not interchangeable and the SDT needs to explain the need to use the term in this case. The phrase “support from
protection equipment manufacturers” is used several times in the technical reference (Section 8 and Section 13) yet there is no
manufacturer represented on the SDT. Rather than developing one size fits all requirements applicable to all equipment, E.ON
U.S. suggests that the SDT pursue comments from manufacturers to obtain recommendations on what they believe is required to
maintain and test their equipment.
Response: The SDT thanks you for your comments.
1. Although this SDT team (as an Interpretation Drafting Team) drafted the recent NERC interpretation of Protection System as it is applied to PRC-005-1,
the SDT believes that the charger is an integral portion of the Station DC supply; thus it has been added to the definition of Protection System by replacing
“station batteries” in the current definition of Protection System to “station dc supply” in the definition for the proposed standard (PRC-005-2). The SDT
disagrees with your contention that testing of the station dc supply is necessary; the station dc supply is a critical component of the Protection System,
and it must be verified that it can perform its required function.
2. A single record is not adequate to demonstrate that the equipment has been maintained according to the intervals.
3.1. The SDT revised the Supplementary Reference to remove references to IEEE function numbers except where they are critical to the discussion.
3.2. The SDT believes that it is actually a single table with multiple sections and has retained the table numbering. The SDT has worked to improve the
consistency between the table sections.
3.3. The tables have been revised to clarify this area.
4. The Supplementary Reference Document has been modified to use the NERC-defined term of “Bulk Electric System” or its defined abbreviation BES,
rather than “Bulk Power System” or BPS. As for manufacturer input, the SDT is concerned that it would be a violation of NERC Anti-Trust rules to seek
input from manufacturers.
Duke Energy
Regarding the Implementation Plan,
1. R1 compliance should be the first day of the first calendar quarter 18 months following applicable regulatory approvals. Entities
will need this time to change monitoring equipment and develop extensive new work practices and procedures to assure time
frames and documentation of practices comply with the wording of the revised standard.
2. The time frames for R2, R3 and R4 are adequate except in cases where upgrades have to be developed and implemented in
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order to be able to meet the intervals (such as breaker trip coil verification every three months).
3. FAQ 2C “If I am unable to complete the maintenance as required due to a major natural disaster, how will this effect my
compliance with the standard.” Response is the Compliance monitor will consider extenuating circumstances? We would like to
see this statement clarified as to the time frame extensions that result in non compliance or fines.
4. R4 States “each transmission owner” shall implement its PSPM, including identification of the resolution of all maintenance
correctable issues. If the intent is to document resolution to misoperations this is a reasonable request. If the intent is to document
that a relay was found out of calibration on a routine test, which was corrected by recalibration we need some clarity on
expectations of how that would be recorded and tracked. As written this statement is vague and somewhat confusing since % of
allowable error may vary utility to utility. R4 doesn’t appear to allow any time beyond the stated intervals for repairs or
replacements that may take additional time. PRC-005-2 is maintenance and testing standard, and R4 inappropriately requires a
replacement strategy and an obsolescence strategy. Is R4 intended to apply to all equipment in Table 1?
Response: The SDT thanks you for your comments.
1. The SDT believes that time provided for R1 is sufficient. Additionally, entities can use the time required for NERC Board of Trustees and regulatory
approvals to work on implementation.
2. The SDT believes that the times provided for R2, R3, and R4 are adequate.
3. The specific issues of how the Compliance Enforcement Authority would address this issue is outside the scope of the SDT. The response in the FAQ
(FAQ IV-2-D, page 23) is extracted directly from the NERC Sanction Guidelines (effective January 15, 2008)
4. The SDT has modified the standard to require initiation of the resolution of maintenance-correctable issues that cannot be resolved during the on-site
maintenance; this is focused on assuring that the Protection System is capable of performing its desired function. R4 is intended to apply to ALL
equipment in the PSMP.
Northeast Power Coordinating
Council
1. Requirements 4.2.5.4 and 4.2.5.5 require clarification. It is recommended that the drafting team provide a schematic diagram to
provide clarity as to which generator and system connected transformers are included in this facility identification.
2. When Measures are added to the Standard, the SDT must consider how the owner will be required to assess and document the
decision of which table will apply to each protection. While this is a compliance element, the standard should provide clarity on
this matter. As written, the requirement does not seem to be measurable.
3. Requirement R4 requires clarification on what is meant by “including identification of the resolution of all maintenance
correctible issues as follows:” Correctible issues should not be combined in the same sentence with the layout of the tables.
4. Table 1b: In the section for “Protection system communication equipment and channels”, there needs to be clarification on
“verify that the performance of the channel and the quality of the channel meets the performance criteria, such as via
measurement of signal level, reflected power, or data error rate.” This may be done as a pass fail test during trip checks. If the
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communication line successfully sends proper signals for the trip checks, then the communication line is acceptable and no
additional measurement are taken.
5. Table 1c: There is some confusion on what is expected on items that have a Maximum Maintenance Interval reported as
“Continuous”. For example, a component in the “Protection System telecommunication equipment and channels” how would one
provide documentation or proof of the continuous verification of the two items listed in the maintenance activities” In other words
how does one prove “Continuous verification of the communication equipment alarm system is provided” and “Continuous
verification that the performance and the quality of the channel meet the performance criteria is provided”. These activities appear
to be “monitoring attributes” more so than they are maintenance activities.
6. Additionally, the Continuous “Maximum Maintenance Interval” needs clarification
because
•
the interval is a monitoring interval and not a maintenance interval
•
a strict interpretation of “Continuous” could require redundant monitoring systems be installed or locations staffed by
personnel to monitor equipment in the event remote monitoring capabilities are unavailable
•
It is unclear how to provide proof to an auditor that continuous monitoring has occurred over a given interval?
7. Table 1a, 1b, and 1c: The maintenance activity for battery chargers are to perform testing of the charger at full rated current
and verify current-limit performance. The drafting team should provide an industry standard as how to perform this check, or
specify an industry equivalent test.
8. The Table 1b Level 2 Monitoring Attributes for Component “Monitoring and alarming of continuity of trip coil(s)” should be
changed to read “Monitoring and alarming of continuity of all DC circuits including the trip coil(s)”. The present wording is
confusing and can be interpreted to mean that the DC control circuitry needs to be checked every 12 years, as opposed to what
we perceive to be the intended 6 years.
9. The Maintenance Activities in Table 1c are not consistent with the Level 3 Monitoring Attributes for Component “Protection
system telecommunications equipment and channels.”
10. “Continuous verification of interface to protective relays” should be added as a third activity should be added under the
Maintenance Activities column.”
11. In Section A. Introduction, 4.2.4 should be made to read “Protection System components which are installed as a Special
Protection System for BES reliability.
12. For Requirement 4.1, a “grace period” similar to the NPCC criteria should be considered in case it is not possible to obtain any
necessary outages to get the prescribed maintenance done.
13. Requirement R1 should be modified to read “Each Transmission Owner, Generator Owner, and Distribution Provider shall
develop, document, and implement a Protection System Maintenance Program (PSMP) for its Protection Systems that use” This
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revision reinforces what is necessary to ensure proper compliance with the program.
14. “The standard has multiple component tests required at different and conflicting intervals, some interdependent. Preference is
to have the component listed with a common maintenance and testing interval assigned (list the testing required at 2, 4 and 6
years). This same interval should apply to all areas in the table.”
15. Life span of PC’s, software and software license’s are much less than 12 years or asset life. This presents a problem during
an audit where proof is required. The components in modern relays have not been proven over these extended time periods,
users are dependent on proper functions of the alarm output of IED’s. Prefer more frequent maintenance cycles over having to
continuously document proof of a robust CBM or PBM program.
16. The burden placed to provide proof of compliance with a CBM or PBM maintenance program seems to outweigh any benefit in
maintenance costs or reliability.
Response: The SDT thanks you for your comments.
1. Figure 2 in the Supplementary Reference Document (page 28) illustrates generator-connected and system-connected station service transformers.
Additionally, 4.2.5.4 and 4.2.5.5 (in the Applicability section) further state, “for generators that are part of the BES”, which must be taken in the context of
the Regional Entity BES definition.
2. It is beyond the scope of a standard to require specific documentation; the entity must determine what documentation is necessary to clearly
demonstrate that they are meeting the requirements. FAQ V-1-D, page 30 provides a discussion to assist in this determination.
3. The footnote for R4 has been modified to read as follows: A maintenance correctable issue is a failure of a device to operate within design parameters that can
not be restored to functional order by repair or calibration while performing the initial on-site maintenance activity, and that requires follow-up corrective action.
4. A functional test only proves that the communication equipment is working. Table 1b requires that the performance criteria, such as signal levels,
reflected power, etc are verified against the original performance criteria established when the channel was commissioned. See FAQ II-6-D, page 17.
5. For items with a maximum maintenance interval of “continuous”, no activities are required, and the specified activities acknowledge that the monitoring
of the component IS addressing the maintenance of the component.
6. The general information within the Table describes the attributes needed to achieve the Level 3 monitoring, and R2 requires that the entity establish a
basis for the components to be addressed within Table 1c. Supplementary Reference Document, Sections 13 and 14 (page 20) provide discussion on this,
and the Decision Trees in the FAQ and FAQ IV-1-A, page 21 also discuss this.
7. The SDT has modified the standard to remove this requirement in consideration of your comments.
8. The SDT has modified the standard to remove this requirement in consideration of your comments.
9. Table 1c has been modified to improve the consistency.
10. The SDT is not clear as to what you are suggesting.
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11. The SDT has modified the standard in consideration of your comment. As revised, 4.2.4 reads as follows: Protection System components installed as a
Special Protection System for BES reliability.
12. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals would
thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace period”
would not conform to this directive.
13. Documentation is a matter of demonstrating compliance, not of meeting the technical requirements of the Standard. R4 specifies the implementation of
the PSMP.
14. The testing specified for many components is different for the varying intervals; therefore, a separate table entry is present for each distinct interval.
For the most part, the intervals are multiples of each other, (3-months, 18-months, 3-years, 6-years, and 12-years).
15. Entities are certainly free to perform maintenance more frequently than specified in the standards.
16. Entities do not have to adopt CBM or PBM; the entity must decide if the benefits of such programs justify the additional administrative effort.
Saskatchewan Power
Corporation
1. Saskatchewan recommends that the PC's and RC's designate what equipment is applied to protect the BES and should be
included in the protection maintenance program. It is questionable whether the facility owners or Distribution Providers will know.
2. What are the impacts on the BES from the protection systems identified in Facilities 4.2.5 and the FAQ? For example there is
an impact on the BES from generator under-frequency protection not being properly coordinated, but assuming it is and if it is not
maintained isn't the impact to the unit itself? Inadvertent energization protection also seems to be an impact to the unit itself not
the BES? The standard should be concerned with protection systems that impact the BES not equipment protection that has
localized impacts however important they may be.
3. Change Facilities 4.2.2 to “Protection System components used for under-frequency load-shedding systems which are installed
to prevent system under-frequency collapse for BES reliability.” The reference to ERO is unnecessary and inappropriate.
Response: The SDT thanks you for your comments.
1. The SDT disagrees. This standard applies to Protection Systems applied on, or that are designed to provide protection for the BES as defined by the
Regional Entities.
2. Fundamentally, if a system component is part of the BES, the protection on that component indeed affects the BES.
3. The SDT believes that this Applicability is correctly stated in the standard. This directly reflects the current PRC-008-1 standard.
Detroit Edison
1. Suggest that the term “alarmed failures” in the table headings be changed to “alarmed abnormalities” to better indicate that the
monitored parameter may be in an abnormal state or out of range but not necessarily failed.
2. Does “system-connected” station service transformers refer to transformers connected to the BES or transformers connected to
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a system at any voltage level?
3. Is the intent of R1.1.2 that each Protection System component (specific relay at specific location) be listed individually with its
associated maintenance method and interval or can the general component category be listed as such?
4. Regarding R4, further clarification would be helpful in understanding the intent of the term “resolution of all maintenance
correctible issues” as it applies to R4.1 and R4.2. Is it intended that “maintenance correctible issues” be completed within the
interval?
5. It is recommended that each line in the tables be given a number or letter designation to make reference to that row easier.
Response: The SDT thanks you for your comments.
1. The SDT understands your comment, and has elected to leave the terminology in the standard unchanged. While “failure” is not a defined term within
th
the standard, the 11 Edition of Merriam Webster’s Collegiate Dictionary includes, within the definition of failure, several relevant applications of this term,
including “an omission of occurrence or performance”, “a failing to perform a duty or expected action”, “a state of inability to perform a normal function”,
and “an abrupt cessation or normal functioning”.
2. This phrase refers to generation plant station-service transformers connected at any voltage level, provided that the generator is part of the BES.
3. This depends on the description of your program. You will need to describe your program in a way that will satisfy the requirements of the Standard.
4. The SDT has modified the standard to require initiation of the resolution of maintenance-correctible issues, with no specific time-frame on completing
the resolution.
5. The SDT thanks you for your suggestion. This has been considered several times during the development of the tables, and several different
arrangements attempted, and the SDT believes that the current presentation is the most effective way to present this complex material. The SDT will,
however, continue to consider suggestions to improve this.
SERC (PCS)
The “zero tolerance” structure proposed combined with the large volume and complexity of Protection System components forces
an entity to shorten their intervals well below maximum. We instead propose a calendar increment carryover period in which a
small percentage of carryover components would be tracked and addressed. For example, up to 1% of an entity’s communication
channel 6 year verifications could carryover into the next year. These carryover components would be addressed with high
priority in that next calendar increment. There are many barriers to 100% completion or zero tolerance. Some utilities have over
ten thousand components.
Response: The SDT thanks you for your comments. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer
interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum
maintenance intervals, and allowing for a “grace period” would not conform to this directive.
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Electric Market Policy
Question 10 Comment
1. The “zero tolerance” structure proposed within this standard combined with the large volume and complexity of Protection
System components requires a utilities processes and built-in grace periods to perform to perfection. Although this is a worthy
goal for our industry, this can result in a large number of non-compliances for minor documentation issues or slightly missed
maintenance schedules on an insignificant percentage of relays. The processing of these non-compliances can be costly in terms
of resources that could be better utilized to address other transmission reliability matters. To provide a better approach, we
suggest an incremental carryover system be permitted that would allow up to 0.5 percent of the PRC-005 maintenance task to be
carried over to the next period, provided they are random events (not repetitive). As an example, a small percentage of our
Protective System Control Trip tests on a 6-year interval could be carried over into the next calendar year when a generator
outage is rescheduled. With this provision, these few tests could be handled without risk of a generator trip and without a
compliance consequence. These carryover tasks could be addressed through an action plan with a defined completion date, and
could be documented through a regional web portal. There are many barriers to 100% completion at a zero tolerance level with
this volume of tasks.
Response: The SDT thanks you for your comments. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer
interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum
maintenance intervals, and allowing for a “grace period” would not conform to this directive.
Oncor Electric Delivery
1. The drafting team is to be commended for taking the Technical Paper and Draft Standard that was prepared by the NERC
System Protection and Control Taskforce (SPCTF) and the recommendations of the SAR drafting team to create PRC-005-2.
This draft standard allows the owners of Protection Systems several options in establishing a maintenance program tailored to
their equipment and the topography of their system.
Response: The SDT thanks you for your support.
US Bureau of Reclamation
The significance of this issue is not reflected in the period of time needed to review the documents. The supplement has many
good ideas; however, the concept is going further than needed for establishing consistent maintenance intervals.
Response: The SDT thanks you for your comments. The NERC Standard Development Process normally allows for only 30-day or 45-day comment
postings. The SDT intends to continue to use only the 45-day posting period of these in recognition of the extensive material to review.
RRI Energy
June 3, 2010
1. The standard was written to implement generally accepted practices, but has developed requirements that are overly
prescriptive relative to what will be required to demonstration compliance. The standard should not assume the need to write all
aspects of a maintenance program into the standard or that maintenance programs will only consist of the standard requirements.
Protection systems of the BES have and will continue to perform very reliably with the basic elements of a maintenance program
without the need to divert resources for the development of excessive documentation to demonstrate compliance. PRC-005-1 is
the most violated standard in the industry; not because of the lack of maintenance to protection systems, but because the
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documentation requirements of the standard, given the large magnitude of components that fall within the scope of the standard.
This standard significantly increases the administrative burden for additional documentation, without corresponding improvements
to the reliability of the BES.
2. Recommend rewording A.4.2.5.1 as follows: “Generator Protection system components that trip the generator circuit breakers
to separate and isolate the generator from the BES either directly in the breaker trip coil circuit or through interposing lockout or
auxiliary tripping relays.” This document should not expand the compliance scope beyond the definition of the BES. The
generator protection systems that “trip the generator” also perform additional control functions that extend beyond the electrical
isolation of the generating unit from the BES. These additional circuits do not protect the BES and do not belong in the scope of
this document.
3. Recommend rewording A.4.2.5.4 as follows: “Protection systems for generator-connected station service transformers that trip
the generator circuit breakers to separate and isolate the generator from the BES.” This document should not expand the
compliance scope beyond the definition of the BES. Related protection circuits of the transformer not involved with the electrical
isolation of the generating unit from the BES does not belong in the scope of this document.
4. Recommend rewording A.4.2.5.5 as follows: “Protection systems for BES elements connecting to the station service
transformers of generating stations.” This document should not expand the compliance scope beyond the definition of the BES.
The requirement incorporates radial feeds (with dedicated breakers) into the scope of the standard that are not necessarily a part
of the BES as defined by some RRO’s. Station service transformers are not necessarily required for generating unit operation. In
some cases there are redundant sources for startup or back-up power. Protection of these transformers does not belong in the
scope of the standard if they are not a part of the BES.
5. The suggested rewording of R1.2 is as follows: “Identify whether each Protection System component is addressed through
time-based, condition-based, performance-based, or a combination of these maintenance methods.” The requirement for the
registered entity to list the interval of maintenance does not belong in the standard, especially since the maximum intervals are
listed in the standard tables. The registered entity may have internal documents that intentionally target a shorter duration than
the maximum interval of Table 1a. The failure to meeting those internally established targets can be a violation of the standard by
the wording of this requirement. Allow R4 of the standard to identify the maximum allowable intervals.
6. In R4, the requirement for “identification of the resolution of all maintenance correctible issues” should be separated from the
maintenance intervals; which define the maximum intervals of maintenance activities. The requirement should be eliminated to
remove the overly prescriptive requirements of auditable documentation. If retained, a rewording of the requirement is as follows:
“Each Transmission Owner, Generator Owner, and Distribution Provider shall identify the resolution of all issues identified and not
corrected at the time the maintenance is initiated and the protected element is returned to service.” The documented resolution of
maintenance correctible issues (if retained) should apply only to activities that are unresolved and incomplete during the normal
maintenance process. The standard should not micromanage the documentation process by creating requirements for excessive
auditable records needed to demonstrate compliance of routine maintenance activities.
7. In R4, the requirements for Generator Owners which establish the durations of maximum allowable intervals should be
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separated from the Transmission Owners, even if the intervals are the same. The reason is to allow for the assignment of
different Violation Risk Factors. The Violation Risk Factor for the application of a 20 MVA generating unit with an operating
capacity factor of less than 5%, and connected to a 138 kV system, should not be the same as those applied to a 500kV
transmission line. The violation risks factors for these two applications are significantly different, and the ability to recognize this is
not permitted by the standard presently.
8. Similarly, the criteria used for the sizing of station batteries for a large generating station is very different than those used for
transmission facilities. Very little of the generating station battery sizing is related to BES protection, and nearly all generator
protection system operations occur without reliance upon the battery. Without NERC standard requirements, Generator Owners
have their own natural incentives to maintain batteries for the protection of the turbine generator bearings on the loss of AC power.
With the most basic requirements of an inspection and maintenance program, there is an extremely high degree of reliability given
the typical design of DC systems within a generating station, even without documented compliance to a rigid set of standards.
With very basic, elementary maintenance (documented or not), the statistical probability for the random and simultaneous failure
of multiple battery cells to disable the protection system of a generating station for the milliseconds of time required to separate a
generating unit from the BES is insignificant (well in excess of 1 billion to 1 across an entire calendar quarter).
9. Violation risk factors and the resulting penalties for non-compliance need to be realistic.
Response: The SDT thanks you for your comments.
1. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Reliability Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to
implement an effective PSMP.
2. The SDT believes that the standard is correct as drafted. Not only does the generator need to be disconnected, but this BES component must also be
protected. Please refer to FAQ III-2-A, page 20 for a discussion of relevant Protection System components.
3. A loss of a generator-connected station auxiliary transformer will result in a loss of the generating plant if the plant is being provided with auxiliary
power from that source.
4. A loss of a system-connected station auxiliary transformer could result in a loss of the generating plant if the plant was being provided with auxiliary
power from that source, and this auxiliary transformer may directly affect the ability to start up the plant and to connect the plant to the system.
5. Inclusion of the intervals is necessary for PBM, and entities may elect to commit to more demanding intervals because of their experience.
6. The SDT has modified the standard to require initiation of the resolution of maintenance-correctible issues, but establishes no time line for the actual
resolution, in recognition of the wide variation in the type of problems and the scale of the resolution.
7. The SDT disagrees. It the protection on the cited 20 MVA generating unit fails to properly isolate the unit from the system for fault conditions, it could
have serious effects on reliability.
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8. The SDT believes that the station dc supply is such an integral part of the Protection System of a generating station that, it falls under NERC Reliability
Standard purview and at a minimum must be maintained using the Maintenance Activities and Maximum Maintenance Intervals of Table 1.
9. The SDT will consider this with developing VRFs and VSLs.
Lower Colorado River Authority
We commend the work done by the SDTSDT. In particular, the merging of previous standards PRC-005-0, PRC-008-0, PRC-0110, and PRC-017-0 which will help with the efficient management of these standards.
Response: The SDT thanks you for your support.
Ontario Power Generation
We note that Verification of Voltage and Current Sensing Device Inputs to Protective Relays is a somewhat ambiguous activity.
NERC’s audit observation team came up with a similar finding. The supporting documents provide some clarity but in our opinion
it would be helpful if the SDT could elaborate this activity in more detail in the Table itself.
Response: The SDT thanks you for your comments. The Tables have been modified to clarify this issue.
Southern Company
1. We presently utilize a UFLS system distributed across many transmission and distribution substations. Are the station batteries
located in stations with no network transmission protection schemes (other than UFLS) subject to the requirements of PRC-0052? This was not addressed in previous revisions.
2. We presently utilize a UVLS system distributed across many transmission and distribution substations. Are the station batteries
located in stations with no network transmission protection schemes (other than UVLS) subject to the requirements of PRC-0052?
3. In the applicability section, there is no exception for smaller units and those with very low capacity factors. Rather, those that
“are part of the BES” are in the scope. We recommend that smaller units and low capacity factor units be exempt from the
requirements of this standard or have extended maintenance intervals. Refer to the current SERC supplement for PRC-005-1.
Section II.A. of the May 29, 2008: SERC Supplement Maintenance & Testing Protection Systems (Transmission, Generation,
UFLS, UVLS, & SPS) NERC Reliability Standards PRC-005-1, PRC-008, PRC-011, & PRC-017.The applicability section
paragraph 4.2.4 should read “are installed” rather than “is installed”.
4. Note 2 at the bottom of the table (1c) implies that one has to apply voltage and inject current into the microprocessor relay to
perform trip checks. Is this the intent of the statement? If so, Note 2 should be revised to make clear the intention. We don’t
think this is necessary with microprocessor relays since they monitor inputs
5. Why is the Violation Severity Level Matrix not a part of this standard revision?
6. In cases where a common dc system exists between a generator owner and transmission owner, who is the responsible entity?
7. We appreciate the work that went into the implementation plan. We agree with the concept of phasing in mandatory compliance
June 3, 2010
181
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Question 10 Comment
and the timing of the implementation.
8. Consider defining the Monitoring Levels once and reformatting the information contained within Tables 1a, 1b, and 1c to
regroup the information by component type rather than by Monitor Level. When considering the various monitoring levels for the
protection system components, each entity will consider each component type apart from the others when determining the Monitor
Level to apply, so this reorganization will assist the end user to understand and apply the levels. See samples attached as a
separate document:
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard to clarify that the only DC Supply requirement relevant to UVLS and UFLS is to verify the DC supply voltage, and that
this may be performed in conjunction with the UFLS/UVLS maintenance itself.
2. The SDT has modified the standard to clarify that the only DC Supply requirement relevant to UVLS and UFLS is to verify the DC supply voltage, and that
this may be performed in conjunction with the UFLS/UVLS maintenance itself.
3. This is properly a NERC registration issue and one of the regional BES definitions. We appreciate that you may disagree with these, but you should seek
resolution via other means. The SDT has modified the standard in consideration of your editorial concern. It the protection on a small generating unit fails
to properly isolate the unit from the system for fault conditions, it could have serious effects on reliability.
4. Note 2 has been removed from the Table.
5. Even though the SDT worked on a VSL matrix during development of this draft, the SDT elected to constrain this posting only to the requirements and
supporting developments. The SDT believes that this was such an extensive body of material that it would be distracting to include compliance elements.
The SDT also recognized that extensive changes were likely to occur to the standard in response to this posting, and considered this in their decision to
not include compliance elements. They will be included in the next posting.
6. The SDT believes that the owner of the battery is responsible. This can be worked out by agreements between the entities.
7. The SDT thanks you for your support.
8. The SDT has experimented with various arrangements of the Tables with some input from external parties, and believes that the presentation shown in
the standard is the best way to present this complex information. The SDT has attempted to make the arrangement of the three tables as similar as
possible to address your concern.
PacifiCorp
What is the definition of "Calendar Year"? Does the term "Six calendar years" include any date in 2004 to any date in 2010?
Response: The SDT thanks you for your comments. Disregard the complete date and just look at the year portion. For a 6 calendar-year interval, if the test
date was IN 2004, the next test must be completed by the end of 2010.
June 3, 2010
182
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Question 10 Comment
AECI
Puget Sound Energy
Great improvement in the standards and clarity of expectations. We appreciate the combining of the multiple PRC standards.
PSE would appreciate the comments and clarification needed regarding the interpretation for PRC-005 under Project 2009-17 to
be included in PRC-005-2. It appears that the interpretation allowed regions to define variances due to the variance in the
Regional Entity definitions of the BES. But how the BES is defined and documented as such creates ongoing confusion for the
registered entities.
Response: The SDT thanks you for your comments. The NERC definition for BES specifically includes, “As specified by the regions”. As long as this
definition persists, the issue noted in your comments will also persist. It is outside the scope of this standard to address these issues.
June 3, 2010
183
Consideration of Comments on 2nd Draft of the Standard for Protection
System Maintenance and Testing Project 2007-17
The Protection System Maintenance and Testing Standard Drafting Team thanks all
commenters who submitted comments on the 2nd draft of the PRC-005-2 standard for
Protection System Maintenance and Testing. This standard was posted for a 45-day public
comment period from June 11, 2010 through July 16, 2010. The stakeholders were asked
to provide feedback on the standards through a special Electronic Comment Form. There
were 58 sets of comments, including comments from more than 130 different people from
over 70 companies representing 8 of the 10 Industry Segments as shown in the table on the
following pages.
Many commenters objected to the establishment of maximum allowable intervals and
offered comments on most of the individual activities and intervals within the Tables.
•
The SDT responded that “FERC Order 693 and the approved SAR assigned the SDT
to develop a Standard with maximum allowable intervals and minimum maintenance
activities.”
To provide more clarity, the SDT completely rearranged and revised the Tables.
•
The Tables now consist of one table for each of the five Protection System
component types, as well as a sixth table to address monitoring and alarming
requirements to support extended intervals for monitored Protection System
components.
Many commenters disagreed with some of the VRF and VSL assignments.
•
The SDT made several modifications to the VRFs and VSLs that are in-keeping with
the guidance provided by NERC and FERC.
Other comments were offered regarding Time Horizons, resulting in modification of the Time
Horizons for both R3 and R4 from Long-Term Planning to Operations Planning.
In response to suggestions relative to the Measures, the SDT made changes to all four
Measures.
Commenters were appreciative for the information contained in the two reference
documents, but indicated a preference for some of the information to be included within the
body of the Standard.
•
In response, the SDT included the definitions of those terms exclusive to this
standard, specifically “component type”, “component”, “segment”, “maintenance
correctable issue”, and “countable event”, within the Standard.
In this report, comments have been organized by question number. Comments can be viewed
in their original format on the following web page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there
is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on PSMTSDT — Project 2007-17
Index to Questions, Comments, and Responses
1.
The SDT has made significant changes to the minimum maintenance activities and
maximum allowable intervals within Tables 1a, 1b, and 1c, particularly related to
station dc supply and dc control circuits. Do you agree with these changes? If not,
please provide specific suggestions for improvement. ............................................ 13
2.
The SDT has included VRFs and Time Horizons with this posting. Do you agree with the
assignments that have been made? If not, please provide specific suggestions for
improvement. ................................................................................................... 75
3.
The SDT has included Measures and Data Retention with this posting. Do you agree
with the assignments that have been made? If not, please provide specific suggestions
for improvement. .............................................................................................. 84
4.
The SDT has included VSLs with this posting. Do you agree with the assignments that
have been made? If not, please provide specific suggestions for change. ............... 100
5.
The SDT has revised the “Supplementary Reference” document which is supplied to
provide supporting discussion for the Requirements within the standard. Do you agree
with the changes? If not, please provide specific suggestions for change. .............. 116
6.
The SDT has revised the “Frequently-Asked Questions” (FAQ) document which is
supplied to address anticipated questions relative to the standard. Do you agree with
these changes? If not, please provide specific suggestions for change. .................. 129
7.
If you have any other comments on this Standard that you have not already provided
in response to the prior questions, please provide them here. ............................... 143
November 17, 2010
2
Consideration of Comments on PSMTSDT — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Joseph DePoorter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
MRO’s NERC Standards Review Subcommittee
(NSRS)
X
Additional Member Additional Organization Region Segment Selection
1. Mahmood Safi
OPPD
MRO
1, 3, 5, 6
2. Chuck Lawrence
ATC
MRO
1
3. Tom Webb
WPSC
MRO
3, 4, 5, 6
4. Jason Marshall
MISO
MRO
2
5. Jodi Jenson
WAPA
MRO
1, 6
6. Ken Goldsmith
ALTW
MRO
4
7. Dave Rudolph
BEPC
MRO
1, 3, 5, 6
8. Eric Ruskamp
LES
MRO
1, 3, 5, 6
9. Joseph Knight
GRE
MRO
1, 3, 5, 6
10. Joe DePoorter
MGE
MRO
3, 4, 5, 6
11. Scott Nickels
RPU
MRO
4
12. Terry Harbour
MEC
MRO
6, 1, 3, 5
November 17, 2010
10
3
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
13. Carol Gerou
2.
Group
MRO
Organization
MRO
Guy Zito
Additional Member
1
2
3
4
5
6
7
8
9
10
10
Northeast Power Coordinating Council
Additional Organization
X
Region Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2. Gregory Campoli
New York Independent System Operator
NPCC 2
3. Kurtis Chong
Independent Electricity System Operator
NPCC 2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7. Ben Eng
New York Power Authority
NPCC 4
8. Brian Evans-Mongeon Utility Services
NPCC 8
9. Dean Ellis
Dynegy Generation
NPCC 5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
11. Kathleen Goodman
ISO - New England
NPCC 2
12. David Kiguel
Hydro One Networks Inc.
NPCC 1
13. Michael R. Lombardi
Northeast Utilities
NPCC 1
14. Randy MacDonald
New Brunswick System Operator
NPCC 2
15. Bruce Metruck
New York Power Authority
NPCC 6
16. Chantel Haswell
FPL Group
NPCC 5
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
18. Robert Pellegrini
The United Illuminating Company
NPCC 1
19. Saurabh Saksena
National Grid
NPCC 1
20. Michael Schiavone
National Grid
NPCC 1
November 17, 2010
Industry Segment
4
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
21. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
22. Si Truc Phan
Hydro-Quebec TransEnergie
3.
Group
1
2
3
4
X
X
5
6
7
8
9
NPCC 1
Pacific Northwest Small Public Power Utility
Comment Group
Steve Alexanderson
Industry Segment
Additional Member Additional Organization Region Segment Selection
1. Russ Noble
Cowlitz PUD
WECC 3, 4, 5
2. Dave Proebstel
Clallam County PUD
WECC 3
3. John Swanson
Benton PUD
WECC 3
4. Steve Grega
Lewis County PUD
WECC 3, 4
4.
Group
Margaret Ryan
Additional Member
PNGC Power
Additional Organization
X
Region Segment Selection
1.
Blachly-Lane Electric Cooperative
WECC 3
2.
Central Electric Cooperative
WECC 3
3.
Clearwater Electric Cooperative
WECC 3
4.
Consumer's Power Company
WECC 3
5.
Coos-Curry Electric Cooperative
WECC 3
6.
Douglas Electric Cooperative
WECC 3
7.
Fall River Electric Cooperative
WECC 3
8.
Lane Electric Cooperative
WECC 3
9.
Lincoln Electric Cooperative
WECC 3
10.
Lost River Electric Cooperative
WECC 3
11.
Northern Lights Electric Cooperative WECC 3
12.
Okanogan Electric Cooperative
WECC 3
13.
Raft River Electric Cooperative
WECC 3
November 17, 2010
X
5
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
14.
Salmon River Electric Cooperative
WECC 3
15.
Umatilla Electric Cooperative
WECC 3
16.
West Oregon Electric Cooperative
WECC 3
17.
PNGC
WECC 8
5.
Group
Dave Davidson
Tennessee Valley Authority
Industry Segment
1
2
3
X
4
5
6
7
8
9
X
Additional Member Additional Organization Region Segment Selection
1. Russell Hardison
TOM Support Manager
SERC
2. Pat Caldwell
TOM Support
SERC
3. David Thompson
GO
SERC
4. Jim Miller
GO
SERC
6.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
BPA, Tx SPC Technical Svcs
WECC 1
2. John Kerr
BPA, Tx Technical Operations
WECC 1
3. Mason Bibles
BPA, Tx Sub Maint and HV Engineering WECC 1
4. Laura Demory
BPA, Tx PSC Technical Svcs
Group
Kenneth D. Brown
X
X
X
X
X
X
X
X
X
X
X
Region Segment Selection
1. Dean Bender
7.
X
WECC 1
Public Service Enterprise Group ("PSEG
Companies")
Additional Member Additional Organization Region Segment Selection
1. Jim Hubertus
PSE&G
2. Scott Slickers
PSEG Power Connecticut NPCC
3. Jim Hebson
PSEG ER&T
ERCOT 5, 6
4. Dave Murray
PSEG Fossil
RFC
8.
Group
Sam Ciccone
November 17, 2010
RFC
1, 3
5
5
FirstEnergy
6
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
4
5
X
X
X
6
7
8
9
Additional Member Additional Organization Region Segment Selection
1. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
2. Jim Kinney
FE
RFC
1
3. K. Dresner
FE
RFC
5
4. B. Duge
FE
RFC
5
5. J. Chmura
FE
RFC
1
6. B. Orians
FE
RFC
5
9.
Group
Terry L. Blackwell
Santee Cooper
X
Additional Member Additional Organization Region Segment Selection
1. S. Tom Abrams
Santee Cooper
SERC
1
2. Rene' Free
Santee Cooper
SERC
1
3. Bridget Coffman
Santee Cooper
SERC
1
10.
Group
Daniel Herring
The Detroit Edison Company
Additional Member Additional Organization Region Segment Selection
1. Dave Szulczewski
11.
Group
Relay Engineering
Sasa Maljukan
RFC
3, 4, 5
Hydro One Networks
X
Additional Member Additional Organization Region Segment Selection
1. Peter FALTAOUS
Hydro One Networks, Inc. NPCC 1
2. David Kiguel
Hydro One Networks, Inc. NPCC 1
3. Paul DIFILIPPO
Hydro One Networks, Inc. NPCC 1
12.
Group
Annette M. Bannon
Additional Member
PPL Supply
Additional Organization
X
Region Segment Selection
1. Mark A. Heimbach
PPL Martins Creek, LLC
RFC
5
2. Joseph V. Kisela
PPL Lower Mount Bethel Energy, LLC RFC
5
November 17, 2010
7
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
3.
PPL Brunner Island, LLC
RFC
5
4.
PPL Montour, LLC
RFC
5
5.
PPL Holtwood, LLC
RFC
5
6.
PPL Wallingford, LLC
NPCC 5
7.
PPL University Park, LLC
RFC
5
8. David L. Gladey
PPL Susquehanna, LLC
RFC
5
9. Thomas E. Lehman PPL Montana, LLC
WECC 5
10. Lloyd R. Brown
PPL Montana, LLC
WECC 5
11. Augustus J. Wilkins PPL Montana, LLC
WECC 5
13.
Group
Richard Kafka
Additional Member
Pepco Holdings, Inc. - Affiliates
Additional Organization
Industry Segment
1
Potomac Electric Power Company RFC
1
2. Carl Kinsley
Delmarva Power & Light
RFC
1
3. Rob Wharton
Delmarva Power & Light
RFC
1
4. Evan Sage
Potomac Electric Power Company RFC
1
5. Carlton Bradsaw
Delmarva Power & Light
RFC
1
6. Jason Parsick
Potomac Electric Power Company RFC
1
7. Walt Blackwell
Potomac Electric Power Company RFC
1
8. John Conlow
Atlantic City Electric
RFC
1
9. Randy Coleman
Delmarva Power & Light
RFC
1
X
X
X
14.
Individual
JT Wood
Southern Company Transmission
X
15.
Individual
Silvia Parada Mitchell
Corporate Compliance
X
Individual
Jana Van Ness, Director
Regulatory Compliance
Arizona Public Service Company
November 17, 2010
3
4
5
6
X
X
X
X
X
X
7
8
9
Region Segment Selection
1. Alvin Depew
16.
2
X
X
8
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
4
5
6
17.
Individual
Tom Schneider
WECC
18.
Individual
Brandy A. Dunn
Western Area Power Administration
X
19.
Individual
Sandra Shaffer
PacifiCorp
X
20.
Individual
John Canavan
NorthWestern Corporation
X
21.
Individual
Dan Roethemeyer
Dynegy Inc.
22.
Individual
Robert Ganley
Long Island Power Authority
X
23.
Individual
Jonathan Appelbaum
The United Illuminating Company
X
24.
Individual
Lauri Dayton
Grant County PUD
X
25.
Individual
Mark Fletcher
Nebraska Public Power District
X
26.
Individual
Brian Evans-Mongeon
Utility Services
27.
Individual
Charles J.Jensen
JEA
X
X
X
28.
Individual
Fred Shelby
MEAG Power
X
X
X
29.
Individual
James A. Ziebarth
Y-W Electric Association, Inc.
30.
Individual
Armin Klusman
CenterPoint Energy
X
31.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
32.
Individual
Edward Davis
Entergy Services
X
X
X
X
33.
Individual
James Sharpe
South Carolina Electric and Gas
X
X
X
X
34.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
35.
Individual
Jeff Nelson
Springfield Utility Board
36.
Individual
Amir Hammad
Constellation Power Generation
37.
Individual
Gerry Schmitt
BGE
X
38.
Individual
Michael R. Lombardi
Northeast Utilities
X
X
X
39.
Individual
Jeff Kukla
Black Hills Power
X
X
X
November 17, 2010
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
9
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
4
5
40.
Individual
John Bee
Exelon
X
41.
Individual
Andrew Z.Pusztai
American Transmission Company
X
42.
Individual
Thad Ness
American Electric Power
X
43.
Individual
Barb Kedrowski
We Energies
X
X
X
44.
Individual
Jianmei Chai
Consumers Energy Company
X
X
X
45.
Individual
Art Buanno
ReliabilityFirst Corp.
46.
Individual
Tyge Legier
San Diego Gas & Electric
X
X
X
47.
Individual
Greg Rowland
Duke Energy
X
X
X
X
48.
Individual
Claudiu Cadar
GDS Associates
X
49.
Individual
Kirit Shah
Ameren
X
X
X
X
50.
Individual
Joe Knight
Great River Energy
X
X
X
X
51.
Individual
Terry Bowman
Progress Energy Carolinas
X
X
X
X
Group
Joe Spencer - SERC staff
and Phil Winston - PCS
co-chair
SERC Protection and Control Sub-committee
(PCS)
52.
Additional Member
X
X
X
7
8
9
10
X
X
X
Additional Organization
Region Segment Selection
1. Paul Nauert
Ameren Services Co.
SERC
2. Bob Warren
Big Rivers Electric Corp.
SERC
3. Trevor Foster
Calpine Corp.
SERC
4. John (David) Fountain Duke Energy Carolinas
SERC
5. Paul Rupard
East Kentucky Power Coop.
SERC
6. Charles Fink
Entergy
SERC
7. Marc Tunstall
Fayetteville Public Works Commission SERC
8. John Clark
Georgia Power Co
November 17, 2010
X
6
SERC
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
9. Nathan Lovett
Georgia Transmission Corp
SERC
10. Danny Myers
Louisiana Generation, LLC
SERC
11. Ernesto Paon
Municipal Electric Authority of GA
SERC
12. Jay Farrington
PowerSouth Energy Coop.
SERC
13. Jerry Blackley
Progress Energy Carolinas
SERC
14. Joe Spencer
SERC Reliability Corp
SERC
15. Russ Evans
South Carolina Electric and Gas
SERC
16. Bridget Coffman
South Carolina Public Service Authority SERC
17. Phillip Winston
Southern Co. Services Inc.
SERC
18. George Pitts
Tennessee Valley Authority
SERC
19. Rick Purdy
Virginia Electric and Power Co.
SERC
53.
Group
Frank Gaffney
Additional Member
Florida Municipal Power Agency
Additional Organization
Utilities Commission of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority
FRCC
1
3. Jim Howard
Lakeland Electric
FRCC
1
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services
FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority
FRCC
4
Group
Mallory Huggins
Additional Member Additional Organization
X
2
3
4
5
X
X
X
6
7
8
NERC Staff
Region
Segment Selection
1. Joel deJesus
NERC
NA - Not Applicable NA
2. Mike DeLaura
NERC
NA - Not Applicable NA
3. Bob Cummings
NERC
NA - Not Applicable NA
November 17, 2010
1
Region Segment Selection
1. Timothy Beyrle
54.
Industry Segment
11
9
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
4. David Taylor
NERC
NA - Not Applicable NA
5. Al McMeekin
NERC
NA - Not Applicable NA
6. Earl Shockley
NERC
NA - Not Applicable NA
Industry Segment
1
2
3
4
5
55.
Individual
Terry Harbour
MidAmerican Energy Company
56.
Individual
Scott Berry
Indiana Municipal Power Agency
57.
Individual
Rex Roehl
Indeck Energy Services
X
58.
Individual
Martin Bauer
US Bureau of Reclamation
X
November 17, 2010
6
7
8
X
X
12
9
10
Consideration of Comments on PSMTSDT — Project 2007-17
1. The SDT has made significant changes to the minimum maintenance activities and
maximum allowable intervals within Tables 1a, 1b, and 1c, particularly related to station dc
supply and dc control circuits. Do you agree with these changes? If not, please provide
specific suggestions for improvement.
Summary Consideration: Commenters expressed concerns with virtually all elements of posted Tables
1a, 1b, and 1c. In response to these comments, the Tables have been completely rearranged and
extensively revised. The Tables now consist of one table for each of the five Protection System
component types, as well as a sixth table to address monitoring and alarming requirements to support
extended intervals for monitored Protection System components.
Several entities proposed extending the 3 month interval for unmonitored communication systems, and
the drafting team did not adopt this suggestion because the SDT believes that three-months is necessary
for these inspection-related activities related to communications systems
Organization
Yes or
No
Question 1 Comment
Santee Cooper
No comment.
Xcel Energy
1. The current language is not aligned with the FAQ concerning the level of maintenance
required for Dc Systems, in particular the FAQ states that with only 1 element of the
Table 1b attributes in place the DC Supply can be maintained using the Table 1b
activities, the table itself is clear that ALL of the elements must be present to classify the
DC Supply as applicable to Table 1b. The FAQ needs to be aligned with the tables.
2. The FAQ also contains a duplicate decision tree chart for DC Supply. The FAQ contains
a note on the Decision tree that reads, "Note: Physical inspection of the battery is
required regardless of level of monitoring used", this statement should be placed on the
table itself, and should include the word quarterly to define the inspection period.
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Question 1 Comment
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. The FAQ has been modified.
2. The FAQ has been modified.
Pepco Holdings, Inc. Affiliates
November 17, 2010
1. There were numerous comments submitted for Draft 1 indicating that the 3 month
interval for verifying unmonitored communication systems was much too short. The
SDT declined to change the interval and in their response stated: The 3 month intervals
are for unmonitored equipment and are based on experience of the relaying industry
represented by the SDT, the SPCTF and review of IEEE PSRC work. Relay
communications using power line carrier or leased audio tone circuits are prone to
channel failures and are proven to be less reliable than protective relays. Statistics on
the causes of BES protective system misoperations, however, do not support this
assertion. The PJM Relay Subcommittee has been tracking 230kV and above
protective system misoperations on the PJM system for many years. For the six year
period from 2002 to 2007, the number of protective system misoperations due to
communication system problems were lower (and in many cases significantly lower)
than those caused by defective relays, in every year but one. Similarly, RFC has
conducted an analysis of BES protection system misoperations for 2008 and 2009, and
found the number of misoperations caused by communication system problems to be in
line with the number attributed to relay related problems. If unmonitored protective
relays have a 6 year maximum maintenance/inspection interval, it does not seem
reasonable to require the associated communication system to be inspected 24 times
more frequently, particularly when relay failures are statistically more likely to cause
protective system misoperations. As such, a 12 or 18 calendar month interval for
inspection of unmonitored communication systems would seem to be more appropriate.
FAQ II 6 B states that the concept should be that the entity verify that the
communication equipment...is operable through a cursory inspection and site visit.
However, unlike FSK schemes where channel integrity can easily be verified by the
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presence of a guard signal, ON-OFF carrier schemes would require a check-back or
loop-back test be initiated to verify channel integrity. If the carrier set was not equipped
with this feature, verification would require personnel to be dispatched to each terminal
to perform these manual checks.
2. The phrase “Verify Battery cell-to-cell connection resistance” has entered the table
where it did not exist before. On some types of stationary battery units, this internal
connection is inaccessible. On other types the connections are accessible, but there is
no way to repair them based on a bad reading. And bad cell-to-cell connections within
units will be detected by the other required tests. This requirement will cause entities to
scrap perfectly good batteries just so this test can be performed, with no corresponding
increase in bulk electric system reliability while taking an unnecessary risk to personnel
and the environment.
Response: Thank you for your comments.
1. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
2. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where
available to measure)” to address this comment.
Indeck Energy Services
No
GDS Associates
No
Table 1a. Protective relays
1. For microprocessor relays need guidance in how all the inputs/outputs will be checked
and how is determined which one are “essential to proper functioning of the Protection
System”
2. For microprocessor relays need guidance in how the acceptable measurement is
physically determined.
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Question 1 Comment
Response: Thank you for comments.
1. The Standard is proscribed from describing “how.” Section 15.3 of the Supplementary Reference provides some guidance, but it is
left to the entity to determine what methods best address their program.
2. The Standard is proscribed from describing “how.” Section 15.3 of the Supplementary Reference provides some guidance, but it is
left to the entity to determine what methods best address their program.
Western Area Power
Administration
No
1) Standard, Table 1a, “Control and trip circuits with electromechanical trip or aux contacts
(except for microprocessor relays, UFLS or UVLS)”: Where would un-monitored control
and trip circuits connected to a microprocessor relay fall, and what is the associated
interval and maintenance activity?
2) Standard, Table 1a, “Control and trip circuits with electromechanical trip or aux contacts
(except for microprocessor relays, UFLS or UVLS)”: Please confirm that the defined
Maintenance Activity requires actual tripping of circuit breakers or interrupting devices.
3) Standard, Table 1a, “Control and trip circuits with unmonitored solid state trip or auxiliary
contacts (except UFLS or UVLS)”: Please confirm that the defined Maintenance Activity
requires actual tripping of circuit breakers or interrupting devices.
4) Standard, Table 1b. On page 13, for Protective Relays, please clarify the intent of
“Conversion of samples to numeric values for measurement calculations by
microprocessor electronics that are also performing self diagnosis and alarming.”
5) Standard, Table 1b. On page 13, for Protective Relays, please clarify the intent of
“Verify correct operation of output actions that used for tripping.” Does this require
functional testing of a microprocessor relay, i.e., using a relay test set to simulate a fault
condition?
6) Standard, Tables 1a and 1b: Would it be possible to provide an interval credit for full
parallel redundancy from relay to trip coil?
7) Table 1a (page 9) Voltage and Current Sensing Inputs to Protective Relays and
November 17, 2010
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associated circuitry – This maintenance activity statement implies that signal tests to
prove the voltage and current are present is all that is required. Can this be accomplished
by adding a step to the Relay Maintenance Job Plan to take a snapshot of the currents
and potentials (In-Service Read) with piece of test equipment?
8) Table 1b (Page 14) Control and Trip Circuitry - Level 2 Monitoring Attributes for
Component is too wordy and hard to understand the meaning. Does this whole paragraph
mean that the dc circuits need to be monitored and alarmed? At what level does the dc
control circuits need the alarming? Can this be at the control panel dc breaker output?
9) Table 1b (Page 15) Station Dc Supply - Should this be in Table 1c because the attributes
indicate that the station dc supply cells and electrolyte levels are monitored remotely. To
do a fully monitored battery system would be cost prohibitive and require a tremendous
amount of engineering.
10) Voltage and Current Sensing Inputs to Protective Relays and associated circuitry - This
maintenance activity statement implies that signal tests to prove the voltage and current
are present is all that is required. Can this be accomplished by adding a step to the Relay
Maintenance Job Plan to take a snapshot of the currents and potentials (In-Service Read)
with piece of test equipment?
11) Table 1a and 1b (Page 11 and 16) Associated communications system - Western has
monitoring capability on all Microwave Radio and Fiber Optics communications systems
with the Communications Alarm System that monitors and annunciates trouble with all
communications equipment in the communications network. The protective relays that
use a communications channel on these systems have alarm capability to the remote
terminal units in the substation. Since these are digital channels how does an entity prove
channel performance on a digital system?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see the new Table 1-5.
November 17, 2010
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2. The Standard requires that breakers (except for those for UFLS/UVLS) be tripped at least once during each 6 calendar year
interval. See new Table 1-5.
3. The Standard requires that breakers (except for those for UFLS/UVLS) be tripped at least once during each 6 calendar year
interval. See new Table 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
6. No. The SDT believes that it is important that all parallel paths be maintained within the indicated interval, and the prescribed
interval already considers the reliability benefits of parallel tripping paths.
7. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. It may be possible to do
as suggested in some cases; a snapshot may be able to determine that voltage and current is present at the relay. However, the
snapshot may not be sufficient to determine that the values are acceptable.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
10. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. It may be possible to do
as suggested in some cases; a snapshot may be able to determine that voltage and current is present at the relay. However, the
snapshot may not be sufficient to determine that the values are acceptable.
11. Many digital communications systems or digital relays themselves use bit-error-rate or other methods to monitor and alarm on
channel performance – check the design of the equipment used.
Southern Company
Transmission
November 17, 2010
No
1) Comment on Control Circuitry - Below in Figure 1 is a previous version of Table 1. It
clearly shows 3 levels of monitoring for Control Circuitry. For Unmonitored schemes such
as EM, SS, unmonitored MP relays, you must do a complete functional trip test every 6
years. For partially monitored schemes such as MP relays with continuous trip coil/circuit
monitoring, you must do a complete functional trip test every 12 years. For fully
monitored schemes where all trip paths are monitored, you do not have to trip test the
scheme but you still have to operate the breaker trip coils, EM aux/lockout relays every 6
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years. This is very clear and reasonable. The latest version of Table 1 is not very clear
or reasonable. The previous Partially Monitored control circuit monitoring requirements
were deleted and the Fully Monitored control circuit monitoring requirements were moved
to Partially Monitored requirements. We are not sure why this major change in
philosophy was made?? This makes all of our MP relay control schemes that
continuously monitor trip coils/circuits fall into the unmonitored category and therefore
requires a 6 year full functional trip test. For a scheme that monitors 99+% of the control
scheme (and probably 100% of the control scheme that actually has problems) to be
considered Unmonitored does not seem logical or reasonable to us. This puts these
“highly monitored” schemes in the same category and requires the same maintenance
requirements / intervals as EM relays with no alarms whatsoever. This also seems to
contradict the intent of the following statement from the Supplementary Reference doc on
page 9: Level 2 Monitoring (Partially Monitored) Table 1b This table applies to
microprocessor relays and other associated Protection System components whose selfmonitoring alarms are transmitted to a location (at least daily) where action can be taken
for alarmed failures. The attributes of the monitoring system must meet the requirements
specified in the header of the Table 1b. Given these advanced monitoring capabilities, it
is known that there are specific and routine testing functions occurring within the device.
Because of this ongoing monitoring hands-on action is required less often because
routine testing is automated. However, there is now an additional task that must be
accomplished during the hands-on process - the monitoring and alarming functions must
be shown to work. Recommendation - Please consider going back to the previous table
as shown below in Figure 1. It seems much clearer and reasonable. Feel free to convert
the old wording to the latest wording. Figure 1 - Previous Table - Control Circuitry See
Figure 1 in email documentation sent to Al McMeekin. Current Table - Control Circuitry
(see pdf file) See pdf file PRC-005-2_clean_20 10June88131418.pdf in email
documentation sent to Al McMeekin.
2) Comments: The comments below are grouped by component type. The following (5)
comments pertain to the maintenance intervals for protective relays:
November 17, 2010
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a. Is the “verify acceptable measurement of power system input values” activity listed in
the protective relay 6 year interval in Table 1a the same activity as the 12-year activity
for Voltage and Current Sensing Inputs in the same table?
b. Please clarify the meaning of “check the relay inputs and outputs” that are specified to
be checked for microprocessor relays at the following table locations: the protective
relay 6 year interval in Table 1a, the protective relay 12-year interval in Table 1b. Is this
referring to a check of the relay internal input recognition and output control ending at
the relay case terminals, or is this referring to a check extending to the source (and
target) of all inputs and outputs to the relay? The latter interpretation results in a repeat
of the maintenance required for dc control circuitry.
c. Are the second, third, and fourth maintenance activities in the Table 1a Protective
Relay, 6-year row those activities that apply to microprocessor relays? If so, we
suggest rewording these items as follows: For microprocessor relays, verify that the
settings are as specified, check the relay digital inputs and outputs that are essential to
proper functioning of the Protection System, and verify acceptable measurement of
power system analog input values.”
d. Please clarify the meaning of “Verify proper functioning of the relay trip contacts” found
in protective relays with trip contacts 12 year interval in Table 1c. Is this verification a
check of the relay internal contact to the relay case terminals or is this meant to be a trip
check functional test? This category of component does not appear in table 1a or 1b.
Should it? Is this activity the same as the protective relay Table 1b maintenance activity
“output actions used for tripping”? If so, please make the wording match exactly to
clarify.
e. Table 1c introduces the use of “Continuous” Maximum Maintenance Intervals. This is
inconsistent with the Table 1a and Table 1b usage of the interval. In Tables 1a and 1b
this interval is used to describe the maximum time frame within which the activities
shown in “Maintenance Activities” must be completed. The table column “Maintenance
Activities” has been used to identify those activities which must be performed in addition
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Question 1 Comment
to those accomplished by the monitoring attributes. To maintain consistency in use of
the interval and activity columns of Tables 1a, 1b, and 1c, each entry that uses the
“Continuous” interval should be changed to N/A and the Maintenance Activities should
be changed to either “No additional activities required” or “None, due to continuous
automatic verification of the status of the relays and alarming on change of settings”
[example given for Table 1c, Protective Relays]
3) The following (8) comments apply to Maintenance Tables 1a, 1b, and 1c for Station DC
supplies.
a. In Table 1a, Station dc supply, 18 calendar month, the verify item “Float voltage of
battery charger” is not listed in Table 1b. Is this requirement independent of the level of
monitoring and always required? If so, should it be added in to Table 1b and 1c, Station
dc supply, 18 calendar months above the “Inspect:” section?
b. The 6 year interval maintenance activity for NiCad batteries in Table 1a and Table 1b
should read “station battery” rather than “substation battery”.
c. It is recommended to simplify the Station dc supply sections in each of the three
maintenance tables by relocating the common items that do not change dependent
upon the level of monitoring. Specifically, the following rows of each of the three tables
have identical maintenance requirements that are independent of the level of
monitoring. The tables would be significantly simplified if these “monitor level
independent” requirements are moved outside of the table:
I. Station dc supply; 18 calendar months; Inspect: “
II. Station dc supply (that has a s a component Valve Regulated Lead Acid batteries)
III. Station dc supply (that has as a component Vented Lead Acid batteries)
IV. Station dc supply (that has as a component Nickel Cadmium batteries)
V. Station dc supply (battery is not used)
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d. Table 1a has 18 calendar month requirements for “Station dc supply (battery is not
used)”. This category is missing from Table 1b - was this intentional?
e. Table 1a has 6 calendar year and 18 calendar month requirements for “Station dc
supply (battery is not used)”. This category is missing from Table 1c - was this
intentional?
f. Please clarify the meaning of “Battery terminal connection resistance”. Does this apply
only to multi-terminal batteries? Is this referring to the cables external to the battery (to
the charger and load panel)?
g. Table 1c contains a Type of Protection System Component not found in any of the
other tables: “Station dc supply (any battery technology). Is this the same as “Station
dc supply” found in Tables 1a and 1b?
h. The Level 3 Monitoring Attributes for “Station dc supply (any battery technology)” are
identical to the Level 2 Monitoring Attributes for “Station dc supply”. This appears to be
duplicative in description with two different “maximum maintenance intervals” and
“maintenance activities” listed.
4) The following (3) comments pertain to the Voltage and Current Sensing Input component
type:
a. Why is “signals” bolded in the Table 1a row for this component type?
b. Are the Table 1a, 12 year maintenance activities for this component type a
duplication of the Table 1a, Protective relay, 6 year maintenance activity for
microprocessor relays (verify acceptable measurement of power system input
values)?
c. Why is this component type highlighted in bold in Table 1c?
5) The following (8) comments pertain to the Control and Trip Circuit component type:
a. Why are microprocessor relay initiated tripping schemes excluded from the 6 year
November 17, 2010
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Question 1 Comment
complete functional testing? The auxiliary relay operations resulting from these
initiating devices are just as likely to stick (mis-operate) as those initiated from
electromechanical devices.
b. We propose simplifying Table 1a for this component type by grouping the two 6 year
and the two 12 year interval maintenance lines into two rather than four table rows.
The 6 year interval maintenance activities for the UFLS/UVLS systems could be
addressed in the table row above using a parenthetical adder to the existing text = (for
UFLS/UVLS systems, the verification does not require actual tripping of circuit breakers
or interrupting devices). All of the other text in the UFLS/UVLS table row matches that
found two rows above. The same parenthetical adder in the first 12 year interval row
for this component type would eliminate the need for the (UFLS/UVLS Systems Only)
row for 12 year intervals.
c. If the two rows are combined as suggested previously - this comment is irrelevant:
The Table 1a 6 year interval activity for UFLS/UVLS Systems Only is missing the word
“contacts” after auxiliary.
d. There appears to be no difference in the 6 year interval maintenance activities for this
component type in Table 1a and Table 1b. Table 1b monitoring attributes include
“Monitoring and alarming of continuity of trip circuits”, but the interval between
electrically operating each breaker trip coil, auxiliary relay, and lockout relay remains at
6 years. What maintenance activity advantage do the Level 1b monitoring attributes
provide?
e. The difference between the two DC Control Circuits in Table 1b (on page 14) is
unclear. What is the difference between the “Control Circuitry (Trip Circuits)” and the
“Control and trip circuitry”? We propose combing the multiple table rows for this
component type into a single line item for this component type, as it takes a
combination of the protective relay action, any auxiliary relay, and the circuit breaker to
comprise a complete tripping system.
f. We have three questions on the monitoring attributes given for this component type on
November 17, 2010
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page 14:
I. Does the attribute beginning “Monitoring of Protection ...” indicate a requirement to
monitor every input, every output, and every connection of every Protection System
Component involved in each tripping scheme?
II. Does the attribute beginning “Connection paths...” related to monitoring of
communication paths?
III. Does the attribute beginning “Monitoring of the continuity...” require the presence of
coil monitoring of any auxiliary relay whose contact is encountered when tracing a
tripping path from a protective relay to a breaker?
g. Are the Table 1c attributes for this component type different from the monitoring
described in Table 1b beginning “Connection paths...”?
h. Are there no requirements to operate any relays functionally for “Protection System
control and trip circuitry” in Table 1c? The devices need to be exercised some or they
will not be reliable.
6) The following (1) comment pertains to the Associated communications system
component type:
The Table 1b monitoring attribute for this component type (communications channel
monitor and alarm) clearly should (and does) eliminate the Table 1a, 3 month interval
activity (verifying the communication system is functional). The common maintenance
activities found in Table 1a (6 year) and Table 1b (12 year) should be same interval - either
6 or 12.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1 for all five of these
November 17, 2010
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Question 1 Comment
comments.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4 for all eight of these
comments.
3f. Please see IEEE 450-2002 Appendix F, IEEE 1188-2005 Appendix D, and Section 6.3.2 of IEEE 1106-2005 for clarification of the
meaning of “battery terminal connection resistance”.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3 for all three of these
comments.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5 for all eight of these
comments.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-2 for this comment.
Consumers Energy
Company
No
1. If multiple redundant Protection System components, with associated parallel tripping
paths, are provided, Table 1a, 1b, and 1c require that each parallel path be maintained,
and that the maintenance be documented. Often, these multiple schemes are provided
not to meet specific reliability-related requirements, but instead to provide operating
flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will
be very cumbersome, and will lead to increased compliance exposure simply by its
volume. This may perversely lead to entities NOT installing the redundant schemes,
resulting in decreased reliability.
2. Many of the activities described in the Tables are not, by themselves, clear. The
standard should include sufficient detail such that entities are clear as to what must be
done for compliance, rather that relying on supplementary documents for this information.
For example, it’s not clear, in Table 1a (Station DC Supply), what is meant by, “Verify that
the dc supply can perform as designed when the ac power from the grid is not present.”
Similarly, it isn’t clear from the general description within the Tables that components
possessing different monitoring attributes within a single scheme, may be distinguished
November 17, 2010
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Question 1 Comment
such that differing relevant tables can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station
battery can perform as designed by evaluating the measured cell/unit internal ohmic
values to station battery baseline. Battery assemblies supplied by some manufacturers
have the connections made internally, making this option unavailable. Experience with
ASME standards show that NERC and SDT members may be jointly and separately
liable for litigation by specifying methods that either prefer or prohibit use of certain
technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional
trip ...” conclude with “... does not require actual tripping of circuit breakers or other
interrupting devices. Do the other two such activities therefore require tripping of circuit
breakers or other interrupting devices?
5. Performance of the minimum activities specified within Table 1a for legacy systems,
particularly regarding control circuits, will require considerable disconnection and
reconnection of portions of the circuits. Such activities will likely cause far more problems
on restoration-to-service than they will locate and correct. We suggest that the SDT
reconsider these activities with regard for this concern.
Response: Thank you for your comments.
1. The SDT believes that it is important that all parallel paths be maintained within the indicated interval, and the prescribed interval
already considers the reliability benefits of parallel tripping paths.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. The use of the term “cell/unit” acknowledges that individual cells may not be accessible, but that assemblies of several cells (into
units) may be available instead, and may be used to address this Requirement. An acceptable base-line value and follow-on tests
may be acceptable for the entire station battery as a single unit.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
November 17, 2010
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5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. To the degree that
performance history for the components within these systems is available, a performance-based program per Requirement R3 and
Attachment A may be useful in these cases.
JEA
No
1. R1.1 What is a Protection System component? Could the SDT provide a better
understanding of what is meant by component?
2. R4: A “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
3. R4: Suggest a stepped VSL for “Entity has failed to initiate resolution of maintenancecorrectable issues”. While we understand the importance of addressing a correctable
issue, it seems like there should be some allowance for an isolated unintentional failure to
address a correctable issue.
Response: Thank you for your comments.
1. A definition of “Component” has been added to the draft Standard. The SDT’s intent is that this definition will be used only in PRC005-2, and thus will remain with the Standard when approved, rather than being relocated to the Glossary of Terms.
2. This comment appears to be related to the VSL for Requirement R1, not Requirement R4 as indicated. The SDT disagrees that this
is a “documentation” issue, and believes that that the related Requirement is fundamental to establishing an effective PSMP per this
Standard. Also, this VSL is graded such that missing up to 5% of the required activity is indeed a Lower VSL.
3. The VSL for Requirement R4 has been modified as suggested.
Entergy Services
November 17, 2010
No
1. Table 1a has a “Control and trip circuits with electromechanical trip or auxiliary contacts
(except for microprocessor relays, UFLS or UVLS)” component type listed, and there is a
“Control and trip circuits with electromechanical trip or auxiliary [editorial comment: add
‘contacts’] (UFLS/UVLS systems only)” component type listed. Suggest a “Control and
trip circuits with electromechanical trip or auxiliary contacts” for a microprocessor relay
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application should be addressed since it seems to be missing.
2. The term “check” has replaced “verify” for some of the maintenance activities in this draft
version. What is the difference between these two terms, and shouldn’t “check” be
defined if it is to be included as a PSMP activity term?
3. Assuming the term “check” replaced “verify proper functioning” in order to allow for the
completion of a maintenance activity within the required interval and yet account for a
maintenance correctable issue being present, suggest the other remaining activities in
the tables where the term “verify proper functioning” is used, also be replaced with
“check”.
4. Consider modifying the definition of “verification” to “A means of determining or checking
that the component is functioning properly or maintenance correctable issues are
identified”, eliminate use of the term “verify proper functioning” (which seems to be
redundant by PRC-005-2 standard definition), and simply use the term “verify”.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. “Check” is not an element of the PSMP definition. This term has been replaced throughout the tables with whatever term of the
definition is relevant.
3. “Check” is not an element of the PSMP definition. This term has been replaced throughout the tables with whatever term of the
definition is relevant.
4. The terms within the PSMP definition have been revised to reflect the action (“verify” rather than “verification,” for example). The
SDT believes that the use of the term “verify” within the modified tables and the definition of this component in the PSMP definition
is appropriate and correct.
MEAG Power
November 17, 2010
No
1. The descriptions for the "type of protection system components" do not appear to be
consistent between Tables, 1a, 1b and 1c.
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2. The maximum maintenance interval for a lead-acid vented battery is listed at 6 calendar
years for performing a capacity test. This type of test has been proven to reduce battery
life and an interval of 10 to 12 years would be better.
3. The maximum maintenance interval for "Station DC supply" was set at 3 months. This is
too short of a period and 6 months would be better.
4. The control and trip circuits associated with UVLS and UFLS do not require tripping of
the breakers but all other protection systems require tripping of the breakers, this appears
to be inconsistent?
5. Digital relays have electromagnetic output relays. Do they fall into the electromechanical
trip or solid state trip?
6. Need for clarification: The standard indicates that only voltage and current signals need
to be verified. Does this mean that voltage and current transformers do not need to be
tested by applying a primary signal and verifying the secondary output?
Response: Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
2. The SDT disagrees, and believes that a capacity test at 6-year levels is appropiate. A properly maintained battery, according to
various credible references (from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle multiple deep discharges over its
expected life.
3. The activity related to this interval is to verify various basic operating parameters. The SDT believes that extension of verification of
these parameters beyond the interval within the Standard is inappropriate.
4. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the Standard,
because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system elements.
5. These devices fall under “electromechanical output contacts.” The Tables have been rearranged and considerably revised to
improve clarity. Please see new Table 1-1.
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No
Question 1 Comment
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
Ameren
No
Ameren does agree that draft 2 is a considerable improvement from draft 1 of PRC-005-2;
however the following still need to be addressed.
1) Use “Control circuitry” to be consistent with the proposed definition. If ‘and trip’ was
included so that users would know this is a trip circuit, then the definition should use ‘Trip
circuitry’ instead of ‘Control circuitry’. It is important to use consistent terminology
throughout the definition and the standard.
2) Please add row numbers in each of Tables 1a, 1b, and 1c, and arrange so that row 1 in
each table corresponds, etc. (or state which rows correspond to each other.) This would
help clarify movement from table to table. The number of sub clauses, nuances, and
varied Type of Component descriptors among rows in the same table as well as from
table-to-table can be overwhelming. This would help keep Regional Entities and System
Owners from making errors.
3) Please clarify that the instrument transformer itself is excluded. The standard indicates
that only voltage and current signals need to be verified. The FAQ seems to cover this,
but see our comments on your question 6.
4) Clarifications need to be made on testing requirements on trip contacts relative to
microprocessor vs. EM relays. Digital relays have electromagnetic output relays. Do they
fall into the electromechanical trip or solid state trip?
5) There appears to be an inconsistency in the use of “check” vs. “verify” in the tables.
Consider modifying the definition of “verification” to “A means of determining or checking
that the component is functioning properly or that the maintenance correctable issues are
identified”, eliminate use of the term “verify proper functioning” (which seems to be
redundant by PRC-005-2 standard definition), and simply use the term “verify”.
6) Alternately if the term “check” replaced “verify proper functioning” in order to allow for the
completion of a maintenance activity within the required interval and yet account for an
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Consideration of Comments on PSMTSDT — Project 2007-17
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Yes or
No
Question 1 Comment
outstanding maintenance correctable issue being present, suggest the other remaining
activities in the tables where the term “verify proper functioning” is used, also be replaced
with “check”.
7) If there is an intentional difference between “verify” and “check”, shouldn’t “check” be
defined if it is to be included as a PSMP activity term?
8) Functional trip testing will require extensive analysis and could involve an extensive
testing evolution to ensure the correct circuit is tested without unexpected trip of other
components, particularly for generator protection systems and some transmission
configurations. The complexity of the system and the test would be conducive to an error
that resulted in excessive tripping, thus affecting the reliability of the BES. It would seem
that the potential for an adverse affect from this test would be greater than the benefit
gained of testing the circuit. In addition, scheduling outages to perform the functional trip
testing in conjunction with other outages required to perform maintenance and other
construction activities will be difficult due to the large number of outage requirements for
the functional testing. This will challenge the BES more often and thus reduce reliability.
For these reasons functional trip testing is too frequent, and should be extended to twelve
years.
9) In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now. Many
batteries are packaged such that the individual cells are not accessible.
10) IEEE battery maintenance standards call for quarterly inspections. These are targets,
though, not maximums. An entity wishing to avoid non-compliance for an interval that
might extend past three calendar months due to storms and outages must set a target
interval of two months thereby increasing the number of inspections each year by half
again. This is unnecessarily frequent. We suggest changing the maximum interval for
battery inspections to 4 calendar months. For consistency, we also suggest that all
intervals expressed as 3 calendar months be changed to 4 calendar months.
11) Replace “State of charge of the individual battery cells/units” with “Voltage of the
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Consideration of Comments on PSMTSDT — Project 2007-17
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Yes or
No
Question 1 Comment
individual battery cells or units”.
12) The maximum maintenance interval for a lead-acid vented battery is listed at 6 calendar
years for performing a capacity test. This type of test has been proven to reduce battery
life and an interval of 10 to 12 years would be better.
13) The level 2 table regarding Protection Station dc supply states that level 1 maintenance
activities are to be used, but then goes on to give a list of Maintenance Activities that
don’t match those in level 1. Which activities shall we use? Same situation for Station DC
Supply (battery is not used) where the 18 month interval is missing.
14) Also, Table 1B, in the second to last row, should be referring to UFLS rather than SPS.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
3. The definition has been modified to clarify that instrument transformers ARE part of the Protection System, and the maintenance
activities in the new Table 1-3 specify WHAT must be done regarding this component type. The FAQ (II.3.A) is correct on this
subject.
4. The Tables have been rearranged and considerably revised to improve clarity. These devices fall under “electromechanical output
contacts.” The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
5. “Check” is not an element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the
definition is relevant. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
6. “Check” is not an element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the
definition is relevant. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
7. “Check” is not an element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the
definition is relevant.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
November 17, 2010
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Question 1 Comment
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This element of the table
has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to
address this comment.
10. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. The Requirement
remains as “3 Calendar Months” and the SDT is not prescribing or suggesting what measures an entity may take within their
program to assure compliance.
11. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. Verification of voltage
of individual cells, etc., is one method; there are other ways.
12. The SDT disagrees, and believes that a capacity test at 6-year intervals is appropiate for Vented Lead Acid and Ni-Cad batteries.
A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI, various manufacturers, etc.), can
easily handle multiple deep discharges over its expected life.
13. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
14. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-5.
American Transmission
Company
November 17, 2010
No
ATC feels additional changes are needed.
1. The functional testing requirement should be altered or removed as it increases the
amount of hands-on involvement and the opportunity for human error related outages to
occur, thereby introducing more opportunities to decrease system reliability. As noted
on p. 8 in the supplementary reference document, “Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.”
By removing circuits from service on the proposed timelines for functional testing, the
chance for human error is greater than a mis-operation from faulty wiring. Alternatively,
entities may choose to schedule more planned outages to conduct their functional
testing in order to limit the risk of unplanned outages resulting from human error. Under
this scenario, more elements will be scheduled out of service on a regular basis, thereby
reducing transmission system availability and weakening the system making it more
challenging to withstand each subsequent contingency (N-1). Thus testing an in-tact
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Consideration of Comments on PSMTSDT — Project 2007-17
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Question 1 Comment
system is more desirable than taking it out of service for testing.
2. While the SDT has included language in the draft standard to use fault analysis to
complete maintenance obligations, in practicality, this option does not offer any relief to
taking outages to perform functional tests. Nearly all BES circuit breakers are equipped
with dual trip coils. Identifying which trip coil operated for a fault only covers the one trip
coil. Functional tests would still be needed on the other. The likelihood of having
multiple trips on a given line in the course of several years is very low. Given it can take
a year to schedule some outages, planning maintenance with random faults is
unpractical and will create unacceptable risk to compliance violations. A better
approach is to use the basis in schedule A, but extend this to cover the entire protection
schemes. The document should establish target goals for mis-operation rates
(dependability and security). This would allow the utilities to develop cost effective
programs to increase reliability. The utilities would have incentives to replace poorly
performing communications systems; they would be able to quantify the value of
upgrading relay systems.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. Operational results, if desired by an entity, MAY be used to meet maintenance requirements to the degree that they verify, etc., the
relevant performance. Whether their use is effective for a specific entity is left to the entity to determine. “Maintenance correctable
issues,” which may result in part from misoperations, are a part of using Attachment A to develop a Performance Based PSMP.
Corporate Compliance
No
Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s
lead-calcium batteries are relatively stable for a 6 month period compared to lead-antimony
batteries used in the past.
Response: Thank you for your comments. The activity related to this interval is to verify various basic operating parameters. The SDT
believes that extension of verification of these parameters beyond the interval within the Standard is inappropriate.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Northeast Power
Coordinating Council
Yes or
No
No
Question 1 Comment
1. Clarification is needed for “to a location where action can be taken”. Some examples in
the FAQ will help in this clarification.
2. What type of documentation is required to show compliance that maintenance
correctable issue has been reported?
3. Clarify the removal of requirement (see redline version, third row of Table 1a) for testing
of unmonitored breaker trip coils. Is it the intention of the SDT to remove a requirement
that would drive the industry to install TC monitors on breakers to improve reliability?
4. UFLS/UVLS DC control and trip circuits (Rows 5 and 6 of Table 1a) - Due to the
distributed nature of this program, random failures to trip are not impactive to the overall
operation of the UFLS protection. There should be no requirement to check the DC
portion of these protections any more often than the DC circuit checks associated with
that LV breaker. Since it is clear the requirement does not include the need to trip the
breakers why the need to check the trip paths? Deletion of this requirement leaves the
requirement to check only the relays and relay trip outputs from the protections every 6
years (or as often as the protective relay component type). Should the maintenance
activities for “UVLS and UFLS relays that comprise a protection scheme distributed over
the power system” not be the same as “Protective Relays”? V and I sensing to relays
have a 12 year Maximum Maintenance Interval listed. It is good work practice to have
this activity done the same time as maintenance activities associated with relay
maintenance.
5. What is the basis for the various Maximum Maintenance Intervals listed in Table 1a?
6. From page 12 of the redline version, for "Station dc Supply (used only for UFLS and
UVLS)", is the requirement applicable to distribution substations only?
7. For “Control and trip circuits with unmonitored solid-state trip or auxiliary contacts
(UFLS/UVLS Systems only)” under Maintenance Activities - the word “complete: may be
removed as it requires to actually trip the breakers. The sentence that tripping of the
circuit breakers is not required contradicts with the word “complete”. More specifics are
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
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Yes or
No
Question 1 Comment
required to spell out the adequate testing e.g. up to the lockout with the trip paths
isolated etc. See Page 12 of the redline version.
8. For “Station dc Supply” having 18 calendar months as the Maximum Maintenance
Interval, a battery has a 20 year life. IEEE standard PM is on a quarterly basis. What is
the basis of the 18 calendar month interval? See page 12 of the redline version.
9. For “Associated communications systems” with a Maximum Maintenance Interval of 6
Calendar years, why is this required? The text "Verify proper functioning of
communications equipment inputs and outputs that are essential to proper functioning
of the Protection System. Verify the signals to/from the associated protective relay(s)"
seems sufficient to ensure reliability. See page 15 of the redline version.
10. For “Relay sensing for Centralized UFLS or UVLS systems UVLS and UFLS relays that
comprise a protection scheme distributed over the power system” under maintenance
activities, clarify “overlapping segments”. What is the specified interval? Is actual
breaker tripping required? See page 15 of the redline version.
11. On the row for Associated communications systems in Table 1c, in the Level 3
Monitoring Attributes for Component column, suggest a change in wording to:
Evaluating the performance and quality of the channel as well as the performance of
any interface to connected protective relays and alarming if the channel/protective relay
connections do not meet performance criteria.
12. In Table 1c it is required to report the detected maintenance correctable issues within 1
hour or less to a location where action can be taken to initiate resolution of that issue.
Even for a fully monitored protection system component it can be difficult to report the
action in 1 hour. A 24 hour period for both Level 2 and Level 3 reporting of maintenance
correctable issues is recommended.
Response: Thank you for your comments.
1. This is addressed in the Supplementary Reference document as posted with this draft (Section 8.1 and Section 13), and within the
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
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Yes or
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Question 1 Comment
FAQ as posted with this draft Standard (V.3.D).
2. Specific effective forms of documentation are left to the entity to determine, but the SDT believes that this could include, among
other things, work orders addressing the maintenance correctable issue.
3. The Tables have been rearranged and considerably revised to simplify and improve clarity. Please see new Table 1-5. Specifically
to your comment, the SDT initially specified inspection of trip-coil monitoring functions at intervals of 3 months, with tripping
otherwise requried annually. This has been revised to simply require tripping at 6-calendar-month intervals.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
5. Please see Supplementary Reference, Section 8.3.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. Specifically for this item,
this applies to whatever interrupting device is being tripped by the UFLS/UVLS. To the degree that the same interrupting devices
are tripped by other Protection System components, the relevant Requirements apply.
7. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
8. This interval is based on EPRI and other industry documents referencing these specific activities.
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
10. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
11. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
12. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 2. This requirement is now
uniformly 24 hours as suggested within the comment.
SERC Protection and
Control Sub-committee
(PCS)
No
1. Clarifications need to be made on testing requirements on trip contacts relative to
microprocessor vs. EM relays. There appears to be an inconsistency in the use of
“check” vs. “verify” in the tables.
2. Also, Table 1B, in the second to last row, should be referring to UFLS rather than SPS.
3. Also, note that M2 incorrectly excludes distribution provider.
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Yes or
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Question 1 Comment
4. In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. Measure M2 has been corrected as suggested.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
BGE
No
Comment 1.1: In its decision to use “calendar years” with the maintenance intervals
prescribed for most components the SDT has provided a framework that is consistent
with a well-run PSMP but with enough flexibility to be practical. However BGE believes
the application of this approach to short maintenance intervals, like three months for
some battery maintenance will risk numerous violations due to practical scheduling
constraints that are not a realistic threat to reliability. As the requirements are presently
defined the inherent flexibility for battery maintenance that is nominally done on three
month intervals may be as long as 1/3 of the interval or as short as one day (Our
interpretation: Maintenance last done on January 1 is next due on April 1 and can be
done no later than April 30. Maintenance done on Jan 31 is next due on April 30 and is
overdue if done on May 1). The only practical solution is to increase the frequency so that
the average intervals are significantly shorter than the nominal requirement.BGE
recommends an alternate formulation for intervals if the nominal interval is less than one
year. Some possible alternatives (assuming a three month nominal interval): Once per
calendar quarter no later than the end of the quarter no earlier than one month before it.
Four times per year, no more than 120 days apart no less than 60.
Comment 1.2: On page 11, Row-3/Column-1 of Table-1a includes the following entry for
functional trip testing:"Control and trip circuits with electromechanical trip or auxiliary
contacts (except for microprocessor relays, UFLS or UVLS)". It is not clear why
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
electromechanical trip contacts in microprocessor relays are excluded.
Comment 1.3: On page 12, Row-3/Column-3 of Table-1a includes the following Verification
Task for Station DC Supplies: "Verify Battery cell-to-cell connection resistance". Multiple
cell units do not provide the ability to measure cell-cell resistance.
Response: Thank you for your comments.
1. The intervals remain as prescribed within the Standard and are designed to be effective, clear, and consistently monitored for
compliance; the SDT is not prescribing or suggesting what measures an entity may take within their program to assure compliance.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where
available to measure)” to address this comment.
Constellation Power
Generation
No
1. Constellation Power Generation (CPG) does not agree with the maximum maintenance
interval for associated communication systems and station dc supply that has as a
component any type of battery, which is 3 months. If the intent of the drafting team was to
make this test quarterly (as recommended in IEEE-450), than the maximum interval
should be 4 months. As written, for a registered entity to ensure they complete this test in
an interval less than 3 months, they will most likely complete this test every 2 months.
This causes two additional and unwarranted tests every year. CPG recommends an
alternate formulation for intervals if the nominal interval is less than one year. Some
possible alternatives (assuming a three month nominal interval):
Once per calendar quarter no later than the end of the quarter no earlier than one month
before it.
Four times per year, no more than 120 days apart no less than 60.
2. CPG does not agree with differentiating between the different battery types. A
suggestion would be to take the maximum maintenance interval for all the battery types,
which is 6 years, and apply them across all types of batteries, eliminating the need to
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
differentiate between them. Furthermore, multiple cell units do not provide the ability to
measure cell-cell resistance, and so that requirement should be removed.
3. CPG is not clear why electromechanical trip contacts in microprocessor relays are
excluded in Table 1a.
Response: Thank you for your comments.
1. The intervals remain as prescribed within the Standard and are designed to be effective, clear, and consistently monitored for
compliance; the SDT is not prescribing or suggesting what measures an entity may take within their program to assure compliance.
2. The appropriate maintenance activities and intervals differ considerably for various battery types. This element of the table has
been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to address
this comment.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
Exelon
No
Exelon does not completely agree with the minimum maintenance activities and maximum
allowable intervals as suggested by SDT. Comments on minimum maintenance activities:
1. Reference Table 1a (Page 11) of Standard PRC-005-2: With regard to the maintenance
activity: "Verify that the station battery can perform as designed by conducting a
performance ......". The standard should clearly define what is meant by "perform as
designed" to eliminate ambiguity in future interpretations.
2. Also, Table 1a Station dc supply (that has as a component Vented Regulated Lead-Acid
batteries) discusses “modified performance capacity test of the entire battery bank”.
This needs additional clarification or should be reworded because modified test includes
both the performance test (which is the capacity test) and the service test. Should be
reworded to be “modified performance test”.
3. Comments on maximum allowable intervals:
Nuclear generating stations have refueling outage schedule windows of approximately
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
18 months or 24 months (based on reactor type). If for some reason the schedule
window shifts by even a few days, an issue of potential non-compliance could occur for
scheduled outage-required tasks. The possibility exists that a nuclear generator may
be faced with a potential forced maintenance outage in order to maintain compliance
with the proposed standard. For the requirements with a maximum allowable interval
that vary from months to years (including 18 Months surveillance activities), the SDT
should consider an allowance for NRC-licensed generating units to default to existing
Operating License Technical Specification Surveillance Requirements if there is a
maintenance interval that would force shutting down a unit prematurely or face noncompliance with a PRC-005 required interval. Therefore, Tables 1a, 1b & 1c should
include an allowance for any equipment specifically controlled within each licensee’s
plant specific Technical Specifications to implement existing Operating License
requirements if such a conflict were to occur. Please see additional comments under
Q7.
Response: Thank you for your comments.
1. This concern is addressed within IEEE standards (specifically IEEE 450, IEEE 1188, and IEEE 1106) by their description and
definition of a “performance test” as further established within this requirement. The SDT believes that entities involved in battery
maintenance will be familiar with these IEEE standards.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. It is left to the the entity to determine how to align these requirements with requirements of other
regulations and with operational concerns. Entities should be able to complete the activities with 18-month or shorter intervals
without outages. See the SDT responses to your comments in Question 7.
Black Hills Power
November 17, 2010
No
1. For Protective Relays, Table 1a Maintenance Activities has no requirement for verifying
output contacts on non-microprocessor based relays. The actual contacts used for
tripping should be verified by this activity.
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Consideration of Comments on PSMTSDT — Project 2007-17
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Question 1 Comment
2. For Protective Relays, Table 1b Maintenance Activities states “Verify correct operation
of output actions that are used for tripping”. This requirement is vague and needs to
define whether all protection logic or conditions that would initiate a relay trip output are
required to be simulated and tested to the relay tripping output contact.
3. For Voltage and Current Sensing Inputs to Protective Relays and associated circuitry,
Table 1a references “current and voltage signals” and Table 1b references “current and
voltage circuit signals”. Need consistency or definitions to meet this requirement.
4. For Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS
Systems Only), Table 1a states “except that verification does not require actual tripping
of circuit breakers or interrupting devices.” This exception to the requirement seems to
defeat the whole purpose of the standard and leaves a huge gap open to interpretation
and conflict. -For Control and trip circuits with unmonitored solid-state trip or auxiliary
contacts (UFLS/UVLS Systems Only), Table 1a states “except that verification does not
require actual tripping of circuit breakers or interrupting devices.” This exception to the
requirement seems to defeat the whole purpose of the standard and leaves a huge gap
open to interpretation and conflict.
5. For Station dc supply, Table 1a requirement includes “Inspect: The condition of nonbattery-based dc supply.” This is redundant with the requirements of the section Station
dc supply (battery is not used) and should be removed from this section.
6. For Voltage and Current Sensing Inputs to Protective Relays and associated circuitry, a
maximum interval of verification of 12 years seems to contradict the intent of the rest of
the Maintenance standard which dictates 6 years on all of the other components. The
requirement for these components should fall in line with the rest of the standard.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1. “Verify” is defined within
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
the PSMP defintion.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. This is an intentional
difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the Standard, because of the
distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system elements.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. These devices are not
typically subject to in-service degradation to the degree that those with 6-year intervals are. Entities have the latitude to perform
maintenance more frequently than specified if they feel that such maintenance is needed.
Duke Energy
No
General comment - the draft changes the word “verify” to “check” in several places; should
use consistent phrasing throughout the standard.
With regards to Table 1a, we have the following comments:
1. Control and trip circuits with electromechanical trip or auxiliary contacts (except for
microprocessor relays. UVLS or UFLS) - We believe that while there may be value in a 6
calendar year cycle, this will be difficult to accomplish, since you either have to get
outages scheduled or block protection, which risks reliability. Since this is essentially a
re-commissioning check, the cycle should be 12 calendar years. Also 6 years appears to
be in conflict with the system protection standard.
2. Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (except for
UVLS or UFLS) - agree with 12 calendar years as consistent with electromechanical
above.
3. Control and trip circuits with electromechanical trip or auxiliary (UVLS or UFLS Systems
Only) - 6 year cycle should be changed to 12 calendar years (see comment above on
non-UVLS/UFLS).
4. Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (UVLS or
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
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Yes or
No
Question 1 Comment
UFLS Systems Only) - agree with change to 12 calendar years.
5. Station dc Supply (used only for UVLS or UFLS) - Strike the word “Station”. We don’t
differentiate between dc supply used for UFLS and other protection.
6. Station dc supply - Change 18 calendar months to 24 months, since this testing requires
generator outages. Nuclear plant fuel cycles can be longer than 18 months.
7. Associated communications systems - More clarity is needed regarding what is to be
included in the definition of “Associated”.
Response: Thank you for your comments. “Check” is not an element of the PSMP definition. The term has been replaced throughout
the tables with whatever term of the definition is relevant.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. The circuit itself is 12
years, but interval for the electromechanical devices such as aux or lockout relays remains at 6 years, as these devices contain
“moving parts” which must be periodically exercised to remain reliable.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
6. The SDT believes the specified intervals and activities are technically effective, and in a fashion that may be consistently
monitored for compliance. The entity must determine how to best align these requirements with requirements of other regulations
and with operational concerns. Entities should be able to complete the activities with 18-month or shorter intervals without
outages.
7. This portion of the definition of Protection System has been modified for clarity. Also, the Tables have been rearranged and
considerably revised to improve clarity. Please see new Table 1-3.
American Electric Power
November 17, 2010
No
1. In Table 1a for the component “Station dc Supply (used only for UVLS and UFLS)”, the
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Question 1 Comment
interval prescribed is "(when the associated UVLS or UFLS system is maintained)" and
the activity is to "verify the proper voltage of the dc supply". The description of the
interval "(when the associated UVLS or UFLS system is maintained)" needs to be
changed. Relay personnel do not generally take battery readings. The interval should
read “according to the maximum maintenance interval in table 1a for the various types
of UFLS or UVLS relays". The testing does not need to be in conjunction with the relay
testing, it is only the test interval that is important, although relay operation during relay
testing is a good indicator of sufficient voltage of the battery.
2. The monitoring and/or maintenance activities listed for batteries are not appropriate in
Tables 1b and 1c. There are no commercial battery monitors that monitor and alarm for
electrolyte level of all cells. Why not move the electrolyte level to the 18 month
inspection and actually open the possibility of condition monitoring to commercially
available devices? Or give an option to do the electrolyte check at other time intervals
(perhaps 12 months) by visual electrolyte inspection and still allow the monitoring of
other functions on the listed 6 year schedule using condition monitoring. It makes no
sense to prescribe an unattainable condition monitoring solution. The way that the
tables are written, there is no advantage to use the charger alarms since battery
maintenance requirements are not reduced in any way.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
Great River Energy
November 17, 2010
No
1. In Table 1a section-Station DC Supply - 18 calendar months, under Maintenance
Activities column, suggest changing under Verify: Battery terminal connection resistance
To: Entire battery bank terminal connection resistance (This could have been interpreted as
individual batteries) And change: Battery cell-to-cell connection resistance To: Battery cellto-cell connection resistance, where an external mechanical connection is available.
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2. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid
batteries) suggest changing Max Maintenance Interval=3 Calendar Years or 3 Calendar
Months to 4 Calendar Years or 12 Calendar Months. Our concern is that the insurance
companies may push NERC maintenance intervals on all battery banks not associated with
the BES.
3. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max
Maintenance Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason:
performance tests may degrade the battery.
4. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max
Maintenance Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason:
performance tests may degrade the battery.
5. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and
trip circuitry) we suggest the following change: If a trip circuit comprises multiple paths, at
least one of those paths is monitored. Alarming for loss of continuity or dc supply for trip
circuits is reported to a location where action can be taken.
6. While all tripping circuits are not completely monitored, the trip coils and the outdoor
cable runs are completely monitored. The only portion that would not be monitored is a
portion of inter and intra-panel wiring having no moving parts located in a control house.
Our company has extremely low failure rate of panel wiring and terminal lugging. I don’t
think that there is provision for moving control and trip circuitry to performance based
maintenance? This control circuitry should be maintained less frequent than un-monitored
trip circuits (6 years).
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This element of the
Table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to
address this comment.
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2. NERC Standards are limited to facilities and equipment related to the BES. How the Standard may be otherwise used is outside the
scope of NERC Standards.
3. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Ni-Cad batteries. A properly
maintained battery, according to various credible references (from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle
multiple deep discharges over its expected life.
4. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Vented Lead Acid and Ni-Cad
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI, various manufacturers,
etc.), can easily handle multiple deep discharges over its expected life.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. Nothing in the draft
Standard (including Attachment A) precludes an entity from using performance-based maintenance for dc control circuits.
Long Island Power
Authority
No
1. In Table 1c it is required to report the detected maintenance correctable issues within 1
hour or less to a location where action can be taken to initiate resolution of that issue.
Even for a fully monitored protection system component it can be difficult to report the
action in 1 hour. LIPA recommends a 24 hour period for both Level 2 and Level 3
reporting of maintenance correctable issues. The time identified is report time and not
response time to correct issue.
2. LIPA seeks clarification on “to a location where action can be taken”. Some examples in
the FAQ will help in this clarification.
3. What type of documentation is required to show compliance that maintenance
correctable issues have been reported?
4. What is the basis of the various Maximum Maintenance Intervals tabulated in Table 1aTime based maintenance?
Response: Thank you for your comments.
November 17, 2010
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1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5 and Table
2. These Tables reflect your proposed change.
2. This is addressed in the Supplementary Reference document as posted with this draft (Section 8.1 and Section 13), and within
the FAQ as posted with this draft Standard (V.3.D).
3. Specific effective forms of documentation are left to the entity to determine, but the SDT believes that this could include, among
other things, work orders addressing the maintenance correctable issue.
4. Please see Section 8.3 of the Supplementary Reference document.
Northeast Utilities
No
1. In Table 1c it is required to report the detected maintenance correctable issues within 1
hour or less to a location where action can be taken to initiate resolution of that issue.
Even for a fully monitored protection system component it can be difficult to report the
action in 1 hour. Recommend a 24 hour period for both Level 2 and Level 3 reporting of
maintenance correctable issues.
2. Additionally, please clarify meaning of “to a location where action can be taken”.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5 and Table
2. These tables reflect your proposed change.
2. This is addressed in the Supplementary Reference document as posted with this draft (Section 13), and within the FAQ as posted
with this draft Standard (V.3.D).
MidAmerican Energy
Company
November 17, 2010
No
1. In the tables trip circuit has been replaced by “control and trip circuit”. From the context
of the standard and the reference and frequently asked question documents it is clear
that the requirement is to test the trip circuit only. Adding the word “control’ introduces
ambiguity and the potential to imply the closing circuit of the interrupting device also
requires testing under the standard. The word “control” should be removed. On this
same subject the nomenclature in Table 1b for type of protection system component is
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Question 1 Comment
not consistent with Table 1a.In Table 1b in the Level 2 Monitoring Attributes for
Component column for Relay sensing for centralized UFLS or UVLS systems there is a
reference to SPS. This reference should likely be to UFLS/UVLS.
2. In Table 1a functional testing of associated communications systems is included with a
maximum maintenance interval of 3 calendar months. Testing of this equipment at that
frequency is not believed to be necessary. It is suggested that the interval be changed
to 12 calendar months.
3. For control and trip circuit maintenance the requirement includes “a complete functional
trip test”. In order to accomplish this type of testing given current design of lock-out relay
and interrupting device trip circuitry multiple breakers and line terminal outages would
be required simultaneously. In addition complete functional testing has the potential to
result in unintentional tripping of equipment that could cause equipment damage and
customer outages. Segmentation of trip circuits by lifting wires has the potential for
incorrect restoration following testing. This type of testing has the potential to degrade
system reliability as multiple entities schedule this work. An alternate to complete
functional testing that does not potentially degrade system reliability should be
substituted.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. The interval for
maintenance of electromechanical devices such as aux or lockout relays remains at 6 years, as these devices contain “moving
parts” which must be periodically exercised to remain reliable.
Nebraska Public Power
District
November 17, 2010
No
1. It would be very helpful in Table 1a, 1b, and 1c to reference the FAQ or
Supplemental Reference by page number and section number for the corresponding
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Maintenance Activity statements.
2. Table 1a, Control and Trip Circuits with electromechanical trip or auxiliary contact how is the control and trip circuit functional trip test performed without affecting the
BES or without tripping more than just the breaker (trip coil)? What is the basis for an
actual trip of the breaker that will affect the BES? Functional trip testing will require
extensive analysis and could involve an extensive testing evolution to ensure the
correct circuit is tested without unexpected trip of other components, particularly for
generator protection systems. The complexity of the system and the test would be
conducive to an error that resulted in excessive tripping, thus affecting the reliability
of the BES. It would seem that the potential for an adverse affect from this test would
be greater than the benefit gained of testing the circuit. In addition, scheduling
outages to perform the functional trip testing in conjunction with other outages
required to perform maintenance and other construction activities will be difficult due
to the large number of outage requirements for the functional testing. This will
challenge the BES more often and thus reduce reliability.
3. 2. Table 1a, Control and Trip circuits with electromechanical trip or auxiliary contacts
- What is the differentiation between control and trip circuits? The FAQ appears to
use the term interchangeably.
4. Table 1a, associated communication systems - What is the basis for checking that
the associated communication equipment is functioning every 3 calendar months for
unmonitored components? NPPDs experience indicates that a check every 6
months is sufficient.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5. Doing as
you suggest would make the supporting information with the FAQ and Suppementary Reference part of the Standard, and this would
add extensive and unnecessary prescription to the Standard.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. These devices contain
November 17, 2010
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Question 1 Comment
“moving parts” which must be periodically exercised to remain reliable.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. The FAQ has been
modified.
4. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
Y-W Electric Association,
Inc.
No
Many of the changes to the proposed standard are reasonable and improve the clarity of
the standard and its requirements.
However, Y-WEA concurs with Central Lincoln and FMPA on their comments regarding the
testing of battery cell-to-cell connection resistance. Many types of stationary batteries are
actually blocks of two or more cells that are internally connected. This requirement would
necessitate either some sort of feasibility exception process (which, as shown by the TFE
process with the CIP standards can be very difficult, cumbersome, and time-consuming to
develop and administer) or replacement of the batteries in question, which would pose
enormous burdens on small entities that must comply with this standard. The language in
this requirement should be changed from “cell-to-cell” to “unit-to-unit” in order to avoid
these issues.
Response: Thank you for your comments.
The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This element of the table
has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to address
this comment.
Progress Energy Carolinas
No
1. The modified definition of “Protection System” (page 2 of the clean version of PRC-0052) uses the terminology “control circuitry associated with protective functions” whereas
Table 1a rows 3-6, Table 1b Rows 3 and 5, and Table 1c Row 4 uses the terminology
“control and trip circuits.” This is a conflict. “Control” implies that the standard applies to
closing/reclosing circuits as well. We do not believe that is the intent.
2. Row 7 of Table 1a (page 10 of the clean version of PRC-005-2) indicates that proper
November 17, 2010
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voltage of the station dc supply must be verified when the associated UVLS or UFLS
maintenance is performed. It is not clear whether this requirement is over and above the
quarterly and 18-month battery maintenance listed elsewhere in the table or is it the only
battery maintenance required for UVLS and UFLS systems? If the intent is to check the
station dc supply only when UVLS and UFLS maintenance is performed, the other rows
addressing station dc should be revised to exclude UVLS and UFLS.
3. Row 4 of Table 1b (page 14 of the clean version of PRC-005-2) indicates that remote
alarms must be verified every twelve calendar years for control circuitry (trip circuits)
(except UFLS/UVLS) provided “Monitoring of Protection System component inputs,
outputs, and connections” exists. Clarification should be made to indicate how to monitor
inputs. For example, a breaker auxiliary switch is relied upon to communicate breaker
status to a protective relay. If the switch is out of adjustment so that incorrect breaker
status is reported to the relay, the relay may not operate when needed. Could proper
operation of the auxiliary contacts be credited through in-service operation or the six-year
breaker operation maintenance?
4. The term “calendar years” is used to define the maximum intervals. Does this mean that
a six-year PM could go one-day shy of seven years? For example, if a six-year
maintenance PM was last performed on 1/1/2010, it would be due on 1/1/2016. Could
this allow until 12/31/2016 to complete the maintenance?
5. Table 1b, Row 14 (Row 2 on page 17): Under the “Level 2 Monitoring Attributes for
Component,” UFLS/UVLS should be referenced instead of SPS.
6. Clarifications need to be made on testing requirements on trip contacts relative to
microprocessor vs. EM relays.
7. There appears to be an inconsistency in the use of “check” vs. “verify” in the tables.
8. In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
Response: Thank you for your comments.
November 17, 2010
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1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. To the degree that inservice test-operating of the breaker also performs the specified maintenance on other portions of the Protection System, the entity
should be able to document and “take credit” for it.
4. Your explanation of “6 Calendar Years” is correct.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1 and 1-5.
7. “Check” is not an element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the
definition is relevant.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
PPL Supply
No
PPL Generation, on behalf of the entities listed above, has the following comments on the
dc entries in these tables:
1. Table 1a, Table 1b, Table 1c- Station DC supply - Maintenance Activities - references
substation batteries. For generators, shouldn't that reference be station battery?
Substation implies an association strictly with transmission, not generation.
2. Station DC supply - verify Battery continuity. What is the technical basis for this
requirement? Neither battery installation and operation instructions nor technical reviews
explain the basis for how this verification is supposed to work. NERC's Protection
System Maintenance: A Technical Reference does not address this requirement. The
Frequently-Asked Questions provides some ways that this verification can be completed.
However, one example is tied to the microprocessor battery chargers. If there is a
technical basis for this requirement, it should be provided.
3. Condition based monitoring on station dc supply - it appears the Table 1b excludes any
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Question 1 Comment
condition based monitoring of the batteries because of the requirement for monitoring
electrolyte level, individual cell state of charge, cell to cell and battery terminal resistance.
Most monitoring equipment does not monitor those functions.
4. In general, the Tables are especially confusing in the dc system area. The “lines”
overlap and need to be labeled, so they can be referenced in a maintenance document to
show how the appropriate program can be followed. Each line should be separate in the
function stated, so one can identify what has to be done to comply.
5. Provide examples of “non-battery-based dc equipment” that is covered under this
standard.
6. For dc supply, the changes from the Sept. 2007 NERC “Protection System
Maintenance”, A Technical Reference seem too restrictive. The Sept. 2007 document
contained a solid maintenance program. What is the basis for the change?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This has been
corrected in the revision.
2. Please see the FAQ (I.5.B, I.5.C and I.5.D)
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
5. The SDT has been advised that entities are considering or using technologies such as flywheels and fuel cells. Also, we have
been told that some entities are using modern battery chargers without the battery.
6. When developing the original technical reference, the SPCTF was not challenged to develop a complete, measurable Standard.
The SDT used the original document as a starting point to develop actual requirements, etc.
San Diego Gas & Electric
November 17, 2010
No
1. Proofing of CT circuits is not always trivial. Given this function is not presently being
performed and documented by the company, a reasonable grace period would be
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required to achieve compliance. The company believes present practice, such as
verification that relay current inputs are not zero and that phases are balanced, is a
reasonable indication individual CTs are functioning properly.
2. An entities protection system maintenance program is a Time Based Maintenance
program. The protection system maintenance program describes the maintenance
intervals and states that the protection system maintenance is triggered every 4 years.
The maintenance program describes that the due date for compliance is 6 months past
the trigger date to allow for planning and scheduling of the maintenance activity.
Therefore the actual due date for the 4 year maintenance interval is 4 years and six
months from the last maintenance completion date. The four year six month time based
interval is within the six year maximum time based interval as required by PRC-005-2.
Given the above, is the four year six month interval as described in the entities
maintenance program compliant with PRC-005-2?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. The intervals remain
as prescribed within the Standard and are designed to be effective, clear, and consistently monitored for compliance; the SDT is
not prescribing or suggesting what measures an entity may take within their program to assure compliance. “Grace periods”
within the Standard are not measurable, and would probably lead to persistently increasing intervals. However, an entity may
establish an internal program with grace-period allowance, as long as the entire program (including grace periods) does not
exceed the intervals within the Standard. Simply observing non-zero instrument transformer outputs may not be sufficient to
determine that the values are acceptable.
2. “Grace periods” within the Standard are not measurable, and would probably lead to persistently increasing intervals. However,
an entity may establish an internal program with grace-period allowance, as long as the entire program (including grace periods)
does not exceed the intervals within the Standard.
Springfield Utility Board
November 17, 2010
No
SUB appreciates the effort to try to strike a balance between specificity around a specific
standard and flexibility to meet the requirement under the standard. The maximum
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allowable intervals don't seem unreasonable combined with the implementation schedule.
However, it seems that the proposed changes stray toward a proscriptive set of
maintenance that 1) does not allow for an alternate method of testing and 2) sets unrealistic
testing requirements.
For example, battery terminal to terminal testing is not feasible with all battery systems.
This is a consistent message SUB has heard from others as well.
First and foremost - a test or maintenance must be done for each device within the defined
interval. With that in mind...SUB's preference would be that the maintenance activities
focus on what specifically must be done for a device (may be type specific) vs. what could
be done for a device for compliance (as an example of what an auditor could look for when
conducting an audit) vs. alternative best-practices for testing and maintenance that the
entity demonstrates constitutes as maintenance or test.
With regard to the first (maintenance activities focus on what specifically must be done for a
device) - it seems that this would apply to a limited number of devices
With regard to the second (maintenance activities focus on what specifically can be done
for a device) - it seems that this would apply broad number of devices and the list of what
can be done should be broad to cover a range of different devices that provide the same
function.
With regard to the last (alternative best-practices for testing and maintenance that the entity
demonstrates constitutes as maintenance or test), it would be helpful to have a mechanism
outside the standard itself to either have a NERC technical group craft a series of criteria
that must be met for an acceptable alternative maintenance or the entity document the
criteria used to determine an adequate test and provide for a test that meets that set of
criteria). It would be anticipated that these would fall under a minority of devices.
Response: Thank you for your comments.
November 17, 2010
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The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
In the draft Standard, the SDT is defining the basic parameters for an effective PSMP; the entity is required to develop its program with
specific activities that would satisfy those basic parameters.
The Detroit Edison
Company
No
Suggest that the interval for cell ohmic testing on VRLA batteries be changed to 12 months.
Also, include ohmic testing of NiCad batteries at 18 mos. as an option.
Response: Thank you for your comments. The activity related to this interval is to verify various basic operating parameters. The
SDT believes that extension of verification of these parameters beyond the interval within the Standard is inappropriate.
NorthWestern Corporation
No
Table 1a - Rows 3 & 4 (control and trip circuits) - add language in the Maintenance
Activities - "except that verification does not require actual tripping of circuit breakers or
interrupting devices"
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-5.
We Energies
No
1. Table 1a, Protective Relays: Change 1st line to: “Test and calibrate if necessary the
relays...”Table 1a, Protective Relays: 3rd line: Change “check the relay inputs...” to
“verify the relay inputs...”. The term “check” is not defined, whereas “verify” is. Tables
1a & 1b We agree that six / twelve years is an acceptable interval for relay
maintenance.
2. Table 1a & 1b, Control & Trip Circuits: The proposed addition to require tripping circuit
breakers during Protection System maintenance is detrimental to BES reliability and
should be removed. Ï
3. Generating unit protection system maintenance is done during scheduled outages.
The high voltage breaker on a generating unit often remains energized to backfeed and
supply station auxiliaries when the generator is offline. The proposed requirement will
increase the amount of equipment requiring an outage for maintenance, and possibly
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the length of the outage, resulting in significantly more equipment out of service as well
as increased costs. This requirement also results in greater maintenance efforts and
costs when there are redundant protection system equipment (breaker trip coils, lockout
relays, etc), which is contrary to good practice and reliability.
4. Many of the breakers that We Energies, as the Distribution Provider, trips from its BES
protection systems are not owned by We Energies and are owned by a separate
transmission company. The trip testing and maintenance of the transmission company
may not coincide with our relay maintenance testing program. The standard shall have
allowances for the entity to ONLY test or maintain equipment that it OWNS!
5. Table 1a, Station dc supply:
a. The activity to verify the state of charge of battery cells is too vague, and requires
more specific action. We assume that the drafting committee is recommending
specific gravity measurements. Specific gravity measurements have not been
shown to an accurate indicator on state of charge. In addition, as shown in the
nuclear power industry, there is no established corrective action that is taken based
on specific gravity results (eg. Don’t require a test where there is no acceptable
corrective action).
b. The activities to “verify battery continuity” and “check station dc supply voltage” are
also vague and need to be more clearly specified what is intended.
c. The 3 month time interval for battery impedance testing is too frequent. 18 month or
annual testing is more appropriate.
d. The 3 calendar year performance or service test is too frequent and will actually
remove life from a battery and reduce reliability. Recommend capacity testing no
more that every 5 years and more frequent test if the capacity is within 10% of
the end of life or design. This is consistent with the nuclear power industry.
6. Table 1b, Station dc supply: Recommend a change or addition to Table 1b Recommend a level 2 monitoring (not just a default to the level 1 maintenance activities)
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which allows for the removal of quarterly “check” of electrolyte levels, DC supply
voltage, and DC grounds - if station DC supply (charger) voltage is continuously
monitored (eg. one should not have detrimental gassing of a battery if the float voltage
of the battery is properly set and monitored).
7. Table 1a, Associated communications systems: The requirement to verify functionality
every three months is excessive; verifying this every twelve months is adequate.
8. Tables 1a & 1b - Although the latest standard provided some additional clarification,
more clarification is required on what maintenance / testing is ONLY required for
UFLS/UVLS protection systems vs. BES protection systems (eg. UFLS / UVLS systems
- Is a verification of proper voltage of the DC supply the only battery or DC supply
required (eg. no state of charge, float voltage, terminal resistance, electrolyte level,
grounds, impedance or performance test, etc.)?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1. “Check” is not an
element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the definition is
relevant.
2. These devices contain “moving parts” which must be periodically exercised to remain reliable.
3. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. It is left to the the entity to determine how to align these requirements with operational concerns.
4. The SDT contends that “its Protection Systems” is synonymous with “Protection Systems that it owns.”
5. a.The SDT is not specifically requiring specific gravity tests, although they may be one effective method of meeting the
requirement. Another method is to measure the individual cell voltage. R4 establishes that the entity must initiate resolution of
maintenance-correctable issues, so it IS necessary to correct problems that are found.
b.The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. The SDT does not
prescribe specific activities to satisfy the requirements, although some guidance may be found in the FAQ (II.5.B, II.5.C and
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II.5.D) and Supplementary Reference Section 15.4.
c. The activity related to this interval is to verify basic operating parameters. The SDT believes that extension of verification of
these parameters beyond the interval within the Standard is inappropriate.
d. The SDT disagrees, and believes that a performance test at 3-year intervals is appropriate for Valve-Regulated Lead Acid
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI, various manufacturers,
etc.) can easily handle multiple deep discharges over its expected life.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
7. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
Hydro One Networks
No
1. Table 1a:
a. V and I sensing to relays - 12 years? Why not perform this activity with maintenance
activities associated with relay maintenance so that they line up? It would only be an
incremental amount of work to perform this with associated relay maintenance work
b. Removal of requirement for testing of unmonitored breaker trip coils? Is it really the
intention of the SDT to remove a requirement that would drive the industry to install TC
monitors on breakers to improve reliability?
c. UFLS/UVLS DC control and trip circuits - Due to the distributed nature of this program,
random failures to trip are not impactive to the overall operation of the UFLS protection.
There should be no requirement to check the DC portion of these protections any more
often than the DC circuit checks associated with that LV breaker. Since it is clear the
requirement does not include the need to trip the breakers why the need to check the
trip paths? Deletion of this requirement leaves the requirement to check only the relays
and relay trip outputs from the protections every 6 years (or as often as the protective
relay component type).
d. Along the same lines as the above comment should the maintenance activities for
November 17, 2010
60
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
“UVLS and UFLS relays that comprise a protection scheme distributed over the power
system” not be the same as “Protective Relays”
2. Table 1c:
a. Level 3 attributes for “Associated communications systems” might better read
“Evaluating the performance and quality of the channel as well as the performance of
any interface to connected protective relays and alarming if the channel/protective relay
connections do not meet performance criteria”
b. We believe that some of the proposed maintenance intervals for station DC supply are
too stringent and that they would not produce significant increase in reliability to justify
associated incremental expenditure. For example we suggest that the following
changes are considered:- The interval for electrolyte level check for all batteries except
VRLAs and internal measured cell/unit Ohmic value for VRLAs be extended to 6
months instead of current time period of 3 months.- The performance or service
capacity test of the VRLA battery banks to be extended from 3 years to 5 years.
Response: Thank you for your comments.
1. a. This activity CAN be performed with the relays (for example, every other relay interval) if the entity so desires.
b. The Tables have been rearranged and considerably revised to simplify and improve clarity. Please see new Table 1-5. Specific
to your comment, the SDT initially specified inspection of trip-coil monitoring functions at intervals of 3 calendar months, with
tripping otherwise requried annually. This has been revised to simply require tripping at 6-calendar-month intervals.
c. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
d. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the
Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system
elements.
2. a. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
b. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
Arizona Public Service
Company
No
The associated maintenance activities are too prescriptive. The activities needed to ensure
the reliable service of the relay or device should be left up to the discretion of the utility.
Response: Thank you for your comments. The SDT disagrees. In the draft Standard, the SDT is defining the basic parameters for an
effective PSMP; the entity is required to develop its program with specific activities that would satisfy those basic parameters.
Manitoba Hydro
No
1. The monitoring attributes required to achieve level 2 monitoring of Station DC supply
seem excessive. We are not aware of any other utilities doing automatic monitoring all
6 attributes required. In particular automatic monitoring of electrolyte level & battery
terminal resistance does not seem practical.
2. There is inconsistency between Table 1 and the FAQ. In the Group by Monitoring Level
section of the FAQ it indicates that a battery with low voltage alarm would be considered
to have level 2 monitoring.
3. In Table 1C under the heading "Maximum Maintenance Interval" some of the entries are
stated as being "Continuous". In the case of other maintenance activities the descriptor
for Maintenance Interval indentifies the maximum period of time that may elapse before
action must be taken. "Continuous" implies continuous action; however, in reality
continuous monitoring enables no maintenance action to be taken until such time as
trends indicate the need to do so. Therefore we recommend that where the
maintenance interval be changed to read "Not Applicable".
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-4.
2. The FAQ has been modified. (See the examples in Section V.)
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
MRO’s NERC Standards
Review Subcommittee
(NSRS)
Yes or
No
No
Question 1 Comment
The NSRS feels additional changes are needed.
1. The functional testing requirement should be altered or removed as it increases the
amount of hands-on involvement and the opportunity for human error related outages to
occur, thereby introducing a greater risk to decrease system reliability. As noted on p. 8
in the supplementary reference document, “Experience has shown that keeping human
hands away from equipment known to be working correctly enhances reliability.” By
removing circuits from service on the proposed timelines for functional testing, the
chance for human error is greater than a misoperation from faulty wiring. Alternatively,
entities may choose to schedule more planned outages to conduct their functional
testing in order to limit the risk of unplanned outages resulting from human error. Under
this scenario, more elements will be scheduled out of service on a regular basis, thereby
reducing transmission system availability and weakening the system making it more
challenging to withstand each subsequent contingency (N-1). Thus testing an intact
system is more desirable than taking it out of service for testing.
2. While the SDT has included language in the draft standard to use fault analysis to
complete maintenance obligations, in practicality, this option does not offer any relief to
taking outages to perform functional tests. Nearly all BES circuit breakers are equipped
with dual trip coils. Identifying which trip coil operated for a fault only covers the one trip
coil. Functional tests would still be needed on the other. The likelihood of having
multiple trips on a given line in the course of several years is very low. Given it can take
a year to schedule some outages; planning maintenance with random faults is
unpractical and will create unacceptable risk to compliance violations. A better
approach is to use the basis in schedule A, but extend this to cover the entire protection
schemes. The document should establish target goals for mis-operation rates
(dependability and security). This would allow the utilities to develop cost effective
programs to increase reliability. The utilities would have incentives to replace poorly
performing communications systems; they would be able to quantify the value of
upgrading relay systems.
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank you for your comments.
1. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be
consistently monitored for compliance. The entity must determine how to align these requirements with operational
concerns.
2. Operational results, if desired by an entity, MAY be used to meet maintenance requirements to the degree that it verifies,
etc., the relevant performance. Whether their use is effective for a specific entity is left to the entity to determine.
“Maintenance correctable issues”, which may result in part from misoperations, are a part of using Attachment A to develop
a performance-based PSMP.
Tennessee Valley Authority
No
The requirement to measure internal ohmic values of the station dc supply batteries every
18 months is excessive. The interval should be 36 months. Our experience from
performing our routine maintenance program including cell impedance testing at 3-year
intervals has been that the program is fully adequate in monitoring bank condition.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4. The activity related to this interval is to verify various basic operating parameters. The SDT believes that extension of
verification of these parameters beyond the interval within the Standard is inappropriate.
Bonneville Power
Administration
No
The requirements pertaining to dc control circuitry are confusing.
1. To start with, a definition or further explanation is required for the term “auxiliary
contact”. Is this strictly a breaker “a” or “b” switch, or does this include lockout relay
contacts, etc.?
2. Another confusing point is that the term trip circuit is used in several places throughout
the tables, but it is not included in the definition of Protection System, where the term dc
control circuitry is used. It is important to use consistent terminology throughout the
definition and the standard.
3. The requirements for (dc) control circuits in Table 1a are fairly straightforward, but in
November 17, 2010
64
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Table 1b control circuits are broken down into three parts: trip coils and auxiliary relays;
trip circuits; and control and trip circuitry. It is very unclear exactly what each of these
three parts includes. In Table 1c, control circuitry is covered as a single element.
Please provide clarity to what is included in each part of a control circuit in Table 1b and
the monitoring attributes of each. Also, please be consistent in the treatment of control
circuits throughout the three tables.
4. Table 1a, SPS, BPA does not understand the following segment of this paragraph “The
output action may be breaker tripping, or other control action that must be verified, but
may be verified in overlapping segments. A grouped output control action need be
verified only once within the specified time interval." In one sentence, it says you can
test a SPS in segments - and in the next sentence it says you have to verify the
grouped output control action at least once within the specified time interval. It seems
that the sentences contradict themselves.
5. Table 1b, Control and trip circuitry - "Monitoring of the continuity of breaker trip circuits
along with the presence of tripping voltage supply all the way from relay terminals (or
from inside the relay) through to the trip coil(s)..." To monitor the trip path as proposed
in this Standard would cost some serious time and $$.
6. BPA does not believe there is a way to meet level two monitoring for batteries. In
addition, some of the maintenance tasks need to be defined:- monitoring the electrolyte
level is not commercially available.- the state of charge of each individual cell may need
to be better defined. There are means to verify the state of charge of the entire bank,
but not each individual cell.
7. Since a device to provide level 2 monitoring is not commercially available, we would be
forced to follow level 1 maintenance guides, which would require maintenance of
communication batteries every three months. Many of these batteries are not
accessible during 9 months of the year except via snow-cat or helicopter. We currently
monitor for some of the level 2 requirements, but not all. Our current practices of
monitoring and yearly maintenance supplemented by opportunity inspections have
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
successfully identified problems before we lost DC power to any of our communication
facilities. VRLA type batteries: - battery continuity needs to be defined.
8. In regards to the maximum allowable intervals; the frequency with which BPA performs
the 18 month maintenance tasks as prescribed in the standard are on a 24 month
interval along with visual inspections and voltage measurements weekly to bi-weekly.
BPA has seen success with this maintenance program with the ability to identify suspect
cells or entire banks with adequate time to perform corrective actions such as repairs or
replacements. BPA also does not perform routine capacity testing, this is an as
required maintenance task to confirm/validate our other test results if needed. Our
suggestion would be to extend the maintenance intervals beyond 18 months, and to
provide some clarity on the above items.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. Please see Section 15.3
of the Supplementary Reference Document and the FAQ (II4.E.).
2. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
3. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
5. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. Also, the SDT believes
that there are devices available to monitor electrolyte levels.
7. The FAQ (II.5.K) advises that “communications system batteries” are not “station batteries” and are maintained with the
communications systems.
8. The activity related to this interval is to verify various basic operating parameters. The SDT believes that extension of verification of
these parameters beyond the interval within the Standard is inappropriate.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Public Service Enterprise
Group ("PSEG
Companies")
Yes or
No
No
Question 1 Comment
The SDT is to be commended for the work and details included in the most recent draft
revision. The standard - with associated references is easier to interpret.
1. The sections on DC supply are too restrictive. Quartile checks of VLA electrolyte levels
for unmonitored systems is reasonable, however the option of checking the electrolyte
levels and voltages with less frequency is not an option with systems that have voltage
alarm notification and ground detection monitoring alarm notification unless all level 2
attributes are followed. The level 2 monitoring attributes are too comprehensive to allow
for a suggested alternative less restrictive interval of 6 months to a year. Suggest there
be an additional option for level 2 monitoring that includes voltage level and ground
alarms with a 6 month maintenance activity interval.
2. The perception of table 1a page 12 for station DC supply - “used for UVLS and UFLS” is
a maintenance activity to verify proper DC supply voltage when the UVLS and UFLS
system is maintained. This is the only DC supply maintenance activity for those
applications and the other more rigorous maintenance activities do not apply? If this is a
correct interpretation specifically list that as such in the maintenance activity description
(State the other DC supply maintenance activities are not applicable for UVLS and
UFLS). The maintenance intervals for station DC supply for level 1 and 2 monitoring
does not appear to be consistent and is somewhat confusing. A battery system with
level 2 monitoring attributes for components has intervals of 6 years, and then in next
section states that no level 2 attributes are defined - use level 1 maintenance activities.
Suggest that all DC supply / batteries be broken out all be included in one separate stand alone table with varied maintenance requirements based on monitoring attributes.
3. The maintenance activities shown on table 1b on page 19 for Station DC supply is
intended for VLA batteries? If so add that in component definition.
4. For DC systems that use a storage battery, suggest that chargers be eliminated as
other required maintenance activities will expose any problems with the charger.
5. The requirements of performing a capacity test every 6 years during the initial service
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
life of a VLA battery in addition to the other maintenance activities are too restrictive and
will cause extensive outages of the affected equipment. Suggest that this frequency be
extended to 10 years for VLA batteries for the first iteration if all the other maintenance
activities are followed. Failure rate of VLA in first 10 years is extremely low. Other
maintenance activities will expose significant issues.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
4. If the charger fails, the battery will quickly discharge via normal dc loads, and be unable to adequately serve the Protection System.
5. The SDT disagrees, and believes that a capacity test at 6-year intervals is appropiate for Vented Lead Acid batteries.
US Bureau of Reclamation
No
1. There is no reliability based justification to alter the standards to include allowable
intervals.
2. The intervals prescription for performance based PSMP virtually eliminates the
capability of smaller utilities who do not have a large equipment database to justify a
performance based system that may be sound based on their experience. This overly
prescriptive approach should be eliminated and return to allowing utilities to justify their
programs. The standard should return to addressing real reliability impacts as required
by law. This would be to develop a maintenance required which identifies that if it is
shown that an event in which reliability is impacted by the utilities PSMP, as evidenced
by disturbance reports, the utility would be required to submit to the RRO a corrective
action plan which addresses how the PSMP will be revised and when compliance with
that PSMP is to be achieved.
3. Finally, the standard presumes that components within a BES Element will cause a
reliability impact to the BES. In numerous meeting with NERC and WECC it was
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
emphasized that a reliability impact has been described as causing cascading outages
or causing loss of service to load above a certain magnitude. The BES has an ability to
absorb element outages resulting from a variety of causes without impact load or
resulting in cascading outages.
Response: Thank you for your comments.
1. FERC Order 693 directs NERC to establish maximum allowable intervals.
2. Small entities are permitted to aggregate their components with similar components of other entities to meet the component
populations, as long as the programs are (and remain) similar – see Section 9 of the Supplementary Reference, the FAQ (IV.3.A)
and the associated footnote to Attachment A. Decreasing the component population below the requirements of Attachment A will
result in an unsound program due to component populations that are not statistically significant.
3. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the
currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and understands this to be consistent with the position
of FERC staff.
Dynegy Inc.
No
We agree with all proposed intervals in Tables 1a, 1b, and 1c except the 3 calendar month
interval for Associated Communication Systems in Table 1a. We suggest using a 1 year
interval because all other elements of the Protection System are being verified a minimum
of every 3 years. Therefore, we believe annual verification of Associated Communication
Systems is sufficient.
Response: Thank you for your comments. The SDT believes that the 3-month interval is proper for unmonitored communications
systems.
Pacific Northwest Small
Public Power Utility
Comment Group
November 17, 2010
No
We agree with most of the changes from the last draft. However, the phrase “Verify Battery
cell-to-cell connection resistance” has entered the table where it did not exist before. On
some types of stationary battery units, this internal connection is inaccessible. On other
types the connections are accessible, but there is no way to repair them based on a bad
reading. And bad cell-to-cell connections within units will be detected by the other required
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
tests. This requirement will cause entities to scrap perfectly good batteries just so this test
can be performed, with no corresponding increase in bulk electric system reliability while
taking an unnecessary risk to personnel and the environment. And because buying battery
units composed of multiple cells allows space saving designs, entities may be forced to buy
smaller capacity batteries to fit existing spaces. This may end up having a negative effect
on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table
now.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)” to address this comment.
PNGC Power
No
We agree with most of the changes from the last draft. However, the phrase “Verify Battery
cell-to-cell connection resistance” has entered the table where it did not exist before. On
some types of stationary battery units, this internal connection is inaccessible. On other
types the connections are accessible, but there is no way to repair them based on a bad
reading. And bad cell-to-cell connections within units will be detected by the other required
tests. This requirement will cause entities to scrap perfectly good batteries just so this test
can be performed, with no corresponding increase in bulk electric system reliability while
taking an unnecessary risk to personnel and the environment. And because buying battery
units composed of multiple cells allows space saving designs, entities may be forced to buy
smaller capacity batteries to fit existing spaces. This may end up having a negative effect
on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table
now.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)” to address this comment.
FirstEnergy
November 17, 2010
No
We support most of the maintenance activities detailed in the Tables, but question the
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
verification of battery cell-to-cell resistance. On some types of battery units, this internal
connection is inaccessible. We suggest substituting "unit-to-unit" in place of "cell-to-cell".
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)” to address this comment.
Florida Municipal Power
Agency
No
1. Will the Standard Introduce Technical Feasibility Exceptions to PRC Standards? A large
proportion of the batteries (as high as 50% as reported by some SMEs) are not able to
accommodate all of the tests prescribed in the draft standard. The phrase “Verify
Battery cell-to-cell connection resistance” has entered the table where it did not exist
before. On some types of stationary battery units, this internal connection is
inaccessible. On other types the connections are accessible, but there is no way to
repair them based on a bad reading. And bad cell-to-cell connections within units will be
detected by the other required tests. This requirement will cause entities to scrap
perfectly good batteries just so this test can be performed, with no corresponding
increase in bulk electric system reliability while taking an unnecessary risk to personnel
and the environment. And because buying battery units composed of multiple cells
allows space saving designs, entities may be forced to buy smaller capacity batteries to
fit existing spaces. This may end up having a negative effect on reliability. Suggest
substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now.
2. The Standard Reaches Beyond the Statutory Scope of the Reliability Standards As
written, the standard requires testing of batteries, DC control circuits, etc., of distribution
level protection components associated with UFLS and UVLS. UFLS and UVLS are
different than protection systems used to clear a fault from the BES. An uncleared fault
on the BES can have an Adverse Reliability Impact and hence; the focus on making
sure the fault is cleared is important and appropriate. However, a UFLs or UVLS event
happens after the fault is cleared and is an inexact science of trying to automatically
restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays
with the same function, there is no significant impact to the function of UFLS or UVLS.
Hence, there is no corresponding need to focus on every little aspect of the UFLS or
UVLS systems. Therefore, the only component of UFLS or UVLS that ought to be
focused on in the new PRF-005 standard is the UFLS or UVLS relay itself and not
distribution class equipment such as batteries, DC control circuitry, etc., and these latter
ought to be removed from the standard. In addition, most distribution circuit are radial
without substation arrangements that would allow functional testing without putting
customers out of service while the testing was underway, or at least without momentary
outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES
reliability.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This element of the
table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to
address this comment.
2. The Standard addresses UFLS and UVLS to the degree that they are installed per NERC Standards, even though entities may
choose to install them on distribution systems.
NERC Staff
Yes
PacifiCorp
Yes
WECC
Yes
Compliance agrees with the changes as they add clarity though the Tables do not define
what is actually required to demonstrate compliance without reading the Supplementary
Reference and the FAQs.
Response: Thank you for your comments. The Measures do provide discussion of what is required to demonstrate compliance.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
The United Illuminating
Company
Yes or
No
Yes
Question 1 Comment
In general yes. There are concerns with verifying cell-to-cell resistance in Batteries. On
some battery sets this is not possible to do.
Response: Thank you for your comments. This element of the table has been modified to state, “Battery internal cell-to-cell or unitto-unit connection resistance (where available to measure)” to address this comment.
South Carolina Electric and
Gas
Yes
Please provide clarity on why Table 1b for “Station dc supply” has a double entry that
appears to be contradictory. The table provides monitoring attributes for a maximum
maintenance interval of 6 calendar years and the next row says to refer to level 1
maintenance activities.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4.
ReliabilityFirst Corp.
Yes
1. The SDT has made significant and worthwhile changes to these tables. However, these
tables still seem overly complex and should be simplified. One possibility would be to
eliminate Table 1c and use Table 1b for those components that meet certain monitoring
attributes.
2. There are some errors in Table 1a in rows 5 and 6. In row 5 in the component column
the word “contact” is missing. In the same row in the third column, there is an extra
period. In row 6 in the third column, “circuit” should be “circuits” as in the other rows.
3. The maintenance intervals seem to give preference to solid-state outputs but there is no
evidence given that these are truly more reliable than an electromechanical trip at least
not sufficient to double the maintenance interval.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
2. The SDT has included VRFs and Time Horizons with this posting. Do you agree with the
assignments that have been made? If not, please provide specific suggestions for
improvement.
Summary Consideration: Many commenters disagreed with various VRFs as specified in the draft
Standard. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and
FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 –
Medium, and R4 – High. Some comments were offered regarding Time Horizons, resulting in modification
of the Time Horizons for both R3 and R4 from Long-Term Planning to Operations Planning.
Organization
Yes or
No
Question 2 Comment
PPL Supply
No comment.
Xcel Energy
No comments
SERC Protection and
Control Sub-committee
(PCS)
The SERC PCS expresses no opinion on this question.
San Diego Gas & Electric
No
The Detroit Edison
Company
No
Black Hills Power
No
The United Illuminating
Company
No
November 17, 2010
The VRF for R1 should be Low. It is administrative to create an inventory list. If R1 failed
to be executed but the other requirements wee executed fully then the BES would be
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
properly secured. Compare this against the scenario of performing R1 but failing to
perform the other tasks; in which case the BES is at risk. UI recognizes that the SDT
considers the inventory as the foundation of the PSMP but it is not the element of the
PSMP that provides for the level of reliability sought. R1 should be VRF Low and R2 thru
R4 VRF is Medium. UI agrees with the Time Horizon.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
JEA
No
1. What role with the Supplementary Reference and FAQ play with reference to the
proposed standard? We have a concern that the standard will stand-alone and not
include the interpretations, examples and explanations that are needed to properly
apply these values in a compliance environment. There needs to be a method to
include the FAQ and Supplementary Reference.
2. The method will also need to allow for future modifications as the standard is revised,
etc.
Response: Thank you for your comments.
1. The Supplementary Reference and FAQ documents provide supporting discussion, but are not part of the Standard. The SDT
intends that these be posted as reference documents, accompanying the Standard.
2. The SDT intends that these documents be updated as the Standard is revised, such that they continue to be relevant to the
application of the Standard.
FirstEnergy
November 17, 2010
No
Although we agree that Requirement 1 is important because it establishes a sound PSMP,
a HIGH VRF assignment is not appropriate and it should be changed to LOWER. By
definition, a requirement with a LOWER VRF is administrative in nature, and documentation
of a program is administrative. Assigning a LOWER VRF to R1 is more logical since R4,
which is the requirement to implement the PSMP, is assigned a MEDIUM VRF because, if
violated, it could directly affect the electrical state or the capability of the bulk electric
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
system. Additionally, revising the VRF to LOWER would provide a consistent assignment to
a VRF on a similar requirement in the proposed FAC-003-2 standard.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
For a VRF to be classified as “Lower” it must be administrative, and none of the requirements in this standard are ‘administrative’.
Pepco Holdings, Inc. Affiliates
No
An explanation is needed to justify why the VRF for R1 of the PSMP is High whereas the
implementing and following of the PSMP is Medium, R2, R3 & R4.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
American Transmission
Company
No
ATC disagrees with the VRFs as specified in the standard. R1 VRF would more likely be
classified as “medium” and R2 through R4 should be classified as a “High” VRF. ATC is
O.K. with the Time Horizons specified.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
Constellation Power
Generation
No
Constellation Power Generation questions why the VRF for R1 is High while all other
requirements are Medium. This VRF should be changed to Medium to follow suit with the
other requirements.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
Florida Municipal Power
Agency
November 17, 2010
No
R1, R2 and R3 are administrative in nature and ought to be a Low VRF, not a High or
Medium VRF. R4 is doing the actual maintenance and testing and ought to be the highest
VRF in the standard. Medium VRF is appropriate for R4.
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
ReliabilityFirst Corp.
No
R4 is the implementation of a maintenance program which is extremely important. Effective
operation of the BES is so dependent on adequate maintenance that requirement R4
warrants a High VRF. It seems that requirement R3 may actually be better categorized as
having an Operations Assessment Time Horizon as the entity needs to review events to
analyze the adequacy of maintenance periods.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
The SDT agrees with the suggestion to change the R3 Time Horizon and has assigned an Operations Planning Time Horizon.
BGE
No
See comments under 7 regarding the ambiguity of R1.1. A high VRF for some
interpretations of R1.1 may not be reasonable. A program may be structured so that
sufficient maintenance to ensure reliability is taking place even though a specific
component is not identified. Contrasting the high VRF for R1 with the medium VRF for R4
seems backwards.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
MRO’s NERC Standards
Review Subcommittee
(NSRS)
No
The NSRS disagrees with the VRFs as specified in the standard. R1 VRF would more
likely be classified as “medium” and R2 through R4 should be classified as a “High” VRF.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
November 17, 2010
78
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
US Bureau of Reclamation
Yes or
No
Question 2 Comment
No
The Time Horizons are too narrow for the implementation of the standard as written. The
SDT appears to have not accounted for the data analysis associated with performance
based systems. The data collection, analysis, and subsequent decisions associated
development of a maintenance program and its justification do not occur overnight
especially with larger utilities. In addition, this new standard will require complete rewrite of
maintenance programs. The internal processes associated with these vary based on the
size of the utility. Since this standard is so invasive into the internal decisions concerning
maintenance, the standard should allow at least 18 months for entities to rewrite their
internal maintenance programs to meet the requirements and 18 months to train the staff
and implement the new program.
Response: Thank you for your comments. The SDT has reviewed the time horizons, and feels that R1 and R2 are properly assigned a
Long-Term Planning Time Horizon, as the activities to develop a program and to determine the monitoring attributes of components are
performed within the related time period. The SDT has assigned an Operations Planning Time Horizon to R3 and R4, as some of the
related activities must take place within 1-year intervals.
Ameren
No
The VRF for R1 should be Medium because the failure to do so is commensurate with the
risks of the other requirements. For example, failing to establish a PSMP for some portion
of the entity’s components could lead to their maintenance not meeting this standard; this is
the same is establishing the PSMP and then not performing the maintenance per the
standard.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
Indeck Energy Services
November 17, 2010
No
The VRF's are highly arbitrary because they treat all registered entities and all protective
systems alike. They're not. For example, under-frequency relays for generators protect the
equipment needed to restore the system after a blackout. The under-frequency load relays
prevent a cascading outage. As discussed at the FERC Technical Conference on
Standards Development, the goal of the standards program is to avoid or prevent
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
cascading outages--specifically not loss of load. That would make under-frequency load
relays more important to prevent cascading outages.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
The risk to the system is independent of entity size. VSLs have been modified where necessary to make them independent of size of
entity.
Springfield Utility Board
No
1. Time horizons for implementation seem adequate and SUB appreciates the attention to
putting together a reasonable but assertive implementation plan.
2. The Violation Risk Factors are problematic. With all due respect, it seems that NERC
still operates in a "BIG UTILITY" mind set. There are "PROTECTION SYSTEMS" and
there are "Protection Systems" - some Protection Systems may significantly impact
system reliability and others may not. This not promote reliability in that if an entity was
thinking about installing a minor system or installing an improvement that enhances
reliability (but is not required) that it might back away because of the risk associated
with somehow being out of compliance. Reliability runs the risk of being diminished
through the standards approach. SUB suggests stepping back and putting more
granularity on VRFs and there needs to be more perspective on the purpose of the
device when arriving at a risk factor. Perhaps a voltage threshold could be attached to
the VRFs. For example language could be added to say "For Elements at 200kV and
above, or for Critical Assets, the risk factor is higher" and "For Elements operating at
100kV and above, the risk factor is medium" and "For Elements below 100kV, the risk
factor is lower" In SUB's view, a discussion on VRF's needs to coupled with Violation
Severity Levels. SUB discusses VRF's later in this comment form. SUB would be
supportive of a Medium VRF designation if there were a more balanced VLF structure
(please refer to the comments of VLFs)
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
According to the current Reliability Standards Development Procedure, each Requirement is assigned one (and only one) VRF.
Manitoba Hydro
No
Time horizons to change from present 6 months to 3 months maintenance time intervals
within proposed implementation time period is not realistic.
Response: Thank you for your comments. The options for Time Horizon are Long-Term Planning, Operations Planning, Same-Day
Operations, Real-Time Operations, and Operations Assessment. The SDT has reviewed the Time Horizons, and feels that R1 and R2
are properly assigned a Long-Term Planning time horizon, as the activities to develop a program and to determine the monitoring
attributes of components is performed within the related time period. The SDT has assigned an Operations Planning Time Horizon to
R3 and R4, as some of the related activities must take place within 1-year intervals.
American Electric Power
Yes
Arizona Public Service
Company
Yes
Bonneville Power
Administration
Yes
Consumers Energy
Company
Yes
Duke Energy
Yes
Dynegy Inc.
Yes
Entergy Services
Yes
Exelon
Yes
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Great River Energy
Yes
Hydro One Networks
Yes
Long Island Power
Authority
Yes
MEAG Power
Yes
MidAmerican Energy
Company
Yes
Northeast Power
Coordinating Council
Yes
Northeast Utilities
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PNGC Power
Yes
Progress Energy Carolinas
Yes
Public Service Enterprise
Group ("PSEG
Companies")
Yes
November 17, 2010
Question 2 Comment
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Santee Cooper
Yes
South Carolina Electric and
Gas
Yes
Southern Company
Transmission
Yes
Tennessee Valley Authority
Yes
We Energies
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Inc.
Yes
PacifiCorp
Yes
Question 2 Comment
Agree with the exception that the time horizon for implementation needs to recognize that
documentation for maintenance tasks performed prior to this standard may not match
current requirements and there should be no penalty for this.
Response: Thank you for your comments. The Implementation Plan needs to address the concerns expressed.
Nebraska Public Power
District
Yes
Please provide an example of how the compliance percentage will be calculated for the
implementation plan.
Response: Thank you for your comments. The SDT does not understand how this comment relates to the VRFs or to the Time
Horizons.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
3. The SDT has included Measures and Data Retention with this posting. Do you agree with
the assignments that have been made? If not, please provide specific suggestions for
improvement.
Summary Consideration: Many commenters expressed concern about the data retention requirements
for two full maintenance intervals, and the SDT responded that this is consistent with today’s expectations
of many Compliance Monitors. Other commenters were concerned about data retention over the
transition from PRC-005-1 to two full maintenance intervals for PRC-005-2, and the SDT offered advice
that, until two maintenance cycles have been experienced under PRC-005-2, the program and associated
documentation for PRC-005-1 will still be relevant.
Comments were offered that “on-site” audits as expressed in the Data Retention Section (item 1.3 under
Compliance) are not relevant for small entities which are not audited on-site; the SDT agrees and changed
the term to “scheduled” audits.
Several commenters offered suggestions relative to the Measures, resulting in changes to all four
Measures. The SDT removed the detailed Protection System definition from Measure M1, inserted
“Distribution Provider” in Measure M2, and made changes to consistently use “shall” rather than “will” or
“should” throughout all the Measures.
Organization
WECC
Yes or
No
Question 3 Comment
1. Compliance agrees with the measures.
2. Compliance recommends making the Supplementary Reference part of the standard
and that it be referenced appropriately in Table 1a, 1b, 1c and Attachment A.
3. Compliance does not agree with the Data Retention as provided in the draft. In order
for an entity to demonstrate that they have maintained system protection elements
within their defined intervals retention of documentation will be required for many years.
November 17, 2010
84
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
This is in order to establish bookends for the maintenance interval. Maintenance
intervals commonly span 5 years or more. Entities should be required to retain data for
the entire period of the maintenance interval.
Data Retention should be changed to: The Transmission Owner and any Distribution
Provider that owns a transmission Protection System and each Generation Owner that
owns a generation Protection System, shall retain evidence of the implementation of its
Protection System maintenance and testing program for a minimum of the duration of
one maintenance interval as defined in the maintenance and testing program.
Response: Thank you for your comments.
1. Thank you.
2. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a Reference
Document, accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of
requirements, etc, and is not to include explanatory information like that included in the Supplementary Reference Document.
3. The SDT believes that the modification suggested in the comment is not sufficient to demonstrate compliance. In order that a
Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding one. The SDT has specified the data retention in the
posted Standard to establish this level of documentation.
Xcel Energy
No comments
San Diego Gas & Electric
No
The Detroit Edison
Company
No
Ameren
No
1) M2 incorrectly excludes Distribution Provider.
2) For those components with numerous cycles between on-site audits, retaining and
November 17, 2010
85
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
providing evidence of the two most recent distinct maintenance performances and the
date of the others should be sufficient. If an entity misses a required maintenance, that
results in a self report. We are subject to spot audits and inquiries at any time between
on-site audits as well.
3) For those components with cycles exceeding on-site audit interval, retaining and
providing evidence of the most recent distinct maintenance performance and the date of
the preceding one should be sufficient. Auditors will have reviewed the preceding
maintenance record. Retaining these additional records consumes resources with no
reliability gain.
4) FAQ II 2B final sentence states that documentation for replaced equipment must be
retained to prove the interval of its maintenance. We oppose this because: the replaced
equipment is gone and has no impact on BES reliability; and such retention clutters the
data base and could cause confusion. For example, it could result in saving lead acid
battery load test data beyond the life of its replacement.
Response: Thank you for your comments.
1. Distribution Provider has been added to Measure M2.
2. The SDT understands that Compliance Monitors will usually wish to review data to review program performance back to the
preceding on-site audit.
3. The SDT believes that the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the
data of the preceding one. The SDT has specified the data retention in the posted Standard to establish this level of
documentation. The SDT understands that Compliance Monitors are currenlty requesting data on retired components to validate
that entities have been in compliance since the last audit (or currently, since the beginning of mandatory compliance), and believes
that this suggestion in the FAQ is appropriate.
Northeast Power
Coordinating Council
November 17, 2010
No
1. Clarification is needed for “on-site audit” - does it include audits by any of the following NPCC/NERC/FERC. Several small entities do not have on-site audits and participate in
86
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
off-site audits. Hence, suggest deleting “on-site” from the requirement.
2. Further clarification is required to the Data Retention section to coordinate with the
statement in FAQ (Section IV.d p. 22 redline). Suggest the following revised Data
Retention requirement consistent with the statement and example given in FAQ:”The
Transmission Owner, Generator Owner, and Distribution Provider shall each retain at
least two maintenance test records or statistical data to demonstrate compliance with
test interval required for each distinct maintenance activity for the Protection System
components. The Compliance Enforcement Authority shall keep the last periodic audit
report and all requested and submitted subsequent compliance records.”
Response: Thank you for your comments.
1. We have modified “on-site” to “scheduled” to address this comment.
2. The SDT was unable to locate the discussion from the comment within the FAQ.
Constellation Power
Generation
No
Constellation Power Generation does not agree with the proposed data retention section.
Retaining and providing evidence of the two most recent performances of each distinct
maintenance activity should be sufficient. For entities that have not been audited since
June of 2007, having to retain evidence from that date to the date of an audit could contain
numerous cycles, which is cumbersome and does not improve the reliability of the BES.
Response: Thank you for your comments. For shorter-interval activities (such as those with quarterly intervals), the SDT understands
that Compliance Monitors are currently requesting data to validate that entities have been in compliance since the last audit (or
currently, since the beginning of mandatory compliance) or for the duration specified in a standard.
JEA
No
November 17, 2010
Data retention becomes a complex issue for maintenance intervals of 12 years where the
last two test intervals are required to be kept, i.e. 24 years. It would seem much more
reasonable to set a limit of two test intervals or the last regional audit, not having to keep
some 24 years of documentation with maintenance systems changing and archival records
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
somewhat problematic to keep.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one. The SDT has specified the data retention in the posted standard to establish this level of documentation.
Public Service Enterprise
Group ("PSEG
Companies")
No
Data retention for battery capacity test should be most recent performance, not last 2. The
other maintenance activities documentation with one iteration of capacity test is sufficient
documentation
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one, as well as data to validate that entities have been in compliance since the last audit (or currently, since the beginning of mandatory
compliance). The SDT has specified the data retention in the posted Standard to establish this level of documentation.
PacifiCorp
No
Data retention requirements need to be modified. The need to maintain records of two
previous tasks is excessive, one should be adequate. Per the two previous task
requirements an entity may need to maintain records for 35 years.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one, as well as data to validate that entities have been in compliance since the last audit (or currently, since the beginning of mandatory
compliance). The SDT has specified the data retention in the posted Standard to establish this level of documentation.
Progress Energy Carolinas
No
M2 incorrectly excludes Distribution Provider.
Response: Thank you for your comments. Measure M2 has been modified to add “Distribution Provider.”
Duke Energy
November 17, 2010
No
M4 states that entities shall have evidence such as maintenance records or maintenance
summaries (including dates that the components were maintained). We would like to see
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
M4 revised/expanded to explicitly include the FAQ Section IV 1.B information which states
that forms of evidence that are acceptable include, but are not limited to:
o Process documents or plans
o Data (such as relay settings sheets, photos, SCADA, and test records)
o Database screen shots that demonstrate compliance information
o Diagrams, engineering prints, schematics, maintenance and testing records, etc.
o Logs (operator, substation, and other types of log)
o Inspection forms
o U.S. or Canadian mail, memos, or email proving the required information was exchanged,
coordinated, submitted or received
o Database lists and records
o Check-off forms (paper or electronic)
o Any record that demonstrates that the maintenance activity was known and accounted
for.
Response: Thank you for your comments. The Standard Development Procedure requires that Measures provide some examples of
evidence, but does not require an exhaustive list. The SDT did add “check-off lists” and “inspection records.”
Indeck Energy Services
No
Measure 1 is complete overkill for a small generating facility. The maintenance program is
to inspect and test the equipment within the intervals. A qualified contractor applies
industry standard methods to maintain the equipment. Trying to have each entity define
the maintenance program down to the component level does not improve reliability.
Response: Thank you for your comments. A definition of “Component” has been added to the draft PRC-005-2 Standard to help
explain how “component” can be characterized.
November 17, 2010
89
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
PPL Supply
Yes or
No
Question 3 Comment
No
1. Measurers M1 - requires having a maintenance program that addresses control circuitry
associated with protective functions from the station dc supply through the trip coil(s) of
the circuit breakers. Some generators do not own this equipment to the circuit breaker
or other interrupting devices. The requirement should be to maintain and test the
equipment owned by the generator.
2. Data Retention 1.3 references on-site audits. Entities registered as GO and GOP are
not audited on-site.
Response: Thank you for your comments.
1. The SDT believes that “its Protection Systems” in Requirement R1 is synonymous with “Protection Systems that it owns” and
declines to modify the Standard to address this comment.
2. We have modified “on-site” to “scheduled” to address this comment.
Arizona Public Service
Company
No
The change to the Protection System definition and establishing a PSMP with prescriptive
maintenance activities relative to the voltage and current sensing devices has created a
situation where data from original or prior verification not being available or not at the
interval to meet the data retention requirement. Although, methods of determining the
integrity of the voltage and current inputs into the relays were used to ensure reliability of
the devices meets the utilities requirements, they may not meet the interval requirement
and would then be considered a violation due to changes in the standard. Recommend a
single exemption of the two recent most recent performances of maintenance activities to
the most recent performance of maintenance activity in the first maintenance interval for
this component due to the long maintenance interval, the changes in the standard
definitions and the prescriptive maintenance activities.
Response: Thank you for your comments. The SDT believes that Compliance Monitors will assess compliance for activities performed
before the effective date of this Standard using the program that you had in place previously.
November 17, 2010
90
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
American Electric Power
Yes or
No
Question 3 Comment
No
1. The measure includes the entire definition of "Protection System". Remove the definition
from the measure and let the definition stand alone in the NERC glossary.
2. 1.3 Data Retention This calls for past 2 distinct maintenance records to be kept. Since
UFLS interval can be 12 years, this would mean that we would need to keep records for
24 years. This is not realistic and consideration should be given to choosing a
reasonable retention threshold.
Response: Thank you for your comments.
1. Measure M2 has been modified as suggested.
2. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data
of the most recent performance of the maintenance, as well as the data of the preceding one, as well as data to validate that entities
have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified
the data retention in the posted Standard to establish this level of documentation.
Springfield Utility Board
November 17, 2010
No
The measures do not seem unreasonable. However the data retention states that
documentation must exist for the two most recent performances of each maintenance
activity. Stepping back, there is an implementation schedule that is designed to bring all
devices into compliance with ONE maintenance or test within (SUB's understanding is) 6
years. There may not be documentation for more than one activity. Further, new or
replacement components won't have more than one activity for a number of years. The
data retention schedule, left unchanged, will promote non-compliance because it is
impossible to have two records when only one may possibly exist. Rather than promote a
culture of compliance, the standard promotes a culture of non-compliance by creating an
standard that cannot be met. The FAQ addresses this issue, but the Data Retention
language seems to be less clear. SUB suggests that the Data Retention language be clear
that new components that do not replace existing components may have only one record
for maintenance if only one maintenance of the component could possibly exist. SUB
suggests that the Data Retention language also be clear that for new components that
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
replace existing components, that the Data Retention requirement reflect that the entity
needs to retain the last test for the pre-existing component and the test for the new
component (for a total of two tests).
Response: Thank you for your comments. First of all, the Data Retention presumes a stable Standard that has been in effect.
Further, the SDT believes that Compliance Monitors will assess compliance for activities performed before the effective date of this
Standard using the program that you had in place previously. Therefore, the documentation for your program under PRC-005-1
(whatever it may have been) will serve as your “second interval” documentation until supplanted by new PRC-005-2 records.
US Bureau of Reclamation
No
The measures M2, M3, and M4 are redundant to measure M1. Either eliminate M1 or M2
through M4. The entity must provide documentation of its maintenance program in M1
irrespective of the type used. As previously mentioned there is not reliability based
justification for the documentation required. The Entity should be afforded the freedom to
make intelligent maintenance choices based on innumerable factors. These choices will be
reviewed if a reliability impact is determined to be related to the choices.
Response: Thank you for your comments. The NERC Reliability Standard Development Procedure establishes that each individual
requirement will have its own Measure. Additionally, the four Measures are NOT redundant – Measure M1 addresses “having a
program,” Measure M2 addresses “monitoring attributes to use extended intervals in the Tables,” Measure M3 addresses “criteria for a
performance-based program,” and Measure M4 addresses “implementation of the program.”
American Transmission
Company
No
The NERC standard assigns a retention period for the two most recent performances of
maintenance activity which implies two intervals of documentation be maintained. ATC
does not agree that requiring all data for two full cycles is warranted. The volume and
length of data retention is unreasonable. ATC recommends that the entity retain the last
test date with the associated data, plus the prior cycle test date only without retaining the
test data. ATC agrees with assignment of the measures.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
November 17, 2010
92
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
one. The SDT has specified the data retention in the posted Standard to establish this level of documentation.
MRO’s NERC Standards
Review Subcommittee
(NSRS)
No
The NERC standard assigns a retention period for the two most recent performances of
maintenance activity which implies two intervals of documentation being maintained. The
NSRS does not agree that requiring all data for two full cycles is warranted. The volume
and length of data retention is unreasonable. The NSRS recommends that the entity retain
the last test date with the associated data, plus the prior cycle test date only without
retaining the test data.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one. The SDT has specified the data retention in the posted Standard to establish this level of documentation.
Pepco Holdings, Inc. Affiliates
November 17, 2010
No
The present wording regarding data retention states - The Transmission Owner, Generator
Owner, and Distribution Provider shall each retain documentation of the two most recent
performances of each distinct maintenance activity for the Protection System components,
or to the previous on-site audit date, whichever is longer. This wording was changed by the
SDT following comments received from Draft 1. However, the present wording is
somewhat confusing. It is assumed that the intent of the SDT was to require
documentation be retained for the two most recent performances of each distinct
maintenance activity, regardless of when they occurred (i.e., whether prior to, or since the
last audit), since the phrase whichever is longer was used. In addition, for those activities
requiring short maintenance intervals (such as battery inspections), records must be kept
for all performances (not just the last two) that have taken place since the last on-site audit.
For example: Assume a PSMP with a 6 year interval for relay maintenance and 3 month
interval for battery inspections. At a particular station assume the batteries have been
inspected every 3 months; the relays were last inspected 5 years ago, and before that 11
years ago. The last audit was 2 years ago. Records from each 3 month battery inspection
going back to the last audit needs to be retained. Also, both relay maintenance records
from 5 and 11 years ago needs to be retained, despite the fact that this interval should
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
have been reviewed during the last audit. Documentation from the 11 year ago activity can
be discarded when the relays are next maintained.
Is this what the SDT intended? If
so, the requirement should be re-worded to better explain the intent. Also, examples
should be included in either the FAQ or Supplemental Reference to demonstrate what is
expected.
Response: Thank you for your comments. You understand the data retention correctly as intended by the SDT and specified in the
draft standard. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will
need the data of the most recent performance of the maintenance, as well as the data of the preceding one, as well as data to validate
that entities have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has
specified the data retention in the posted Standard to establish this level of documentation. .
We Energies
No
The requirement to retain data for the two most recent maintenance cycles is excessive.
The required data should be limited to the complete data for the most recent cycle, and
only the test date for the previous cycle.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one. The SDT has specified the data retention in the posted Standard to establish this level of documentation.
Long Island Power
Authority
No
1. Two most recent performances of each distinct maintenance activity for the Protection
System components will require data retention for an extended period of time. For
example, in certain cases, battery maintenance is on a 12 year cycle which suggests
that records need to be retained for 24 years. LIPA suggests retaining data for the most
recent maintenance activity.
2. LIPA seeks clarification on “on-site audit” - does it include audits by any of the following
- NPCC/NERC/FERC. Also, several small entities do not have on-site audits and
participate in off-site audits. Hence, LIPA suggests deleting “on-site” from the
requirement. In addition further clarification is required to the Data Retention section to
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
coordinate with the statement in FAQ (Section IV.d p. 22 redline).
Response: Thank you for your comments.
1. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data
of the most recent performance of the maintenance, as well as the data of the preceding one; thus, records for maintenance which
is performed every 12 years will need to be retained for 24 years.. The SDT has specified the data retention in the posted Standard
to establish this level of documentation. Audits may be by any of the entities listed. The term “on-site” has been replaced by
“scheduled” to address your concern.
Northeast Utilities
No
Two most recent performances of each distinct maintenance activity for the Protection
System components will require data retention for an extended period of time. From the
FAQ, it is understood that “the intent is not to have three test result providing two time
intervals, but rather have two test results proving the last interval”. However two intervals
still results in an extended period of time. For example, for a twelve year interval, data
would need to be retained for ~24 years. During that period of time a number of on-site
audits would have been completed - it is not clear why the requirement is the longer of the
two most recent performances or to the previous on site audit date.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one. The SDT has specified the data retention in the posted Standard to establish this level of documentation.
MidAmerican Energy
Company
No
Verification of compliance with the maximum time intervals for testing only needs to include
retention of the documentation of the two most recent maintenance activities. The phrase
“or to the previous on-site audit (whichever is longer)” should be deleted.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one, as well as data to validate that entities have been in compliance since the last audit (or currently, since the beginning of mandatory
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
compliance). The SDT has specified the data retention in the posted Standard to establish this level of documentation.
BGE
Yes
Black Hills Power
Yes
Bonneville Power
Administration
Yes
Consumers Energy
Company
Yes
Dynegy Inc.
Yes
Entergy Services
Yes
Exelon
Yes
Great River Energy
Yes
Hydro One Networks
Yes
MEAG Power
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PNGC Power
Yes
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
ReliabilityFirst Corp.
Yes
Southern Company
Transmission
Yes
The United Illuminating
Company
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Inc.
Yes
South Carolina Electric and
Gas
Yes
Question 3 Comment
(Note that Section C.M2 leaves off "Distribution Provider" but references Requirement R2
at the end of the Section. "R2 applies to the Distribution Provider.")
Response: Thank you for your comments. Measure M2 has been modified to add “Distribution Provider.”.
Nebraska Public Power
District
Yes
Additional guidance on what is acceptable evidence is always good.
Response: Thank you for your comments. In addition to the lists within the Measures, the FAQ (IV.1.B) and Section 15.7 of the
Supplementary Reference Document provide additional guidance about acceptable evidence.
Florida Municipal Power
Agency
Yes
M1 could be shortened to just a program in accordance with R1, rather than repeat the
entire requirement
Response: Thanks you for your comments. The restatement of the definition has been removed from Measure M1, but the Reliability
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
Standards Development Procedure specifies that Measures contain levels of detail similar to Measure M1 as posted.
NERC Staff
Yes
Make sure that the use of verbs like “shall,” “should,” and “will” is consistent across
Requirements and Measures. In these four measures, all three verbs are used, and they
should be made uniform to avoid misinterpretation.
Response: Thank you for your comments. The Measures have been modified to consistently use “shall.”
Manitoba Hydro
Yes
No issues or concerns at present
Yes
The SERC PCS expresses no comments on this question.
Yes
We agree with the Measures but suggest some improvements:
Response: Thank you.
SERC Protection and
Control Sub-committee
(PCS)
Response: Thank you.
FirstEnergy
1. In Measures M2 and M3, the term "should" must be changed to "shall"
2. In Measure M2, the Distribution Provider entity is missing
Response: Thank you for your comments.
1. Measure M2 and Measure M3 have been modified as suggested.
2. Distribution Provider has been added to Measure M2.
Santee Cooper
November 17, 2010
Yes
We are concerned with the long-term implementation of the data retention requirements for
activities with long maximum intervals. For example, if you are performing an activity that is
required every 12 years, the implementation plan says that you should be 100% compliant
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
in 12 years following regulatory approval. However, assuming that 100% compliant meant
that you got through all of your components once, you still would not be able to show the
last two test dates. 12 years from now, would you still have to discuss the program you
were using prior to 12 years ago for those components to have a complete audit, because
of having to address the last 2 test dates?
Response: Thank you for your comments. First of all, the Data Retention presumes a stable Standard that has been in effect.
Further, the SDT believes that Compliance Monitors will assess compliance for activities performed before the effective date of this
Standard using the program that you had in place previously. Therefore, the documentation for your program under PRC-005-1
(whatever it may have been) will serve as your “second interval” documentation until supplanted by new PRC-005-2 records.
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Consideration of Comments on PSMTSDT — Project 2007-17
4. The SDT has included VSLs with this posting. Do you agree with the assignments that have
been made? If not, please provide specific suggestions for change.
Summary Consideration: Many commenters were concerned about the basis for the percentage
increments for different severities of VSLs; these commenters were referred to the VSL Guidelines which
propose a Lower VSL as noncompliant with “5% or less,” the Medium VSL as “more than 5% but less than
(or equal to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the Severe VSL as
“more than 15% noncompliant.”.
Similarly, many commenters suggested that binary VSLs be assigned a Lower or High rather than a
Severe, and were also referred to the VSL Guidelines which indicate that total noncompliance with a
requirement is a Severe VSL. VSLs are not indicators of “importance” or “reliability-related risk” – VSLs
are an indication of the degree of noncompliant performance.
The VSL for Requirement R4 was modified to add stepped VSLs relating to resolution of maintenancecorrectable issues in response to several comments.
Several commenters suggested that the Lower VSL for R4 start at 1% rather than 5%, which is not in
accordance with the VSL Guidelines.
Organization
Yes or
No
Question 4 Comment
PPL Supply
No Comment.
Xcel Energy
No comments
San Diego Gas & Electric
No
The Detroit Edison
No
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
Company
GDS Associates
No
1. We do agree with the majority of the assignments that have been made, however the
standard needs specific guidance so to be clearly evidentiated the components as
included in the definition of Protection System. The applicability of the standard does
not address the current issues regarding radial + load serving only situation when
Protection System not designed to provide protection for the BES.
2. Not sure if the percentages corresponding to the events and activities are appropriately
assigned. What were the criteria on which all these percentages are based upon?
3. Requirement R3 Severe VSL note 3 allows smaller segment population than the Lower
VSL. How these segment limits were developed?
Response: Thank you for your comments.
1. This is an issue related to your Regional BES definition, not to the VSLs.
2. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the Lower VSL for stepped VSLs as “5% or
less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including)
15%,” and the Severe VSL as “more than 15%.”
3. The segment limits for Requirement R3 and Attachment A were developed according to statistical references to assure that
performance-based programs are based on a statistically-significant population. See Section 9 of the Supplementary Reference
Document. The Lower VSL addresses “a slightly smaller segment population” than specified; the Severe VSL addresses “a
significantly smaller segment population” than specified.
Ameren
November 17, 2010
No
1) The Lower VSL for all Requirements should begin above 1% of the components. For
example for R4: “Entity has failed to complete scheduled program on 1% to 5% of total
Protection System components.” PRC-005-2 unrealistically mandates perfection without
providing technical justification. A basic premise of engineering is to allow for reasonable
tolerances, even Six Sigma allows for defects. Requiring perfection may well harm
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
reliability in that valuable resources will be distracted from other duties.
2) In R1, a “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based. It is possible
that a component that failed to be individually identified per R1.1 was included by entity
A’s maintenance plan. This documentation issue gets a higher VSL than entity B that
identified a component without maintaining it. We suggest the R1 VSL be change to Low,
since we believe lack of maintenance to be more severe than documentation issues.
Response: Thank you for your comments.
1. The SDT shares your concerns regarding the Lower VSL portion of the stepped VSLs not providing any tolerance for nonconformance without being non-compliant. However, the VSL Guidelines, which conform to the FERC VSL Order, specify that
Lower shall be “5% or less.”
2. The VSL for Requirement R1 addresses various levels of severity for degrees of non-compliance. The VSL Guidelines, developed
in accordance with the FERC VSL Order, establish that if only a single VSL is provided, it must be Severe. The reliability-related
risk related to noncompliance with this requirement is addressed by the VRF being assigned as Lower.
Entergy Services
No
1. R4: A “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
2. R4: Suggest a stepped VSL for “Entity has failed to initiate resolution of maintenancecorrectable issues”. While we understand the importance of addressing a correctable
issue, it seems like there should be some allowance for an isolated unintentional failure to
address a correctable issue. If possible, consider the potential impact to the system. For
example, a failure to address a pilot scheme correctable issue for an entity that only
employs pilot schemes for system stability applications should not necessarily have the
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
same VSL consequence as an entity which employs pilot schemes everywhere on their
system as a standard practice.
Response: Thank you for your comments.
1. This actually addresses the VSL for Requirement R1, which addresses various levels of severity for degrees of non-compliance.
The risk related to this is addressed by the VRF being assigned as Lower.
2. The VSL for Requirement R4 has been modified to provide stepped VSLs for initiation of resolution of maintenance-correctable
issues.
WECC
No
Compliance does not agree. The R1 VSL allows too much to interpret. What does no
more than 5% of the component actually use to define the percentage; it should be specific
if it is referring to the weight of each component and how many components are there. For
example, Protective Relay is one component of five. In addition the VSL for Lower,
Moderate and High states in the first paragraph that the entity included all of the “Types” of
components according to the definition, though failed to “Identify the Component”. It needs
clarity on how it can be included though not specifically identified like the next two bullets.
The same concern applies to R2 and R4. Be specific about what is included (or not) to
calculate those percentages.
Response: Thank you for your comments. The percentages will depend to a large degree how the entity describes their components.
A definition of “Component” has been added to the Standard to provide guidance and help provide consistency.
Constellation Power
Generation
No
Constellation Power Generation does not agree with the proposed data retention section.
Retaining and providing evidence of the two most recent performances of each distinct
maintenance activity should be sufficient. For entities that have not been audited since
June of 2007, having to retain evidence from that date to the date of an audit could contain
numerous cycles, which is cumbersome and does not improve the reliability of the BES.
Response: Thank you for your comments. This comment is not relevant to VSLs. In order for a Compliance Monitor to be assured of
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
compliance, the SDT believes that the Compliance Monitor will need the data of the most recent performance of the maintenance, as
well as the data of the preceding one, as well as data to validate that entities have been in compliance since the last audit (or currently,
since the beginning of mandatory compliance). The SDT has specified the data retention in the posted Standard to establish this level
of documentation.
Northeast Utilities
No
For R1 under Severe VSL - suggest moving the first criteria “The entity’s PSMP failed to
address one or more of the type of components included in the definition of “Protection
System” under High VSL since this criteria cannot have the same VSL level as “Entity has
not established a PSMP”.
Response: Thank you for your comments. The SDT believes that, if an entity has missed one (of the five) entire component types in
their program, they do not have a complete program.
Florida Municipal Power
Agency
No
1. For the VSLs of R1 and R2, we do not understand where the 5%, 10% come from.
There are only a few types of components, relays, batteries, current transformers and
voltage transformers, DC control circuitry, communication, that’s 6 component types by
our count, so, missing 1 component type in discussing the type of maintenance program
is already a 17% error and Low, Medium and High VSLs are meaningless as currently
drafted and every violation would be Severe, was the intention to apply this is a different
fashion?
2. Perfection is Not A Realistic Goal R4 allows no mistakes. Even the famous six sigma
quality management program allows for defects and failures (i.e., six sigma is six
standard deviations, which means that statistically, there are events that fall outside of
six standard deviations). PRC-005 has been drafted such that any failure is a violation,
e.g., 1 day late on a single relay test of tens of thousands of relays is a violation. That is
not in alignment with worldwide accepted quality management practices (and also
makes audits very painful because statistical, random sampling should be the mode of
audit, not 100% review as is currently being done in many instances). FMPA suggests
considering statistically based performance metrics as opposed to an unrealistic
performance target that does not allow for any failure ever. Due to the shear volume of
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
relays, with 100% performance required, if the standards remain this way, PRC-005 will
likely be in the top ten most violated standards for the forever. In other words, 1-2% of
components outside of the program should be allowed without a violation and Low VSL
should start at a non-zero number, such as “Entity failed to complete scheduled
program for 3-6% of components based on a statistically significant random sampling”
or something to that affect.
3. There is a fundamental flaw in thinking about reliability of the BES. We are really not
trying to eliminate the risk of a widespread blackout; we are trying to reduce the risk of a
widespread blackout. We plan and operate the system to single and credible double
contingencies and to finite operating and planning reserves. To eliminate the risk, we
would need to plan and operate to an infinite number of contingencies, and have an
infinite reserve margin, which is infeasible. Therefore, by definition, there is a finite risk
of a widespread blackout that we are trying to reduce, not eliminate, and, by definition,
by planning and operating to single and credible double contingencies and finite
operating and planning reserves, we are actually defining the level of risk from a
statistical basis we are willing to take. With that in mind, it does not make sense to
require 100% compliance to avoid a smaller risk (relays) when we are planning to a
specified level of risk with more major risk factors (single and credible double
contingencies and finite planning and operating reserves).
Response: Thank you for your comments.
1. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the Lower VSL for stepped VSLs as “5% or
less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including)
15%,” and the Severe VSL as “more than 15%.” Much of this comment seems to relate to the VSL for Requirement R1; this VSL
has been extensively revised, and additional terms have been added to the Definitions section to clarify.
2. The SDT shares your concerns regarding the Lower VSL portion of the stepped VSLs not providing any tolerance for nonconformance without being non-compliant. However, the VSL Guidelines, which conform to the FERC VSL Order, specify that
Lower shall be “5% or less.” The VRF and VSLs are only a starting point in determining the size of a penalty or sanction – the
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
Compliance Enforcement Authority has latitude to consider aggravating factors and mitigating factors in determining whether there
should be any penalty, and the size of any penalty. These mitigating and aggravating factors are oultined in the Compliance
Monitoring and Enforcement Program. http://www.nerc.com/files/Appendix4C_Uniform_CMEP_10022009.pdf
3. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the
currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and understands this to be consistent with the position
of FERC staff. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in
violation.
Santee Cooper
No
In R1, a “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance.
SERC Protection and
Control Sub-committee
(PCS)
No
In R1, a “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance.
Progress Energy Carolinas
No
In the VSL for R1, a failure to “specify whether a component is being addressed by timebased, condition-based, or performance-based maintenance” by itself is a documentation
issue and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of nonNovember 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
compliance.
Pacific Northwest Small
Public Power Utility
Comment Group
No
is possible that a component that failed to be individually identified per R1.1 was included
by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B
that identified a component without maintaining it. We suggest the R1 VSL be change to
Low, since we believe lack of maintenance to be more severe than documentation issues.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance. The risk related to non-compliance with the various requirements is addressed by assignment of the associated VRFs.
Additionally, Requirement R1 and the associated VSLs have been substantially modified, and may address your concern.
Pepco Holdings, Inc. Affiliates
No
It is possible that a component that failed to be individually identified per R1.1 was included
by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B
that identified a component without maintaining it. We suggest the R1 VSL be change to
Low, since we believe lack of maintenance to be more severe than documentation issues.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance.
PNGC Power
No
It is possible that a component that failed to be individually identified per R1.1 was included
by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B
that identified a component without maintaining it. We suggest the R1 VSL be change to
Low, since we believe lack of maintenance to be more severe than documentation issues.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance.
Long Island Power
Authority
November 17, 2010
No
1. R4 under Severe VSL mentions - Entity has failed to initiate resolution of maintenancecorrectable issues. What proofs will satisfy the requirement that the entity has initiated the
resolution.
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
2. R1 under Severe VSL - LIPA suggests moving the first criteria “The entity’s PSMP failed
to address one or more of the type of components included in the definition of “Protection
System” under High VSL since this criteria cannot have the same VSL level as “Entity has
not established a PSMP”.
Response: Thank you for your comments.
1. The SDT is unable to categorically state what will satisfy a Compliance Monitor, but it seems that a work order addressing the
maintenance-correctable issue would be one example. FAQ IV.1.B and Section 15.7 of the Supplementary Reference Document
may also be helpful.
2. The SDT believes that if an entity has missed one (of the five) entire component types in their program, they do not have a complete
program.
Northeast Power
Coordinating Council
No
1. R4 under Severe VSL mentions - Entity has failed to initiate resolution of maintenancecorrectable issues. What proof will satisfy the requirement that the entity has initiated
the resolution?
2. R1 under Severe VSL - Move the first criteria “The entity’s PSMP failed to address one
or more of the type of components included in the definition of ‘Protection System’”
under High VSL since this criteria cannot have the same VSL level as “Entity has not
established a PSMP”.
Response: Thank you for your comments.
1. The SDT is unable to categorically state what will satisfy a Compliance Monitor, but it seems that a work order addressing the
maintenance-correctable issue would be one example. FAQ IV.1.B and Section 15.7 of the Supplementary Reference Document
may also be helpful.
2. The SDT believes that if an entity has missed one (of the five) entire component types in their program, they do not have a complete
program.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
MidAmerican Energy
Company
Yes or
No
No
Question 4 Comment
The lower VSL specification for R4 should allow for a small level of incomplete testing.
Suggest changing “5% or less” to “from 1% to 5%”.
Response: Thank you for your comments. The SDT shares your concerns regarding the Lower VSL portion of the stepped VSLs not
providing any tolerance for non-conformance without being non-compliant. However, the VSL Guidelines, which conform to the
FERC VSL Order, specify that Lower shall be “5% or less.”The VRF and VSLs are only a starting point in determining the size of a
penalty or sanction – the Compliance Enforcement Authority has latitude to consider aggravating factors and mitigating factors in
determining whether there should be any penalty, and the size of any penalty. These mitigating and aggravating factors are oultined
in the Compliance Monitoring and Enforcement Program. http://www.nerc.com/files/Appendix4C_Uniform_CMEP_10022009.pdf
Springfield Utility Board
No
The Violation Risk Factors are problematic.
1. With all due respect, it seems that NERC still operates in a "BIG UTILITY" mind set. Big
utilities have potentially hundreds or thousands of components under different device
types. Looking at the VRFs, the percentages 5% or 15% as an example, are looked at
based on a deep pool of multiple devices so a "BIG UTILITY" that misses a component
or small number of components may not trigger a high severity level. However a small
utility may have only a handful of components under each type. Therefore if the small
utility were to miss one component all of a sudden the utility automatically triggers the
5% or 15% threshold. This type of dynamic unreasonable and not equitable. Therefore
(in an attempt to work within the framework proposed), SUB proposes that there be a
minimum number of components that might not be in compliance which result in a much
lower Violation Severity Level. SUB suggests that NERC try to create a level playing
field. If 15% of a Big Utility's total number of components averages at around 15 out of
100 total then perhaps a reasonable outcome would be that up to 5 components
(regardless of the total number of components an entity has under each type) could be
in violation without tripping into a high VSL.(the 5 components threshold may not apply
to all types, this is just for illustrative purposes).
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
2. Also, are the missed components compounding? For example, if an entity missed 5
components on year three and another 5 components in year 10 is the VSL based on
10 components or 5 components. There should be a time horizon attached to the VSL
such that the VSL does not count prior components that were brought into compliance
through a past action. That intent may be to not have the VSLs be based on
compounding numbers of components; however that should be made clear.
Response: Thank you for your comments. You discussed VRFs, but it appears that you are actually discussing VSLs.
1. The SDT shares your concern about the stepped VSLs. However, the VSL Guidelines, developed in accordance with the FERC
VSL Order, establish the Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as “more than 5% but less than (or equal
to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the Severe VSL as “more than 15%.” The SDT did,
however, modify the VSLs for R1 so that they do not use percentages.
2. The VSLs are assigned on the basis of percentages of components for which you are non-compliant. The SDT suggests that you
review the Compliance Monitoring Enforcement Program for clarification on self-reports, and so forth.
Tennessee Valley Authority
No
The Violation Severity Level Table listing for Requirement R4 lists the following under
“Severe VSL”.”Entity has failed to initiate resolution of maintenance-correctable issues” The
threshold for a Severe Violation in this case is too broad and too subjective. The threshold
needs to be clearly defined with low, medium, and high criteria.
Response: Thank you for your comments. The VSLs for Requirement R4 have been modified to provide stepped VSLs for initiation of
resolution of maintenance-correctable issues.
BGE
No
The VSL’s as proposed may be reasonable but it is difficult to endorse them until the
ambiguity in R1.1 is reduced.
No
The VSLs for PRC-005-2 requirements R1, R2 and R4 have significantly tighter
Response: Thank you.
Duke Energy
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
percentages than the corresponding requirements in PRC-005-1. We believe that the
Lower VSL should be up to 10%, the Moderate VSL should be 10%-15%, the High VSL
should be 15% to 20%, and the Severe VSL should be greater than 20%, which is still a
lower percentage than the 25% Lower VSL currently in PRC-005-1.
Response: Thank you for your comments. The SDT shares your concern abuout the stepped VSLs. However, the VSL Guidelines,
developed in accordance with the FERC VSL Order, establish the Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as
“more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the Severe VSL as
“more than 15%.”
Indeck Energy Services
No
1. The VSL's treat all entities, components and problems alike. By combining 4 protection
maintenance standards, it elevates the VSL on otherwise minor problems to the highest
levels of any of the predecessor standards. The threshold percentages are very
arbitrary. Severe VSL doesn't in any way relate to reliability. For a small generator to
miss or mis-categorize 1 out of 7 relays is unlikely to have any impact on reliability,
much less deserving a severe VSL. The R2 & R4 VSL's don't care about results of the
program, only whether all components are covered. Half of the components could fail
annually and it’s not a Severe VSL.
2. The R3 VSL allows 4% countable events, which can be hundreds for a large entity and
only allows a few for a small entity.
Response: Thank you for your comments.
1. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the Lower VSL for stepped VSLs as “5% or
less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including)
15%,” and the Severe VSL as “more than 15%.” VSLs are not intended to assess the risk to reliability of noncompliance, VSLs are
intended to identify different degrees of noncompliance with the associated requirement. The VRFs assess the risk to reliability of
noncompliance with the requirement.
2. Relating to the R3 VSL, the “4% countable events” corresponds to the requirement relevant to performance-based programs in
Attachment A. This value was determined to be a statistically significant value relating to performance-based programs, which
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
may not be practical for a small entity to implement without aggregation with other entities having similar programs. See Section 9
of the Supplementary Reference Document.
US Bureau of Reclamation
No
1. The VSL's use terms that are not tied back to a requirement and appear to be based on
the concept that every component will cause an impact on the BES. The VSL's use the
term "countable event" to score the VSL; however, there is no requirement associated
with the number of "countable events".
2. The VSL's should allow for minor gaps in maintenance documentation where there is no
impact to the BES if the component failed.
Response: Thank you.
1. The VSL for Requirement R3, which you are questioning, addresses limits on “countable events” as they relate to the requirements
for a Perfomance Based program within Attachment A.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation. The VRF
and VSLs are only a starting point in determining the size of a penalty or sanction – the Compliance Enforcement Authority has
latitude to consider aggravating factors and mitigating factors in determining whether there should be any penalty, and the size of
any penalty. These mitigating and aggravating factors are oultined in the Compliance Monitoring and Enforcement Program.
http://www.nerc.com/files/Appendix4C_Uniform_CMEP_10022009.pdf
Black Hills Power
No
-VSL's are based on percentages of components, where the definition of a 'component' is in
many cases up to the entity to interpret (see PRC-005-2 FAQ sheet, Page 2). Basing VSL's
on an entities interpretation (or count) of 'components' is not an equitable measure of
severity level.
Response: Thank you for your comment. A definition of “Component” has been added to the Standard to provide guidance and help
provide consistency.
JEA
No
November 17, 2010
We could find no rational provided for the % associated with each VSL, or component
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
rationale used to determine the proposed values listed. Is this included in some
documentation that is available but not included as part of this review?
Response: Thank you for your comments. The percentages, are established in accordance with the VSL Guidelines, developed in
accordance with the FERC VSL Order, which establish the Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as “more
than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the Severe VSL as “more
than 15%.” The VSL Guidelines are posted on the Standard Resources web page:
http://www.nerc.com/files/VSL_Guidelines_20090817.pdf
American Electric Power
Yes
American Transmission
Company
Yes
Arizona Public Service
Company
Yes
Bonneville Power
Administration
Yes
Consumers Energy
Company
Yes
Dynegy Inc.
Yes
Exelon
Yes
FirstEnergy
Yes
Great River Energy
Yes
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Hydro One Networks
Yes
MRO’s NERC Standards
Review Subcommittee
(NSRS)
Yes
Nebraska Public Power
District
Yes
PacifiCorp
Yes
Public Service Enterprise
Group ("PSEG
Companies")
Yes
ReliabilityFirst Corp.
Yes
South Carolina Electric and
Gas
Yes
The United Illuminating
Company
Yes
We Energies
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Yes
November 17, 2010
Question 4 Comment
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
Inc.
MEAG Power
Yes
It would be good to have the basis of the 5%, 10% and 15% defined. With time and
experience these percentages may need to be changed.
Response: Thank you for your comment. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the
Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as
“more than 10% up to (and including) 15%,” and the Severe VSL as “more than 15%.”
Manitoba Hydro
Yes
There is no rational provided for the % associated with each VSL, or component rationale
used to determine the proposed values listed.
Response: Thank you for your comment. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the
Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as
“more than 10% up to (and including) 15%,” and the Severe VSL as “more than 15%.”
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Consideration of Comments on PSMTSDT — Project 2007-17
5. The SDT has revised the “Supplementary Reference” document which is supplied to provide
supporting discussion for the Requirements within the standard. Do you agree with the
changes? If not, please provide specific suggestions for change.
Summary Consideration: Most commenters seemed to appreciate the information provided within the
Supplementary Reference document. Many commenters asked whether the Supplementary Reference
was part of the Standard, to which the SDT replied, “No.”
Several commenters also were concerned that the Supplementary Reference document may not be kept
current with the Standard itself. There were assorted individual technical comments about the
Supplementary Reference document, to which the SDT responded. Several comments irrelevant to the
Supplementary Reference document were also offered; the SDT offered responses relevant to the
comments.
Organization
Yes or
No
Question 5 Comment
PPL Supply
No Comment.
Santee Cooper
No Comment.
SERC Protection and
Control Sub-committee
(PCS)
The SERC PCS expresses no opinion on this question.
San Diego Gas & Electric
No
Ameren
No
November 17, 2010
1) Is this document considered part of the standard? We expect to use it as a reference in
developing our PSMP, during audits, and for self-certification as an authentic source of
information. It is also unclear how this document will be controlled (i.e. Revised and
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
Approved, if at all).
2) On page 22 please clarify that only applies to high speed ground switches associated
with BES elements.
3) We appreciate the SDT providing this valuable reference.
Response:Thank you for your comments.
1. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference
document, accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of
Requirements, etc., and is not to include explanatory information like that included in the Supplementary Reference document. The
SDT intends that this document help explain, clarify, and in some cases suggest methods to comply with the Standard. The
Standards Committee has a formal process for determining whether to authorize posting a reference document with an approved
standard. That process is posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. The Standard applies to High-Speed Ground Switches that are used to trip BES elements or that are used to protect BES elements.
In response to your comment, the SDT has modifed the Supplementary Reference Section 15.3 as follows: “The SDT believes that
this is essentially a transferred-tripping device without the use of communications equipment. If this high-speed ground switch is
“…applied on, or designed to provide protection for the BES…” then this device needs to be treated as any other Protection System
component. The control circuitry would have to be tested within 12 years and any electromechanically operated device will have to
be tested every 6 years. If the spring-operated ground switch can be disconnected from the solenoid triggering unit then the solenoid
triggering unit can easily be tested without the actual closing of the ground blade.
3.
Thank you.
Xcel Energy
No
1. As we commented on in the previous draft of the standard that proposed the
Supplementary Reference and FAQ, we are concerned as to what role these
documents will play in compliance/auditing. It is also unclear how these documents will
be controlled (i.e. Revised and Approved, if at all).
2. Inconsistencies have been identified between proposed standard and the documents
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
(e.g. page 29 of FAQ example 1).
Response: Thank you for your comments.
1. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a Reference
Document, accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of Requirements,
etc., and is not to include explanatory information like that included in the Supplementary Reference document. The Supplementary
Reference and FAQ have been revised to make them consistent with the new version of PRC-005-2. The Standards Committee has
a formal process for determining whether to authorize posting a reference document with an approved standard. That process is
posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. Thank you. The FAQ has been revised to make it consistent with the new version of PRC-005-2 and the Supplementary Reference
document.
Pepco Holdings, Inc. Affiliates
No
Figure 1 & 2 Legend (page 29), Row 5, Associated Communications Systems, includes
Tele-protection equipment used to convey remote tripping action to a local trip coil or
blocking signal to the trip logic (if applicable). This description does not include all the
various types of signals communicated for proper operation of various protective schemes
(i.e., DUTT, POTT, DCB, Current Differential, Phase Comparison, synchro-phasors, etc.)
A more inclusive and generic description might be - Tele-protection equipment used to
convey specific information, in the form of analog or digital signals, necessary for the
correct operation of protective functions. This is also consistent with the revised definition
of Protection System. Conversely, excluded equipment would be - Any communications
equipment that is not used to convey information necessary for the correct operation of
protective functions.
Response: Thank you for your comment.
The Supplementary Reference and FAQ have been revised to make them consistent with the new version of PRC-005-2 and each
other, and to incorporate language similar to your suggestion.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
MEAG Power
No
Further clarification is needed. The information provided on verifying outputs of voltage
and current sensing devices is confusing. In one part, it indicates that the intent is to verify
that intended voltages and currents are getting to the relay apparently without regards to
accuracy. A practical method of verifying the output of VTs and CTs is not identified and
need to be identified.
Response: Thank you for your comments.
The intent of the maintenance activity is to verify that the necessary values reach the protective relays. The SDT believes that a
maintenance plan that requires infra-red scanning of VTs and CTs is not sufficient. The SDT further believes that routine
commissioning tests, while certainly allowed, need not be required in the Standard because mere ratio tests would not prove that the
values reach the relay.
A practical method is to read the values at the relays and, as you state, verify that the quantities meet your needs.
The SDT believes that the discussion in Section 15.2 of the Supplementary Reference is sufficient, and is supplemented in several
subsections of FAQ II.3.
Indeck Energy Services
No
In 2.3, the applicability is stated to have been modified. As discussed at the FERC
Technical Conference on Standards Development, the goal of the standards program is to
avoid or prevent cascading outages--specifically not loss of load. The modified applicability
moves away from the purpose of the standards program to an undefined fuzzy concept.
Applicable Relays ignore the fact that some relays, or even some entities, have little to no
affect on reliability. The global definition of Protective System encompasses all equipment,
and doesn't differentiate the components that meet the purpose of the standards program.
The Supplementary Reference doesn't overcome the inherent shortcomings of the
standard.
Response: Thank you for your comments.
The Supplementary Reference is intended to help clarify the Standard.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
The United Illuminating
Company
Yes or
No
Question 5 Comment
No
Include a detailed example of an Inventory list. Allow for different means of maintaining the
lists electronically, that is, as spreadsheets, or databases.
Response: Thank you for your comments.
The Supplementary Reference is intended to help clarify the Standard, not add to the Requirements of the Standard. Maintaining your
lists is a business practice that you make, spreadsheets and/or databases have not been precluded in the Standard or in any reference
document.
US Bureau of Reclamation
No
It is not reasonable to assert that a statistical analysis of survey data is reliability based
justification for requiring specific maintenance intervals. The reference document admits
that intervals varied widely. To assert a postage stamp interval does not account for other
variables which optimize a specific maintenance program. That is not saying that the
reference documents are worthless. Indeed it has many good suggestions. However, to
impugn the maintenance programs in practice because they do not follow the "weighted
average" is hardly scientific or credible. The reference document should analyze the
maintenance programs from the stand point of the outages associated with those facilities.
If a specific maintenance practice was shown to have compromised the performance of the
facility and the reliability of the BES, then it would added to the statistical database of
practices which would not be acceptable. Now the statistical analysis of the database
would show that certain practices have consequences which impact reliability and a
requirement can be constructed to disallow them.
Response: Thank you for your comments.
FERC directed the SDT to set maximum time intervals between maintenance activities. The SDT recognized that different types of
equipment, different generations of equipment, different failure modes of equipment and different versions of time-based maintenance
had to be considered. The SDT agrees with the commenter that the Standard allows statistical analysis and performance-based
maintenance allows an entity to create time intervals that could exceed any “weighted-averages” time-based intervals. The
Supplementary Reference adds a section (9) to show how an entity can create a performance-based maintenance interval.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Public Service Enterprise
Group ("PSEG
Companies")
Yes or
No
No
Question 5 Comment
1. Suggest that figure 2 has a line of demarcation added that shows components
specifically not part of the standard requirements. (Medium voltage bus).
2. Battery charger should be removed from table of components when a storage battery is
used for the DC supply.
Response: Thank you for your comments.
1. The figures are intended to be general information and not to be inclusive of all situations.
2. The modification of the Protection System definition from “station battery” to “station dc supply” is intended to include battery
chargers, and Table 1-4 within draft PRC-005-2 includes activities specifically related to battery chargers.
JEA
No
The Supplementary Reference document is critical in our current compliance environment
to be approved as part of the standard and any standard modifications need to be kept in
synchronization with the FAQ and the Supplementary Reference.
Response: Thank you for your comments.
1. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference
document, accompanying the S. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc.,
and is not to include explanatory information like that included in the FAQ and Supplementary Reference. The Supplementary
Reference and FAQ have been revised to make them consistent with the new version of PRC-005-2.
Long Island Power
Authority
No
1. There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an
entity can count components however; an example in the reference document will
provide clarity.
2. Page 7 of the redline version of Supplemental Reference - bullet 1 under Maintenance
Services, paragraph 2, it says “ If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time clock
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
is reset for those components. LIPA believes that resetting the time clock will make
tracking difficult (unless entities have a sophisticated automated tool for tracking).
Another option where an entity can take credit for a correct performance within
specifications at the time of the maintenance cycle should be included.
Response: Thank you for your comments.
1. A definition of “Component” has been added to the draft Standard to provide guidance. The Standard and the Tables have also
been revised throughout for clarity.
2. The example cited is only offered as an option for entities that may wish to make use of observed real-time operations within their
PSMP. An entity may, if desired, reset the time clock on a correct real-time occurrance. An entity does not have to “reset the time
clock” if it chooses to maintain all of its components on a set schedule. The example given is merely one method to log a
completed tripping action, which would alleviate the need to validate that same trip path. The SDT acknowledges that there are
many ways to prove circuits; real-time switching or fault-clearing activities can be used but are not the only methods.
Northeast Power
Coordinating Council
No
1. There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an
entity can count components.
2. However; an example in the reference document will provide clarity. Page 7 of the
redline version of Supplemental Reference - bullet 1 under Maintenance Services,
paragraph 2 states “ If specific protection scheme components have demonstrated
correct performance within specifications, the maintenance test time clock is reset for
those components.” Resetting the time clock will make tracking difficult (unless entities
have a sophisticated automated tool for tracking). Another option where an entity can
take credit for a correct performance within specifications at the time of the maintenance
cycle should be included.
Response: Thank you for your comments.
1. A definition of “Component” has been added to the draft Standard to provide guidance. The Standard and the Tables have also
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
been revised throughout for clarity.
2. The example cited is only offered as an option for entities that may wish to make use of observed real-time operations within their
PSMP. An entity may, if desired, reset the time clock on a correct real-time occurrance. An entity does not have to “reset the time
clock” if it chooses to maintain all of its components on a set schedule. The example given is merely one method to log a
completed tripping action, which would alleviate the need to validate that same trip path. The SDT acknowledges that there are
many ways to prove circuits; real-time switching or fault-clearing activities can be used but are not the only methods.
Northeast Utilities
No
There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an entity
can count components however; an example in the reference document will provide clarity.
Response: Thank you for your comments. A definition of “Component” has been added to the draft Standard to provide guidance.
The Standard and the Tables have also been revised throughout for clarity.
Tennessee Valley Authority
No
1. There needs to be a defined method of deferral when equipment can’t be gotten out
of service until a scheduled outage.
2. Give some examples of what “inputs and outputs that are essential to proper
functioning of the Protection System” are.
3. a) Define what a “Control and Trip Circuit” is.
4. b) Is there one per relay?
5. c) Do I have to have a list of them in my work management system?
Response: Thank you for your comments.
1. “Grace periods” within the Standard are not measurable, and could lead to persistently increasing intervals.
2. Some examples of outputs may include but are not limited to: trip, initiate zone timer, initiate breaker fail. Some examples of input
may include but are not limited to: breaker fail initiate, start timer. This cannot be an all-inclusive list as any given scheme could
have many variations. In short, if your scheme requires a specific input to function properly then you must have that input
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
maintained; if your scheme has a specific output that must function then it must be maintained. If the input or output is used for a
non-protective function (such as, but not limited to, Sequence-of-Events Recorder, alarm or indication) then it does not have to be
maintained under this Standard. See Section 15.3 of the Supplementary Reference and FAQ II.2.L.
3. a) Circuitry needed for the correct operation of the protective relay. A definition of “Component” has been added to the draft
Standard to provide guidance. See Section Section 15.3 of the Supplementary Reference.
4. b) This depends on your scheme and your relay. A definition of “Component” has been added to the draft Standard to provide
guidance.
5. c) The SDT believes that a PSMP that requires maintenance upon all of the circuits, and includes a check-off (list) system that
accounts for all circuits being verified would suffice.
American Electric Power
Yes
American Transmission
Company
Yes
Arizona Public Service
Company
Yes
BGE
Yes
Black Hills Power
Yes
Constellation Power
Generation
Yes
Consumers Energy
Company
Yes
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Duke Energy
Yes
Dynegy Inc.
Yes
Entergy Services
Yes
Exelon
Yes
Great River Energy
Yes
Hydro One Networks
Yes
Manitoba Hydro
Yes
MidAmerican Energy
Company
Yes
MRO’s NERC Standards
Review Subcommittee
(NSRS)
Yes
NERC Staff
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PacifiCorp
Yes
November 17, 2010
Question 5 Comment
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
PNGC Power
Yes
Progress Energy Carolinas
Yes
ReliabilityFirst Corp.
Yes
South Carolina Electric and
Gas
Yes
Southern Company
Transmission
Yes
The Detroit Edison
Company
Yes
We Energies
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Inc.
Yes
WECC
Yes
November 17, 2010
Question 5 Comment
Compliance does agree with the clarity and the Supplementary Reference should be
specially referenced where appropriate the Tables 1a, 1b, 1c and Attachment A that are
included with the Standard. But this reference is not a part of the approved standard and
there are no controls which prevent changes in the reference document that could impact
the scope or intent of the standard. If the standard is approved with reference to the
Supplementary Reference then future changes to the Supplementary Reference should not
be allowed without due process. Only the version in existence at the time of approval of the
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
standard could be used to clarify or explain the standard.
Response: Thank you for your comments. The SDT intends that the Supplementary Reference document be updated as the Standard is
revised to maintain its relevance to the application of the Standard. The Standards Committee has a formal process for determining
whether to authorize posting a reference document with an approved standard. That process is posted on the Standard Resources web
page – here is a link to the procedure: http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
Nebraska Public Power
District
Yes
Is this document considered part of the standard and may be referenced during audit and
self-certification as an authentic source of information?
Response: Thank you for your comments. This document provides supporting discussion, but is not part of the Standard. The SDT
intends that these be posted as reference documents, accompanying the Standard. The Standards Committee has a formal process for
determining whether to authorize posting a reference document with an approved standard. That process is posted on the Standard
Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
Springfield Utility Board
Yes
SUB appreciates that Time Based, Performance Based, and Condition Based programs
can be combined into one program. However it should be clear that a utility may include
one, two or all three of these types of programs for each individual device type. Currently
the language reads:"TBM, PBM, and CBM can be combined for individual components, or
within a complete Protection System." The "and" requires all three to be combined if they
are combined. SUB suggests the “and” be changed to "or". Language Change: "TBM,
PBM, or CBM can be combined for individual components, or within a complete Protection
System."
Response: Thank you for your comments. The SDT modified Requirement R1 of the Standard.
FirstEnergy
November 17, 2010
Yes
We support the reference document and appreciate the SDT's hard work developing this
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
document. We offer the following suggestions for possible improvements:
1. The reference document should be linked in Section F of the standard. Otherwise it may
be difficult for someone to navigate the NERC website in search of the document.
2. Section 2.2 - It would be helpful if a short discussion of the reasons for the changes to
the definition of Protection System was included in this reference document. In addition, it
would be beneficial to discuss what is included in "dc supply" components, such as "dc
supplies include battery chargers which are required to be maintained per the Tables in
PRC-005-2."
3. Section 8.1 - The fourth bullet which reads "If your PSMP (plan) requires more then you
must document more." Should be removed. This is already covered in the sixth bullet
which states "If your PSMP (plan) requires activities more often than the Tables
maximum then you must document those activities more often."
Response: Thank you for your comments.
1. This issue may be a good idea. The Standards Committee has a formal process for determining whether to authorize posting a
reference document with an approved standard. That process is posted on the Standard Resources web page – here is a link to the
procedure: http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf.
2. The reasons for the definition change are transitory and should not be in the Supplementary Reference document. The reasons may
be found in the SAR for Project 2007-17. See Section 15.4 of the Supplementary Reference for discussion about batteries and dc
supply.
3. The SDT disagrees with your assertion. The first cited example applies to the activities within your program, and the second applies
to the intervals. These are related but separate. The fourth bullet in Section 8.1 has been revised to clarify.
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Consideration of Comments on PSMTSDT — Project 2007-17
6. The SDT has revised the “Frequently-Asked Questions” (FAQ) document which is supplied to
address anticipated questions relative to the standard. Do you agree with these changes?
If not, please provide specific suggestions for change.
Summary Consideration: Most commenters seemed to appreciate the information provided within the
FAQ document. Many commenters asked whether the FAQ was part of the Standard, to which the SDT
replied, “No.” Several commenters also were concerned that the FAQ document may not be kept current
with the Standard itself. There were assorted individual technical comments about the FAQ, to which the
SDT responded. Several comments irrelevant to the FAQ were also offered; the SDT offered responses
relevant to the comments.
Organization
Yes or
No
Question 6 Comment
MEAG Power
No comment.
PPL Supply
No Comment.
Santee Cooper
No comment.
SERC Protection and
Control Sub-committee
(PCS)
The SERC PCS expresses no opinion on this question.
Indeck Energy Services
No
San Diego Gas & Electric
No
Consumers Energy
No
November 17, 2010
1. FAQ II.3A attempts to clarify the requirements of “Verify the proper functioning of the
current and voltage signals necessary for Protection System operation from the voltage
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Company
Question 6 Comment
and current sensing devices to the protective relays” suggesting that “simplicity can be
achieved” by verifying that the protective relays are receiving “expected values.” It
concludes with a statement of the need to “ensure that all of the individual components
are functioning properly ...” implying that just verifying “expected values” at the protective
relay end of the circuit may be inadequate.
2. FAQ II.4D describes what is required for testing of aux relays to include, “that their trip
output(s) perform as expected”. Does that include timing tests? (Example - high speed
ABB AR relays vs. standard AR relays).
3. The SDT responses to the Draft 1 comments regarding “grace periods” essentially says,
“Absolutely not”. However, FAQ IV.1.D reflects data retention requirements relative to an
entities’ program which includes a grace period!
Response: Thank you for your comments.
1. “Expected values” was intended to convey that the current and/or voltage sensing devices were functioning properly. The SDT
intentionally left out any Requirement in the Standard that the values being read at the protective relays be within a specific
tolerance because each entity may have valid rationale for tolerances at any level. To find a current or voltage value that is wrong
would indicate that something in the voltage or current secondary delivery system is not functioning properly and needs corrective
action. Typically an entity can review values measured at the relay and determine that the values are as expected and that the
maintenance activity has been satisfied.
2. If an entity has designed a protection scheme which contains parts that need to function in a specific manner then those parts need
to be routinely maintained to assure that they perform at that level. The SDT believes that Protection Systems exist at all levels of
complexity and that some systems will be easier to test than others, but that all components that are necessary for the proper
functioning of the Protection System must be maintained. In short, if an entity decided that specific parts were necessary for the
proper operation of the Protection System then those parts need to be routinely maintained.
3. There is no “grace period” allowed by the Standard; a “grace period” is not measurable. That means that the intervals between the
specified maintenance activities in the Standard cannot exceed those established within the Tables. However, many entities have
built in “allowable extensions” to their intervals (thus creating “grace periods” within their own PSMP). In these particular PSMP’s
the total time allowed between the specified maintenance activities (including any allowable extensions or “grace periods”) does not
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exceed the maximum allowed time interval established in the Standard. For example, an entity has in their PSMP that “…the
electro-mechanical relays will be tested every 3 calendar years with a maximum allowable extension of 18 additional calendar
months to allow for scheduling difficulties and unplanned emergencies.” In this way the entity will be audited to their PSMP, they
have added 50% time in the form of their own grace period and the maximum time between the specified maintenance activities
does not exceed the time interval established in the Standard. Also see FAQ IV.2.H for additional discussion on this.
Xcel Energy
No
1. As we commented on in the previous draft of the standard that proposed the
Supplementary Reference and FAQ, we are concerned as to what role these
documents will play in compliance/auditing. It is also unclear how these documents will
be controlled (i.e. Revised and approved, if at all).
2. Inconsistencies have been identified between proposed standard and the documents
(e.g. page 29 of FAQ example 1).
Response: Thank you for your comments.
1. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference
document, accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements,
etc., and is not to include explanatory information like that included in the Supplementary Reference document. The FAQ and the
Supplementary Reference documents have been revised to make them consistent with the new version of PRC-005-2. 1. The
Standards Committee has a formal process for determining whether to authorize posting a reference document with an approved
standard. That process is posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. Thank you. The FAQ has been revised to be consistent with the new version of the Standard.
Nebraska Public Power
District
November 17, 2010
No
1. FAQ 2.G, page 24 - NPPD believes system reliability will be decreased if an entity is
considered non-compliant for exceeding a PSMP stated interval that is within the PRC005-2 Maximum Maintenance Interval. Considering an entity non-compliant for such a
situation will encourage establishment of intervals that only meet the minimum standard.
There should be one standard interval that all entities must be monitored against. If an
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compliance if it misses its target but meets the Maximum Maintenance Interval in the
standard.
2. There are definitions at the beginning of the FAQ that should be contained in the NERC
definitions and not in an FAQ. Placing these in an approved definition will help avoid
interpretation issues that would arise during future audits.
Response: Thank you for your comments.
1. The SDT believes that there are many reasons that would prompt an entity to have some intervals that are more frequent than
those intervals established in the Standard (performance-based maintenance is but a single example). If an entity chooses to
perform maintenance more often than the limits set within the Standard then it may do so. If an entity chooses to perform
maintenance more often than the limits set within its own PSMP then it may do so.
2. The SDT desires to conform to certain rules regarding this issue. If a term appears in the NERC Glossary then all Standards will
have to conform to the definition established. If the terms are shown elsewhere, in the FAQ for example, then clarity can be
achieved when the Standard is read. The SDT intends to help clarify by creating the two supporting reference documents, but not
to restrict other Standards to the uses of some words that will inevitably be shared amongst Standards. The SDT has also moved
several of these definitions to the Standard with the intent that they be part of only this Standard and not a general definition within
the NERC Glossary of Terms.
Progress Energy Carolinas
No
1. FAQ II.2.A: What degree of testing is required for a relay firmware upgrade? Complete
commissioning tests?
2. FAQ V.1.A. There appears to be a typo in Example #1 for “Vented lead-acid battery
with low voltage alarm connected to SCADA (level 2)”: Table 1b does not list any level
2 requirements. Rather, the table refers reader back to the Level 1 requirements.
Same comment for Example #2 as well.
3. FAQ III.1.A: Project 2009-17 provides a response to a request for interpretation of the
term “transmission Protection System” as related to PRC-004-1 and PRC-005-1. The
interpretation addresses the boundaries of the transmission system. NERC should
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investigate whether this same boundary should be defined within the new PRC-005-2.
4. Also, numerous potential boundary issues exist between entities which should be
contemplated and addressed. See the examples below:
a) Utility A may own equipment in Utility B’s substation. Utility A contracts Utility B to
perform maintenance on their equipment. However, the two utilities have different
maintenance programs and intervals for the same types of equipment. Who is
responsible for NERC compliance? Would Utility A be found in violation because their
equipment is being maintained under Utility B’s program which deviates from Utility
A’s maintenance basis?
b) EMC protection is fed from a utility’s instrument transformers. Who is responsible for
validation of the relay inputs and testing of the instrument transformers?
c) Utility-owned communication units (used for transfer trip or carrier blocking) are
coupled to the utility’s power line using customer-owned CCVTs. Who is responsible
for maintenance and testing of these CCVTs?
d) Utility A owns all equipment at one end of line (line terminal A) and Utility B owns all
equipment at other end of line (line terminal B). Who is responsible for demonstrating
the carrier blocking scheme or POTT scheme works correctly?
Response: Thank you for your comments.
1. Complete commissioning tests can be required by the entity. Commissioning tests are not specified within the Standard. The status
of the relay should be that it is ready for use after the firmware upgrade. If the maintenance activities were performed that are
specified within the Standard and its PSMP, then the entity may choose to reset the time clock for maintenance for that device.
2. The Tables within the Standard have been completely revised, and the FAQ revised to align.
3. When the interpretation (Project 2009-17) is approved, the SDT for PRC-005-2 will consider if the interpretation is appropriate for
PRC-005-2 and make associated changes.
a) The owner of the equipment is responsible for assuring that the equipment is maintained according to its PSMP. This is
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consistent with the concepts in the Functional Model. b) The owner of the equipment is responsible for assuring that the equipment
is maintained according to its PSMP.
c) The owner of the equipment is responsible for assuring that the equipment is maintained according to its PSMP.
d) The owner of the equipment is responsible for assuring that the equipment is maintained according to its PSMP. The entities
should coordinate on equipment that affects each other to assure that the equipment is tested in such a fashion that it complies with
both entities’ PSMP.
Tennessee Valley Authority
No
If a relay is tested during a generator outage, what date is allowed to be used for
compliance - actual test date or date equipment was returned to service? These are
usually only a few weeks apart, but may be as much as three months different.
Response: Thank you for your comments.
An entity’s own records are used to judge compliance. The date placed on the evidence should be the date on which testing of the
relevant Protection System component is completed.
Northeast Utilities
No
Page 2 under Component definition, term “somewhat arbitrary” is used by the drafting team
to address what constitutes a dc control circuit. Though the drafting team has provided
entities with flexibility to define as per their methodologies, it is recommended to clearly
determine “what constitutes a dc control circuit” since it will be used to determine
compliance.
Response: Thank you for your comments.
The SDT believes that if the circuit is needed for the Protection System to operate or function correctly, then that circuit must be
maintained.
South Carolina Electric and
Gas
November 17, 2010
No
Question/Answer 4-C (Pg. 10 of FAQ) seems to indicate that by documenting breaker
operations for fault conditions the table 1b requirements for control circuitry (Trip Coils and
Auxiliary relays) can be satisfied. It is possible that even though a breaker successfully
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operates for a fault condition one trip coil of a primary/backup design can be inoperable and
“masked” by the good trip coil. Although it is likely that a faulty trip coil would be caught by
monitoring of continuity it is not a certainty that both trip coils actually operated to clear a
fault (example-mechanical binding)
Response: Thank you for your comments.
The SDT agrees. While a successful trip operation can fulfill requirements of the Standard, it is useful only for the trip paths for which
successful operation was demonstrated and documented.
BGE
No
The FAQ is a very helpful document. A few more changes would be beneficial. See
comments regarding manufactures’ advisories and R1.1 under section 7 below. It is our
recommendation that manufacturers service advisories not be an implied part of the PMSP
requirements and that the expectations for R1.1 be more explicitly described in the FAQ.
Response: Thank you for your comments.
The Supplementary Reference and the FAQ are not a part of the Standard. The intent of the SDT is that the documents help provide
clarity, not to imply additional maintenance. The required minimum maintenance activities are listed in the Standard. Requirement R1
and the tables have been extensively revised.
American Transmission
Company
No
The FAQs are helpful, however, with the revised standard as written; ATC has issues with
the answers provided. Please refer to Question #7 for areas of concern.
Response: Thank you for your comments.
The Standard and the Tables have been revised to add clarity. The FAQ and the Supplementary Reference documents have been
revised to make them consistent with the new version of PRC-005-2. Please see our responses to your comments in Question 7.
MRO’s NERC Standards
Review Subcommittee
November 17, 2010
No
The FAQs are helpful, however, with the revised standard as written, The NSRS has issues
with the answers provided. Please refer to Question #7 for areas of concern.
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(NSRS)
Response: Thank you for your comments.
The Standard and the tables have been revised to improve clarity. The FAQ and the Supplementary Reference documents have been
revised to make them consistent with the new version of PRC-005-2. Please see our responses to your comments in Question 7.
Constellation Power
Generation
No
The PT/CT testing section is implying that the testing must be completed while energized,
which is counter to industry practice at generation facilities. Leeway should be given to the
entities to devise their own methods for testing voltage and current sensing devices and
wiring to the protection system.
Response: Thank you for your comments.
The required minimum maintenance activities are listed in the Standard. The intent of the cited section is to provide examples of how
an entity might perform the testing. Any examples listed in either of the supporting documents should be looked upon as suggestions;
these suggestions are not considered to be a complete list of the methods available. To the contrary, the Standard and the supporting
documents were written considering that there are many ways to achieve a good test. Leeway is certainly available in how an entity
complies with the Standard as the maintenance activities generally specify “what” must be achieved but not “how” an entity achieves it.
Please see FAQ II.3.D.
Pepco Holdings, Inc. Affiliates
No
1. The three month inspection interval for communication equipment mentioned in FAQ II 6
B should be extended to 12 - 18 months (see response to Question #1).
2. In addition, the example used in this section should address what is expected for ONOFF carrier systems. Checking that the equipment is free from alarms and still powered
up does not seem sufficient to verify functionality. The FAQ states that the concept
should be that the entity verifies that the communication equipment...is operable
through a cursory inspection and site visit. However, unlike FSK schemes where
channel integrity can easily be verified by the presence of a guard signal, ON-OFF
carrier schemes would require a check-back or loop-back test be initiated to verify
channel integrity. If the carrier set was not equipped with this feature, verification would
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require personnel to be dispatched to each terminal to perform these manual checks.
Response: Thank you for your comments.
1. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
2. As you suggest, this funcitionality would normally be verified by a manual or automatic checkback system, and, even then, a
station visit would be necessary if alarms are not provided. Where such equipment is not available, a station visit would be
necessary.
Public Service Enterprise
Group ("PSEG
Companies")
No
This is a very useful document and provides a good source of additional information; there
are some cases where it could be interpreted as a standard requirement that can lead to
confusion if conflicts exist. For example, the group by monitoring level example V.1.A
shown on page 29 describes a level 2 partial monitoring as circuits alerting a 24Hr staffed
operations center, page 38 shows level 2 monitoring as detected issues are reported daily.
The actual standard table 1b level 2 monitor describes alarms are automatically provided
daily to a location where action can be taken for alarmed failures within 1 day or less. This
is listed as a supplemental reference document in the standard. The FAQ document
“supports” the standard but is or is not an official interpretation tool, or if it is state as such.
Response: Thank you for your comments.
The FAQ provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference document,
accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc., and is
not to include explanatory information like that included in the FAQ.
The United Illuminating
Company
November 17, 2010
No
What actions are taken if the owner can not perform a specific activity elaborated on the
tables due to the design of the equipment? Is the owner in non-compliance? Must the
owner only accept equipment solutions that allow the maintenance activities elaborated in
the standard to be performed?
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Response: Thank you for your comments.
The SDT is not aware of any activities that cannot be performed as you cite.
JEA
No
Yes the FAQ is also a very important document to be approved along with the standard.
There must be a way to have the standard and the FAQ go hand-in-hand or the standard
must be revised to include much of the FAQ.
Response: Thank you for your comments.
The FAQ provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference document,
accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc., and is not
to include explanatory information like that included in the Supplementary Reference and the FAQ. The FAQ and the Supplementary
Reference documents have been revised to make them consistent with the new version of PRC-005-2. The Standards Committee has
a formal process for determining whether to authorize posting a reference document with an approved standard. That process is posted
on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
American Electric Power
Yes
Arizona Public Service
Company
Yes
Black Hills Power
Yes
Duke Energy
Yes
Dynegy Inc.
Yes
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No
Entergy Services
Yes
Exelon
Yes
Great River Energy
Yes
Hydro One Networks
Yes
Long Island Power
Authority
Yes
Manitoba Hydro
Yes
MidAmerican Energy
Company
Yes
NERC Staff
Yes
Northeast Power
Coordinating Council
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PacifiCorp
Yes
PNGC Power
Yes
November 17, 2010
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ReliabilityFirst Corp.
Yes
Southern Company
Transmission
Yes
Springfield Utility Board
Yes
The Detroit Edison
Company
Yes
We Energies
Yes
Y-W Electric Association,
Inc.
Yes
Ameren
Yes
Question 6 Comment
1) Is this document considered part of the standard? We expect to use it as a reference in
developing our PSMP, during audits, and for self-certification as an authentic source of
information. It is also unclear how this document will be controlled (i.e. Revised and
Approved, if at all).
2) The FAQ needs to be aligned with the tables. The FAQ also contains a duplicate
decision tree chart for DC Supply. The FAQ contains a note on the Decision tree that
reads, "Note: Physical inspection of the battery is required regardless of level of
monitoring used", this statement should be placed on the table itself, and should include
the word quarterly to define the inspection period.
3) We appreciate the SDT providing this valuable reference.
Response: Response: Thank you for your comments.
1. The FAQ provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference document,
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accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc., and is
not to include explanatory information like that included in the Supplementary Reference and the FAQ. The FAQ and the
Supplementary Reference documents have been revised to make them consistent with the new version of PRC-005-2. The
Standards Committee has a formal process for determining whether to authorize posting a reference document with an approved
standard. That process is posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. The FAQ has been revised to make it consistent with the new version of PRC-005-2. The decision trees were removed.
3. Thank you.
Western Area Power
Administration
Yes
Clarification
1) FAQ, page 36, Control Circuit Monitor Level Decision Tree: It’s not clear if the note on
Level 1 device operation is required for Level 3 monitoring.
Response: Thank you for your comments. The Standard and Tables have been extensively revised. The FAQ has been revised to
make it consistent with the new version of PRC-005-2. The decision trees were removed from the FAQ.
WECC
Yes
Compliance does agree with the clarity. The FAQ answers should be referenced
specifically to the Standard and the Supplementary Reference to further understand those
two documents. However, endorsement of the Standard should not imply endorsement of
the FAQ and vice versa.
Response: Thank you for your comments.
FirstEnergy
Yes
We support the FAQ document and appreciate the SDT's hard work developing this
document. The reference document should be linked in Section F of the standard.
Otherwise it may be difficult for someone to navigate the NERC website in search of the
document.
4. Response: Thank you for your comments. The Standards Committee has a formal process for determining whether to authorize
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posting a reference document with an approved standard. That process is posted on the Standard Resources web page – here is a
link to the procedure: http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
If approved as a permanent reference to a standard, then on the “Reliability Standard” web page, there will be a link (in the same cell
as the link to the standard and its archive) to any reference documents approved for posting with the standard.
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7. If you have any other comments on this Standard that you have not already provided in
response to the prior questions, please provide them here.
Summary Consideration: Comments were offered on virtually every aspect of the draft Standard. Many
of these comments resulted in changes to the Standard. The Tables were commented on heavily, and
they were completely revised in response. Many commenters were concerned about not having provision
for a “grace period,” and the SDT responded that this was not allowable. “100% compliance” was also a
concern, and the SDT responded that there was not a means of permitting some level of non-conformance
without being also non-compliant.
Organization
GDS Associates
Question 7 Comment
Definition of Terms Used in the Standard. Protection System Maintenance Program
1. Monitoring. Concerned about the interpretation of this activity description
2. Upkeep. Not sure about how this activity will be enforced –
A. Introduction. 4.2. Facilities.
3. The applicability does not address the current issues regarding radial + load serving
only situation when Protection System not designed to provide protection for the BES.
Standard should clearly state this exemption.
B. Requirements.
4. 1.1. The standard does not provide guidance in how to identify the components of a
transmission Protection System (tPS). See prior comment referring to the case of a
radial load serving transmission topology.
5. 1.3. Requirement should read “For each identified Protection System component from
Requirement 1, part 1.1, include all maintenance activities listed in PSMP and
specified in Tables 1a, 1b, or 1c associated with the maintenance method used per
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Requirement 1, part 1.2.”
6. 1.4. This requirement should be eliminated since already included in Table 1a and
covered through Requirement 1, part 1.3.
7. 4.3. Footnote 3 shall be eliminated since duplicates footnote 2 –
C. Measures
8. M1. The added wording in the Protection System definition, requirements and
measures with respect to the inclusion of the “associated circuitry from the voltage
and current sensing devices” and control circuitry “through the trip coil(s) of the
circuit breakers or other interrupting devices” seem right but a bit excessive under
current circumstances (form of the standard). The standard should clearly specify how
the maintenance program will address the verification, monitoring, etc. of the actual
wiring and the trip coils. We suggest that the wording of the standard to reflect that
the maintenance activities on the wiring will be conducted in a visual fashion without
implying activities that require disconnecting the primary equipment.
9. We recommend to change the Protection System definition to read “up to the trip
coils(s)” instead the word “through” (see comment on the definition as well). We
consider that the gain in reliability by pursuing a thorough maintenance program that
require to take primary equipment out of service (which in many instances will lead to
the entire substation being put out of service) cannot counterweight the sole purpose
of the standard and the economics emerging from this program.
Response: Thank you for your comments.
1. The SDT is unable to determine the nature of your concern. “Monitoring” is used within PRC-005-2 only as discussed in the new
Table 2.
2. The SDT has removed “Upkeep” from the PSMP definition in response to your comment.
3. This is an issue for your regional BES definition.
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4. The SDT has extensively revised Requirement R1 and its sub-requirements.
5. The SDT has extensively revised Requirement R1 and its sub-requirements.
6. The SDT has removed Requirement R1, part 1.4, in consideration of your comment.
7. The footnotes have been removed.
8. The SDT is not specifying the means of achieving requirements. This allows entities the flexibility to determine their own optimal
methods.
9. The SDT considers that the electrical trip coils are an integral portion of the dc control circuit, and therefore must be exercised.
Western Area Power
Administration
1) Standard, Page 4, R 4.3: Is the utility free to define its own “acceptable limits”?
2) Standard, Page 4, R 4.3: Must the “acceptable limits” be stated in the PSMP?
3) Standard, Page 4, Footnotes 2 and 3 are the same.
4) Attachment A says we can go to a performance based program; does this apply to every part of the
standard? In other words, does this apply to component testing, functional testing, etc., and do we
define the intervals of the test. That is, do we determine how long we test the sample of at least 30
units that Attachment A discusses?
Response: Thank you for your comments.
1. As “acceptable limits” may vary with the specific application, the entity is expected to determine appropriate acceptable limits.
2. There is no requirement within the draft Standard for an entity to specify the acceptable limits within its own PSMP.
3. The footnotes have been removed.
4. The draft Standard allows entities to implement a performance-based program for all component types except batteries if they have
appropriate populations. Attachment A specifies that the entity “Maintain the components in each segment according to the timebased maximum allowable intervals established in Tables 1-1through 1-5 until results of maintenance activities for the segment are
available for a minimum of 30 individual components of the segment.” After that period, the entity may shift to the performancebased program for the entire segment.
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Ameren
Question 7 Comment
1) We commend the SDT for developing a generally clear and well documented second draft. The SDT
considered and adopted many industry comments from the first draft. It generally provides a well
reasoned and balanced view of Protection System Maintenance, and good justification for its
maximum intervals. Ameren generally agrees that this second draft will be beneficial to BES
reliability, but several inconsistencies, unclear items, and a couple issues need to be addressed
before we will be able to support it.
2) Facilities Section 4.2.1 “or designed to provide protection for the BES” needs to be clarified so that it
incorporates the latest Project 2009-17 interpretation. The industry has deliberated and reached a
conclusion that provides a meaningful and appropriate border for the transmission Protection System;
this needs to be acknowledged in PRC-005-2 and carried forward.
3) We are concerned over R1.1, where all components must be identified, without a definition for the
word component or the granularity specified. While the FAQ gives a definition, and allows for entity
latitude in determining the granularity, the FAQ is not part of the standard. Certainly this could
confuse an entity or an auditor and lead to much wasted work and / or violations for unintended or
insignificant issues. We suggest that the FAQ definitions be included within the standard.
4) Implementation of the PSMP must coincide with the beginning of a calendar year.
5) Generating Plant system-connected Station Service transformers should not be included as a Facility
because they are serving load. Omit 4.2.5.5 from the standard. There is no difference between a
station service transformer and a transformer serving load on the distribution system. This has no
impact on the BES, which is defined as the system greater than 100 kV.
6) The term “maintenance correctable issue” used in Requirement 4 seems to be at odds with the
definition given for it. It seems that an issue that cannot be resolved by repair or calibration during the
maintenance activity would be a maintenance non-correctable issue. Also, in Requirement 4, the
term “identification of the resolution” is ambiguous. Suggested changes for Requirements 4 and 4.1
are: “R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its
PSMP, and resolve any performance problems as follows: 4.3 Ensure either that the components are
within acceptable parameters at the conclusion of the maintenance activities or initiate actions to
replace the component or restore its performance to within acceptable parameters.”
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Question 7 Comment
Response: Thank you for your comments.
1. Thank you.
2. When the interpretation (Project 2009-17) is approved, the SDT for PRC-005-2 will consider if the interpretation is appropriate for
PRC-005-2 and make associated changes.
3. Requirement R1 has been extensively revised, and the SDT has added a definition of “Component” and “Component Type” to the
draft Standard. The SDT’s intent is that this definition will be used only in PRC-005-2, and thus will remain with the Standard when
approved, rather than being relocated to the Glossary of Terms.
4. The SDT Guidelines, which were endorsed by the NERC Standards Committee in April 2009, establishes that proposed effective
dates “must be the first day of the first calendar quarter after entities are expected to be compliant.” The Implementation Plan is in
accordance with these guidelines.
5. The “load” being served by the station service transformer may be essential to operation of the generating plant, and therefore is not
the same as general distribution system load. Therefore, the SDT believes that these system components must remain within the
Applicability section of the Standard.
6. The definition of “maintenance correctable issue” is consistent with the way it is used within the Standard.
PPL Supply
1. For applicability to generators, the responsibility for a maintenance program will usually rest with the
plant operator when the operator and plant owner(s) are different entities. Consider changing the
applicability as it applies to the generator in such situations.
2. Time-based frequency should allow for flexibility; i.e. engineering analysis should allow the entity to
exceed the intervals noted in the table. An engineering evaluation that defines a test interval
differently than those intervals prescribed in the table should allow an entity to build a program with
different intervals.
3. A Grace Period should be defined. This allows a tolerance window to allow for unforeseen
occurrences. A grace period would allow for some schedule flexibility and reduce the number of
reports to the regulator for exceeding an interval by a reasonable about.
4. The implementation plan for this revision should take into account that a generator outage may be
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required to implement a new maintenance frequency. The implementation plan should account for
outage time, especially nuclear plants that have extended operating cycles.
5. Table 1b Protective Relays Level 2 Monitoring Attributes includes input voltage or current waveform
sampling three or more times per power cycle. No further guidance is provided in the reference
documents. If this sampling rate is not provided in the specification by the manufacturer, what can
the entity use to demonstrate that the attribute is satisfied? Please provide additional guidance.
6. Consider numbering the tables to improve cross-referencing the entries in program documentation.
This will allow entities to reference in program documents exactly which activities are being
implemented in accordance with the standard.
7. Requirement 1.1 states, “Identify all Protection System components.” This is too broad and must be
clarified.
Response: Thank you for your concern.
1. The Generator Owner, as defined within V5 of the NERC Functional Model, includes, “Design and authorize maintenance of
generation plant protective relaying systems…” No maintenance activities are assigned to the Generation Operator within the
Functional Model.
2. Requirement R3 and Attachment A provide the framework and requirements to develop and implement a performance-based
maintenance program as you suggest.
3. “Grace periods” within the Standard are not measurable, and would probably lead to persistently increasing intervals. However, an
entity may establish an internal program with grace-period allowance, as long as the entire program (including grace periods) does
not exceed the intervals within the Standard.
4. The Implementation Plan has been revised in consideration of your comment.
5. This attribute is only relevant to microprocessor-based relays; no other technology possesses this attribute. The entity should
contact the manufacturer to obtain this information.
6. The Tables have been completely revised in consideration of your comment.
7. Requirement 1, part 1.1 has been modified to state, “Address all Protection System component types.”
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Consumers Energy
Company
Question 7 Comment
In the Standard, Footnote 2 and Footnote 3 are identical. We presume that some information has been
omitted. We do not agree that Footnotes are an appropriate method of providing information that is
important to the application of the Standard. Important information should be provided within the
standard text.
Response: Thank you for your comments. The footnotes have been removed.
Nebraska Public Power
District
1. 4.2.5.1 (And elsewhere in the standard) Please define auxiliary tripping relays.
2. 4.2.5.5 Do station “system connected” service transformers that do not supply house load for the
generating unit, other than during start up or emergency conditions, fall under this clause? If so, can
these transformers be eliminated if the house load can be back-fed from “generator connected”
service transformer switchgear? What if there are redundant “system connected” feeds?
3. R1 1.4 Clarification requested. This wording would suggest all battery activities fall under Table 1.a.
exclusively.
4. R4 4.3 Does initiation of activities require documentation, or is inclusion of “initiation” in the testing
procedure sufficient evidence?
5. Tables 1b &1c: Suggestion: If at all possible, combine and simplify. The number of sub clauses and
nuances that are being described in these sections (with little change to interval or procedures for
that matter) is overwhelming. These two tables are setting RE’s and System Owners up for making
errors. Implementation and auditability should be the focus of this standard, SIMPLIFY.
6. SPS - Does the output signal need to be verified, or does the actual expected action need to be
verified. Actual expected action would affect electrical generation production for NPPD’s SPS.
Response: Thank you for your comments.
1. Please see FAQ II.4.C, II.4.D, II.4.E, II.4.F, II.4.G, and Sections 2.4 and 15.3 of the Supplementary Reference document for
discussion regarding auxiliary relays.
2. The “load” being served by the station service transformer may be essential to operation of the generating plant, and therefore is not
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the same as general distribution system load. Therefore, the SDT believes that these system components must remain within the
Applicability section of the Standard. This is not affected by redundancy.
3. The Tables have been completely revised in consideration of your comment. Please see the new Table 1-4 for these activities.
4. As indicated in Measure M4, the SDT believes that documentation such as work orders, etc., is necessary.
5. The Tables have been completely revised.
6. The draft Standard requires that the expected action is verified. This may be conducted in overlapping segments, and a simulation
may be sufficient to verify in some cases.
CenterPoint Energy
CenterPoint Energy believes the proposed Standard is overly prescriptive and too complex to be
practically implemented. An entity making a good faith effort to comply will have to navigate through the
complexities and nuances, as illustrated by the extensive set of documents the SDT has provided in an
attempt to explain all the requirements and nuances. The need for an extensive “Supplementary
Reference Document” and an extensive “Frequently Asked Questions Document”, in addition to 13
pages of tables and an attachment in the standard itself, illustrate that the proposal is too prescriptive
and complex for most entities to practically implement. CenterPoint Energy is opposed to approving a
standard that imposes unnecessary burden and reliability risk by imposing an overly prescriptive
approach that in many cases would “fix” non-existent problems. To clarify this point, CenterPoint
Energy is not asserting that maintenance problems do not exist. However, requiring all entities to
modify their practices to conform to the inflexible approach embodied in this proposal, regardless of how
existing practices are working, is not an appropriate solution. Among other things, requiring entities to
modify practices that are working well to conform to the rigid requirements proposed herein carries the
downside risk that the revised practices, made solely to comply with the rigid requirements, degrade
reliability.
Response: Thank you for your comments. The SDT has extensively revised the Tables and the Standard in efforts to simplify and
remove complexity. FERC Order 693 and the approved SAR for this project directed the SDT to establish both maximum maintenance
intervals and minimum maintenance activities within the revised Standard.
BGE
1. Comment 7.1. The standard, FAQs, and supplementary reference all make references to upkeep
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and include in “upkeep” changes associated with manufacturer’s service advisories. The FAQs
include statements that the entity should assure the relay continues to function after implementation
of firmware changes. This statement is uncontestable as general principle but is problematic in its
inclusion in an enforceable standard because there is no elaboration on what the standard expects,
if anything, as demonstration of an entity’s execution of this responsibility. PRC-005-2 appropriately
focuses on implementation of time-based, condition based, or performance based PSMPs; but
addressing service advisories does not fit well with any of these ongoing preventive maintenance
activities. It is instead episodic, more like commissioning after upgrades, or corrective maintenance
work generated by condition-based alarms or anomalies discovered by analyzing operations. The
standard appropriately steers clear of imposing requirements for these latter responsibilities as long
as execution of an ongoing maintenance program is being demonstrated. BGE recommends that
implied inclusion of service advisories should be removed from the standard and supporting
documents.
2. Comment 7.2 R1.1 Requires the identification of all protection systems components. But it provides
no elaboration on the level of granularity expected or acceptable means of identification. It is unlikely
that the SDT expected the unique identification of every discrete component down to individual test
switches or dc fuses. In the case of current transformers, several of which, or even dozens of which
may be connected to a single relay there is no apparent reliability benefit that comes from
indentifying them uniquely so long as it is proven that a protection system is receiving accurate
current signals from the aggregate connection. (It may be argued that the revised definition of
“protection systems” eliminates the need to include CT’s under R1.1 but that’s just one
interpretation.) Some discrete components of communication systems may exist in an environment
that is not owned by or known to the protection system owner. Additionally all protection system
components may be indentified in documents that are current and maintained but not in the form of a
specific searchable list that is limited to components that are within the scope of PRC-005.
Examples may be indexed engineering drawings that indentify relays and other components for each
protection systems or scanned relay setting and calibration documents that are current but not
attached to searchable metadata. It is unclear whether or not these would be considered acceptable
identification meeting R1.1. If they are not then the implementation plan for R1 is in all probability
unachievable. BGE requests that the SDT provide more elaboration on R1.1 in the standard and in
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the supporting documents.
3. Comment 7.3 For clarity footnote 1 to R1 which excludes devices that sense non-electrical signals
should explicitly say that the auxiliary relays, lockout relays and other control circuitry components
associated with such devices are included. The matter is well-addressed in the FAQ’s but could
easily be misunderstood if not included here.
Response: Thank you for your comments.
1. “Upkeep” has been removed from the definition of Protection System Maintenance Program, and from the Supplementary
Reference and FAQ documents.
2. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types.”
3. The SDT believes that these components are clearly included within the scope of dc control circuits.
WECC
1. Compliance believes it will be difficult to demonstrate compliance when an entity chooses Condition
Based Level 2 or Level 3 maintenance as the details of the requirements are still open to
interpretation. The FAQ has answers to specific questions that are multiple choices.
2. Breaking down this standard into this level of granularity requires supplementary documents to
understand it and for auditors to understand how to determine compliance. Industry standards are
specific to equipment types and should be allowed to set intervals and maintenance tasks rather
than a one-size fitting all approach.
Response: Thank you for your comments.
1. The Tables have been completely revised to clarify the monitoring attributes and related intervals and activities.
2. FERC Order 693 and the approved SAR for this project directed the SDT to establish both maximum maintenance intervals and
minimum maintenance activities within the revised Standard.
Constellation Power
Generation
November 17, 2010
1. Constellation Power Generation does not agree with the changes to Voltage and Current Sensing
inputs to protective relays in Table 1a. It is inferring that the only way to complete testing on these
components to satisfy NERC is to complete online testing, which is dangerous and does not improve
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the reliability of the BES. In fact, it can be argued that it decreases the reliability of the BES. The
verbiage should be changed back to what was originally proposed to allow for offline testing.
2. Furthermore, Constellation Power Generation does not agree with several of the inclusions of
generator Facilities in this standard. For example, in 4.2.5.1, the proposed standard looks to include
any components that can trip the generator. At a nuclear facility, this could include protection of
motors at the 4 kV level that may trip the generator due to NRC regulated safety issues. This should
not fall under NERC jurisdiction.
3. The inclusion of station service transformers is another inclusion that should not be in this standard.
There is no difference between a station service transformer and a transformer serving load on the
distribution system. This has no impact on the BES, which is defined as the system greater than 100
kV.
4. Additionally, CPG has concerns regarding the vague language of R1.1, which requires the
identification of all protection systems components. It provides no elaboration on the level of
granularity expected or acceptable means of identification. It is unlikely that the SDT expected the
unique identification of every discrete component down to individual test switches or dc fuses. In the
case of current transformers, several of which, or even dozens of which may be connected to a
single relay there is no apparent reliability benefit that comes from identifying them uniquely so long
as it is proven that a protection system is receiving accurate current signals from the aggregate
connection. (It may be argued that the revised definition of “protection stems” eliminates the need to
include CT’s under R1.1 but that’s just one interpretation.) Some discrete components of
communication systems may exist in an environment that is not owned by or known to the protection
system owner. Additionally all protection system components may be identified in documents that
are current and maintained but not in the form of a specific search-able list that is limited to
components that are within the scope of PRC-005. Examples may be indexed engineering drawings
that identify relays and other components for each protection systems or scanned relay setting and
calibration documents that are current but not attached to search-able meta data. It is unclear
whether or not these would be considered acceptable identification meeting R1.1. If they are not
then the implementation plan for R1 is in all probability unachievable.
5. CPG requests that the SDT provide more elaboration on R1.1 in the standard and in the supporting
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documents. In that vein, to clarify footnote 1 to R1 which excludes devices that sense non-electrical
signals, it should explicitly say that the auxiliary relays, lockout relays and other control circuitry
components associated with such devices are included. The matter is well-addressed in the FAQ’s
but could easily be misunderstood if not included here.
6. Lastly, Constellation Power Generation would like to voice concern over the expedited process in
which this standard is being developed. Voting within a week of submitting comments does not leave
enough time for the drafting team to thoroughly vet through the issues and identify much needed
changes, let alone implement them.
Response: Thank you for your comments.
1. The intent of the cited section is to provide examples of how an entity might perform the testing. Any examples listed in either of the
supporting documents should be looked upon as suggestions; these suggestions are not considered to be a complete list of the
methods available. To the contrary, the Standard and the supporting documents were written considering that there are many ways
to achieve a good test. Leeway is certainly available in how an entity complies with the Standard as the maintenance activities
generally specify “what” must be achieved but not “how” an entity achieves it. Please see FAQ II.3.D.
2. FAQ III.2.A specifies that relays that trip breakers serving station auxiliary loads such as fans, pumps, and fuel handling equipment
need not be included in the program even if loss of those loads could result in the tripping of the generator.
3. The “load” being served by the station service transformer may be essential to operation of the generating plant, and therefore is not
the same as general distribution system load. Therefore, the SDT believes that these system components must remain within the
Applicability section of the Standard.
4. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types.”
5. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types.” The SDT believes that the
components associated with devices that sense non-electrical signals are clearly included within the scope of dc control circuits.
6. This Standard has been designated for an expedited process in order to achieve approval in the minimum time possible.
Pepco Holdings, Inc. Affiliates
November 17, 2010
Dates of the Supplemental Reference Documents in Section F of the standard need to be updated.
1. The word “calendar” is used widely to define month and year intervals. Sometimes causes
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confusion, need definition/examples.
2. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are
to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1.
Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the
18 month interval is missing.
3. Req 1.1: “All Components” wording should say something like all components covered in our plan
Response: Thank you for your comments.
1. Section 8.4 of the Supplementary Reference document provides an example to assist in this determination. A “calendar year” is a
single number year on the Gregorian calendar; a calendar month is any one of the twelve months within a single calendar year.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
SERC Protection and
Control Sub-committee
(PCS)
1. Descriptors in the "type of the protection system component" column need to be consistent between
1A, 1B and 1C.
2. Also, in the tables, please clarify “complete functional trip test” for UVLS and UVLS trip tests since
the breaker is not being tripped. Facilities Section 4.2.1 “or designed to provide protection for the
BES” needs to be clarified so that it incorporates the latest Project 2009-17 interpretation. The
industry has deliberated and reached a conclusion that provides a meaningful and appropriate
border for the transmission Protection System; this needs to be acknowledged in PRC-005-2 and
carried forward.
3. We commend the SDT for developing such a clear and well documented second draft. The SDT
considered and adopted many industry comments on the first draft. It generally provides a well
reasoned and balanced view of Protection System Maintenance, and good justification for its
maximum intervals. The SERC Protection & Control Subcommittee generally agrees that this
second draft will be beneficial to BES reliability.
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Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. Thank you for your comment.
Dynegy Inc.
For protection system component verification, flexibility is needed subsequent to a system event to allow
the analysis of a protection system operation to be utilized as a protection system component
verification. We believe this flexibility is needed and should be incorporated in Requirement R4.
Response: Thank you for your comments. Operational results, if desired by an entity, MAY be used to meet maintenance
requirements to the degree that they verify, etc., the relevant performance. The entity must determine if their use is effective.
MidAmerican Energy
Company
1. From the compliance registry criteria for generator owner/operator and the language in 4.2.5.3 it is
implied that the intent is that protection systems for individual generators less than 20 MVA would not be
covered by PRC-005. To make this clear in the PRC-005-2 standard, the following footnote to section
4.2.5.3 is recommended: Protection systems for individual generating units rated at less than 20 MVA in
aggregated generation facilities are not included within the scope of this standard. The Request for
Interpretation of a Reliability Standard submitted March 25, 2009 indicates that a protection system is
only subject to the NERC standards if the protection system interrupts the BES and is in place to protect
the BES.
The following changes are recommended to clarify this in the standard:
A.3. Purpose: To ensure all transmission and generation Protection Systems protecting and affecting
the reliability of the Bulk Electric System (BES) are maintained.
A.4.2.1. Protection Systems applied on, or and designed to provide protection for the BES.B.R1. Each
Transmission Owner, Generator Owner, and Distribution Provider shall establish a PSMP for its
Protection Systems that use measurements of voltage, current, frequency and/or phase angle to
determine anomalies and to trip a portion of the BES and that are applied on, or and are designed to
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provide........
2. FERC Order 693 includes the directive that “testing of a protection system must be carried out within
a maximum allowable interval that is appropriate to the type of the protection system and its impact
on the reliability of the Bulk-Power System”. If unanticipated conditions (e.g. force majeure) of the
bulk-power system do not allow outages to complete protection system maintenance as required by
the standard without compromising the reliability of the system delay of the particular maintenance
activity should be allowed. This provision should be included in the standard in R4.
Response: Thank you for your comments.
1. This is an issue for your regional BES definition. The SDT has drafted the Standard to apply to all NERC entities with due regard
for the applicable BES definition.
2. “Grace periods” within the Standard are not measurable, and would probably lead to persistently increasing intervals. However, an
entity may establish an internal program with grace-period allowance, as long as the entire program (including grace periods) does
not exceed the intervals within the Standard.
Southern Company
Transmission
1. General FAQ1) Attached is an elementary drawing showing a typical transmission line relay
protection scheme utilizing SEL-351S and SEL-321 microprocessor relays. Does this qualify as
partially monitored control circuitry? See pdf file Control Elementary_1-07-13 & Control
Elementary_2-07-13in email documentation sent to Al McMeekin. If not, and this is an unmonitored
circuit, what would be the appropriate maintenance interval (6 years or 12 years) for the Control and
Trip Circuits from page 9 of PRC-005-2? The description of the two choices is ambiguous See pdf
file PRC-005-2_clean_2 010June8.pdf in email documentation sent to Al McMeekin. If not, what
would it take to make this circuit partially monitored (including inputs)?
2) Table 1a, page 9, row 2 (Voltage and Current Sensing Inputs) Question - Does this mean secondary
quantities from CT’s and VT’s only? If so, please consider changing the wording from “Voltage and
Current Sensing Inputs” to “CT and VT secondary quantities”.
3) Table 1a, page 9, row 3 (Control and trip circuits with EM contacts)Question - Does
"electromechanical trip or auxiliary contacts" mean EM protective relay outputs and EM
tripping/lockout tripping contacts only? Or does it also include any part of the trip circuitry such as
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cutout switch contacts and breaker trip coils plus associated aux. breaker contacts. For example, the
schematic with a microprocessor relay described in the first bulleted item could be considered an
unmonitored EM control circuitry (6 year interval). Is this because of the mechanical breaker aux
contacts, breaker maintenance switch, and FT-1 test switch? If so, how could any control circuitry fall
in the solid state trip contacts category (12 year interval)?
4) Table 1a, page 9, rows 3, 4, 5, 6 - Please consider rewording these to make it clear where control
schemes with MP relays that do have trip coil / circuit monitors but don’t meet the Partially Monitored
requirements fit. (Does this type scheme fit in the 6 year trip test category or the 12 year category?)
5) Table 1a, page 12, row 1 - The maintenance requirements are not the latest wording used for all
other Protective Relays. Please consider changing for consistency.
6) Table 1b, page 13, row 1 (Protective Relays) - Line three of the maintenance activities requires us to
check inputs and outputs. The last maintenance item is to verify correct operation of output actions
that are used for tripping. Question - How is this different than the line three maintenance
requirements to check inputs and “outputs”?
7) Table 1b, page 14, rows 1 and 2 - Consider combining these into one row. The maintenance
intervals and maintenance activities are these same. Please specify what is required for UFLS and
UVLS control schemes).
8) Table 1b, page 14, rows 1 - The first sentence is very general for a monitoring attribute. (“Monitoring
of Protection System component inputs, outputs, and connections with reporting of monitoring alarms
to a location where action can be taken.”) Consider deleting this row or make it more specific.
9) Table 1b, page 14, row 2 [Control Circuitry (Trip Circuits) (except for UFLS/UVLS)]Question: Should
there be a 12 year functional trip test requirement for this partially monitored control circuitry? Should
this be added to Table 1b?
10) Table 1b, page 14, row 1 [Control Circuitry (Trip Circuits) (except for UFLS/UVLS)] - It states
Monitoring of Protection System component inputs, outputs, and connections ... Question - what
does “inputs” mean? There are Protection System components such as protective relays, control
circuitry, station dc supply, associated communications systems, etc. Does this mean we must
monitor inputs to any or all of these Protection System components? How would this be
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accomplished?
11) Table 1c, page 18, row 4 - Should there still be a requirement to trip breakers by all trip coils every 6
years?
Supplementary Reference Document
12) Question on Figure 1, page 27 - Box 1 denoting Protection Relays includes Aux devices, Test or
Blocking Switches. The Aux devices Test or Blocking Switches should be part of Box 3 (Control
Circuitry). Please correct or note accordingly.
FAQ Document
13) On Page 30, please add an Example with Partially Monitored (Level 2) Control Circuit.
14) On the Control Circuit Decision Tree on page 36, the flow chart does not match the current Table 1
requirements. They match the previous version which is described in the first question of this
document. We still propose leaving the flow chart on page 36 as is and change Table 1 to match the
original requirements.
15) Please consider adding a diagram /elementary drawing of a Partially Monitored Control Circuit
showing the trip output contacts, inputs, etc that must be monitored to meet the Monitoring Attributes
/ Requirements. A diagram showing an Unmonitored control scheme and what it would take to make
it Partially Monitored would be helpful too.
Additional General FAQ
16) PRC-005-2, R1 requires the Functional Entity to establish a Protection System Maintenance
Program (PSMP). It is not clear if this standard establishes a specified frequency for reviewing and
updating the PSMP itself or the PSMP criteria outlined in subparts 1.1 through 1.4. By comparison,
EOP-005-1 System Restoration Plans, requires the Functional Entity to (a) have a restoration plan
and (b) to review and update the restoration plan annually (see EOP-005-1, R1 and R2). This
approach to a comprehensive and periodic review considers the PSMP as a whole and is
independent of the specific maintenance methods (time-based, condition-based, or performancebased) and maintenance intervals for those respective methods. It is noted however that PRC-005
Attachment A mentions annual updates to the list of Protection System component. According to the
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Attachment’s subtitle, Criteria for a Performance-Based Protection System Maintenance Program,
this annual update seems limited to performance-based maintenance and not inclusive of other
maintenance methods. The recommendation is to evaluate the need for a periodic review of the
PSMP as a whole.
17) R1, Criteria 1.1, and companion VSL. This Criterion requires the identification of all Protection
System components. The VSL for R1 uses a percent-based approach to parse out different
quantities of components across the four VSL categories. This implies that a Functional Entity must
have the ability to put a numerical quantity on its various components and should be able to
demonstrate within certain tolerances that its components are included (or counted). If the number of
components within scope amount to hundreds or thousands of individual items, the PSMT SDT
should consider the Functional Entities’ ability to track and quantify the items for a compliance
demonstration. If an entity is not able to reasonably quantify which components are in scope,
demonstrating compliance on a percent-basis may prove difficult or impossible. Further review may
indicate the need to reformat the VSL. Similar concerns are noted in other VSLs (R2, R3, and R4)
and in Attachment A where percentage-of-components are mentioned.
18) R4 essentially requires the Functional Entity to implement its PSMP. R4 takes care to highlight the
specific task of “identification of the resolution of all maintenance correctable issues.” It is noted that
other “identification tasks” are included as criterion for the PSMP in R1. If these tasks are all
appropriately categorized as identification-type tasks, it may be more efficient to restructure the
standard by incorporating this task into R1 with the other criteria. R4 could remain as a basic
implementation requirement with more detail provided in subparts 4.1, 4.2, and 4.3.
19) Footnote No. 2 describes maintenance correctable issues and could be interpreted as a potential
new term for inclusion in NERC’s Glossary of Terms. The PSMT SDT should conduct further review
of this terminology as a potential new Glossary term.
20) At R4, subpart 4.3, insert “design” such that it reads as follows: “Ensure that the components are
within acceptable design parameters at the...” Also, this subpart duplicates Footnote No. 3 which
describes “maintenance correctable issues” and was established in the main requirement R4 at
Footnote No. 2.
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Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. This portion of the definition of Protection System has been revised. Also, the Tables have been rearranged and considerably
revised to improve clarity. Please see new Table 1-3.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
5. The Tables have been rearranged and considerably revised to improve clarity.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
7. The Tables have been rearranged and considerably revised to improve clarity.
8. The Tables have been rearranged and considerably revised to improve clarity.
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
10. Some examples of input may include, but are not limited to: breaker fail initiate, start timer. This cannot be an all-inclusive list as
any given scheme could have many variations. In short, if your scheme requires a specific input to function properly then you must
have that input maintained; if your scheme has a specific output that must function then it must be maintained. If the input or output
is used for a non-protective function (such as, but not limited to, Sequence-of-Events Recorder, alarm or indication) then it does not
have to be maintained under this Standard. See Section 15.3 of the Supplementary Reference and FAQ II.2.L.
11. Yes.
12. The diagram is for illustrative purposes only, and is intended to demonstrate all devices which need to be included within a PSMP.
Box 1 shows the cited devices as being within the relay panel, and makes no distinction regarding what specific type of Protection
System component is being addressed. The preceding Table has been revised to avoid this conclusion.
13. The Tables have been revised to remove descriptions of various levels of monitoring.
14. The decision trees have been removed.
15. The Tables have been revised to remove descriptions of various levels of monitoring.
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16. The expectation is that an entity’s PSMP will be current. No periodicity is provided. However, in Attachment A, the performancebased program necessarily requires an ongoing review of the program to assure that it is still relevant.
17. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types.”
18. The SDT believes that the identification of maintenance-correctable issues is properly an issue for implementation of the PSMP,
not establishment of the PSMP.
19. The referenced footnote has been removed and a new definition established for this Standard only.
20. The SDT disagrees. The acceptable parameters for a specific application may not be identical to the design parameters for the
component.
FirstEnergy
Implementation Plan
a. We do not support the 3 month implementation timeframe for Requirement 1. For many entities, it will
take some time to develop a sound PSMP that meets the new PRC-005-2 standard. We suggest a 12
month implementation which we believe is more logical and in alignment with the implementation
timeframe for Protection System Components with maximum allowable intervals of less than 1 year, as
established in Table 1a.
b. Although we support the implementation timeframes for Requirements R2, R3, and R4, we do not
support the required periodic percentages of protections systems to be completed. There could be
numerous reasons where an entity has to adjust its program schedule which could lead to
noncompliance with these percentage milestones. We suggest simply requiring 100% completion of the
maintenance per the maximum maintenance intervals. Alternatively an entity should have the flexibility
to indicate they have fully transitioned to the new standard during the early stages of the implementation
plan if their existing maintenance practices meet or exceed the standards minimum expectations. Doing
so should negate the need to produce the "% complete" implementation status.
Response: Thank you for your comments.
a. The Implementation Plan has been modified in consideration of your comment.
b. The SDT disagrees and feels that a “phased” Implementation Plan is appropriate. The Implementation Plan has been revised to
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clarify that the percentages are minimums, not absolute.
American Transmission
Company
1. It is appreciated that the SDT is attempting to provide options for maintenance and testing programs.
Practically speaking, it will be difficult to perform any type of program outside of Time-Based
Maintenance (TBM). Too many circuits are a mix of technology. For example, a line may have
microprocessor relays for detecting and tripping line faults, but the bus differential lockout could also
trip the line breaker. One may be partially monitored and the other unmonitored. It will force the
utility to perform maintenance at the shorter of the maintenance cycles. Additional time and cost will
be required to organize and switch out the applicable equipment for the outage, approximately
doubling the cost associated with performing these trip tests. When entities are required to maintain
tens of thousands of these devices, the simplest approach will be to revert to TBM. ATC does not
support the existing 2nd Draft of PRC-005-2 Standard because it is our opinion that:
o There is a high probability that system reliability will be reduced with this revised standard.
o The number of unplanned outages due to human error will increase considerably.
o Availability of the BES will be reduced due to an increased need to schedule planned outages for
test purposes (to avoid unplanned outages due to human error). o To implement this standard, an
entity will need to hire additional skilled resources that are not readily available. (May require
adjustments to the implementation timeline.)
o The cost of implementing the revised standard will approximately double our existing cost to
perform this work.
2. ATC requests that relevant reliability performance data (based on actual data and/or lessons learned
from past operating incidents, Criteria for Approving Reliability Standards per FERC Order 672) be
provided to justify the additional cost and reliability risks associated with functional testing.
3. Under a Performance-Based Program, what happens if the population of components drops below 60
(as all will eventually)? Is there an implementation period to default to TBM?
4. Are the internal relays and timers associated with a circuit breaker included as part of the protection
scheme? In the Independent Pole Operation breakers (IPO), there are various internal schemes built
to protect for pole discordance (one pole open, two closed, event measured over time frame
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(milliseconds)), these schemes may re-trip the breaker, initiate breaker failure protection or trip a bus
lock out relay. In DC control schemes fuses and panel circuit breakers protect for wiring faults. Do
these devices need to be tested? Is there an obligation to test the distribution circuit breakers for
correct operation points? Is there an obligation to replace fuses after a defined time period?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see the new Tables.
2. The Standard does not preclude an entity from largely utilizing other methods of verification, although functional testing may be the
easiest to achieve.
3. The entity must revert to TBM if the population falls below 60. There is no implementation period; the SDT believes that the annual
PBM review will alert the entity that the population is nearing 60, and allow the entity to react to the diminishing component
population accordingly.
4. Only those control circuit components necessary for proper Protection System operation are included. As noted, many breakers
have numerous other internal auxiliary functions (gas pressure, etc.) that are not relevant. A purely-functional test may address
many of the issues cited. There is no obligation to test either distribution circuit breakers or dc panel fuses.
NERC Staff
NERC staff is pleased with the current iteration of this standard. The staff understands that while PRC005-2 has historically been the most frequently violated standard, it has mostly been due to
documentation issues. The standard has not been much of a heavy hitter in causal or contributive
aspects, and with respect to relay operations, there have been very few times that lack of maintenance
has been the problem.
1. NERC staff does propose a slight change to 4.2.5.1. The concern is that 4.2.5.1 could be interpreted
to apply to devices that protect the generator as opposed to those that protect the Bulk Electric
System. The suggested language is as follows: “Protection System components that act to trip
generators that are part of the BES, either directly or via generator lockout or auxiliary tripping
relays.”
2. Additionally, staff suggests some changes to R1. In that requirement, the PSMP covers “Protection
Systems that use measurements of voltage, current, frequency and/or phase angle to determine
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anomalies and to trip a portion of the BES...” It probably would be better if the list was limited to
voltage and current or if the list was replaced with electrical quantities. The former would be okay
since voltage and current are the only two electrical quantities that relays measure directly. To
remove ambiguity, the most inclusive way to rephrase this is probably the latter alternative, to
change the requirement to, “...that use measurements of electrical quantities to determine
anomalies...”
3. Finally, Footnotes 2 and 3 (in Requirement 4) are identical. Unless that’s intentional, one should be
removed. (And note that Footnote 2 is missing a period.)
Response: Thank you for your comments.
1. The essence of your suggestion is already addressed within 4.2.5 itself.
2. The definition of Protection System has been revised to address your suggestion.
3. The footnotes have been removed.
MEAG Power
No comment.
Exelon
1. Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission
(NRC). Each licensee operates in accordance with plant specific Technical Specifications (TS)
issued by the NRC which are part of the stations’ Operating License. TS allow for a 25% grace
period that may be applied to TS Surveillance Requirements.
Referencing NRC issued NUREGs for Standard Issued Technical Specifications (NUREG-143
through NUREG-1434) Section 3.0, "Surveillance Requirement (SR) Applicability," SR 3.02 states
the following: "The specified Frequency for each SR is met if the Surveillance is performed within
1.25 times the interval specified in the Frequency, as measured from the previous performance or as
measured from the time a specified condition of the Frequency is met."
The NRC Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness of maintenance to
ensure reliable operation of equipment within the scope of the Rule. Adjustments are made to the
PM (preventative maintenance) program based on equipment performance. The Maintenance Rule
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program should provide an acceptable level of reliability and availability for equipment within its
scope.
The NRC has provided grace periods for certain maintenance and surveillance activities. Exelon
strongly believes that SDT should consider providing this grace period to be in agreement and be
consistent with the NRC methodology. Not providing this grace period will directly affect the existing
nuclear station practices (i.e., how stations schedule and perform the maintenance activities) and
may lead to confusion as implementing dual requirements is not the normal station process. Nuclear
generating stations have refueling outage schedule windows of approximately 18 months or 24
months (based on reactor type). If for some reason the schedule window shifts by even a few days,
an issue of potential non-compliance could occur for scheduled outage-required tasks. The
possibility exists that a nuclear generator may be faced with a potential forced maintenance outage in
order to maintain compliance with the proposed standard.
For the requirements with a maximum allowable interval that vary from months to years (including 18
Months surveillance activities), the SDT should consider an allowance for NRC-licensed generating
units to default to existing Operating License Technical Specification Surveillance Requirements if
there is a maintenance interval that would force shutting down a unit prematurely or face noncompliance with a PRC-005 required interval.
Therefore, at a minimum, maintenance intervals should include an allowance for any equipment
specifically controlled within each licensee’s plant specific Technical Specifications to implement
existing Operating License requirements if such a conflict were to occur.
2. PECO would like to have the implementation plan provide at least 1 year for full implementation of
the new standard. This will provide adequate time for development of documentation, training for all
personnel, and testing then implementation of the new process(es).
Response: Thank you for your comments.
1. The SDT understands that nuclear power plants are licensed and regulated by the NRC, has a general understanding of the role
that plant Technical Specifications (TS) and associated Surveillance Requirements (SR) in the facilities’ operating licenses, and has
tried to be sensitive to potential conflicts between PRC-005-2 and NRC requirements.
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The SDT believes that the majority of components making up the protection systems for in-scope generating facilities as discussed
in Section 4.2.5 of the Standard would be considered balance of plant equipment and, therefore, not subject to NRC-issued TS and
associated SR requirements. While availability of plant auxiliary sources to the plant’s safety related equipment is addressed by TS
and associated SR requirements, these documents are focused on the effects that the availability of these transformers have on
reactor safety rather than specifying maintenance and testing requirements for the Protection Systems for these transformers.
The SDT recognizes that some battery systems may serve as a source of DC power to both reactor safety systems and to
Protection Systems discussed in Section 4.2.5. The SDT acknowledges that there might be plant TS and SR applicable to these
batteries. However, the SDT believes that the 3-month and 18-month inspection requirements called for in PRC-005-2 would be no
more onerous than plant TS requirements for routine online safety system battery inspections and, furthermore, would not
necessitate a plant outage. The SDT recognizes that the PRC-005-2 requirement for validating battery design capability via battery
capacity testing would require a plant outage. However, it is the opinion of the SDT that the maximum allowed battery capacity
testing intervals of not to exceed 6 calendar years for vented lead acid or NiCad batteries (not to exceed 3 calendar years for VRLA
batteries) could easily be integrated within the plant’s routine 18-month to 2-year interval refueling outage schedule.
The SDT believes that PRC-005-2 is complementary to the NRC Maintenance Rule in that PRC-005-2 requirements allow for the
leveraging of the entire electrical power industry experience in establishing minimum maintenance activities and maximum allowed
maintenance intervals necessary to ensure reliable Protection System performance.
Please see Supplemental Reference Section 8.4 for further discussion for the SDT’s rationale for exclusion of grace periods.
Please see FAQ IV.2.C for further discussion of impact of PRC-005-2 testing requirements on power plant outage schedules. The
challenge of integrating PRC-005-2 testing requirements with a plant’s outage schedule is not unique to nuclear plants.
Finally, the SDT notes that an entity may build grace periods into its own PSMP as long as the maximum allowed time intervals of
PRC-005-2 are not exceeded. If an entity wishes to build a 25% grace period into its program, it may do so by setting its program
maintenance and testing intervals at <80% of the PRC-005-2 maximum allowable time interval.
2. The Implementation Plan has been modified in consideration of your comments.
Hydro One Networks
1. Footnotes 2 and 3 on page 4 are identical. Delete footnote 3.
2. UFLS systems by design can suffer random failures to trip. It would make sense for a requirement to
exist to perform maintenance on the UFLS relay as their failure to operate may affect numerous
distribution level feeders. However maintenance on associated DC schemes connected to the
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devices should only be done on the same frequency as maintenance on the relevant interrupting
devices. Consideration should be given to exempting schemes that have a maintenance program in
place on those distribution level devices from PRC-005 Standard-specified maintenance intervals.
Such Standard-specified intervals could apply to interrupting devices that have no maintenance
program in place.
Response: Thank you for your comments.
1. The footnotes have been removed.
2. The Tables have been rearranged and considerably revised to improve clarity, and many activities related to UFLS have been
removed. Please see the new Tables.
Progress Energy Carolinas
1. R1.1.1 states that “all” protection system components be identified. Does the term “all” refer to the
major components identified in the Protection System definition (protective relays, communication
systems, voltage and current sensing devices, station dc supply, and control circuitry) or does it
include all sub-components (jumpers, fuses, and auxiliary relays used in dc control circuits and
communication paths/wavetraps/tuners/filters)? We assume the former but request clarification.
2. Draft Implementation Plan for PRC-005-02: The phased implementation plan for R2, R3, and R4
seems reasonable. However, the three-month implementation plan for R1 seems extremely short.
Utilities will have to change procedures, job plans, basis documents, provide training, and change
intervals in their work tracking databases. In addition, if the utility wants to take advantage of the
longer intervals allowed by partial monitoring, significant print work must be performed up front.
3. Descriptors in the type of the protection system column needs to be consistent between 1A, 1B and
1C. In the tables, please clarify “complete functional trip test” for UVLS and UVLS trip tests since the
breaker is not being tripped.
Response: Thank you for your comments.
1. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
2. This portion of the Implementation Plan has been revised to twelve months in consideration of your comment.
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3. The Tables have been rearranged and considerably revised to improve clarity. Please see the new Tables.
Manitoba Hydro
1. Once the new Standard is approved, NERC must allow for a greater implementation stage and no
further changes proposed for the foreseeable future. It does take a lot of resources for a Utility to
make the required changes in maintenance frequency templates or type of maintenance required as
per the proposed "Standard".
2. Regarding the use of the term “Calendar” (i.e. end of calendar year) for maximum maintenance
interval. Our utility uses end of fiscal year as our cutoff date for completing maintenance tasks for a
given year. It would be considerable work for us to have to switch to end of calendar year with zero
improvement in our overall reliability. We suggest it be left up to each utility to define their calendar
yearly maintenance cycle when all tasks for that year must be completed.
Response: Thank you for your comments.
1. The implementation period for Requirement R1 has been extended from 3 months to 12 months in consideration of your comments.
2. With the vast array of entities subject to compliance monitoring, it would be very difficult for the ERO to assess compliance for
varying “years.” Additionally, the SDT understands that most compliance monitors currently request data on a calendar year basis
when assessing compliance.
Grant County PUD
PRC005-02 Comment
We offer some comment for your consideration for incorporation into the Standard PRC-005-02 (draft)
as presented in the May 27th 2010 PRC 005-02 “Standard Development Roadmap.” RE: Comment on
the 2nd Draft of the Standard for Protection System Maintenance and Testing”
1) The term “The Protection System Maintenance Program” (Page 2) appears to be centered on the
concept of maintaining specific components as stand alone objects, and therefore infers that the
resultant documentation be organized in a similar fashion. Neither is optimal from a practical or a
functional perspective. Many rational work practices combine components (example, meggering from
the relay input test switch through the cables and the CTs) in the interest of minimizing circuit
intrusion and human error. For this reason, such maintenance practices are superior from a reliability
standpoint. The emphasis on “components” in the current draft is, at best, tangential to NERC’s
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stated goal and purpose of PRC-005 to improve reliability. How would we fix this? We would insert
the phrase “or Element”-as defined in NERC’s Glossary of Terms to include “one or more
components / devices with terminals that measures voltage, current, frequency and/or phase angle”
to determine anomalies and to trip a portion of the BES” immediately after any occurrence of the word
“component” in each of the Requirements or in a Definition paragraph, intending it to be applied
globally to R-1 through R4. This would foster the validity of maintenance activities being applied to
aggregations of components - “Elements”-such as would occur during Verification of DC control
circuitry or through the employment of fault data analysis.
2) Protection System Maintenance Program. The categorization of maintenance into 7 maintenance
activities is welcomed as advancing practices which foster BES reliability. Likewise we find the
clarifications denoted by superscripts 1 and 2 helpful. However....under C: MEASURES: M1, the last
sentence of the paragraph provides: “For each protection system component, the documentation
shall include the type of maintenance program applied (time based, etc), maintenance activities (1 or
more of the 7 identified) and maintenance intervals.....” This measure goes beyond the requirements
of the standard and should be revised consistent with the deletion of the previous R.1.1 as shown in
track changes under the version 2 draft which had included the identification of the maintenance
activity associated with each component. COMMENT: It should be apparent in reviewing the
evidence that one or more of the 7 listed activity categories are represented. The proscription to
explicitly call out these categories is thus redundant---the requirement being that at least one has to
be identifiable in the program-and will cause unnecessary complications to the Entity and
interpretation issues in the Compliance monitoring effort. We recommend that the words
“maintenance activities” be removed from the last sentence in the paragraph pertaining to C:
MEASURES: M1.We also believe it is unnecessary to restate the definition of “Protection System” in
the Measure.
3) A fundamental incompatibility exists between NERC’s proposition of “maximum maintenance (time
based) interval” and the typical CMMS PM generation algorithm. SPCTF members and regional
compliance engineers have verbally represented that the “maximum maintenance interval” is a
precise term “not to exceed-even by one day---” maximum, otherwise generating a fine-able Violation
and that fixed intervals plus or minus a certain additional period of time to account for other
operational exigencies are no longer going to be permitted. There is always an interval between the
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time a CMMS PM is issued and its completion. The time interval between the issue date and the
completion date is normally a period of time to allow maintenance staff to schedule their work in an
orderly fashion. The maximum time based interval is fixed by the time period specified for issuance of
the planned maintenance (PM) work order (e.g. every 3 years) and the defined period of time to
complete the work (usually described as a percentage of the PM interval e.g. 25%). So predicating a
PM issue date based on the last issue date plus a percentage of the interval time to complete the
work is not inconsistent with a fixed time interval. Under the proposed tables, however, there is no
accommodation for this predominate maintenance practice.
Even if maintenance intervals were shortened to ensure that the required completion date as defined
by program intervals does not exceed the NERC maximum interval as described in the tables, this
will not be sufficient because auditors may conclude that the tables permit the use of only a single
defined interval and not permit an additional defined period of time to schedule and complete the
work. Remember, it is immaterial whether the Entity’s interval is more stringent than the NERC
maximum, a violation may occur if the maintenance is not performed within the Entity’s maintenance
interval, even if it is shorter than the NERC maximum. A precise maximum interval requires constant
managerial intervention on the part of the Entity to ensure that operational exigencies do not cause
violations on a component-by component (or element) basis. The shortened interval would tend to
destroy the sense of rhythm and pattern which should be manifest in a time based program.
Further, after one or more iterations, seasonal restrictions on outages begin to impinge requiring
adjustments to be made to the Maintenance Program document to adjust the interval or maintenance
activity. At best, it results in a clumsy way of doing business and requiring significantly more
oversight into keeping the maintenance program document updated for presentation to auditors
rather than focusing on prudent maintenance activities as desired by FERC Order 693. Auditing is
not any more difficult if the Maintenance Program also specifies that a percentage of a fixed target /
time interval is allowed to schedule and complete the work-as meeting the interval requirements of a
time based maintenance program. This method allows for a fixed time for issuance of the work order
and maintenance personnel some flexibility to schedule and complete their work within a defined
period of time. We recommend to vote against adoption until some more workable solution is
identified and disseminated, satisfying both the Compliance Authority and the affected Entities.
Specifically, we recommend that the drafting team adopt “target” intervals with a +/- range of
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acceptability, based on percentage or a fixed time per interval, which can be global for the Program
or specific to the elements or components in question. The target intervals must be stated in the
PSMP, the range of acceptability easily calculable and enforceable, and within the maximum intervals
to be identified in the tables 1a, b, and c, satisfying compliance issues. This also allows the Entities
to rationally plan their maintenance using existing CMMS technologies.
4) Within the Violation Security levels, we are aware of no activity by NERC to differentiate the relative
criticality of components or Elements of the BES system. For example, protection system
components or Elements in a regional switchyard may present a larger potential for disruption of the
BES in the event of a mis-operation than does one associated with one generator among fifteen
others and which is more electrically remote from and of less consequence to the BES. Unless and
until this issue is addressed, both the PRC-005 maintenance and documentation will be less effective
and more expensive than it could be.
5) PRC-005-02’s proposed effective date is “See Implementation Plan.” This is not adequate to provide
regulated entities with appropriate notice of the Effective Date of PRC-005-2 standard. “
6) Additionally, NERC has not posted the “Implementation Plan” for comment in the same manner as
the proposed standard and thus we are not able to comment on the schedule provided in the Plan.
We understand that the retention and documentation cycles go back three years and that a regulated
entity, depending on the effective date of this standard and the entity’s audit cycle, will be audited to
both PRC-005-1 and PRC-005-2 during the same audit period. Some further discussion should be
given to allowing comment on the Implementation Plan because of the potential overlapping
requirements during a single audit cycle.
Response: Thank you for your comments.
1. The draft Standard supports a variety of methods of designing the PSMP.
2. A definition of “Component” and “Component Type” has been added to the draft Standard. The SDT’s intent is that this definition
will be used only in PRC-005-2, and thus will remain with the Standard when approved, rather than being relocated to the Glossary
of Terms. The Requirements and Measures have been modified to use these terms in a consistent manner. These defintions will
assist in addressing your concern.
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3. This comment seems to suggest that a “grace period” should be permitted. “Grace periods” within the Standard are not
measurable, and would probably lead to persistently increasing intervals. However, an entity may establish an internal program
with grace-period allowance, as long as the entire program (including grace periods) does not exceed the intervals within the
Standard.
4. Thank you for your comment. The VRFs address the reliability impact of the Requirements, while the VSLs simply address “how
bad did you miss it?”
5. The Implementation Plan for Requirement R1 has been revised from 3 months to 12 months to address this comment.
6. The Implementation Plan was posted for comment, with a question on the comment form during the first posting. The
Implementation Plan was not substantially revised for the second posting. During the implementation period, there will be some
overlap between PRC-005-1 and PRC-005-2. An unattractive alternative would be to minimize the implementation period for PRC005-2.
Xcel Energy
1. R1.1 “Identify all Protection System Components” - does this mean that the PSMP must contain a
“list”? Please explain what this means. If it is a list, then essentially it will be a dynamic database,
not necessarily a “program” as defined in the PSMP
2. R1.3 “include all maintenance activities...” seems to be an indirect way of indicating that the entities
PSMP must comply with the tables. Tables the components related to DC Supply and battery
are confusing. It the battery is the specific component then state “battery". If the charger is the
specific component, then state “charger”. As currently written, one must sort through all of the
different “Station DC Supply” line items to figure out what is required.3. In tables 1b and above, it is written “no level 2 monitoring attributes are defined - use level 1
maintenance activities” but then maintenance activities are listed that don’t match with Level 1
maintenance activities. Please clarify what exactly needs to be done if using Table 1 b and above.
Response: Thank you for your comments.
1. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
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3. The Tables have been rearranged and considerably revised to improve clarity.
Northeast Utilities
1. R1.1 It is not clear what would constitute “all Protection System components”. Suggest the addition
of a definition for “Protection System components”.R1.4 Suggest revise to read: “all batteries or dc
sources”
2. Table 1a vented lead acid -- “Verify that the station battery can perform as designed by evaluating
...” -- Please define evaluating, including:
a. What is the basis for the evaluation?
b. Is 5% 10% 20% etc acceptable?
c. Where does baseline come from for older batteries?
3. Request clarification of 2.3 Applicability of New Protection System Maintenance Standards from
Supplementary Reference. Specifically, please clarify if a functional trip test is needed to be
performed on the distribution circuit breakers to protect the Bulk Electric System (BES) if these low
side breakers are not part of the transmission path. (A diagram identifying the applicable breakers
would be helpful in the Supplementary Reference)
Response: Thank you for your comments.
1. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types”..(a) The basis is related to
the variation from the baseline. Please see FAQ II.5.G and II.5.F. (b) This is determined by the entity based on the application. (c)
The baseline can be provided by the battery manufacturer or the test equipment OEMs.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
South Carolina Electric and
Gas
R1.1 states “Identify all Protection System Components”. To avoid confusion this should be clarified. It
could be interpreted that discreet components must be individually identified. An example would be as
individual aux relays used in the tripping path.
Response: Thank you for your comment. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System
component types”.
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PacifiCorp
Question 7 Comment
1. R1.1: Please clarify what the requirements for “identify” means. Does each component need to be
“identified” in our maintenance system, or at least referenced in the maintenance program or labeled
in the field???
2. R4.3: Please provide guidance on what will be required to prove compliance that “maintenance
correctable issues” have been identified and corrective actions initiated.
3. What is the implication of finding maintenance correctable issues as it relates to other requirements
for no single points of failure? In other words, if during maintenance a relay is found to have failed, is
there an acceptable time period under which we may operate the system without redundancy until a
repair can be made? Similarly, if part of a redundant relay system is taken out of service for
maintenance, may the facility it was protecting be left in service? If not, then is the implication that
protection systems must be triple redundant in order to do relay maintenance on in service
equipment? Otherwise facilities would always have to be removed from service to do relay
maintenance.
4. Section D / 1.3: The data retention requirement for the two most recent performances of each
maintenance activity is excessive. The requirement should be limited to the most recent or all
activities since the last on-site audit. At the worse case an entity would have to retain records for up
to 35 years for maintenance performed on a 12 year cycle.
5. Table 1a “Protective Relay” entry: The last maintenance activity is listed as “for microprocessor
relays verify acceptable measurement of power system input values “ for which a 6 year interval is
provided”. How is this different than the next item “Voltage and Current Sensing Inputs to Protective
Relays and associated circuitry” which is on a 12 year interval?? Please clarify this.
6. Implementation Plan: This revised standard will drive significant revisions in existing maintenance
programs. 3 months is not adequate time after approval to ensure compliance with R1. A minimum
of 6 months should be utilized after regulatory approval. The Implementation plan requirements
should also recognize that if the requirement to maintain records of the two previous maintenance
tasks is implemented, it may not be possible to produce this information upon implementation. The
implementation plan should be structured that the requirement to produce previous maintenance
records should be phased in as the maintenance is performed. (ie. The requirement to produce two
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previous records for maintenance performed on a two year cycle should not be enforced until four
years after implementation).
Response: Thank you for your comments.
1. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types”.
2. Various means may be used. One suggestion would be work orders that addressed the issue.
3. It is left to the entity to determine HOW to address maintenance-correctable issues. It is reasonable that an entity would do so in a
manner that presents the least disruption to the system and considers the impact of the malfunctioning component on reliability.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data
of the most recent performance of the maintenance, as well as the data of the preceding one, as well as data to validate that entities
have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified
the data retention in the posted Standard to establish this level of documentation. The Tables have been rearranged and
considerably revised to improve clarity. Please see new Table 1-1.
5. The Implementation Plan for Requirement R1 had been revised from 3 months to 12 months.
Springfield Utility Board
SUB is supportive of the intent behind the standard and appreciates the ability to provide input into this
process.
1.The following is a repeat of the comment in Question #5 with regard to the supplemental reference.
SUB appreciates that Time Based, Performance Based, and Condition Based programs can be
combined into one program. However it should be clear that a utility may include one, two or all three of
these types of programs for each individual device type.
Currently the language reads:"TBM, PBM, and CBM can be combined for individual components, or
within a complete Protection System." The "and" requires all three to be combined if they are combined.
SUB suggests the “and” be changed to "or" language.
Change:"TBM, PBM, or CBM can be combined for individual components, or within a complete
Protection System."
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Response: Thank you for your comments. Please see our response to your comment in Question 5.
The Detroit Edison
Company
1. Suggest that the implementation plan for R1 (PSMP) be changed to 12 months.
2. The statement in R1.1, “Identify all Protection System components” regarding the PSMP should be
clarified. Is a complete list of every “component” of each specific protection system required to be
included in the PSMP?
Response: Thank you for your comments.
1. The Implementation Plan for Requirement R1 has been revised from 3 months to 12 months.
2. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
Long Island Power
Authority
1. Table 1a under Maintenance Activities for Control and trip circuits with unmonitored solid-state trip or
auxiliary contacts (UFLS/UVLS Systems Only) states: Perform a complete functional trip test that
includes all sections of the Protection System control and trip circuit, including all solid-state trip and
auxiliary contacts (e.g. paths with no moving parts), devices, and connections essential to proper
functioning of the Protection System., except that verification does not require actual tripping of
circuit breakers or interrupting devices. The word complete may be removed as it requires actually
tripping the breakers. The sentence that tripping of the circuit breakers is not required contradicts
with the word complete.
2. More specifics are required to spell out the adequate testing e.g. up to the lockout with the trip paths
isolated etc.
3. Table 1a under Maintenance Activities for Station dc Supply (used only for UVLS or UFLS) states:
Verify proper voltage of the dc supply. Is this requirement applicable to the distribution substations
only?
4. Table 1a under Maintenance Activities for Station dc supply (battery is not used) - states Verify that
the dc supply can perform as designed when the ac power from the grid is not present. - Please
clarify this requirement.
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5. Table 1a for Associated communications systems - specify the group for the applicability of this
requirement. BPS,BES,UFLS etc.
6. Table 1a under Maintenance Activities for Associated communications systems states - Verify that
the performance of the channel meets performance criteria, such as via measurement of signal level,
reflected power, or data error rate. Why is this required? The requirement "Verify proper functioning
of communications equipment inputs and outputs that are essential to proper functioning of the
Protection System. Verify the signals to/from the associated protective relays seems sufficient to
ensure reliability.
7. Table 1a under Maintenance Activities for Relay sensing for Centralized UFLS OR UVLS systems
UVLS and UFLS relays that comprise a protection scheme distributed over the power system states:
Perform all of the Maintenance activities listed above as established for components of the UFLS or
UVLS systems at the intervals established for those individual components. The output action may
be breaker tripping, or other control action that must be verified, but may be verified in overlapping
segments. A grouped output control action need be verified only once within the specified time
interval, but all of the UFLS or UVLS components whose operation leads to that control action must
each be verified. Clarify what is meant by overlapping segments? What is the specified interval? Is
actual breaker tripping required?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
6. Communications systems are subject to a variety of problems. The listed activities will detect many of these problems. The Tables
have been rearranged and considerably revised to improve clarity. Please see new Table 1-2.
7. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1. Please see Section 8 of
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the Supplementary Reference document regarding “overlapping segments.”
American Electric Power
1. The "Supplementary Reference" and the "Frequently-Asked Questions" document should be
combined into a single document. This document needs to be issued as a controlled NERC
approved document. AEP suggests that the document be appended to the standard so it is clear
that following directions provided by NERC via the document are acceptable, and to avoid an entity
being penalized during an audit if the auditor disagrees with the document’s contents.
2. NiCAD batteries should not be treated differently from Lead-Acid batteries. NiCAD battery condition
can be detected by trending cell voltage values. Ohmic testing will also trend battery conditions and
locate failed cells (although will usually lag behind cell voltages). A required load test is detrimental
to the NiCAD manufacturer's business, and will definitely hurt the NiCAD business for T&D
applications. Historically NiCADs may have been put into service because of greater reliability,
smaller space constraints, and wider temperature operation range.”Individual cell state of charge” is
a bad term because it implies specific gravity testing. Specific gravity cannot be measured
automatically (without voiding battery warranty or using an experimental system), and when it is
measured, it is unreliable due to stratification of the electrolyte and differing depths of electrolyte
taken for samples. “Battery state of charge” can be verified by measuring float current. Once the
charging cycle is over the battery current drops dramatically, and the battery is on float, signaling
that the battery has returned to full state of charge. This is an appropriate measure for Level 3
monitoring as float current monitoring is a commercially viable option and electrolyte level monitoring
is not.
3. In Table 2b, why is Ohmic testing required if the battery terminal resistance is monitored? Cell to cell
and battery terminal resistance should not be monitored because they will be taken in 18 month
intervals. This further supports the argument that the battery charger alarms would be sufficient for
level 2 monitoring, while keeping an 18 month requirement for Ohmic testing, electrolyte level
verification, and battery continuity (state of charge). Automatic monitoring of the float current should
be sufficient for level 3 monitoring as it gives state of charge of the string, and battery continuity
(detect open cells). Shorted cells will still be found during the Ohmic testing and a greater interval is
sufficient to locate these problems.
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Response: Thank you for your comments.
1. The SDT disagrees that the documents should be combined. The Supplementary Reference is a holistic presentation of rationale
and basis for the various elements of the Standard – discussing mostly the “what” behind the requirements. The FAQ, on the other
hand, presents responses to specific frequently-asked questions, and, as such, offers more-focused advice on specific subjects, and
is more of a how-to/example discussion. The FAQ is primarily a means of capturing some of the most prevalent comments offered
on the Standard by various entities, with the SDT’s response. The SDT believes that the format of the FAQ is a more effective
means of presenting the included information than it would be to include this information within the text of the Supplementary
Reference document. The Standards Committee has a formal process for determining whether to authorize posting a reference
document with an approved standard. That process is posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. The SDT believes that, since the IEEE Stationary Battery Committee has determined that VRLA batteries and Ni-Cad batteries are
different enough to require separate IEEE Standards (IEEE 1188 and IEEE 1106, respectively), these battery technologies are
different enough to be treated separately within PRC-005-2. The SDT has drawn upon these IEEE Standards, as well as other
sources (EPRI, etc) to develop the Requirements of PRC-005-2. The trending activity cited has not been shown to be effective for
Ni-Cad batteries (see FAQ II.5.G), and thus a performance tests must be performed; the performance test may take many forms.
The Tables have been rearranged and considerably revised to improve clarity, and all references to specific gravity have been
removed. Please see new Table 1-4. Determining the “state of charge” by monitoring the float voltage may be relevant to the
overall station battery, but does not provide an indication of the condition of individual cells as required within the new Table 1-4.
3. Battery terminal resistance shows the condition of the external connections, but reveals nothing regarding the internal condition of
the individual cells. Measuring the internal cell/unit resistance provides an opportunity to trend the cell condition over time by
verifying the electrical path through the electrolyte within the battery. The ohmic testing is not intended to look for open cells/units,
but instead at the ability of the individual cell/unit to perform properly. The new Table 1-4 clarifies that, if the electrolyte level is
monitored, the internal ohmic testing need only be performed every six years. Please see FAQ II.5.B, II.5,C, and II.5.D for a
discussion about continuity.
JEA
The current interpretation by the SDT of partially monitored is set at a higher bar than most utilities use
in their current designs today. We all wish to take advantage of the microprocessor relays and their
renowned and improved monitoring capability. If TC1 is monitored by primary relay A and TC2 is
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monitored by primary relay B, and these relays in turn monitor their DC supplies, the vast majority of the
system is monitored - (partially monitored), including all the control cable out to the remote breakers and
their trip coils. To add to this some additional contacts within the scheme, located very near the primary
relays, is extending the partially monitored bar to a higher level than most designs incorporate today. If
you know that 98% of the DC control system is monitored - isn't that partially monitored? Please
consider changes to the SDT's current view of a partially monitored protection systems.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Tables 1-1 through 1-5.
Arizona Public Service
Company
1. The generator Facilities subsections 4.2.5.1 through 5 are too prescriptive and inconsistent with
sections 4.2.1 through 4. Recommend this section be limited to description of the function as in the
preceding sections.
2. Clarification is needed on how the “Note 1” in Table 1a, which appears to be used in to define a
calibration failure would be used in Time Based Maintenance. In PRC-005-2 Attachment A: Criteria
for a Performance-Based Protection System Maintenance Program, a calibration failure would be
considered an event to be used in determining the effectiveness of Performance Based
Maintenance. It is unclear in how it will be used in time based maintenance.
Response: Thank you for your comments.
1. The SDT believes that transmission lines, UFLS, UVLS, and SPS are clear without additional granularity, but that the additional
granularity regarding generation plants is necessary. This is illustrated by numerous questions regarding “what is included for
generation facilities?” relative to PRC-005-1.
2. The Tables have been rearranged and considerably revised to improve clarity. In addition, the Note was removed, and
Requirement 4 has been considerably revised.
Pacific Northwest Small
Public Power Utility
Comment Group
November 17, 2010
1. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are
to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1.
Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the
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18 month interval is missing.
2. IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not
maximums. An entity wishing to avoid non-compliance for an interval that might extend past three
calendar months due to storms and outages must set a target interval of two months thereby
increasing the number of inspections each year by half again. This is unnecessarily frequent. We
suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4
calendar months.
3. We are concerned over R1.1, where all components must be identified, without a definition for the
word component or the granularity specified. While the FAQ gives a definition, and allows for entity
latitude in determining the granularity, the FAQ is not part of the standard. We believe this will allow
REs to claim non-compliance for every three inch long terminal jumper wire not identified in a trip
circuit path. We suggest that the FAQ definitions be included within the standard.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
2. The SDT disagrees. The entity should schedule routine inspections to complete the specified activities within the specified 3-month
interval.
3. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
PNGC Power
The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to
be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1.
Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the 18
month interval is missing.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity.
MRO’s NERC Standards
Review Subcommittee
November 17, 2010
1. The NSRS does not support the existing 2nd Draft of PRC-005-2 Standard because it is our opinion
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that:
o There is a high probability that system reliability will be reduced with this revised standard.
o The utility industry is in the business of keeping the lights on, but these requirements will force the
industry to take customers out of service in order to fulfill these requirements. A possible solution is
to increase the test intervals, set performance targets, test set on a basis of past performance, etc.
o The number of unplanned outages due to human error will increase considerably.
o The requirement of a complete functional trip test will reduce the level of reliability and all levels of
the BES to include distribution systems.
o Availability of the BES will be reduced due to an increased need to schedule planned outages for
test purposes (to avoid unplanned outages due to human error).
o To implement this standard, an entity will need to hire additional skilled resources that are not
readily available. (May require adjustments to the implementation timeline.)
o The cost of implementing the revised standard will approximately double our existing cost to
perform this work.
2. Requests that relevant reliability performance data (based on actual data and/or lessons learned
from past operating incidents, Criteria for Approving Reliability Standards per FERC Order 672) be
provided to justify the additional cost and reliability risks associated with functional testing.
3. Under a Performance-Based Program, what happens if the population of components drops below
60 (as all will eventually)? Is there an implementation period to default to TBM?
4. Please clarify In R1, the statement “or are designed to provide protection for the BES” re-opens the
argument about transformer protection or breaker failure protection for transformer high-side
breakers tripping BES breakers being included in the transmission protection systems.
5. Also, for Table 1b “Verify that each breaker trip coil, each auxiliary relay, and each lockout relay is
electrically operated within this time interval” should be changed from a 6 year interval to a 12 year
interval similar to the relay input and outputs. Experience has shown that these both have very
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similar reliability.
6. The standard as currently drafted raises concern as it relates to the identification of all Protection
System components, particularly those with associated communications equipment. In the case of
leased lines, a utility would be expected to maintain equipment they do not own. Recommend
revising the standard to consider maintenance activities on a communications channel basis in which
intermediate device functioning can be verified by sending a signal from one relay to another.
7. Clarification should be given as to the reason for stating control circuitry separately, such as in
“Control and trip circuits”. As currently stated, this implies that close circuit DC paths are now
subject to a protection system maintenance program when reclosing and closing of breakers have
never before been considered part of a Protection System.
8. Statements 3 (For microprocessor relays, check the relay inputs and outputs that are essential to
proper functioning of the Protection System. ) and 6 (Verify correct operation of output actions that
are used for tripping. in Table 1b for Protective Relays essentially address the same issue. Please
clarify if these are addressing the same issue or not. If the purpose is to describe the functionality of
the protection system, that should be covered under another section in the table, such as DC
circuitry.
9. How one identifies a voltage and current sensing input is not well defined. In most cases, this should
already be identified with the relay. Also, the scope of detail required is ambiguous. Would
individual cables, terminal blocks, etc. need to be identified as would be implied by “associated
circuitry”? Please clarify. The NSRS recommends that individual cables, terminal blocks, etc are not
included in this program.
10. Recommend removing “proper functioning of” from the maintenance activities for voltage and current
sensing inputs in Table 1b. A utility is not verifying the functionality of the signal(s), they are verifying
the signals themselves. Any functioning of the signals, which is related to ensuring proper relay
interpretation, would be covered under the protective relay section.
11. In general, has thought been put into the possibility of degrading reliability by implementing such a
rigorous maintenance program? To implement such a program, the number of scheduled outages
would greatly increase resulting in scheduling conflicts that will increase, as well as degrading
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system conditions by taking lines, transformers, etc. out of service. Because of past design
practices many of the requirements for maintenance will only be able to be performed by lifting wires
to isolated trip paths. Potential error is introduced anytime a wire is lifted, especially numerous
wires, by means of ensuring they are put back in the correct place. Redundancy is one thing that
has been implemented in great detail throughout the history of protection systems to ensure that
they work as intended. Diligent commissioning may need to be given its due credit.
Response: Thank you for your comments.
1. Thank you for your opinions.
2. The Standard does not preclude an entity from largely utilizing other methods of verification, although functional testing may be the
easiest to achieve.
3. The entity must revert to TBM if the population falls below 60. There is no implementation period; the SDT believes that the annual
PBM review will alert the entity that the population is nearing 60, and allow the entity to react to the diminishing component
population accordingly.
4. This comment relates to your regional BES definition, not the Standard.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. The SDT believes that
mechanical solenoid-operated devices share performance attributes (and failure modes) with electromechanical relays and need to
be tested at similar intervals. Performance-based maintenance is an option to increase the intervals if the performance of these
devices supports those intervals.
6. The functional testing of the channel will verify that the communications system operates properly. If the communications system
does not perform properly, the applicable entity is responsible to assure that it is restored to service; the physical actions to do so
may have to be performed by other parties. Your suggested end-to-end test is one effective way of performing this maintenance;
however, this is only one of several ways of doing this.
7. This component of the definition is stated to apply as “associated with protective functions” and thus excludes close/reclosing
circuits. Please see FAQ II.1.A.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
9. This component of the Protection System definition is to generally include this functionality as a part of the Protection System. The
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detailed applicability of this component within PRC-005-2 is addressed within the Standard. The “protective relay” only addresses
how the relay itself uses these signals, but does not address the concern regarding whether these signals are accurate. The Tables
have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. Requirement R1, part 1.1, has been
revised to state, “Address all Protection System component types” to clarify that “individual cables, terminal blocks, etc.” need not
be discretely addressed. The definition has also been revised to remove “associated circuitry” from this portion. Please see FAQ
II.3.A.
10. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
11. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.
Indiana Municipal Power
Agency
1. The proposed effective date working is confusing and maybe incorrect. It looks like the second part
of the paragraph refers to the additional maintenance and testing required by requirement 2 of the
current version of PRC-005-1. PRC-005-2 will be adding additional maintenance and testing. Since
the current wording is confusing, we are not sure when we have to ensure the new testing is done on
the protection equipment.
2. When it comes to battery maintenance, the battery cell to cell connection resistance has to be
verified. IMPA is not sure how the SDT wants this maintenance performed. Some battery banks are
made up of individual battery cases with two posts at each end that contain two to four individual
battery cells inside of each case. To actually tear down the individual cells in a case would be
extremely hard and maybe impossible on the sealed cases without destroying the cases. It would be
nice to describe how the SDT wants the connection resistance of battery cell to cell verified in the
FAQ guide.
3. In the same guide, the SDT might give insight on what is meant by verifying the state of charge of
the individual battery cell/units (table 1A). It seems like measuring the voltage level of the individual
battery would work for this verification, but additional information of what the SDT wants for this
verification would eliminate any doubt and help with being in compliant with this requirement.
Response: Thank you for your comments.
1. The SDT does not understand your concern. Perhaps you are referring to the Implementation Plan for the definition rather than the
Implementation Plan for the Standard. The second bullet in the introductory portion of the Implementation Plan for the Standard has
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been modified to state, “ ... is being performed according to …” rather than “has been moved to” to be more concise.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. The term “cell” has been
modified to “cell/unit” to address part of your concern. Please see FAQ II.5.L.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. IEEE Standards 1188,
450, and 1106 provide “how-to” guidance specific to various battery technologies.
ReliabilityFirst Corp.
The SDT should be congratulated on its hard work in making substantial improvements to an existing
standard.
1. In revising the draft standard, the SDT should consider the difficulty an entity will have in providing
the evidence required to show compliance.
2. R1 unnecessarily limits PSMPs to “Protection Systems that use measurements of voltage, current,
frequency and or phase angle to determine anomalies.” However, if an entity applies devices that
protect equipment based on other non-electrical quantities or principles such as temperature or
changes in pressure, the entity is not required to maintain them. These types of devices have long
been considered by many organizations as important forms of protection and therefore in some
instances are connected to trip. There are also many organizations that consider these types of
devices too unreliable to use as protection and therefore only connect them for monitoring (and not
to trip). If protection based on non-electrical quantities is not properly maintained, it will Misoperate
and will negatively impact reliability. The standard cannot simply ignore a type of protection that can
ultimately affect the reliability of the BES.
Response: Thank you for your comments.
1. The SDT has considered this, and has provided examples in the Measures. Please see Section 15.7 of the Supplementary
Reference document and FAQ IV.1.B.
2. Requirement R1 does not preclude entities from maintaining such devices or including them in the PSMP.
Indeck Energy Services
November 17, 2010
The standard should include an assessment of, and criteria for, determining whether a Protective
System is important to reliability. It presently treats a fault current relay on a 345 kV or higher voltage
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transformer the same as one on a small generator on the 115 kV system. The impact of failures on both
on a hot summer day like we've had recently in NY, would be very different. As discussed at the FERC
Technical Conference on Standards Development, the goal of the standards program is to avoid or
prevent cascading outages--specifically not loss of load. This seems to have been lost in the drafting
process. Much of the effort expended on complying with the existing PRC maintenance standards, as
well as that to be expended on PRC-005-2, has little to no significant in terms of improving reliability.
That effort could be better utilized if focused on activities that could significantly improve reliability. As
one of the Commissioners at the FERC Technical Conference on Standards Development characterized
the relationship between FERC and NERC as a wheel off the track. The whole standards program, and
especially PRC-005-2, is off the track.
Response: Thank you for your comments. Your comments seem to be related to NERC Standards Development in general, and to
BES definitions. The 2007-17 SDT is unable to address these concerns. The SDT is addressing its assignment from the approved
SAR, and believes that performing maintenance on Protection Systems will benefit the reliability of the BES.
US Bureau of Reclamation
1. The sub-requirements for R1, are not criteria, rather implementation requirements more suitable to
be included in R4. Examples of what the PSMP shall address which would be more consistent with
the language in R1 would be:
•
How are changes to the PSMP administered?
•
Who approves the determination of the use of time-based, condition based or performance
based maintenance.
•
Who reviews activities under the PSMP
2. References used within the standard are not consistent. In R1.2 Attachment as is referred to as
Attachment A. In R3 Attachment A is referred to as PRC-005 Attachment A. This implies a
difference. Under a voluntary world, we could draft criteria and procedures with these problems and
interpret them correctly. Today in the compliance world, the language must be precise and
unambiguous. The reference must be the same it means something different.
3. The requirement in R1, which is consistent with the purpose, does not support the applicability in
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R4.2.5.4. Protection systems associated with stations service are not designed to provide protection
for the BES. In particular we have been told that intent was not to look at every device that tripped
the generator but devises that sensed problems on the BES and trip the generator. Hence we
include such things as frequency relays, Differential relays, zone relays, over current, and under
voltage relays. Even a loss of field looks at the system as included. Speed sensing devices were
explicitly excluded. As such, if the stations service transformer protection looks toward the BES (e.g.
differential relays and zone relays) they would be included. Over current would not as it would be on
the station side. If a Station Service transformer saw excess current, the system would in most
cases fail over to other side. If not, it would cause the generator to trip much like a generator thermal
device which is also excluded. Maintenance programs offer a unique problem to the FERC and
regulatory world. The knee jerk reaction is to define them. What happens if the solution is bad, who
will accept the consequences that narrow prescription was wrong and the interval caused a reliability
impact. It would no longer be the Entity. History is replete with examples of this type of micro
managing. Rather than fall into the same trap, and suffer the consequences of the unknown, allow
Entities to optimize their programs to ensure reliability of the BES and create a standard of
disallowed practices which have a demonstrated impact on reliability.
Response: Thank you for your comments.
1. Requirement R1 presents the requirements to establish a PSMP; Requirement R4 presents the implementation of the program.
The SDT believes that this arrangement is correct. The examples cited seem to be related more to the internal administration of the
PSMP within an entity, and not to the requirements.
2. The Standard has been modified to make these phrases consistent in consideration of your comment.
3. The SDT believes that the station service transformers may be essential to the operation of the generator (which is the BES
element), and thus that the protection of these needs to be addressed as part of PRC-005-2.
Bonneville Power
Administration
November 17, 2010
1. The term “maintenance correctable issue” used in Requirement 4 seems to be at odds with the
definition given for it. It seems that an issue that cannot be resolved by repair or calibration during
the maintenance activity would be a maintenance non-correctable issue. Also, in Requirement 4, the
term “identification of the resolution” is ambiguous. Suggested changes for Requirements 4 and 4.1
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are:
a. R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement
its PSMP, and resolve any performance problems as follows:
b. 4.3 Ensure either that the components are within acceptable parameters at the conclusion of
the maintenance activities or initiate actions to replace the component or restore its
performance to within acceptable parameters.
Response: Thank you for your comments.
1. The definition of “maintenance correctable issue” is consistent with the way it is used within the Standard.
Santee Cooper
There is some discussion in the documents, such as the definition of component in the FrequentlyAsked Questions, about the idea that an entity has some latitude in determining the level of “protection
system component” that they use to identify protection systems in their program and documentation.
The example given is about DC control circuitry. There are requirements in this standard that are
specific to a component, such as R1.1 - Identify all protection system components. Historically, if your
maintenance and testing program is defined as (say, for relays) testing all the relays in a station at one
time, your program, test dates, etc. could be identified by the station. There needs to be some addition,
possibly to the Frequently asked questions, to explain what kind of documentation will be required with
this new standard. For example, if your program is to test all the relays at a station every 4 years, and all
the relays are tested at the same time, can your documentation of your schedule (the “date last tested”
and previous date) be listed by station (accepting that you should have the backup data to show the
testing was thorough) or must you be able to provide a list by each relay. Without some clarification, it
seems like this could get confusing at an audit with many of the requirements pertaining to “each
component.”
Response: Thank you for your comments. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System
component types.” The remaining issues within your comment are dependent on how your PSMP addresses them.
Northeast Power
November 17, 2010
1. UFLS systems by design can suffer random failures to trip. A requirement should exist that
stipulates to perform maintenance on the UFLS relay as their failure to operate may affect numerous
190
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Coordinating Council
Question 7 Comment
distribution level feeders. However maintenance on associated DC schemes connected to the
devices should only be done on the same frequency as maintenance on the relevant interrupting
devices. Consideration should be given to exempting schemes that have a maintenance program in
place on those distribution level devices from PRC-005 Standard-specified maintenance intervals.
Such Standard-specified intervals could apply to interrupting devices that have no maintenance
program in place.
2. This standard is overly prescriptive. Owners of protection system equipment establish maintenance
procedures and timelines based on manufacturers’ recommendations and experiences to ensure
reliability. Maintenance intervals change with improved practices and equipment designs, and
whenever that occurs PRC-005 will have to go through the revision process, which would be
frequent and unnecessary if the standard were more general.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
2. FERC Order 693 and the approved SAR for this project directed the SDT to establish both maximum maintenance intervals and
minimum maintenance activities within the revised Standard.
Entergy Services
We support this project and believe it is a positive step towards BES reliability. However, we believe the
draft document needs additional work as per our comments. Also, as indicated by the amount of
industry input on the last version draft comments, we believe revisions are still needed to properly
address this technically complex standard.
If this standard is to deviate from the original project schedule and follow a fast track timeline for
approval, then we disagree with the 3 month implementation for Requirement 1 and ask for at least 12
months. The original schedule provided sufficient advance notice to work on an implementation plan
and it included the typical time required for NERC Board of Trustees and regulatory approvals. If the
project schedule and typical NERC Board of Trustees and regulatory approval times are to be
accelerated, the implementation plan should be extended.
Response: Thank you for your comments. The Implementation Plan for Requirement R1 has been revised from 3 months to 12
November 17, 2010
191
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Question 7 Comment
months.
Utility Services
With regard to DPs who own transmission Protection Systems, the standard is still very unclear on when
a DP owns a transmission Protection System. Many DPs own equipment that is included within the
definition of a Protection System; however, ownership of such equipment does not necessarily translate
directly into a transmission Protection System under the compliance obligations of this standard. DPs
need to know if this standard applies to them and right now, there is no certain way of determining that
from within this language or previous versions of this standard. Additionally, the NPCC Regional
Standards Committee withdrew a SAR on this very subject as we informed the question would be
addressed in this proposal.
Response: Thank you for your comments. Your concern seems to be primarily related to the applicable regional BES definition.
Y-W Electric Association,
Inc.
1. Y-WEA concurs with Central Lincoln regarding the timing of required battery tests. The IEEE
standards referenced indicate target maintenance intervals. In order to remain reasonable, then, this
compliance standard needs to allow some buffer between a targeted maintenance and inspection
interval and a maximum enforceable maintenance and inspection interval. Central Lincoln’s
suggestion of a four-month maximum window is reasonable and should be incorporated into the
standard.
2. Y-WEA is also concerned with R1.1’s language indicating that all components must be identified with
no defined “floor” for the significance of a component to the Protection System. The SDT cannot
possibly expect that a parts list containing every terminal block, wire and jumper, screw, and lug is
going to be maintained with every single part having all the compliance data assigned to it, but
without clearly stating this, that is exactly the degree of record-keeping that some overzealous auditor
could attempt to hold the registered entity to. The FAQ is much clearer as to what is and is not a
component and should be considered for the standard.
3. Y-WEA also concurs with FMPA’s comments regarding the testing of batteries and DC control circuits
associated with UFLS relaying. Many UFLS relays are installed on distribution equipment.
Furthermore, many distribution equipment vendors are including UFLS functions in their distribution
equipment. For example, many recloser controls incorporate a UFLS function in them. These
November 17, 2010
192
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Question 7 Comment
controls and the reclosers they are attached to, however, are strictly distribution equipment. 16 USC
824o (a)(1) limits the definition of the Bulk-Power System to “not include facilities used in the local
distribution of electric energy.” A distribution recloser and its control clearly fall into this exclusion. 16
USC 824o (i)(1) prohibits the ERO from developing standards that cover more than the Bulk-Power
System. As such, the DC control circuitry and batteries associated with many UFLS relaying
installations are precluded from regulation under NERC’s reliability standards and may not be
included in this standard because they are distribution equipment and therefore not part of the BulkPower System. The proposed standard needs to be rewritten to allow for this exclusion and to allow
for the testing of only the UFLS function of any distribution class controls or relays.
Response: Thank you for your comments.
1. The SDT disagrees. You should complete the activities within the intervals specified.
2. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-4 and 1-5.
November 17, 2010
193
Consideration of Comments on Proposed Definition of Protection System
for Project 2007-17
The Protection System Maintenance and Testing Standard Drafting Team thanks all
commenters who submitted comments on the draft definition of “Protection System.” This
document was posted for a special 35-day public comment period from June 11, 2010
through July 16, 2010. Stakeholders were asked to provide feedback on the proposed
definition through a special Electronic Comment Form. There were 50 sets of comments,
including comments from more than 110 different people from over 55 companies
representing 8 of the 10 Industry Segments as shown in the table on the following pages.
Based on stakeholder comments, the drafting team refined its proposed definition of
Protection System as shown below:
Protective relays , which respond to electrical quantities, communication systems
necessary for correct operation of protective functions, voltage and current sensing
devices providing inputs to protective relays, station dc supply, and control circuitry
associated with protective functions through the trip coil(s) of the circuit breakers or
other interrupting devices.
Several comments questioned the reason for implementing the definition of Protection
System in advance of implementing the proposed modifications to PRC-005-1. When the
Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by
the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team
caused by the definition of "protection system" and directed that work to close this reliability
gap should be given “priority.” To close this reliability gap the BOT has directed that revised
definition be applied to PRC-005-1 as soon as practical - not years from now.
Stakeholder comments indicated that applying the expanded scope of the definition of
Protection System would to PRC-005-1 would require more than six months and suggested
expanding this to 12 months, and the drafting team made this change to the
implementation plan. The team adjusted the implementation plan so that entities will have
at least twelve months, rather than the six months originally proposed, to apply the new
definition of Protection System to PRC-005-1 – Protection System Maintenance and Testing
to Requirement R1 of PRC-005-1. The other parts of the implementation plan remain
unchanged.
All work of the drafting team has been posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_200717.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition,
there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on the Definition of Protection System — Project 2007-17
Index to Questions, Comments, and Responses
1.
Do you believe the proposed definition of Protection System is ready for ballot? If not,
please explain why. ........................................................................................... 10
2.
Do you agree with the implementation plan for the revised definition of Protection
System? The implementation plan has two phases – the first phase gives entities at
least six months to update their protection system maintenance and testing program;
the second phase starts when the protection system maintenance and testing program
has been updated and requires implementation of any additional maintenance and
testing associated with the program changes by the end of the first complete
maintenance and testing cycle described in the entity’s revised program. If you
disagree with this implementation plan, please explain why. ................................... 30
July 22, 2010
2
Consideration of Comments on the Definition of Protection System — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Guy Zito
Additional Member
Organization
1
2
3
4
5
6
7
8
9
Northeast Power Coordinating Council
Additional Organization
New York State Reliability Council, LLC
NPCC 10
2. Gregory Campoli
New York Independent System Operator
NPCC 2
3. Kurtis Chong
Independent Electricity System Operator
NPCC 2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7. Ben Eng
New York Power Authority
NPCC 4
8. Brian Evans-Mongeon Utility Services
NPCC 8
9. Dean Ellis
Dynegy Generation
NPCC 5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
11. Kathleen Goodman
ISO - New England
NPCC 2
12. David Kiguel
Hydro One Networks Inc.
NPCC 1
13. Michael R. Lombardi
Northeast Utilities
NPCC 1
14. Randy MacDonald
New Brunswick System Operator
NPCC 2
15. Bruce Metruck
New York Power Authority
NPCC 6
10
X
Region Segment Selection
1. Alan Adamson
July 22, 2010
Industry Segment
3
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
Organization
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
21. Chantel Haswell
FPL Group
NPCC 5
22. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
2.
Group
Pacific Northwest Small Public Power Utility
Comment Group
Steve Alexanderson
Industry Segment
1
2
3
4
X
X
5
6
7
8
9
Additional Member Additional Organization Region Segment Selection
1. Russ Noble
Cowlitz PUD
WECC 3, 4, 5
2. Dave Proebstel
Clallam County PUD
WECC 3
3. John Swanson
Benton PUD
WECC 3
4. Steve Grega
Lewis County PUD
WECC 3, 5
3.
Group
Margaret Ryan
Additional Member
PNGC Power
Additional Organization
X
Region Segment Selection
1.
Blachly-Lane Electric Cooperative
WECC 3
2.
Central Electric Cooperative
WECC 3
3.
Clearwater Electric Cooperative
WECC 3
4.
Consumer's Power Company
WECC 3
5.
Coos-Curry Electric Cooperative
WECC 3
6.
Douglas Electric Cooperative
WECC 3
7.
Fall River Electric Cooperative
WECC 3
8.
Lane Electric Cooperative
WECC 3
9.
Lincoln Electric Cooperative
WECC 3
10.
Lost River Electric Cooperative
WECC 3
11.
Northern Lights Electric Cooperative WECC 3
12.
Okanogan Electric Cooperative
WECC 3
13.
Raft River Electric Cooperative
WECC 3
July 22, 2010
X
4
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
Organization
14.
Salmon River Electric Cooperative
WECC 3
15.
Umatilla Electric Cooperative
WECC 3
16.
West Oregon Electric Cooperative
WECC 3
17.
PNGC
WECC 8
4.
Group
Denise Koehn
Additional Member
1. Dean Bender
5.
Group
Bonneville Power Administration
Additional Organization
Industry Segment
1
2
3
X
X
X
X
X
X
X
X
4
5
6
X
X
X
X
7
8
9
Region Segment Selection
BPA, Transmission SPC Technical Svcs WECC 1
Sam Ciccone
FirstEnergy
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
2. Jim Kinney
FE
RFC
1
3. Ken Dresner
FE
RFC
5
4. Brian Orians
FE
RFC
5
5. Bill Duge
FE
RFC
5
6. J. Chmura
FE
RFC
1
7. Dave Folk
FE
RFC
1, 3, 4, 5, 6
6.
Group
Terry L. Blackwell
Santee Cooper
X
Additional Member Additional Organization Region Segment Selection
1. S. Tom Abrams
Santee Cooper
SERC
1
2. Rene' Free
Santee Cooper
SERC
1
3. Bridget Coffman
Santee Cooper
SERC
1
7.
Group
Kenneth D. Brown
Public Service Enterprise Group ("PSEG
Companies")
X
X
Additional Member Additional Organization Region Segment Selection
1. Jim Hubertus
PSE&G
2. Scott Slickers
PSEG Power Connecticut NPCC
3. Jim Hebson
PSEG ER&T
ERCOT 5, 6
4. Dave Murray
PSEG Fossil
RFC
July 22, 2010
RFC
1, 3
5
5
5
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
8.
Group
Daniel Herring
Organization
Industry Segment
1
The Detroit Edison Company
2
3
4
5
X
X
X
6
7
8
9
Additional Member Additional Organization Region Segment Selection
1. David A Szulczewski Relay Engineering
RFC
9.
Hydro One
Group
Sasa Maljukan
3, 4, 5
X
Additional Member Additional Organization Region Segment Selection
1. David Kiguel
Hydro One Networks, Inc. NPCC 1
10.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
11.
Individual
Brent Inebrigtson
E.ON U.S.
X
X
X
X
12.
Individual
Brandy A. Dunn
Western Area Power Administration
X
13.
Individual
Jana Van Ness
Arizona Public Service Company
X
14.
Individual
Jack Stamper
Clark Public Utilities
X
15.
Individual
Dan Roethemeyer
Dynegy Inc.
16.
Individual
Robert Ganley
Long Island Power Authority
X
17.
Individual
Lauri Dayton
Grant County PUD
X
18.
Individual
Fred Shelby
MEAG Power
X
19.
Individual
James A. Ziebarth
Y-W Electric Association, Inc
20.
Individual
Armin Klusman
CenterPoint Energy
X
21.
Individual
Andrew Z.Pusztai
American Transmission Company
X
22.
Individual
Eric Ruskamp
Lincoln Electric System
X
X
X
X
23.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
24.
Individual
Edward Davis
Entergy Services
X
X
X
X
25.
Individual
James Sharpe
South Carolina Electric and Gas
X
X
X
X
26.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
27.
Individual
Scott Kinney
Avista Corp
X
July 22, 2010
X
X
X
X
X
X
X
X
X
6
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
4
5
6
28.
Individual
Amir Hammad
Constellation Power Generation
29.
Individual
Jeff Nelson
Springfield Utility Board
30.
Individual
Michael R. Lombardi
Northeast Utilities
X
X
X
31.
Individual
John Bee
Exelon
X
X
X
32.
Individual
Barb Kedrowski
We Energies
X
X
X
33.
Individual
Jianmei Chai
Consumers Energy Company
X
X
X
34.
Individual
Art Buanno
ReliabilityFirst Corp.
35.
Individual
Greg Rowland
Duke Energy
X
X
X
X
36.
Individual
Thad Ness
American Electric Power
X
X
X
X
37.
Individual
Rex Roehl
Indeck Energy Services
38.
Individual
Claudiu Cadar
GDS Associates
X
39.
Individual
Terry Bowman
Progress Energy Carolinas
X
X
X
X
40.
Individual
Kirit Shah
Ameren
X
X
X
X
Group
Joe Spencer - SERC
staff and Phil Winston PCS co-chair
SERC Protection and Control Sub-committee
(PCS)
41.
Additional Member
8
9
10
X
X
X
X
X
Additional Organization
Region Segment Selection
1. Paul Nauert
Ameren Services Co.
SERC
2. Bob Warren
Big Rivers Electric Corp.
SERC
3. Trevor Foster
Calpine Corp.
SERC
4. John (David) Fountain Duke Energy Carolinas
SERC
5. Paul Rupard
East Kentucky Power Coop.
SERC
6. Charles Fink
Entergy
SERC
7. Marc Tunstall
Fayetteville Public Works Commission SERC
8. John Clark
Georgia Power Co
SERC
9. Nathan Lovett
Georgia Transmission Corp
SERC
July 22, 2010
7
7
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
Organization
10. Danny Myers
Louisiana Generation, LLC
SERC
11. Ernesto Paon
Municipal Electric Authority of GA
SERC
12. Jay Farrington
PowerSouth Energy Coop.
SERC
13. Jerry Blackley
Progress Energy Carolinas
SERC
14. Joe Spencer
SERC Reliability Corp
SERC
15. Russ Evans
South Carolina Electric and Gas
SERC
16. Bridget Coffman
South Carolina Public Service Authority SERC
17. Phillip Winston
Southern Co. Services Inc.
SERC
18. George Pitts
Tennessee Valley Authority
SERC
19. Rick Purdy
Virginia Electric and Power Co.
SERC
42.
Group
Frank Gaffney
Additional Member
Florida Municipal Power Agency
Additional Organization
Utilities Commission of New Smyrna Beach FRCC 4
2. Greg Woessner
Kissimmee Utility Authority
FRCC 1
3. Jim Howard
Lakeland Electric
FRCC 1
4. Lynne Mila
City of Clewiston
FRCC 3
5. Joe Stonecipher
Beaches Energy Services
FRCC 1
6. Cairo Vanegas
Fort Pierce Utilities Authority
FRCC 4
Group
Richard Kafka
Additional Member
Pepco Holdings, Inc. - Affiliates
Additional Organization
2
3
4
5
6
X
X
X
X
X
X
X
X
X
7
8
9
Region Segment Selection
1. Alvin Depew
Potomac Electric Power Company RFC
1
2. Carl Kinsley
Delmarva Power & Light
RFC
1
3. Rob Wharton
Delmarva Power & Light
RFC
1
4. Evan Sage
Potomac Electric Power Company RFC
1
5. Carlton Bradsaw
Delmarva Power & Light
RFC
1
6. Jason Parsick
Potomac Electric Power Company RFC
1
7. Walt Blackwell
Potomac Electric Power Company RFC
1
8. John Conlow
Atlantic City Electric
RFC
1
9. Randy Coleman
Delmarva Power & Light
RFC
1
July 22, 2010
1
Region Segment Selection
1. Timothy Beyrle
43.
Industry Segment
8
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
44.
Group
Mallory Huggins
Additional Member Additional Organization
Organization
1
2
3
4
5
6
7
8
9
10
NERC Staff
Region
Segment Selection
1. Joel DeJesus
NERC
NA - Not Applicable NA
2. Mike DeLaura
NERC
NA - Not Applicable NA
3. Al McMeekin
NERC
NA - Not Applicable NA
4. Earl Shockley
NERC
NA - Not Applicable NA
5. Bob Cummings
NERC
NA - Not Applicable NA
6. David Taylor
NERC
NA - Not Applicable NA
45.
Individual
JT Wood
Southern Company Transmission
46.
Individual
Tom Schneider
WECC
47.
Individual
Hugh Conley
Allegheny Power
48.
Individual
Scott Berry
Indiana Municipal Power Agency
49.
Individual
Terry Habour
MidAmerican Energy Company
50.
Individual
Martin Bauer
US Bureau of Reclamation
July 22, 2010
Industry Segment
X
X
X
X
X
X
X
9
Consideration of Comments on the Definition of Protection System — Project 2007-17
1. Do you believe the proposed definition of Protection System is ready for ballot? If not,
please explain why.
Summary Consideration: Almost half of the commenters felt that the definition itself was not ready for ballot.
Many commenters wanted more clarity regarding the portion of the definition addressing “voltage and current sensing inputs to
protective relays ... “. The SDT inserted the words “devices providing” into the phrase to clarify that instrument transformers are
included in the definition. This portion of the definition now reads:
•
Voltage and current sensing devices providing inputs to protective relays,
Many commenters also suggested that the definition should limit the protective relays “to those using electrical quantities”, rather
than addressing this subject as a footnote in the standard. The SDT incorporated this suggestion; this portion of the definition now
reads:
•
“Protective relays which respond to electrical quantities”.
The SDT also removed the phrase “from the station dc supply” from the “control circuitry” portion of the definition.
Some commenters suggested that “protective relays” be defined; the SDT chose not to do this as IEEE already defines this term.
Many commenters also offered comments on the standard itself. These comments are being addressed in the comment forms for
the standard.
The revised definition is:
Protection System:
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply, and
• Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting
devices.
Several commenters indicated that the definition should not apply to PRC-005-1. When the Board of Trustees was asked to approve
an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the
July 22, 2010
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not
years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1,
and that should give entities time to apply the new definition to PRC-005-1.
Organization
GDS Associates
Yes or
No
Question 1 Comment
No
1. The inserted wording “and associated circuitry from the voltage and current sensing
devices” implies that the maintenance program will include the verification, monitoring,
etc. of the wiring from the voltage/current sensing devices which requirement will be a
bit excessive under current presentation of the standard. See comment on the standard
as well.
2. SDT’s additional wording such as “from the station DC supply through the trip coil(s) of
the circuit breakers or other interrupting devices” can be a bit of an issue as the coils
could be good at time of verification and testing, but can fail right after or due to the
testing. We recommend to change the Protection System definition to read “up to the
trip coils(s)” instead the word “through”
Response: Thank you for your comments.
1. The definition has been modified to say, “voltage and current sensing devices providing inputs to protective relays”.
2. The SDT disagrees, and asserts that the trip coil(s) must be included within the Protection System. The observation that
the element may be good at the time of verification and testing, but fail immediately thereafter, is true of any device that is
not monitored continuously for proper operating function.
Grant County PUD
No
1) We note that the definition of a “Protection System” has been expanded to include the
trip coils and what used to be confined to batteries has now been expanded to “station
DC supply.” “Trip coils” is an improvement. Inasmuch as the mark-up changing “DC” to
“dc” is intended to communicate a more general term as opposed to a strict definition, it
leaves room for differing opinions among auditors as to what all should be included. We
July 22, 2010
11
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
support the change to exclude battery chargers since the rationale for their inclusion was
never clear. The battery itself will be, without exception, the “first responder” to provide
DC power to a Protection System. However, battery chargers have not been excluded
under the FAQs.
2) The SPCTF’s effort to define applicability in terms of “Facilities” is confusing.
Additionally, it is unclear how the terms “component,” “element” and “Facility” are
intended to relate to one another. An assumption may be that one or more components
(which are physical assets) can comprise an “element,” one or more of which can be
associated with an identifiable function, aligning with the five Protection System
Equipment Categories, found in SPCTF’s “PROTECTION SYSTEM MAINTENANCE-A
Technical Reference, dated Sept. 13, 2007, and that “Facility” is as used in 4.2.1 of the
Standard Development Roadmap, dated May 27, 2010. Please provide guidance on the
terms relate to one another.
3) The structure of the proposed standard is less clear than the existing standard PRC-0051 because of the potential for ambiguity between the definition of Protection System and
how the term “Facilities” is applied. A suggested resolution would be to revise the
definition of Protection System to resolve this ambiguity or to delete reference to 86
lockouts and auxiliary relays in the description of “Facilities.” If the 86 lockout relays are
to be included, they should be added as part of the DC Control Circuitry “element” (as
found in the NERC Glossary) of the circuit that energizes the 86 relay, thus placing it
within the definition of a “Protection System.”-once-and therefore in a manner that would
require only one scheduled maintenance to be performed if the testing schemes are
properly set up. We do agree, however, that sudden pressure relays, reclosing relays,
and other non fault detecting relays such as loss of cooling relays should not be
referenced as part of the “dc control circuitry” Element.
Response: Thank you for your comments.
1. A recent Interpretation request, referring to the currently approved definition specifying “station batteries”, excluded
July 22, 2010
12
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
battery chargers. The change to “station dc supply” is intended to expand the definition to include all essential elements
including battery chargers; without proper functioning of battery chargers, the battery will be discharged by normal
station dc load, and will be unable to perform its function; also, there are some entities which use a charger to provide the
dc supply without use of a battery. Use of “dc” rather than “DC” reflects the IEEE style guide for this term. The FAQ
intentionally does not exclude battery chargers as the SDT intend to include them within PRC-005-2.
2. This comment does not appear to apply to the definition, but instead to the draft Standard itself.
3. The SDT contends that “dc control circuitry” includes elements such as lockout relays and auxiliary relays.
Consumers Energy
No
1. It is unclear whether “voltage and current sensing inputs” include the instrument
transformer itself, or does it pertain to only the circuitry and input to the protective relays?
2. It is not clear what is included in the component, “station dc supply” without referring to
other documents (the posted Supplementary Reference and/or FAQ) for clarification. The
definition should be sufficiently detailed to be clear.
3. If Protection Systems trip via AC methods, are those systems, and the associated
control circuitry included?
Response: Thank you for your comments.
1.
The SDT has modified the definition for clarity; the SDT intends that the output of these devices, measured at the relay,
properly represents the primary quantities.
2.
There are many possible variations to “station dc supply”; it seems impossible to reflect all variations in the definition.
The definition must be sufficiently general such that variations can be included.
3.
The definition has been generalized such that ac tripping is included.
Public Service Enterprise
Group ("PSEG
Companies")
July 22, 2010
No
Based on review of ballot pool comments there are still too many questions that should be
resolved prior to submittal for ballot. It is suggested that a specific reference to the
supplementary reference document figures 1 & 2 and the legend be added. That would
13
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
further define the protection system components and scope boundary.
Response: Thank you for your comments. The SDT has revised the definition to make it more clear as a stand-alone product.
CenterPoint Energy
No
CenterPoint Energy believes the proposed definition of “Protection System” is technically
incorrect. The present definition does not include trip coils of interrupting devices, such as
circuit breakers; and correctly so, as trip coils are components of the interrupting device. A
Protection System has correctly performed its function if it provides tripping voltage up to
the circuit breaker trip coil. From that point, the circuit breaker can fail to timely interrupt
fault current due to several factors, such as a binding mechanism that affects breaker
clearing time, a broken pull rod, a bad insulating medium, or bad trip coils. Local breaker
failure protection, or remote backup protection, is installed to address the various possible
causes of circuit breaker failure.
For correctness, the definition of “Protection System” should be “Protective relays,
communication systems necessary for correct operation of protective functions, voltage and
current sensing inputs to protective relays and associated circuitry from the voltage and
current sensing devices, station dc supply, and control circuitry associated with protective
functions from the station dc supply UP TO THE TERMINALS OF the trip coil(s) of the
circuit breakers or other interrupting devices.”
Response: Thank you for your comments. The SDT disagrees, and asserts that the trip coil(s) must be included within the
Protection System.
Constellation Power
Generation
July 22, 2010
No
Constellation believes that this definition is to verbose, which can lead to unintended
interpretations. Constellation is concerned with the term sensing inputs, which may infer
that testing on instrument transformers must be completed while they are energized. This
proves difficult at a generating facility where most testing is completed during planned
outages when this equipment is not energized.
14
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
4.
Yes or
No
Question 1 Comment
Response: Thank you for your comments. The SDT has modified the definition for clarity; the SDT intends that the
output of these devices, measured at the relay, properly represents the primary quantities. Testing methods are not a
part of the definition.
Hydro One
No
1. Hydro One suggests adding “Components including” in the beginning. This is because
the word “components” has been used extensively throughout the standard and there is
no mention of what constitutes a protection system component in the standard. The
word “component” does find mention in FAQs, however, it is recommended to mention it
in the main standard.
The revised definition should read as follows: Protective System Components including
Protective relays, communication systems necessary for correct operation of protective
functions, voltage and current sensing devices providing inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station dc supply, and
control circuitry associated with protective functions from the station dc supply through
the trip coil(s) of the circuit breakers or other interrupting devices.
2. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly
identify which all protection system components does it own and need to maintain. This
is critical since NPCC had proposed a SAR to this effect which was not accepted by
NERC citing that this concern will be incorporated in the revised standard.
3. Also, reference should be made to Project 2009-17 in which Y-W Electric Association,
Inc. (Y-WEA) and Tri-State Generation and Transmission Association, Inc. (Tri-State)
requested an interpretation of the term "transmission Protection System" and
specifically whether protection for a radially-connected transformer protection system
energized from the BES is considered a transmission Protection System and is subject
to these standards.
Response: Thank you for your comments.
1. The SDT believes that the suggested text does not add to the definition, and may actually lead to additional problems,
July 22, 2010
15
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
such as an implication that the list within the definition is incomplete.
2. This issue is properly addressed within the Standard, not within the definition.
3. This issue relates to the application of the standard, and is not part of the definition.
Pacific Northwest Small
Public Power Utility
Comment Group
No
1. It is still unclear whether relays that respond to mechanical inputs, such as sudden
pressure relays, are included in the proposed definition as protective relays.
While PRC-005-2 R1 limits the scope of that particular standard to protection systems
that sense electrical quantities, it is remains unclear in other standards that use the
defined term whether mechanical input protections are included.
2. We suggest that “Protective Relay” also be defined, and that the definition clearly
exclude devices that respond to mechanical inputs in line with the NERC interpretation of
PRC-005-1 in response to the CMPWG request.
Response: Thank you for your comments.
1. The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
2. “Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC standard, thus the SDT
sees no need to either modify or duplicate that definition.
Pepco Holdings, Inc. Affiliates
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden
pressure relays, are included in the proposed definition as protective relays.
While PRC-005-2 R1 limits the scope of that particular standard to protection systems that
sense electrical quantities, it remains unclear in other standards that use the term
“Protection System” (such as PRC-004) whether devices responding to mechanical inputs
July 22, 2010
16
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
are included.
As such, we suggest that the term “Protective Relay” also be defined, and that the definition
clearly exclude devices that respond to mechanical inputs in line with the NERC
interpretation of PRC-005-1 in response to the CMPWG request.
Response: Thank you for your comments.
The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
“Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC standard, thus the SDT sees
no need to either modify or duplicate that definition.
PNGC Power
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden
pressure relays, are included in the proposed definition as protective relays.
While PRC-005-2 R1 limits the scope of that particular standard to protection systems that
sense electrical quantities, it is remains unclear in other standards that use the defined
term whether mechanical input protections are included.
We suggest that “Protective Relay” also be defined, and that the definition clearly exclude
devices that respond to mechanical inputs in line with the NERC interpretation of PRC-0051 in response to the CMPWG request.
Response: Thank you for your comments.
The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
“Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC standard, thus the SDT sees
July 22, 2010
17
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
no need to either modify or duplicate that definition.
Duke Energy
No
It is unclear whether the revised definition includes PTs and CTs, but it does include the
wiring. We don’t see a way to list the wiring in R1.1 and provide supporting compliance
evidence. We believe the phrase “and associated circuitry from the voltage and current
sensing devices” should be struck from the definition.
Response: Thank you for your comments. The definition has been modified as suggested.
Indeck Energy Services
No
It presumes that all relays in a plant are Protective Systems that affect BES reliability.
As discussed at the FERC Technical Conference on Standards Development, the goal of
the standards program is to avoid or prevent cascading outages--specifically not loss of
load. The purpose of PRC-005-2 uses the term in its global sense but there is no subset of
the Protection Systems that affect reliability. PRC-005 R1 requires identification of all
components.
With the broad definition proposed and no separate term for only relays and other
components that have been identified as affecting reliability, confusion results. If this term
has its global meaning, then another term, such as Reliability Protection Systems, should
be instituted to avoid confusion.
Response: Thank you for your comments. The SDT believes that this issue is one for application of the definition within
various standards, not one of the definition itself.
Lincoln Electric System
July 22, 2010
No
LES believes the proposed definition of Protection System as written remains open to
interpretation. LES offers the following Protection System definition for the SDT’s
consideration: “Protection System” is defined as: A system that uses measurements of
18
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
voltage, current, frequency and/or phase angle to determine anomalies and trips a portion
of the BES and consists of 1) Protective relays, and associated auxiliary relays, that initiate
trip signals to trip coils, 2) associated communications channels, 3) current and voltage
transformers supplying protective relay inputs, 4) dc station supply, excluding battery
chargers, and 5) dc control trip path circuitry to the trip coils of BES connected breakers, or
equivalent interrupting device, and lockout relays.
Response: Thank your for your comments. The SDT has modified the definition to address some of the suggestions. Other
elements of the suggestion do not add to the existing definition, and the SDT disagrees with the suggestions regarding “trip a
portion of the BES” since Special Protection Systems and UVLS may actually trip non-BES facilities, and with excluding
battery chargers.
Long Island Power
Authority
No
1. LIPA suggests adding “Protection System Components including” in the beginning. This
is because the word “components” has been used extensively throughout the standard
and there is no mention of what constitutes a protection system component in the
standard. The word “component” does find mention in FAQs, however, it is
recommended to mention it in the main standard.
2. Also, LIPA proposes a change in the proposed definition (changing "voltage and current
sensing inputs" to "voltage and current sensing devices providing inputs").The revised
definition should read as follows: Protective System Components including Protective
relays, communication systems necessary for correct operation of protective functions,
voltage and current sensing devices providing inputs to protective relays and associated
circuitry from the voltage and current sensing devices, station dc supply, and control
circuitry associated with protective functions from the station dc supply through the trip
coil(s) of the circuit breakers or other interrupting devices.
3. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly
identify all protection system components it owns and needs to maintain. This is critical
since NPCC had proposed a SAR to this effect which was not accepted by NERC citing
that this concern will be incorporated in the revised standard.
July 22, 2010
19
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank you for your comments.
1. The SDT believes that the suggested text does not add to the definition, and may actually lead to additional problems,
such as an implication that the list within the definition is incomplete.
2. The SDT has modified the definition as suggested regarding voltage and current sensing inputs.
3. This issue is properly addressed within the Standard.
Progress Energy Carolinas
No
See comment associated with question 2.
Response: Thank you for your comments. Please see our response to your comment associated with question 2.
Northeast Power
Coordinating Council
No
1. Suggest adding “Protection System Components including” in the beginning. This is
because the word “components” has been used extensively throughout the standard
and there is no mention of what constitutes a protection system component in the
standard. The word “component” does find mention in FAQs, however, it is
recommended to mention it in the body of the standard.
The revised definition should read as follows: Protection System Components including
Protective relays, communication systems necessary for correct operation of protective
functions, voltage and current sensing devices providing inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station dc supply, and
control circuitry associated with protective functions from the station dc supply through
the trip coil(s) of the circuit breakers or other interrupting devices.
2. An alternative definition for Protection System to eliminate the need to capitalize
“component”:The collective components comprised of protective relays, communication
systems necessary for correct operation of protective functions, voltage and current
sensing devices providing inputs to protective relays and associated circuitry from the
voltage and current sensing devices, station dc supply, and control circuitry associated
with protective functions from the station dc supply through the trip coil(s) of the circuit
July 22, 2010
20
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
breakers or other interrupting devices.
3. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly
identify which protection system components it does own and needs to maintain. Many
DPs own and/or operate equipment identified in the existing or proposed definition.
However, not all such equipment translates into a transmission Protection System. The
definition needs clarification on when such equipment is a part of the transmission
protection system. This is critical since NPCC had proposed a SAR to this effect which
was not accepted by NERC citing that this concern will be incorporated in the revised
standard. Also, reference should be made to Project 2009-17 in which Y-W Electric
Association, Inc. (Y-WEA) and Tri-State Generation and Transmission Association, Inc.
(Tri-State) requested an interpretation of the term "transmission Protection System" and
specifically whether protection for a radially-connected transformer protection system
energized from the BES is considered a transmission Protection System and is subject
to these standards.
Response: Thank you for your comments.
1. The SDT believes that the suggested text does not add to the definition, and may actually lead to additional problems,
such as an implication that the list within the definition is incomplete.
2. The SDT believes that the suggested text does not add to the definition, and may actually lead to additional problems,
such as an implication that the list within the definition is incomplete.
3. This issue relates to the application of the standard, and is not part of the definition.
Y-W Electric Association,
Inc
July 22, 2010
No
The application of this definition to Reliability Standards NUC-001-2, PER-005-1, PRC-0011, and PRC-004-1 results in confusion as to whether relays with mechanical inputs are
included or excluded from this definition. PRC-005-2_R1 contains language limiting its
applicability to relays operating on electrical inputs only, but the remaining standards that
rely on this definition are not so specific. This being the case, it would make much more
sense to clearly define what devices are actually meant in the glossary definition rather
21
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
than leaving it up to each individual standard to do so.
Response: Thank you for your comments. The definition has been modified to specify, “Protective relays which respond to
electrical quantities”.
Arizona Public Service
Company
No
1. The change to the definition relative to the voltage and current sensing devices is too
prescriptive.
2. Methods of determining the integrity of the voltage and current inputs into the relays to
ensure reliability of the devices should be up to the discretion of the utility.
Response: Thank you for your comments.
1. The SDR modified the definition, relating to voltage and current sensing inputs, for clarity.
2. The issue regarding methods, etc, is an issue for the standard itself, not the definition.
MidAmerican Energy
Company
No
The definition is expanded and clarified in the language of PRC-005-2. These changes
should be incorporated in the definition to insure it is used consistently in PRC-005 and any
other standards where it appears.
The following is a suggested revised definition:”Protection System” is defined as: A system
that uses measurements of voltage, current, frequency and/or phase angle to determine
anomalies and to trip a portion of the BES to provide protection for the BES and consists of
1) Protective relays for BES elements and, 2) Communications systems necessary for
correct BES protection system operations and, 3) Current and voltage sensing devices
supplying BES protective relay input and, 4) Station DC supply to BES protection systems
excluding battery chargers, and 5) DC control trip paths to the trip coil(s) of the circuit
breakers or other interrupting devices for BES elements.
July 22, 2010
22
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank your for your comments.
The SDT modified the definition to address some of the suggestions. Other elements of the suggestion do not add to the
existing definition, and the SDT disagrees with the suggestions regarding “trips a portion of the BES” since Special
Protection Systems and UVLS may actually trip non-BES facilities, and with excluding battery chargers.
The Detroit Edison
Company
No
The definition should clarify whether current and voltage transformers themselves are
included.
Response: Thank you for your comments. The SDT modified the definition to state, “voltage and current sensing devices
providing inputs to protective relays”.
Avista Corp
No
The modified definition of Protection System now refers to “functions” rather than “devices.”
What are the “functions?” This new term adds confusion without being defined in the
standard.
Response: Thank you for your comments. The “functions” are the accumulated performance of the various portions of the
Protection System. This term is used to distinguish “protective functions” from annunciation, signaling, or information.
American Electric Power
No
The term "station" should either be defined or removed from the definition, as it implies
transmission and distribution assets while the term "plant" is used to define generation
assets. It would suffice to simply refer to the "DC Supply".
Response: Thank you for your comments. The term “station” is used in a generic sense to apply to either “substation” or
“generation station” facilities.
Xcel Energy
No
We recommend modifying the language to remove circuit breakers altogether: “...through
the trip coil(s) of the circuit breakers or other interrupting devices.”
Response: Thank you for your comments. The SDT believes that circuit breakers are by far the most prevalent interrupting
July 22, 2010
23
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
devices, and to generalize as suggested will lead to industry confusion.
Allegheny Power
Yes
American Transmission
Company
Yes
Bonneville Power
Administration
Yes
Clark Public Utilities
Yes
Dynegy Inc.
Yes
E.ON U.S.
Yes
Entergy Services
Yes
Exelon
Yes
Indiana Municipal Power
Agency
Yes
Manitoba Hydro
Yes
MEAG Power
Yes
Northeast Utilities
Yes
PacifiCorp
Yes
July 22, 2010
24
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Springfield Utility Board
Yes
US Bureau of Reclamation
Yes
We Energies
Yes
WECC
Yes
Western Area Power
Administration
Yes
Florida Municipal Power
Agency
Yes
Question 1 Comment
Because the definition changes the scope of what a protection system covers, increasing
that scope, the definition should not be balloted separately from PRC-005-2 so that the
industry knows what is being committed to. For instance, the circuitry connecting the
voltage and current sensing devices to the relays is a scope expansion. Station DC supply
increases the scope to include the charger, etc. This scope increase needs to have an
appropriate implementation period.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
NERC Staff
July 22, 2010
Yes
Still, to make sure the reference to dc supply is more generic than just “station dc supply,”
NERC staff suggests the following modified definition of Protection System:"Protective
relays, communication systems necessary for correct operation of protective functions,
voltage and current sensing inputs to protective relays and associated circuitry from the
voltage and current sensing devices, and any dc supply or control circuitry associated with
25
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
the preceding devices."
Response: Thank you for your comments. The SDT believes that modifying the definition as suggested does not add to the
definition.
FirstEnergy
Yes
1. The definition is ready for ballot with the addition of auxiliary relays to the definition of
protective relays. There is a potential for an entity to determine that auxiliary relays do
not perform a protection function since they typically do not sense fault current.
Furthermore, one could determine that the term "circuitry" only refers to the wiring to
connect the various DC devices together. We suggest adding "auxiliary relays
necessary for correct operation of protective devices" to improve clarity of the definition.
2. With regard to the change from the current definition phrase "station batteries" to the
new definitions phrase "station DC supply", it may not be clear to the reader that this
includes battery chargers. To alleviate future interpretation issues, we suggest adding a
clarifying statement at the end of the definition, such as "The station DC supply includes
the battery, battery charger, and other DC components".
3. The acronym "dc" should be capitalized.
Response: Thank you for your comments.
1. The SDT believes that auxiliary relays are implicitly part of the control circuitry. The Supplementary Reference as posted
in June 2010 (Section 15.3, page 22) specifically states that “the dc control circuitry also includes each auxiliary tripping
relay …”.
2. Clarifications such as this properly belong in supplementary materials. This is described in the FAQ posted in June 2010
(FAQ II.5.A).
3. The term, “dc”, rather than “DC”, reflects the NERC style guide.
ReliabilityFirst Corp.
July 22, 2010
Yes
The definition should probably include interrupting devices as the Protection System is of
26
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
little value if the fault cannot be interrupted.
Response: Thank you for your comments. Interrupting devices are not within the scope of this project.
South Carolina Electric and
Gas
Yes
The new definition effective date should be directly linked to the approval and
implementation schedule of PRC-005-2 to avoid any possible compliance issues under the
current PRC-005 standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Ameren
Yes
1. We agree that the definition provides clarity and will enhance the reliability of the
Protection Systems to which it is applicable; however, we suggest that a Glossary term
for Protective Relay be added in order to clarify in all standards inclusion of relays that
measure voltage, current, frequency and/or phase angle to determine anomalies, as
stated in PRC-005-2 R1.
2. We believe there should be a direct linkage of the definition’s effective date to the
approval and implementation schedule of PRC-005-2. Since this new definition is
directly linked to the proposed revised standard, it would be premature to make this
definition effective prior to the effective date of the new standard.
3. We agree that the voltage and current inputs at the protective relays correctly identifies
that component, that this excludes the instrument transformer itself.
4. We suggest replacing "to" with "at", and omitting "and associated circuitry from the
voltage and current sensing devices."
July 22, 2010
27
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank you for your comments.
1. Thank you. “Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC standard,
thus the SDT sees no need to either modify or duplicate that definition.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the
board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed
that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The implementation plan now
proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to
apply the new definition to PRC-005-1.
3. Based on other industry comments, the SDT has modified the definition to include these devices.
4. The SDT modified this portion of the definition to state, “voltage and current sensing devices providing inputs to
protective relays”.
SERC Protection and
Control Sub-committee
(PCS)
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection
Systems to which it is applicable; however, we believe there should be a direct linkage of
the definition’s effective date to the approval and implementation schedule of PRC-005-2.
Since this new definition is directly linked to the proposed revised standard, it would be
premature to make this definition effective prior to the effective date of the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Southern Company
July 22, 2010
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection
Systems to which it is applicable. However, we feel that there needs to be a direct linkage
28
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Transmission
Question 1 Comment
of the definition’s effective date to the approval and implementation schedule of PRC-0052. Since this new definition is directly linked to the proposed revised standard, it would be
premature to make this definition effective prior to the effective date of the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Santee Cooper
Yes
We agree with the proposed definition. However, the effective date of this definition should
be linked to the implementation schedule of PRC-005-2. This definition should not be
made effective prior to the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
July 22, 2010
29
Consideration of Comments on the Definition of Protection System — Project 2007-17
2. Do you agree with the implementation plan for the revised definition of Protection System? The
implementation plan has two phases – the first phase gives entities at least six months to update their
protection system maintenance and testing program; the second phase starts when the protection
system maintenance and testing program has been updated and requires implementation of any
additional maintenance and testing associated with the program changes by the end of the first
complete maintenance and testing cycle described in the entity’s revised program. If you disagree with
this implementation plan, please explain why.
Summary Consideration: Most commenters felt that the definition and its implementation should be linked to the approval and
implementation of the revised standard. The retirement date for the existing definition, in the Implementation Plan, was developed
upon advice of NERC Compliance staff and is intended to address a reliability gap caused by the existing definition. When the Board
of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the
reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this
reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC005-1 as soon as practical - not years from now.
Additional commenters indicated that a 6-month implementation schedule for modifying their Protection System maintenance and
testing program is insufficient. The SDT revised the first phase of the implementation plan to 12-months. The implementation plan
now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply
the new definition to PRC-005-1.
Organization
WECC
Yes or
No
Question 2 Comment
Compliance agrees only if the original “Protection System” definition is in place for the
interim implementation period, so that only the changes and or additions to the “Protection
System” definition are covered under the proposed implementation plan.
Response: Thank you for your comments. The retirement date for the existing definition, in the Implementation Plan, was
developed upon advice of NERC Compliance staff and is intended to address a reliability gap caused by the existing
July 22, 2010
30
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
No
1. The draft implementation plan general considerations have a requirement to identify all
the protection system components addressed under PRC-005-1 and PRC-005-2 for
potential audits while modifying the existing programs. The standard revision will require
extensive reviews and possibly add significant amounts of components to the program.
This is listed as a requirement without a specific deadline other than supplying the
information as part of an audit. If an audit is scheduled or announced early in the
implementation period the evidence is required. The requirement for identifying all the
components in the implementation process should have a time specified with bases for
the starting point.
definition.
Public Service Enterprise
Group ("PSEG
Companies")
2. Where additional definition of a protection system scope boundary is determined as a
result of the standard revisions, the implementation plan completion requirement should
be at the end of next maintenance interval of that added protection system component.
There may be situations where additional scope as determined by the additions or
revisions to the standard and/or supporting reference material (e.g., an auxiliary contact
input in a tripping scheme) would require going back and taking equipment out of
service to perform that one check. To keep the maintenance and outage schedules
coordinated the new requirements should be at the end of current cycles, not beginning.
Response: Thank you for your comments.
1. The posted implementation plan for the definition specifies that the program be updated by the end of the first calendar
quarter six months following regulatory approvals. This establishes the requested schedule for the definition alone.
Implementation of PRC-005-2 is discussed in the implementation plan for the standard.
2. The posted implementation plan for the definition provides for the requested implementation by specifying, “and
implement any additional maintenance and testing (required in Requirement R2 of PRC-005-1 – Transmission and
Generation Protection System Maintenance and Testing) by the end of the first complete maintenance and testing cycle
described in the entity’s program description and basis document(s) following establishment of the program changes
July 22, 2010
31
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
resulting from the revised definition”.
Ameren
No
As noted above, the implementation plan should be linked to the approval of PRC-005-2.
Since this new definition is directly linked to the proposed revised standard, it would be
premature to make this definition effective prior to the effective date of the new standard.
Otherwise, entities must address equipment, documentation, work management process,
and employee training changes needed for compliance twice within an unreasonably short
timeframe. If PRC-005-2 receives regulatory approval in 1st quarter 2011, PSMP
implementation along with this revised definition should be effective at the beginning of
2012 to coincide with the calendar year. These nine months will be needed to fully assess
and address the necessary maintenance program documentation changes, maintenance
system tool revisions, and personnel training needed to incorporate this new definition into
our program.
Response: Thank you for your comments. The retirement date for the existing definition, in the Implementation Plan, was
developed upon advice of NERC Compliance staff and is intended to address a reliability gap caused by the existing
definition. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection
system" and directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT
has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The implementation
plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time
to apply the new definition to PRC-005-1.
SERC Protection and
Control Sub-committee
(PCS)
No
As noted above, the implementation plan should be linked to the approval of PRC-005-2.
Since this new definition is directly linked to the proposed revised standard, it would be
premature to make this definition effective prior to the effective date of the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
July 22, 2010
32
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Florida Municipal Power
Agency
No
As stated in response to Question 1, it is inappropriate to change the definition of
Protection System for PRC-005-1 and the new definition should wait for the new standard.
In all honesty, the new PRC-005-2 lays out the program anyway, so, any change to the
definition needs to be accompanied by the commitment associated with that change.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
American Electric Power
No
As written, the implementation plan only specifies a time frame for entities to update their
documentation for PRC-005-1 and PRC-005-2 compliance. The implementation plan also
needs to give entities a time frame to address any required changes to their documentation
for other standards that use the term "Protection System", including but not limited to NUC001-2, PER-005-1, PRC-001-1, etc.
Response: Thank you for your comments. An assessment of the changes to the definition (posted with the first comment
period), relative to the entire body of other NERC Standards using this defined term, determined that the changes are
consistent with the other existing uses of the definition, and that no other implementation plan considerations were
necessary. No comments were received relative to this assessment.
American Transmission
Company
July 22, 2010
No
1. ATC does not agree to the implementation plan proposed. While it makes common
sense to proceed with R1 prior to proceeding with implementing R2, R3, and R4, the
timeline to be compliant for R1 is too short. It will take a considerable amount of
33
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
resources to migrate the maintenance plan from today’s standard to the new standard in
phase one. ATC recommends that time to develop and update the revised program be
increased to at least one year followed by a transition time for the entity to collect all the
necessary field data for the protection system within its first full cycle of testing. (In
ATC’s case would be 6 years) To address phase two, ATC believes human and
technological resources will be overburdened to implement this revised standard as
written. The transition to implementing the new program will take another full testing
cycle once the program has been updated. Increased documentation and obtaining
additional resources to accomplish this will be challenging.
2. Implementation of PRC-005-2 will impact ATC in the following manner: a. Increase
costs: double existing maintenance costs. b. Since there will be a doubling of human
interaction (or more), it is expected that failures due to human error will increase,
possibly proportionately. c. Breaker maintenance may need to be aligned with
protection scheme testing, which will always contain elements that are include in the
non-monitored table for 6 yr testing. d. ATC is developing standards for redundant bus
and transformer protection schemes. This would allow ATC to test the protection
packages without taking the equipment out of service. Further if one system fails, there
is full redundancy available. With the current version of PRC-005-2, ATC would need to
take an outage to test the protection schemes for a transformer or a bus, there is not an
incentive to install redundant schemes. ATC is working with a condition based breaker
maintenance program. This program’s value would be greatly diminished under PRC005-2 as currently written.
3. Consideration also needs to be given for other NERC standards expected to be passed
and in the implementation stage at the same time, such as the CIP standards.
Response: Thank you for your comments.
1. This comment appears to address implementation of the draft Standard, not the definition.
2. This comment appears to address implementation of the draft Standard, not the definition.
July 22, 2010
34
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
3. Thank you.
Duke Energy
No
Definition should be implemented concurrently with PRC-005-2.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Consumers Energy
Company
No
For entities that may not have included all elements reflected in the modified definition
within their PRC-005-1 program, 6-months following regulatory approvals may not be
sufficient to identify all relevant additional components, develop maintenance procedures,
develop maintenance and testing intervals, develop a defendable technical basis for both
the procedures and intervals, and train personnel on the newly implemented items. We
propose that a 12-month schedule following regulatory approvals may be more practical.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule as
suggested. However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
Exelon
No
PECO would like to have the implementation plan provide at least 1 year for full
implementation of the new standard. This will provide adequate time for development of
documentation, training for all personnel, and testing then implementation of the new
process(es).
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule as
suggested. However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
July 22, 2010
35
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Progress Energy Carolinas
Yes or
No
Question 2 Comment
No
Progress Energy does not believe that the definition should be implemented separately
from and prior to the implementation of PRC-005-2. We believe there should be a direct
linkage between the definition’s effective date to the approval and implementation schedule
of PRC-005-2. Since this new definition should be directly linked to the proposed revised
standard, it would be premature to make this new definition effective prior to the effective
date of the new standard. We believe that changes to the maintenance program should be
driven by the revision of the PRC standard, not by the revision of a definition.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Pepco Holdings, Inc. Affiliates
No
The 6 month time frame to update the revised maintenance and testing program is too
short. Specifically identifying and documenting each component not presently individually
identified in our maintenance databases, auxiliary relays, lock-out relays, etc. will require a
major effort. We recommend at least one year.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule as
suggested. However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
Indeck Energy Services
No
The definition should not be implemented separate from PRC-002-2. The PRC-002-2
implementation plan would be adequate.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
July 22, 2010
36
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
E.ON U.S.
No
The first phase is only 3 months (per Implementation Plan) to update the program, not the 6
months as listed in this question. E.ON U.S. recommends that it should be a minimum of 6
months, regardless.
Response: Thank you for your comments. The Implementation Plan for the definition specifically indicated a 6-month
(increased to 12-months in response to comments) implementation schedule to update the program. However, to agree with
the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the first calendar
quarter”.
Santee Cooper
No
The implementation plan should be linked to the approval of PRC-005-2. The definition
should not be made effective prior to the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Xcel Energy
No
1. The implementation plans for both the definition and standard are confusing. Does this
imply a "clean slate" approach can be used? i.e. do entities have up to the first interval
window to complete the maintenance or must they have it complete on day 1 of the
standard and again by the first interval?
2. It also appears that the implementation plans are conflicting whereby one requires full
compliance and the other allows 6 months...the definition implementation plan also refer
July 22, 2010
37
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
to a basis document though the standard does not require one.
Response: Thank you for your comments.
1. The implementation plan for the definition specifically states that the entity has until the end of the first full interval
established per their program and basis documents to implement the updated program (i.e. complete the maintenance).
2. The Implementation Plan for the definition specifically indicated a 6-month (increased to 12-months in response to
comments) implementation schedule to update the program. However, to agree with the SDT Guidelines established by
NERC, “end of the first calendar quarter” was modified to “first day of the first calendar quarter”. PRC-005-1 requires
basis documents, where PRC-005-2 (draft) does not, as maximum intervals and minimum activities are prescribed within
the standard.
Manitoba Hydro
No
The proposed implementation stage of 6 months is much too stringent and an 18 month
window is suggested.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule.
However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day
of the first calendar quarter”.
MidAmerican Energy
Company
No
The protection system definition implementation plan should be consistent with the
implementation plan of PRC-005-2 R1. Actual maintenance requirements implementation
should be as required by the PRC-005-2 implementation plan and should not be included in
the implementation plan for the protection system definition.
Response: Thank you for your comments.
Southern Company
Transmission
July 22, 2010
No
The revised definition should not be made effective until the revised PRC-005-2 is in effect.
There is no definite reliability benefit to balloting this definition prior to the revised standard.
If balloted and approved, entities would definitely have to modify their Protection System
Maintenance and Testing Program methodology, but there is no obligation to or guarantee
38
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
of any additional maintenance being performed. PRC-005-2 includes this definition, the
maintenance activities, and the intervals that will ensure execution of the maintenance and
testing.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Indiana Municipal Power
Agency
No
The second part of the implementation effective date does not make sense and might be
wrong. The second part talks about implementing any additional maintenance and testing
(required in R2 of PRC-005-1- Transmission and Generation Protection system
Maintenance and Testing); this is referring to version 1 of the standard and there should be
no additional maintenance and testing added from version 1 of the standard, just version 2
which is the new version. Overall, the wording on this implementation plan needs to be
made more clear about how the implementation plan will work.
Response: Thank you for your comments. The second part of the implementation plan for the definition allows the entity to
implement any program changes that result from the modified definition systematically via the intervals establised to address
those changes. The SDT believes that this portion of the implementation plan is clear.
US Bureau of Reclamation
July 22, 2010
No
The Time Horizons are too narrow for the implementation of the standard as written. The
SDT appears to have not accounted for the data analysis associated with performance
based systems. The data collection, analysis, and subsequent decisions associated
development of a maintenance program and its justification do not occur overnight
especially with larger utilities. In addition, this new standard will require complete rewrite of
an entities internal maintenance programs. The internal processes associated with these
vary based on the size of the entity and its organizational structure. Since this standard is
39
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
so invasive into the internal decisions concerning maintenance, the standard should allow
at least 18 months for entities to rewrite their internal maintenance programs to meet the
program development requirements and 18 months to train the staff in the new program,
incorporate the program into the entities compliance processes, and to implement the new
program.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule to
update the entities’ program in accoradnce with the modified definition.
Hydro One
No
1. The time provided for the first phase “at least six months” is too open ended and does
not give entities a clear timeline. HYDRO ONE suggests 1 year for the first phase.
2. Also, HYDRO ONE suggests phasing out the second phase in stages.
Response: Thank you for your comments.
1. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to agree with the SDT
Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the first calendar
quarter”.
2. The SDT does not understand this comment.
Long Island Power
Authority
No
1. The time provided for the first phase “at least six months” is too open ended and does
not give entities a clear timeline. LIPA suggests 1 year for the first phase.
2. It is also suggested phasing out the second phase in stages.
Response: Thank you for your comments.
1. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to agree with the SDT
Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the first calendar
quarter”.
July 22, 2010
40
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
2. The SDT does not understand this comment.
Northeast Power
Coordinating Council
No
1. The time provided for the first phase “at least six months” is too open ended and does
not give entities a clear timeline. Suggest 1 year for the first phase.
2. Suggest phasing out the second phase in stages.
Response: Thank you for your comments.
1. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to agree with the SDT
Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the first calendar
quarter”.
2. The SDT does not understand this comment.
Northeast Utilities
No
The time provided for the first phase “at least six months” is too open ended and does not
give entities a clear timeline. Northeast Utilities suggests 1 year for the first phase.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule as
suggested. However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
Grant County PUD
No
There needs to be more clarity concerning the role of the 3 year audit during the
implementation phase. Do the audit tests consist of varying proportions of -1 criteria and -2
criteria?
Response: Thank you for your comments. This comment appears to address implementation of the revised standard, not the
revised definition.
Constellation Power
Generation
July 22, 2010
No
This does not match the implementation proposed for PRC-005-2. The implementation plan
for revising the program is 6 months based on the “definition implementation” but R1 in
41
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
PRC-005-2 has a 3 month implementation plan.
Response: Thank you for your comments. The intent is to implement the definition and apply it to PRC-005-1 before PRC005-2 becomes effective. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written
by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of
"protection system" and directed that work to close this reliability gap should be given “priority.” To close this reliability gap
the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should
give entities time to apply the new definition to PRC-005-1.
The Detroit Edison
Company
No
This implementation plan and the one for PRC-005-2 should be consistent.
Response: Thank you for your comments. The intent is to implement the definition and apply it to PRC-005-1 before PRC005-2 becomes effective. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written
by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of
"protection system" and directed that work to close this reliability gap should be given “priority.” To close this reliability gap
the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should
give entities time to apply the new definition to PRC-005-1.
Entergy Services
No
1. We agree with the definition, however we do not agree with the implementation plan.
We believe implementation of the definition needs to coincide with the implementation
of Standard PRC-005-2. To do otherwise, will cause entities to address equipment,
documentation, work management process, and employee training changes needed for
compliance twice within an unreasonably short timeframe.
2. Additional time, 12 months minimum, will be needed to fully assess and address the
necessary maintenance program documentation changes, maintenance system tool
revisions, and personnel training needed to incorporate this new definition into our
July 22, 2010
42
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
program.
Response: Thank you for your comments.
1. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the
board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed
that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The implementation plan now
proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to
apply the new definition to PRC-005-1.
2. The Implementation Plan for the definition has been modified to allow a 12-month schedule as suggested. However, to
agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the
first calendar quarter”.
Clark Public Utilities
No
1. While the drafting team has done a great job of simplifying the implementation plan from
the original draft 1 language, the current language has some ambiguities. I do not
understand what the term “the end of the first calendar quarter six months following
regulatory approvals” means. What is wrong with just saying “within nine months (or six
months or twelve months) following regulatory approvals? Using the current language I
would be inclined to assume it is six months so I can avoid a dispute (and quite possibly
a notice of alleged violation) over a date.
2. Also, I am not sure what the term “the end of the first complete maintenance and testing
cycle described in the entity’s program description” means. It is quite likely that a
registered entity will make the required definition change to its maintenance program (at
approximately six months) and wind up with devices that need to be tested. Is the
implementation plan attempting to provide some allowed time delay so the registered
entity will not be out of compliance even though it has devices that are now beyond the
maximum testing interval due to the definition change? The existing language implies
that within approximately six months of regulatory approval, the maintenance program
needs to be changed to incorporate the revised definition for Protection System.
July 22, 2010
43
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
However, the effective date for the revised maintenance program is going to be some
date that corresponds with the end of the first complete maintenance and testing cycle
in that program. I really don’t understand what that time period is and I believe the
drafting team needs to put in something that clears up this confusion. By testing cycle
do you mean “maximum interval” as shown in the PRC-005 table? Do you mean the
“maximum interval” that a registered entity includes in their maintenance program? If
so, do you intend the implementation to be a different date for protection devices
depending on the maximum testing interval? Or do you envision some date beyond the
six months where the entire maintenance program (with the definition change) becomes
effective and any registered entities with out-of-compliance issues would need to file
mitigation plans?
Response: Thank you for your comments.
1. Within the US, NERC Standards are not mandatory and enforceable until approval by FERC. As established within the
NERC Drafting Team Guidelines, the effective dates must be “the first day of the first calendar quarter after entities are
expected to be compliant”. The effective dates are always on the first day of a calendar quarter to make it easier for
entities to track the effective dates of requirements. To agree with the SDT Guidelines established by NERC, “end of the
first calendar quarter” was modified to “first day of the first calendar quarter”.
2. Continuing on the example above, if an entity then establishes a 3-calendar-year schedule for additional components as
addressed by the definition, the entity must be fully compliant by the end of 2014.
We Energies
No
Wisconsin Electric does not agree with the six-month implementation requirement in the
first phase. It is our position that a longer adjustment time is needed for entities to update
their maintenance programs to implement the new definition. The new definition results in
a significant increase in the scope of affected equipment and the documentation required to
implement the program, and requires additional resources beyond present levels, including
hiring and training. We estimate that this effort will require three years to fully implement.
Response: Thank you for your comments. The Implementation Plan for the definition has been modified to allow a 12-month
July 22, 2010
44
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
schedule to update the program. The entity then has the full interval as established within their program to implement the
program for added components.
Allegheny Power
Yes
Arizona Public Service
Company
Yes
Avista Corp
Yes
Bonneville Power
Administration
Yes
Dynegy Inc.
Yes
FirstEnergy
Yes
Lincoln Electric System
Yes
MEAG Power
Yes
NERC Staff
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PacifiCorp
Yes
PNGC Power
Yes
July 22, 2010
45
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
ReliabilityFirst Corp.
Yes
South Carolina Electric and
Gas
Yes
Springfield Utility Board
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Inc
Yes
July 22, 2010
Question 2 Comment
46
Consideration of Comments on Non-binding Poll of VRFs and VSLs associated with PRC-005-2 – Protection
System Maintenance
The PRC-005 Standard Drafting Team thanks all those who participated in non-binding poll for the VRFs and VSLs associated with
PRC-005-2. The initial non-binding poll was conducted from July 8 through July 17, 2010 and achieved a quorum with 85.96 % of the
ballot pool members returning an opinion, and with 32.29 % of those indicating support for the proposed VRFs and VSLs.
Many commenters proposed that the VSLs allow for some amount of non-compliance with the Standard before incurring a violation.
NERC’s guidelines for VSLs do not allow some level of non-performance without being in violation. The SDT did, however, modify
the VSLs for Requirements R1 and R4 to provide gradated VSLs.
Some commenters suggested the SDT re-evaluate the VRF assignments. The SDT reconsidered the VRFs in accordance with the
guidance provided by NERC and FERC, and modified the Standard to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium,
and R4 – High. Some commenters made comments that appeared to be related to the technical content of the Standard, not to the
VRFs or VSLs and these comments were addressed in the report containing responses to comments on the standard. All comments
submitted have been publicly posted on the following web page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process! If you feel there has been an error or omission, you can contact the Vice President and Director of
Standards, Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
November 17, 2010
1
Segment:
Organization:
Member:
3, 4, 5
Cowlitz County PUD
Russell A Noble, Rick Syring, Bob Essex
Comment:
Cowlitz does not understand a High VRF designation for requirement R1; this should be a Low or Medium
designation. R1 is merely covering a maintenance program, not the actual maintenance. Actual missed
maintenance of components (requirement R4) should have the Medium or High VRF. This Standard is very
descriptive of minimum maintenance intervals on each “component;” thus, it is possible to have maintenance
documentation that is in full compliance once the Program is built around it. It should never be a case where
an entity can receive a higher VRF over missing documentation of a process, and then a lower VRF over
missing documentation of the implementation of the process.
Response:
The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and the
Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 –
High.
Segment:
Organization:
Member:
Comment:
1
United Illuminating Co.
Jonathan Appelbaum
The VRF for R1 should be Low. It is administrative to create an inventory list. If R1 failed to be executed but
the other requirements wee executed fully then the BES would be properly secured. Compare this against the
scenario of performing R1 but failing to perform the other tasks; in which case the BES is at risk. UI
recognizes that the SDT considers the inventory as the foundation of the PSMP but it is not the element of the
PSMP that provides for the level of reliability sought.
R1 should be VRF Low and R2 thru R4 VRF is Medium.
UI agrees with the Time Horizon.
Response:
November 17, 2010
The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and the
Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 –
High.
2
Segment:
Organization:
Member:
1, 3, 4, 5, 6
FirstEnergy Energy Delivery, FirstEnergy Solutions, Ohio Edison Company, FirstEnergy Solutions,
FirstEnergy Solutions
Robert Martinko, Kevin Querry, Douglas Hohlbaugh, Kenneth Dresner, Mark S Travaglianti
Comment:
FirstEnergy appreciates the hard work of the drafting team, but unfortunately we must cast a Negative vote for
the VRF for Requirement R1. Although we agree that Requirement 1 is important because it establishes a
sound PSMP, a HIGH VRF assignment is not appropriate and it should be changed to LOWER. By definition,
a requirement with a LOWER VRF is administrative in nature, and documentation of a program is
administrative. Assigning a LOWER VRF to R1 is more logical since R4, which is the requirement to
implement the PSMP, is assigned a MEDIUM VRF because, if violated, it could directly affect the electrical
state or the capability of the bulk electric system.
Response:
The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and the
Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 –
High.
Segment:
Organization:
Member:
1
Ameren Services
Kirit S. Shah
Comment:
The Lower VSL for all Requirements should begin above 1% of the components.
Response:
The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
Segment:
Organization:
Member:
Comment:
November 17, 2010
5
Constellation Power Source Generation, Inc.
Amir Y Hammad
In general, the VSLs are completely biased against small generating facilities that may have only 20 or 30
components to their protective system. If a facility with only 30 components were to fail to identify 2
components, then that would automatically fall under a moderate VSL. This is true for R1 and R4. A
suggestion would be to eliminate the percentage of components and instead focus on what the violation is. For
example, for R1, a lower VSL could state “the entity’s PSMP includes all of the ‘types’ of components
included in the definition of ‘Protection System’, but failed to specify whether a component is being addressed
3
by time-based, condition-based, or performance-based maintenance.
Response:
Segment:
Organization:
Member:
The SDT believes the stepped VSLs are not biased against small entities.
5
Liberty Electric Power LLC
Daniel Duff
Comment:
Voting no due to a no vote on the standard, as well as a disagreement with the percentage concept. Smaller
entities will have a higher violation level for the same offense due to fewer chances for a violation.
Response:
The SDT believes the stepped VSLs are not biased against small entities.
Segment:
Organization:
Member:
Comment:
5, 6
Tennessee Valley Authority
George T. Ballew, Marjorie S. Parsons
The reason for the no vote on the Non-Binding Poll for VRFs and VSLs is the Violation Severity Level Table
listing for Requirement R4 lists the following under “Severe VSL”. “Entity has failed to initiate resolution of
maintenance-correctable issues”
The threshold for a Severe Violation in this case is too broad and too subjective. The threshold needs to be
clearly defined with low, medium, and high criteria. This feedback has been added to the NERC Standards
Under Development Comment webpage.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
The VSL for Requirement R4 has been modified to provide a stepped VSL for initiation of resolution of
maintenance correctable issues.
1
Duke Energy Carolina
Douglas E. Hils
We appreciate the work of the team however we do not agree with some of the text proposed. The VSLs for
PRC-005-2 requirements R1, R2 and R4 have significantly tighter percentages than the corresponding
requirements in PRC-005-1.
We believe that the Lower VSL should be up to 10%, the Moderate VSL should be 10%-15%, the High VSL
should be 15% to 20%, and the Severe VSL should be greater than 20%, which is still a lower percentage than
4
the 25% Lower VSL currently in PRC-005-1.
Response:
Segment:
Organization:
Member:
Comment:
The percentages for the stepped VSLs were established in accordance with the NERC VSL Guidelines which
were in turn established pursuant to the FERC VSL Order. The current approved PRC-005-1 preceded these
guidelines, and therefore is not in accordance with them.
5
U.S. Bureau of Reclamation
Martin Bauer
The intervals in the standard are based on the weighted average practice of entities surveyed. The weighted
average practice was the result of a requirement to have a documented program. The intervals did not have
demonstrated relationship to reliability of the BES. This nullifies the requirements and subsequent VSL's.
1. The VSL's use terms that are not tied back to a requirement and appear to be based on the concept that
every component will cause an impact on the BES. The VSL's use the term "countable event" to score the
VSL; however, there is no requirement associated with the number of "countable events".
2. The VSL's should allow for minor gaps in maintenance documentation where there is no impact to the BES
if the component failed.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
1. The SDT disagrees that the VSLs are not tied back to a requirement. R3 refers to Attachment A for the
criteria for a performance based program, which establishes criteria for the percentage of countable events
allowed for the components in any specific designated segment.
2. “Minor gaps in maintenance documentation” would seem to be within the description of a Lower VSL; the
NERC criteria for VSLs do not currently permit them to allow some “gaps” without being in violation. The
VSL for Requirement R4 has been modified to provide a stepped VSL for initiation of resolution of
maintenance correctable issues.
1
Georgia Transmission Corporation
Harold Taylor, II
1. As the current requirements are written in R1 of PRC-005-2 Draft, we disagree with the terms identify all
Protection System components. We recommend a less prescriptive requirement as listed below.
R1.1 Identify BES substations or facilities containing Protection Systems.
5
R1.2 Identify whether Protection Systems per substation or facilities are addressed through time-based,
condition-based, performance based or a combination based etc.
R1.3 For each substation/facility with Protection Systems, include all maintenance activities etc.
2. The VRF for R1 ranking should be lower or no greater than R2, R3, and R4. The task of identifying
Protection System components has very little to do with increasing reliability of the BES. The implementation
of the PSMP most likely will cover all the specific functions of Protection System components although the
entity failed to identify all PS components.
3. We recommend the above language changes and agree the requirement adds some value but not a high-risk
value to the BES. After correcting the language we feel that a requirement of 100% maintenance on 100% of
all components as listed on page 6 of the standard for the VSLs leaves no room for error for systems designed
with contingences. The violations should start for more than a level of 5% not identified, not maintained, etc.
Response:
Segment:
Organization:
Member:
1. This appears to be a comment related to the standard content, not the VRFs and VSLs.
2. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and
the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 –
High.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
1, 3
National Grid, Niagara Mohawk (National Grid Company)
Saurabh Saksena, Michael Schiavone
Comment:
National Grid does not support the VSL criteria based on "total number of components". Calculating total
number of components will be hugely costly and does not enhance any reliability. It will also take away the
much needed resources required for maintenance.
Response:
The SDT believes establishing multiple levels within the VSL is preferable to assigning only a Severe VSL;
consequently, a method of measuring relative performance must exist, and determining the quantity of
components is a necessity.
Segment:
Organization:
November 17, 2010
1, 3, 3, 3, 3, 5
Southern Company Services, Inc., Georgia Power Company, Gulf Power Company, Mississippi Power,
6
Alabama Power Company, Southern Company Generation
Member:
Horace Stephen Williamson, Anthony L Wilson, Gwen S Frazier, Don Horsley, Richard J. Mandes, William
D Shultz
Comment:
If an entity is not able to reasonably quantify which components are in scope, demonstrating compliance on a
percent-basis may prove difficult or impossible. Further review may indicate the need to reformat the VSL.
Response:
The SDT believes establishing multiple levels within the VSL is preferable to assigning only a Severe VSL;
consequently, a method of measuring relative performance must exist, and determining the quantity of
components is a necessity.
Segment:
Organization:
Member:
3
Allegheny Power
Bob Reeping
Comment:
The draft standard expects 100% compliance for millions of protection system components at all times. The
standard should consider a statistically based performance metric instead of a performance target that expects
100% compliance.
Response:
The SDT shares your concerns regarding the Lower VSL portion of the stepped VSLs not providing any
tolerance for non-conformance without being non-compliant. However, the VSL Guidelines, which conform
to the FERC VSL order, specify that Lower shall be “5% or less.”
Segment:
Organization:
Member:
5
AEP Service Corp.
Brock Ondayko
Comment:
AEP has stated in other projects, setting a VSL at “Severe” for a binary outcome could be challenged as being
arbitrary and another level should be used as the starting point.
Response:
The NERC VSL Guidelines, which were established pursuant to the FERC VSL Order, specify that Severe
VSLs be assigned for binary outcomes.
Segment:
Organization:
Member:
November 17, 2010
3, 4
Georgia System Operations Corporation
R Scott S. Barfield-McGinnis, Guy Andrews
7
Comment:
1. Do not agree with the 3 calendar months interval and suggest using quarterly. Both terms require a
minimum of four inspections per year have proven to be successful, but the term “quarterly” provides a bit
more flexibility than the term “3 calendar months”. Given a 3 month maximum interval an entity would
need to schedule these tasks every 2 months. As the current requirements are written in R1 of PRC-005-2
Draft, we disagree with the terms identify all Protection System components. We recommend a less
prescriptive requirement as listed below. -R1.1 Identify BES substations or facilities containing Protection
Systems. -R1.2 Identify whether Protection Systems per substation or facilities are addressed through timebased, condition-based, performance based or a combination based etc. -R1.3 For each substation/facility
with Protection Systems include all maintenance activities etc.
2. The VRF for R1 ranking should be lower or no greater than R2, R3, and R4. The task of identifying
Protection System components has very little to do with increasing reliability of the BES. The
implementation of the PSMP most likely will cover all the specific functions of Protection System
components although the entity failed to identify all PS components. We recommend the above language
changes and agree the requirement adds some value but not a high-risk value to the BES.
2. After correcting the language we feel that a requirement of 100% maintenance on 100% of all components
as listed on page 6 of the standard for the VSLs leaves no room for error for systems designed with
contingences.
3. The violations should start for more than a level of 5% not identified, not maintained, etc. Listing each
individual Protection System component as current draft is onerous and impedes any interpretation of
application with very little value.
4. The standard as written will require a great deal of effort by the utilities to maintain 100% compliance as
listed. The concern is the power system design allows for some contingencies but the standard allows for no
errors. Failing to complete 1% of the maintenance by 1 day infers an entity is out of compliance or in
violation.
5. The violations should start for more than a level of 5% not identified, or not maintained. We feel the minor
changes of wording as described in R1.1 – R1.3 as listed above will go a long way in removing the concerns
of the standard. We feel the intent of the standard is sound and request minor changes to facilitate an
interpretable standard that sensibly mitigates problems with the BES. As the standard written, the
November 17, 2010
8
interpretation seems to create a stringent environment with undue compliance requirements.
6. Lastly, the SDT should attempt to embrace Gerry Cauley’s vision of “results-based standards” and clearly
identify the “risk mitigation objectives, reliability result or outcome” of the revised requirements and allow
each entity to meet the outcome and mitigate the risk without writing in such a prescriptive manner which is
not preferred. The prescriptive details currently proposed in the standard could then be captured in a
reference document.
Response:
Segment:
Organization:
Member:
1. This comment appears be related to the technical content of the standard and not on the VRFs or VSLs.
2. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and
the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4
– High.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
4. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
5. The SDT believes establishing multiple levels within the VSL is preferable to assigning only a Severe VSL;
consequently, a method of measuring relative performance must exist, and determining the quantity of
components is a necessity.
6. This comment appears to be related to the standard itself, not to the VRFs or VSLs.
1
Tennessee Valley Authority
Larry Akens
Comment:
The VSL Table listing for Requirement R4 list the following under Severe VSL: "Entity has failed to initiate
resolution of maintenance-correctable issues" The threshold for a Severe Violation in this case is too broad
and too subjective. The threshold needs to be clearly defined with low, medium, and high criteria.
Response:
The VSL for Requirement R4 has been modified to provide a stepped VSL for initiation of resolution of
maintenance correctable issues.
Segment:
Organization:
Member:
November 17, 2010
3, 5, 6
Entergy, Entergy Corporation, Entergy Services, Inc.
Joel T Plessinger, Stanley M Jaskot, Terri F Benoit
9
Comment:
Entergy provides the following reasons for our Negative Ballot. Entergy reserves the right, after review of all
the submitted ballots, to join with other balloters, whether positive or negative ballots, where any reasons
included in their ballot that may be applicable to or otherwise impact Entergy as related to this ballot.
1. The VSLs for R1 is “Failure to specify whether a component is being addressed by time-based, conditionbased, or performance-based maintenance” by itself is a documentation issue and not an equipment
maintenance issue. We recommend this warrants only a Lower VSL, especially when one of the required
components can only be time based.
2. We also recommend the VSLs for R4 be revised to be stepped from Lower to Severe for “Entity has failed
to initiate resolution of maintenance-correctable issues”. While we understand the importance of
addressing a correctable issue, it seems like there should be some allowance for an isolated unintentional
failure to address a correctable issue. If possible, consider the potential impact to the system. For example,
a failure to address a pilot scheme correctable issue for an entity that only employs pilot schemes for
system stability applications should not necessarily have the same VSL consequence as an entity which
employs pilot schemes everywhere on their system as a standard practice.
Response:
Segment:
Organization:
Member:
1. This portion of the VSL for Requirement R1 has been modified to provide a stepped VSL relating to the
number of Component Types that are not addressed by time-based, condition-based, or performance-based
maintenance.
2. The VSL for Requirement R4 has been modified to provide a stepped VSL for initiation of resolution of
maintenance correctable issues.
1
Pacific Gas and Electric Company
Chifong L. Thomas
Comment:
We cannot vote affirmative on the VRFs and VSLs until concerns on the proposed standard have been
addressed.
Response:
Thank you.
Segment:
Organization:
Member:
November 17, 2010
1, 3
Platte River Power Authority
John C. Collins, Terry L Baker
10
Comment:
Because of the recommended NO vote on the standard, it would not make sense to approve the proposed
VRFs and VSLs until such time the requirements of the standard are clarified.
Response:
Thank you.
Segment:
Organization:
Member:
1
Public Service Company of New Mexico
Laurie Williams
Comment:
Because of the NO vote on the standard, it would not make sense to approve the proposed VRFs and VSLs
until such time that the requirements of the standard are clarified.
Response:
Thank you.
Segment:
1
Organization:
Xcel Energy, Inc.
Member:
Gregory L Pieper
Comment:
Xcel Energy believes the standard still contains many aspects that are not clearly understood by entities,
including what is needed to demonstrate a compliant PSMP. Comments have been submitted concurrently to
NERC via the draft comment response form.
Response:
Thank you.
Segment:
Organization:
Member:
2
Midwest ISO, Inc.
Jason L Marshall
Comment:
We are abstaining because a number of our stakeholders have concerns regarding the definition of Protection
System and inclusion of UVLS and UFLS in a standard dealing with maintenance of protection systems.
Response:
Thank you.
Segment:
Organization:
Member:
Comment:
November 17, 2010
5
Pacific Gas and Electric Company
Richard J. Padilla
We cast a negative ballot due to a negative vote on the standard and recommend that the VRFs and VSLs be
11
addressed after the standard comments are resolved
Response:
Segment:
Organization:
Member:
Thank you.
10
Western Electricity Coordinating Council
Louise McCarren
Comment:
Do not agree with all of the requirements of the current proposed standard, so will not vote to approve
associated VRFs and VSLs
Response:
Thank you.
Segment:
Organization:
Member:
3
Central Lincoln PUD
Steve Alexanderson
Comment:
Too early to approve the VRFs and VSLs since the requirements need to be fixed first.
Response:
Thank you.
Segment:
Organization:
Member:
1
American Electric Power
Paul B. Johnson
Comment:
AEP has comments regarding the current requirements and measures that need to be addressed, so comments
on VSLs are irrelevant at this time.
Response:
Thank you.
Segment:
6
Organization:
AEP Marketing
Member:
Edward P. Cox
Comment:
AEP has comments regarding the current requirements and measures that need to be addressed.
Response:
Thank you.
Segment:
November 17, 2010
1
12
Organization:
Member:
BC Transmission Corporation
Gordon Rawlings
Comment:
Not prepared to vote affirmative until such time as BC Hydro can support Project 2007-17 PRC-005-2
Response:
Thank you.
Segment:
Organization:
Member:
3
City of Bartow, Florida
Matt Culverhouse
Comment:
The proposed draft opens the standard up to regulate DC circuit testing on distribution elements with no
significant improvement to BES reliability.
Response:
This appears to be a comment on the technical content of the standard, not on the VRFs or VSLs.
Segment:
Organization:
Member:
3
Tri-State G & T Association Inc.
Janelle Marriott
Comment:
Clarification is needed to address the potentially onerous implementation, administration, audit of the
proposed revisions.
Response:
Without details of your concern, the SDT is unable to respond.
Segment:
Organization:
Member:
3
Consolidated Edison Co. of New York
Peter T Yost
Comment:
There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate equipment
identified in the existing or proposed definition. However, not all such equipment translates into a
transmission Protection System. The definition needs clarification on when such equipment is a part of the
transmission protection system. Also, the time provided for the first phase "at least six months" is too open
ended and does not provide entities with a clear timeline. It is suggested that one year is appropriate for the
first phase phasing out the second year in stages.
Response:
This appears to be a comment on the technical content of the standard, definition, and Implementation Plan,
November 17, 2010
13
not on the VRFs or VSLs.
Segment:
Organization:
Member:
2
New York Independent System Operator
Gregory Campoli
Comment:
There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate
equipment identified in the existing or proposed definition. However, not all such equipment translates into
a transmission Protection System. The definition needs clarification on when such equipment is a part of
the transmission protection system. Also, the time provided for the first phase "at least six months" is too
open ended and does not provide entities with a clear timeline. It is suggested that one year is appropriate
for the first phase phasing out the second year in stages. Regarding battery visuals, the suggestion for
consideration is it should be changed from 3 months to 6 months. Electrolyte levels of today's lead-calcium
batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past.
The Implementation plan is too short - In many instances it will be impossible to meet, especially if entities
have to create, purchase and adopt new databases to track maintenance activities. Often new procedures
will have to be written and additional resources justified and hired. It would be more acceptable if a staged
approached was taken similar to the DME Standard. Accounting for every component of a protection
system will be an enormous overhead and will take away resources from actually doing maintenance.
Emphasis should be on systems and not individual components.The Standard does not provide a grace
period if an entity is unable to meet the maintenance requirement for extenuating circumstances. For
example if an entity has to divert maintenance resources to storm restoration following a major event, slack
built into a maintenance program can be eaten up and put the maintenance over the prescribed period.
Provision should be made for a mitigation plan to get back on track. We do not believe the reliability of the
Bulk Electric System will be compromised if an entities' maintenance program slips by a few months due
to extreme contingencies, especially if it is brought back on track within a short time frame.
Response:
These comments appear to be related to the technical content of the standard, definition, and Implementation
Plan, not on the VRFs or VSLs.
Segment:
4, 5
Organization:
Florida Municipal Power Agency
Member:
Frank Gaffney, David Schumann
November 17, 2010
14
Comment:
November 17, 2010
FMPA recommends a negative vote on PRC-005-2, Project 2007-17, for three significant reasons
1. As written, it opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard as explained by Steve
Alexanderson in a prior e-mail to the ballot pool. The draft standard would cause NERC to regulate through
the standards battery testing, DC circuit testing, etc. on distribution elements with no significant
improvement to BES reliability, which is beyond the statutory scope of the standards
2. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components. Will the Standard Introduce Technical Feasibility Exceptions to PRC
Standards? As described by Steve Alexanderson in a prior e-mail to the ballot pool, a large proportion of the
batteries (as high as 50% as reported by some SMEs) are not able to accommodate all of the tests prescribed
in the draft standard. Will this necessitate the introduction of TFEs into the process unnecessarily? The
Standard Reaches Beyond the Statutory Scope of the Reliability Standards As written, the standard requires
testing of batteries, DC control circuits, etc., of distribution level protection components associated with
UFLS and UVLS. UFLS and UVLS are different than protection systems used to clear a fault from the BES.
An uncleared fault on the BES can have an Adverse Reliability Impact and hence; the focus on making sure
the fault is cleared is important and appropriate. However, a UFLs or UVLS event happens after the fault is
cleared and is an inexact science of trying to automatically restore supply and demand balance (UFLS) or
restore voltages (UVLS) to acceptable levels. If a few UFLS or UVLS relays fail to operate out of
potentially thousands of relays with the same function, there is no significant impact to the function of
UFLS or UVLS. Hence, there is no corresponding need to focus on every little aspect of the UFLS or UVLS
systems. Therefore, the only component of UFLS or UVLS that ought to be focused on in the new PRF-005
standard is the UFLS or UVLS relay itself and not distribution class equipment such as batteries, DC control
circuitry, etc., and these latter ought to be removed from the standard. In addition, most distribution circuit
are radial without substation arrangements that would allow functional testing without putting customers out
of service while the testing was underway, or at least without momentary outages while customers were
switched from one circuit to another. Therefore, as written, we would be sacrificing customer service for a
negligible impact on BES reliability. Perfection is Not A Realistic Goal The standard allows no mistakes.
Even the famous six sigma quality management program allows for defects and failures (i.e., six sigma is
six standard deviations, which means that statistically, there are events that fall outside of six standard
deviations). PRC-005 has been drafted such that any failure is a violation, e.g., 1 day late on a single relay
test of tens of thousands of relays is a violation. That is not in alignment with worldwide accepted quality
management practices (and also makes audits very painful because statistical, random sampling should be
the mode of audit, not 100% review as is currently being done in many instances). FMPA suggests
15
considering statistically based performance metrics as opposed to an unrealistic performance target that does
not allow for any failure ever. Due to the shear volume of relays, with 100% performance required, if the
standards remain this way, PRC-005 will likely be in the top ten most violated standards for the forever.
There is a fundamental flaw in thinking about reliability of the BES. We are really not trying to eliminate
the risk of a widespread blackout, we are trying to reduce the risk of a widespread blackout. We plan and
operate the system to single and credible double contingencies and to finite operating and planning reserves.
To eliminate the risk, we would need to plan and operate to an infinite number of contingencies, and have
an infinite reserve margin, which is infeasible. Therefore, by definition, there is a finite risk of a widespread
blackout that we are trying to reduce, not eliminate, and, by definition, by planning and operating to single
and credible double contingencies and finite operating and planning reserves, we are actually defining the
level of risk from a statistical basis we are willing to take. With that in mind, it does not make sense to
require 100% compliance to avoid a smaller risk (relays) when we are planning to a specified level of risk
with more major risk factors (single and credible double contingencies and finite planning and operating
reserves).
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
1. This comment appears to be related to the technical content of the Standard, not on the VRFs or VSLs.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation. Much of this comment appears to be related to the technical content of the
standard, not on the VRFs or VSLs.
1
Lake Worth Utilities
Walt Gill
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit testing,
etc. on distribution elements with no significant improvement to BES reliability, which is beyond the
statutory scope of the standards
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components. Will the Standard Introduce Technical Feasibility Exceptions to PRC
Standards? a large proportion of the batteries (as high as 50% as reported by some SMEs) are not able to
accommodate all of the tests prescribed in the draft standard. Will this necessitate the introduction of TFEs
into the process unnecessarily? The Standard Reaches Beyond the Statutory Scope of the Reliability
16
Standards As written, the standard requires testing of batteries, DC control circuits, etc., of distribution level
protection components associated with UFLS and UVLS. UFLS and UVLS are different than protection
systems used to clear a fault from the BES. An uncleared fault on the BES can have an Adverse Reliability
Impact and hence; the focus on making sure the fault is cleared is important and appropriate. However, a
UFLs or UVLS event happens after the fault is cleared and is an inexact science of trying to automatically
restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable levels. If a few UFLS
or UVLS relays fail to operate out of potentially thousands of relays with the same function, there is no
significant impact to the function of UFLS or UVLS. Hence, there is no corresponding need to focus on
every little aspect of the UFLS or UVLS systems. Therefore, the only component of UFLS or UVLS that
ought to be focused on in the new PRF-005 standard is the UFLS or UVLS relay itself and not distribution
class equipment such as batteries, DC control circuitry, etc., and these latter ought to be removed from the
standard. In addition, most distribution circuit are radial without substation arrangements that would allow
functional testing without putting customers out of service while the testing was underway, or at least
without momentary outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES reliability. Perfection is
Not A Realistic Goal The standard allows no mistakes. Even the famous six sigma quality management
program allows for defects and failures (i.e., six sigma is six standard deviations, which means that
statistically, there are events that fall outside of six standard deviations). PRC-005 has been drafted such
that any failure is a violation, e.g., 1 day late on a single relay test of tens of thousands of relays is a
violation. That is not in alignment with worldwide accepted quality management practices (and also makes
audits very painful because statistical, random sampling should be the mode of audit, not 100% review as is
currently being done in many instances). FMPA suggests considering statistically based performance
metrics as opposed to an unrealistic performance target that does not allow for any failure ever. Due to the
shear volume of relays, with 100% performance required, if the standards remain this way, PRC-005 will
likely be in the top ten most violated standards for the forever. There is a fundamental flaw in thinking
about reliability of the BES. We are really not trying to eliminate the risk of a widespread blackout, we are
trying to reduce the risk of a widespread blackout. We plan and operate the system to single and credible
double contingencies and to finite operating and planning reserves. To eliminate the risk, we would need to
plan and operate to an infinite number of contingencies, and have an infinite reserve margin, which is
infeasible. Therefore, by definition, there is a finite risk of a widespread blackout that we are trying to
reduce, not eliminate, and, by definition, by planning and operating to single and credible double
contingencies and finite operating and planning reserves, we are actually defining the level of risk from a
statistical basis we are willing to take. With that in mind, it does not make sense to require 100%
November 17, 2010
17
compliance to avoid a smaller risk (relays) when we are planning to a specified level of risk with more
major risk factors (single and credible double contingencies and finite planning and operating reserves).
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
1. This comment appears to be related to the technical content of the standard, not on the VRFs or VSLs.
2. This comment appears to be related to the technical content of the standard, not on the VRFs or VSLs.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation. Much of this comment appears to be related to the technical content of the Standard, not
on the VRFs or VSLs.
4
Wisconsin Energy Corp.
Anthony Jankowski
see comments on standard
Please refer to the SDT responses to your comments on the comment form.
5
Consumers Energy
James B Lewis
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided,
Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented.
Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead
to provide operating flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will be very
cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely
lead to entities NOT installing the redundant schemes, resulting in decreased reliability.
2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include
sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply),
what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not
present.” Similarly, it isn’t clear from the general description within the Tables that components possessing
different monitoring attributes within a single scheme, may be distinguished such that differing relevant
tables can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can
18
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.
Battery assemblies supplied by some manufacturers have the connections made internally, making this
option unavailable. Experience with ASME standards show that NERC and SDT members may be jointly
and separately liable for litigation by specifying methods that either prefer or prohibit use of certain
technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“ conclude
with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
such activities therefore require tripping of circuit breakers or other interrupting devices? 5. Performance of
the minimum activities specified within Table 1a for legacy systems, particularly regarding control circuits,
will require considerable disconnection and reconnection of portions of the circuits. Such activities will
likely cause far more problems on restoration-to-service than they will locate and correct. We suggest that
the SDT reconsider these activities with regard for this concern.
5. We do not agree that Footnotes within the Standard are an appropriate method of providing information that
is important to the application of the Standard. Important information should be provided within the
standard text.
6. As for the definition, it is unclear whether “voltage and current sensing inputs” include the instrument
transformer itself, or does it pertain to only the circuitry and input to the protective relays.
7. As for the definition, it is not clear what is included in the component, “station dc supply” without referring
to other documents (the posted Supplementary Reference and/or FAQ) for clarification. The definition
should be sufficiently detailed to be clear.
8. If Protection Systems trip via AC methods, are those systems, and the associated control circuitry included
in the definition and within the requirements of the Standard as expressed within the Tables?
Response:
Segment:
Organization:
Member:
These comments all appear to be related to the technical content of the Standard and to the definition, not to
the VRFs or VSLs.
1, 3, 5, 6
Kansas City Power & Light Co.
Mike Gammon, Charles Locke, Scott Heidtbrink, Thomas Saitta
Comment:
The proposed changes in the Standard are far too prescriptive and do not take into account the multitude of
manufacturers' equipment by establishing broad maintenance cycles and testing intervals.
Response:
This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
Segment:
November 17, 2010
5
19
Organization:
Member:
Salt River Project
Glen Reeves
Comment:
SRP believes the requirements of the Standard are confusing and may be problematic in determining
compliance. We also believe the required functional testing of the breaker trip coil may potentially increase
maintenance outages of circuit breakers. In most cases, circuit breaker maintenance outages can be
coordinated such that Protection System maintenance and testing can be done simultaneously. However, in
some cases this may not be possible. Outages of any BES facility whether planned or unplanned can impact
system reliability. SRP suggests that trip coil monitoring devices be included as an acceptable means of
ensuring the trip coil is functioning properly. This will help to avoid unnecessary outages.
Response:
This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
Segment:
Organization:
Member:
6
Seattle City Light
Dennis Sismaet
Comment:
Functional testing is impractical.
Response:
This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
Segment:
Organization:
Member:
1
Keys Energy Services
Stan T. Rzad
Comment:
1. As written, it opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard. The draft standard would cause
NERC to regulate through the standards battery testing, DC circuit testing, etc. on distribution elements with
no significant improvement to BES reliability, which is beyond the statutory scope of the standards
2. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components.
Response:
1. This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation. Much of this comment appears to be related to the technical content of the Standard, not
on the VRFs or VSLs.
November 17, 2010
20
Segment:
Organization:
Member:
1
PPL Electric Utilities Corp.
Brenda L Truhe
Comment:
PPL EU is voting negative because Requirement 1.1 "Identify all Protection System components" is too broad
and must be clarified and the definition of Protective Relays is not limited to only those devices that use
electrical quantities as inputs (exclude pressure, temperature, gas, etc).
Response:
This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
Segment:
Organization:
Member:
3
Springfield Utility Board
Jeff Nelson
Comment:
Please refer to SUB's comments on VRFs and VFLs in the Comment Form
Response:
Please refer to the SDT responses to your comments on the comment form.
Segment:
Organization:
Member:
3
Louisville Gas and Electric Co.
Charles A. Freibert
Comment:
Comments will be submitted under a comment form
Response:
Please refer to the SDT responses to your comments on the comment form.
November 17, 2010
21
Consideration of Comments on Initial Ballot of “Protection System” Definition
The PRC-005 Standard Drafting Team thanks all those who participated in the initial ballot for the proposed revision to the definition
of the term, “Protection System.”
All balloters are advised to review the comments and responses in this report as an aid in determining how to participate in the
recirculation ballot.
Based on stakeholder comments, the drafting team refined its proposed definition of Protection System as shown below:
Protective relays which respond to electrical quantities, communication systems necessary for correct operation of
protective functions, voltage and current sensing devices providing inputs to protective relays, station dc supply, and control
circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting devices.
Several comments questioned the reason for implementing the definition of Protection System in advance of implementing the
proposed modifications to PRC-005-1. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of
"protection system" and directed that work to close this reliability gap should be given “priority.” To close this reliability gap the
BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
Stakeholder comments indicated that applying the expanded scope of the definition of Protection System would to PRC-005-1 would
require more than six months and suggested expanding this to 12 months, and the drafting team made this change to the
implementation plan. The team adjusted the implementation plan so that entities will have at least twelve months, rather than the
six months originally proposed, to apply the new definition of Protection System to PRC-005-1 – Protection System Maintenance and
Testing to Requirement R1 of PRC-005-1. The other parts of the implementation plan remain unchanged.
Both clean and redline versions of the definition and the implementation that show the conforming revisions are posted at the
following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
July 22, 2010
1
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process! If you feel there has been an error or omission, you can contact the Vice President and Director of
Standards, Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
July 22, 2010
2
Segment: 1
Organization: International Transmission Company Holdings Corp
Member: Michael Moltane
It should clearly state in the definition or elsewhere in the standard that automatic ground switches intended to
Comment: protect the BES are to be considered interrupting devices. This is stated in the Supplemental Reference but the
Supplemental Reference is not part of the standard.
Response: The definition does not identify individual types of interrupting devices. It is left to Regional BES definitions
to determine if these devices, the system components “protected” by these devices, and their initiating
Protection Systems are BES elements.
Segment: 1, 6
Organization: Cleco Power LLC
Member: Danny McDaniel, Matthew D Cripps
The revised definition to Protection System should include the following exception. "Devices that sense non
Comment: electrical conditions, such as thermal or transformer sudden pressure relays are not included." For consistence
across the standards, see PRC-004, which references System Protection, the same definition should be used.
Response: The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
Segment: 1, 5, 6
Organization: American Electric Power, AEP Service Corp., AEP Marketing
Member: Paul B. Johnson, Brock Ondayko, Edward P. Cox
1. The term "station" should either be defined or removed from the definition, as it implies transmission and
distribution assets while the term "plant" is used to define generation assets. It would suffice to simply
refer to the "DC Supply".
Comment: 2. As written, the implementation plan only specifies a time frame for entities to update their documentation
for PRC-005-1 and PRC-005-2 compliance. The implementation plan also needs to give entities a time
frame to address any required changes to their documentation for other standards that use the term
"Protection System", including but not limited to NUC-001-2, PER-005-1, PRC-001-1, etc.
Response:
July 22, 2010
1. The term “station” is used in a generic sense to apply to either “substation” or “generation station”
3
facilities.
2. An assessment of the changes to the definition (posted with the first comment period), relative to the
entire body of other NERC Standards using this defined term, determined that the changes are
consistent with the other existing uses of the definition, and that no other implementation plan
considerations were necessary. No comments were received relative to this assessment.
Segment: 1
Organization: Avista Corp.
Member: Scott Kinney
Comment:
The modified definition of Protection System now refers to “functions” rather than “devices.” What are the
“functions?” This new term adds confusion without being defined in the standard.
Response: The “functions” are the accumulated performance of the various portions of the Protection System. This term
is used to distinguish “protective functions” from annunciation, signaling, or information.
Segment: 1, 3
Organization: MidAmerican Energy Co.
Member: Terry Harbour, Thomas C. Mielnik
The following changes should be incorporated in the definition to insure it is used consistently in PRC-005
and any other standards where it appears. The following is a suggested revised definition:
“Protection System” is defined as: A system that uses measurements of voltage, current, frequency and/or
phase angle to determine anomalies and to trip a portion of the BES to provide protection for the BES and
consists of
Comment:
1) Protective relays for BES elements and,
2) Communications systems necessary for correct BES protection system operations and,
3) Current and voltage sensing devices supplying BES protective relay input and,
4) Station DC supply to BES protection systems excluding battery chargers, and
5) DC control trip paths to the trip coil(s) of the circuit breakers or other interrupting devices for BES
July 22, 2010
4
elements.
Response: The definition of Protection System establishes “what a Protective System is”, not “what it does”. The
application-related suggestions in the comment are best left to individual standards. The SDT, however, did
modify the “protective relays” to include only those that respond to electrical quantities. Additionally,
constraining relays to “on BES elements” would necessarily exclude UFLS relays, and “trip a portion of the
BES” would exclude SPS and UVLS which are on the BES, but which trip non-BES elements. The SDT also
disagrees with excluding battery chargers.
Segment: 3, 5, 6
Organization: Lincoln Electric System
Member: Bruce Merrill, Dennis Florom, Eric Ruskamp
LES believes the proposed definition of Protection System as written remains open to interpretation. LES
offers the following Protection System definition for the SDT’s consideration:
“Protection System” is defined as: A system that uses measurements of voltage, current, frequency and/or
phase angle to determine anomalies and trips a portion of the BES and consists of
1) Protective relays, and associated auxiliary relays, that initiate trip signals to trip coils,
Comment: 2) associated communications channels,
3) current and voltage transformers supplying protective relay inputs,
4) dc station supply, excluding battery chargers, and
5) dc control trip path circuitry to the trip coils of BES connected breakers, or equivalent interrupting device,
and lockout relays.
Response: The definition of Protection System establishes “what a Protective System is”, not “what it does”. The
application-related suggestions in the comment are best left to individual standards. The SDT, however, did
modify the “protective relays” to include only those that respond to electrical quantities. Additionally,
constraining relays to “on BES elements” would necessarily exclude UFLS relays, and “trip a portion of the
BES” would exclude SPS and UVLS which are on the BES, but which trip non-BES elements. The SDT also
July 22, 2010
5
disagrees with excluding battery chargers.
Segment: 4
Organization: Madison Gas and Electric Co.
Member: Joseph G. DePoorter
Comment: Recommend the following definition “Protection System” is defined as: A system that uses measurements of
voltage, current, frequency and/or phase angle to determine anomalies and trips a portion of the BES and
consists of
1) Protective relays, and associated auxiliary relays, that initiate trip signals to trip coils,
2) associated communications channels,
3) current and voltage transformers supplying protective relay inputs,
4) dc station supply, excluding battery chargers, and
5) dc control trip path circuitry to the trip coils of BES connected breakers, or equivalent interrupting device,
and lockout relays.
Response: The definition of Protection System establishes “what a Protective System is”, not “what it does”. The
application-related suggestions in the comment are best left to individual standards. The SDT, however, did
modify the “protective relays” to include only those that respond to electrical quantities. Additionally,
constraining relays to “on BES elements” would necessarily exclude UFLS relays, and “trip a portion of the
BES” would exclude SPS and UVLS which are on the BES, but which trip non-BES elements. The SDT also
disagrees with excluding battery chargers.
Segment: 1
Organization: National Grid
Member: Saurabh Saksena
1. National Grid suggests adding “Protection System Components including” in the beginning. This is because
the word “components” has been used extensively throughout the standard and there is no mention of what
Comment:
constitutes a protection system component in the standard. The word “component” does find mention in
FAQs, however, it is recommended to mention it in the main standard.
July 22, 2010
6
2. Also, National Grid proposes a change in the proposed definition (changing "voltage and current sensing
inputs" to "voltage and current sensing devices providing inputs"). The revised definition should read as
follows: Protective System Components including Protective relays, communication systems necessary for
correct operation of protective functions, voltage and current sensing devices providing inputs to protective
relays and associated circuitry from the voltage and current sensing devices, station dc supply, and control
circuitry associated with protective functions from the station dc supply through the trip coil(s) of the circuit
breakers or other interrupting devices.
3. The time provided for the first phase “at least six months” is too open ended and does not give entities a
clear timeline. National Grid suggests 1 year for the first phase.
4. As a result, National Grid suggests phasing out the second phase in stages.
Response:
1. The SDT believes that the suggested text does not add to the definition, and may actually lead to
additional problems, such as an implication that the list within the definition is incomplete.
2. The definition has been modified to reflect the proposed change and the “associated circuitry …” has
been removed.
3. The implementation plan has been modified to replace “six months” with “twelve months”.
4. The SDT does not understand this comment.
Segment: 10
Organization: Midwest Reliability Organization
Member: Dan R. Schoenecker
Comment:
Response:
1. The MRO’s NERC Standards Review Subcommittee believes the proposed protection system
definition is unclear specifically as it relates to dc station supply. We would like more clarity as to
what is included in the dc station supply.
2. We believe battery chargers should not be included in the definition; if the Standard Drafting Team
revises the definition we would ask that Table 1 be adjusted, accordingly
1. The definition addressing “dc supply” was modified.
2. The SDT believes that battery chargers should be included in the definition. Without proper
functioning of battery chargers, the battery will be discharged by normal station dc load, and will be
unable to perform its function; also, there are some entities which use a charger to provide the dc
supply without use of a battery.
Segment: 4
July 22, 2010
7
Organization: Old Dominion Electric Coop.
Member: Mark Ringhausen
I am voting Yes on the ballot, but I do have a small issue with the wording of 'station DC supply'. In some of
our UFLS locations, we are not in a substation, but out on the feeder circuit and utilizing the DC supply on the
Comment:
feeder recloser. I think my reading of this definition would apply to this recloser DC supply as well as the
Station DC Supply.
Response: To the extent that UFLS is implemented within distribution system devices not within substations, the
activities and intervals established within the standard would apply.
Segment: 6
Organization: Northern Indiana Public Service Co.
Member: Joseph O'Brien
Comment: It is still not clear whether battery chargers fall under this definition.
Response: The change to “station dc supply” is intended to expand the definition to include all essential elements
including battery chargers.
Segment: 8
Organization: SPS Consulting Group Inc.
Member: Jim R Stanton
Comment: The words in the definition, “...includes one or more of the following activities” are ambiguous and subject to
inconsistent interpretation by auditors. Suggest changing the language to, "...at least one of the following
activities."
Response: This comment does not appear to apply to the “Protection System” definition.
Segment: 4
Organization: Detroit Edison Company
Member: Daniel Herring
Comment:
1. The definition should clarify whether current and voltage transformers themselves are included.
2. This implementation plan and the one for PRC-005-2 should be consistent.
Response:
1. This portion of the definition has been modified for clarity.
July 22, 2010
8
2. The Implementation Plan for the definition has been modified. The Implementation Plan for the
Standard is a separate issue.
Segment: 1
Organization: BC Transmission Corporation
Member: Gordon Rawlings
Comment: The definition excludes mechanical relays (Gas Relays) which may affect the BES
Response: The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
Segment: 1, 3, 4, 5, 6
Organization:
Empire District Electric Co., Cowlitz County PUD, Cowlitz County PUD, Cowlitz County PUD, Florida
Municipal Power Pool
Member: Ralph Frederick Meyer, Russell A Noble, Rick Syring, Bob Essex, Thomas E Washburn
Comment:
1. It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are
included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that
particular standard to protection systems that sense electrical quantities, it is remains unclear in other
standards that use the defined term whether mechanical input protections are included.
2. We suggest that “Protective Relay” also be defined, and that the definition clearly exclude devices that
respond to mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the
CMPWG request.
Response:
1.
The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
2. “Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC
standard, thus the SDT sees no need to either modify or duplicate that definition.
Segment: 3
Organization: Central Lincoln PUD
Member: Steve Alexanderson
Comment: 1. Do you believe the proposed definition of Protection System is ready for ballot? If not, please explain why.
July 22, 2010
9
0 Yes X No
Comments: It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure
relays, are included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope
of that particular standard to protection systems that sense electrical quantities, it is remains unclear in
other standards that use the defined term whether mechanical input protections are included. We suggest
that “Protective Relay” also be defined, and that the definition clearly exclude devices that respond to
mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG
request.
2. Do you agree with the implementation plan for the revised definition of Protection System? The
implementation plan has two phases – the first phase gives entities at least six months to update their
protection system maintenance and testing program; the second phase starts when the protection system
maintenance and testing program has been updated and requires implementation of any additional
maintenance and testing associated with the program changes by the end of the first complete maintenance
and testing cycle described in the entity’s revised program.
If you disagree with this implementation plan, please explain why. X Yes 0 No Comments:
Response:
1. The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
2. Thank you.
Segment: 3
Organization: Consumers Energy
Member: David A. Lapinski
Comment:
1. It is unclear whether “voltage and current sensing inputs” include the instrument transformer itself, or
does it pertain to only the circuitry and input to the protective relays.
2. It is not clear what is included in the component, “station dc supply” without referring to other
documents (the posted Supplementary Reference and/or FAQ) for clarification. The definition should
be sufficiently detailed to be clear.
3. If Protection Systems trip via AC methods, are those systems, and the associated control circuitry
included in the definition and within the requirements of the Standard as expressed within the Tables?
Response: 1. The definition has been changed for clarity; the SDT intends that the output of these devices, measured at
the relay should properly represent the primary quantities.
July 22, 2010
10
2. There are many possible variations to “station dc supply”. The definition must be sufficiently general such
that variations can be included.
3. The definition has been generalized such that ac tripping is included.
Segment: 1, 3, 5
Organization: Arizona Public Service Co., APS
Member: Robert D Smith, Thomas R. Glock, Mel Jensen
The change to the definition relative to the voltage and current sensing devices is too prescriptive. Methods of
Comment: determining the integrity of the voltage and current inputs into the relays to ensure reliability of the devices
should be up to the discretion of the utility.
Response: The definition has been changed for clarity; the SDT intends that the output of these devices, measured at the
relay should properly represent the primary quantities.
Segment: 4
Organization: Consumers Energy
Member: David Frank Ronk
1. It is unclear whether “voltage and current sensing inputs” include the instrument transformer itself, or does
it pertain to only the circuitry and input to the protective relays?
2. It is not clear what is included in the component, “station dc supply” without referring to other documents
(the posted Supplementary Reference and/or FAQ) for clarification. The definition should be sufficiently
detailed to be clear.
Comment: 3. If Protection Systems trip via AC methods, are those systems, and the associated control circuitry included?
4. For entities that may not have included all elements reflected in the modified definition within their PRC005-1 program, 6-months following regulatory approvals may not be sufficient to identify all relevant
additional components, develop maintenance procedures, develop maintenance and testing intervals,
develop a defendable technical basis for both the procedures and intervals, and train personnel on the
newly implemented items. We propose that a 12-month schedule following regulatory approvals may be
more practical.
Response: 1. The SDT made several changes to the definition to improve clarity. The SDT intends that the output of
July 22, 2010
11
these devices, measured at the relay should properly represent the primary quantities.
2. There are many possible variations to “station dc supply”. The definition must be sufficiently general such
that variations can be included.
3. The definition has been generalized such that ac tripping is included.
4. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to agree
with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day
of the first calendar quarter”.
Segment: 1, 3, 6
Organization: Consolidated Edison Co. of New York
Member: Christopher L de Graffenried, Peter T Yost, Nickesha P Carrol
1. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate
equipment identified in the existing or proposed definition. However, not all such equipment translates into
a transmission Protection System.
Comment:
2. The definition needs clarification on when such equipment is a part of the transmission protection system.
3. Also, the time provided for the first phase "at least six months" is too open ended and does not provide
entities with a clear timeline. It is suggested that one year is appropriate for the first phase phasing out the
second year in stages.
Response:
1. This issue is properly addressed within the Standard, not within the definition.
2. This issue is properly addressed within the Standard, not within the definition.
3. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to
agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
Segment: 1, 3
Organization: Hydro One Networks, Inc.
Member: Ajay Garg, Michael D. Penstone
Comment: The proposed definition of Protection System needs clarification on when such equipment is a part of the
July 22, 2010
12
transmission protection system. Emphasis should be on systems and not individual components.
Response: This issue is properly addressed within the Standard, not within the definition.
Segment: 4
Organization: Y-W Electric Association, Inc.
Member: James A Ziebarth
From Question 1 on the comment form: The application of this definition to Reliability Standards NUC-0012, PER-005-1, PRC-001-1, and PRC-004-1 results in confusion as to whether relays with mechanical inputs
are included or excluded from this definition. PRC-005-2_R1 contains language limiting its applicability to
Comment:
relays operating on electrical inputs only, but the remaining standards that rely on this definition are not so
specific. This being the case, it would make much more sense to clearly define what devices are actually
meant in the glossary definition rather than leaving it up to each individual standard to do so.
Response: The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
Segment: 1, 3
Organization: Platte River Power Authority
Member: John C. Collins, Terry L Baker
1. Although the applicable relays to which protective relays are outlined in the NERC PRC-005-2 Protection
system Maintenance Draft Supplementary Reference dated May 27, 2010, they are not defined in the
NERC Glossary of terms. Until it is clearly defined which relays are included inconsistencies will exists
from region to region in their audit approaches and which relays they will be looking at.
Comment:
2. Also, there is still debate why the protective relays would extend to mechanical devices such as the lock-out
relay and tripping for trip-free relays. In our system configuration we risk reliability to customer load by
testing the lock-out relays which we feel out weights the benefit of testing devices that we see little to no
evidence of failure in.
Response: 1. This is properly an issue for the various Regional BES definitions.
2. The definition does not explicitly include these devices, although they are implicitly part of “control
circuitry”.
Segment: 3
Organization: Public Utility District No. 2 of Grant County
July 22, 2010
13
Member: Greg Lange
These systems are not always maintained at the component level, i.e. meggering from the relay input test
switch through the cable and the CT. This has not closed all the issues around professional judgment
Comment:
(interpretations) that make us nervous when faced with the human element of an audit. We need more
specificity to close that gap.
Response: This issue is properly addressed within the Standard, not within the definition.
Segment: 1, 3, 5, 6
Organization:
Dominion Virginia Power, Dominion Resources Services, Dominion Resources, Inc., Dominion Resources,
Inc.
Member: John K Loftis, Michael F Gildea, Mike Garton, Louis S Slade
Comment: The proposed definition introduces ambiguity and we suggest retaining the current definition.
Response: The existing definition presents ambiguities and gaps which must be addressed in accordance with directives
from the NERC BOT. Additionally, the draft definition constrains certain components to remove ambiguities.
Segment: 5
Organization: Southern Company Generation
Member: William D Shultz
We agree that the definition provides clarity and will enhance the reliability of the Protection Systems to
which it is applicable. The negative vote is a result of a belief that the definition’s effective date must be
coincident with the approval and implementation schedule of PRC-005-2. Since this new definition is directly
Comment: linked to the proposed revised standard, it would be premature to make this definition effective prior to the
effective date of the new standard. If balloted and approved, there is no obligation to or guarantee of any
additional maintenance to be performed. PRC-005-2 includes this definition, the maintenance activities, and
the intervals that will ensure execution of the maintenance and testing.
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
July 22, 2010
14
definition to PRC-005-1.
Segment: 1, 3, 6
Organization: Great River Energy
Member: Gordon Pietsch, Sam Kokkinen, Donna Stephenson
Comment:
We agree with the revised Protection System definition. The revised definition should only be applied to PRC005-2. The revised definition should not be applied to PRC-005-1.
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
Segment: 5
Organization: Progress Energy Carolinas
Member: Wayne Lewis
Progress Energy does not believe that the definition should be implemented separately from and prior to the
implementation of PRC-005-2. We believe there should be a direct linkage between the definition’s effective
date to the approval and implementation schedule of PRC-005-2. Since this new definition should be directly
Comment:
linked to the proposed revised standard, it would be premature to make this new definition effective prior to
the effective date of the new standard. We believe that changes to the maintenance program should be driven
by the revision of the PRC standard, not by the revision of a definition.
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
July 22, 2010
15
Segment: 1
Organization: Ameren Services
Member: Kirit S. Shah
Comment: The implementation of the revised definition and PRC-005-2 PSMP must align on the same date.
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
Segment: 3
Organization: Niagara Mohawk (National Grid Company)
Member: Michael Schiavone
Comment:
Response:
1. National Grid does not agree with the proposed implementation plan. The time provided for the first
phase “at least six months” is too open ended and does not give entities a clear timeline. National Grid
suggests 1 year for the first phase.
2. National Grid also suggests phasing out the second phase in stages.
1. The Implementation Plan has been modified to replace “six months” with “twelve months”.
2. We do not understand your comment.
Segment: 1, 3, 3, 3, 3
Organization:
Southern Company Services, Inc., Alabama Power Company, Georgia Power Company, Gulf Power
Company, Mississippi Power
Member: Horace Stephen Williamson, Richard J. Mandes, Anthony L Wilson, Gwen S Frazier, Don Horsley
We agree that the definition provides clarity and will enhance the reliability of the Protection Systems to
which it is applicable. However, we feel that there needs to be a direct linkage of the definition’s effective
Comment: date to the approval and implementation schedule of PRC-005-2. Since this new definition is directly linked to
the proposed revised standard, it would be premature to make this definition effective prior to the effective
date of the new standard.
July 22, 2010
16
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
Segment: 1, 5
Organization: Entergy Corporation
Member: George R. Bartlett, Stanley M Jaskot
The following are the reasons associated with our Negative Ballot.
1. We agree with the definition, however we do not agree with the implementation plan. We believe
implementation of the definition needs to coincide with the implementation of Standard PRC-005-2. To do
otherwise, will cause entities to address equipment, documentation, work management process, and
Comment:
employee training changes needed for compliance twice within an unreasonably short timeframe.
2. A 12 month minimum timeframe is need to implement this definition
3. We also reserve the right to include selected reasons submitted by other Negative balloters for their
Negative Ballot.
Response:
1. Thank you.
2. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to
agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”. When the Board of Trustees was asked to approve an
interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the
reliability gap identified by the drafting team caused by the definition of "protection system" and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap
the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years
from now. The implementation plan now proposes at least 12 months for entities to apply the new
definition to PRC-005-1, and that should give entities time to apply the new definition to PRC-005-1.
3. Thank you.
Segment: 3, 6
July 22, 2010
17
Organization: Entergy
Member: Joel T Plessinger, Terri F Benoit
1. We agree with the definition, however we do not agree with the implementation plan. We believe
implementation of the definition needs to coincide with the implementation of Standard PRC-005-2. To do
Comment:
otherwise, will cause entities to address equipment, documentation, work management process, and
employee training changes needed for compliance twice within an unreasonably short timeframe.
2. A 12 month minimum timeframe is need to implement this definition
Response:
1. Thank you.
2. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to
agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”. When the Board of Trustees was asked to approve an
interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the
reliability gap identified by the drafting team caused by the definition of "protection system" and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap
the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years
from now. The implementation plan now proposes at least 12 months for entities to apply the new
definition to PRC-005-1, and that should give entities time to apply the new definition to PRC-005-1.
Segment: 5
Organization: U.S. Bureau of Reclamation
Member: Martin Bauer
1. It is unfortunate that the definition did not retain consistency in the terms. As an example, the definition
indicates it includes protective relays and communication systems for the correct operation of protective
functions. It would have been better to use the term relays instead of the term functions. Now it is unclear
what the communication systems are for.
Comment:
July 22, 2010
2. The Time Horizons are too narrow for the implementation of the standard as written. The SDT appears to
have not accounted for the data analysis associated with performance based systems. The data collection,
analysis, and subsequent decisions associated development of a maintenance program and its justification do
not occur overnight especially with larger utilities. In addition, this new standard will require complete rewrite
of an entities internal maintenance programs. The internal processes associated with these vary based on the
18
size of the entity and its organizational structure. Since this standard is so invasive into the internal decisions
concerning maintenance, the standard should allow at least 18 months for entities to rewrite their internal
maintenance programs to meet the program development requirements and 18 months to train the staff in the
new program, incorporate the program into the entities compliance processes, and to implement the new
program.
Response:
1. “Functions” was used, as some applications (SPS, for example) may have communications systems
that operate other than via protective relays.
2. This comment appears to be focused on the revised Standard, not on the definition.
Segment: 2
Organization: Midwest ISO, Inc.
Member: Jason L Marshall
Comment:
We are abstaining because a number of our stakeholders have concerns regarding the definition of Protection
System and the inclusion of UVLS and UFLS in a standard dealing with maintenance of protection systems.
Response: The inclusion of UVLS/UFLS is related to a directive from FERC in Order 693, and to the SAR for this
project.
Segment: 1
Organization: Lakeland Electric
Member: Larry E Watt
Comment: An implementation plan should be associated with this definition change.
Response: An Implementation Plan specifically for the definition is posted.
Segment: 1
Organization: Clark Public Utilities
Member: Jack Stamper
Comment: The proposed definition does not provide the level of clarity that is needed.
Response: The SDT made several changes to the definition to improve clarity.
Segment: 1
Organization: Beaches Energy Services
July 22, 2010
19
Member: Joseph S. Stonecipher
Comment: While better than the last draft, too many problems still exist.
The following series of comments all indicate that the entity has submitted comments via the official comment form.
Segment: 1, 5, 6
Organization: Public Service Electric and Gas Co., PSEG Energy Resources & Trade LLC
Member: Kenneth D. Brown, David Murray, James D. Hebson
Comment: Please reference comments submitted by the PSEG companies on the official comment form for this standard.
Segment: 1
Organization: Potomac Electric Power Co.
Member: Richard J. Kafka
Comment: PHI submitted comments
Segment: 3
Organization: Louisville Gas and Electric Co.
Member: Charles A. Freibert
Comment: Comments will be submitte4d under the comment form
Segment: 3
Organization: Bonneville Power Administration
Member: Rebecca Berdahl
Comment: Please see BPA's comments submitted during the concurrent formal comment period ending July 16, 2010.
Segment: 1
Organization: GDS Associates, Inc.
Member: Claudiu Cadar
Comment: All comments included in the NERC comment form
Segment: 1, 3, 4, 5, 6
Organization: FirstEnergy Energy Delivery, FirstEnergy Solutions, FirstEnergy Solutions, Ohio Edison Company,
July 22, 2010
20
FirstEnergy Solutions
Member: Robert Martinko, Kevin Querry, Kenneth Dresner, Douglas Hohlbaugh, Mark S Travaglianti
Comment:
Please see FE comments for suggested enhancements submitted via the parallel comment period for this
definition.
Segment: 1
Organization: Duke Energy Carolina
Member: Douglas E. Hils
Comment: Please see our responses in the comment form - thank you.
Segment: 8
Organization: Utility Services LLC
Member: Brian Evans-Mongeon
Comment: see filed comments
Segment: 5
Organization: PPL Generation LLC
Member: Mark A. Heimbach
Comment: Please see comments submitted by "PPL Supply" on 7/16/10.
From this point on, all comments provided relate to the proposed standard, not to the proposed definition and its implementation plan.
Responses to comments submitted with ballots for the standard are included in the comment report for the standard – they are not
duplicated here.
Segment: 1
Organization: Lake Worth Utilities
Member: Walt Gill
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard 2. The draft standard would cause
Comment: NERC to regulate through the standards battery testing, DC circuit testing, etc. on distribution elements with
no significant improvement to BES reliability, which is beyond the statutory scope of the standards 3. The
standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of protection
July 22, 2010
21
system components. Will the Standard Introduce Technical Feasibility Exceptions to PRC Standards? a large
proportion of the batteries (as high as 50% as reported by some SMEs) are not able to accommodate all of the
tests prescribed in the draft standard. Will this necessitate the introduction of TFEs into the process
unnecessarily? The Standard Reaches Beyond the Statutory Scope of the Reliability Standards As written, the
standard requires testing of batteries, DC control circuits, etc., of distribution level protection components
associated with UFLS and UVLS. UFLS and UVLS are different than protection systems used to clear a fault
from the BES. An uncleared fault on the BES can have an Adverse Reliability Impact and hence; the focus on
making sure the fault is cleared is important and appropriate. However, a UFLs or UVLS event happens after
the fault is cleared and is an inexact science of trying to automatically restore supply and demand balance
(UFLS) or restore voltages (UVLS) to acceptable levels. If a few UFLS or UVLS relays fail to operate out of
potentially thousands of relays with the same function, there is no significant impact to the function of UFLS
or UVLS. Hence, there is no corresponding need to focus on every little aspect of the UFLS or UVLS
systems. Therefore, the only component of UFLS or UVLS that ought to be focused on in the new PRF-005
standard is the UFLS or UVLS relay itself and not distribution class equipment such as batteries, DC control
circuitry, etc., and these latter ought to be removed from the standard. In addition, most distribution circuit are
radial without substation arrangements that would allow functional testing without putting customers out of
service while the testing was underway, or at least without momentary outages while customers were switched
from one circuit to another. Therefore, as written, we would be sacrificing customer service for a negligible
impact on BES reliability. Perfection is Not A Realistic Goal The standard allows no mistakes. Even the
famous six sigma quality management program allows for defects and failures (i.e., six sigma is six standard
deviations, which means that statistically, there are events that fall outside of six standard deviations). PRC005 has been drafted such that any failure is a violation, e.g., 1 day late on a single relay test of tens of
thousands of relays is a violation. That is not in alignment with worldwide accepted quality management
practices (and also makes audits very painful because statistical, random sampling should be the mode of
audit, not 100% review as is currently being done in many instances). FMPA suggests considering statistically
based performance metrics as opposed to an unrealistic performance target that does not allow for any failure
ever. Due to the shear volume of relays, with 100% performance required, if the standards remain this way,
PRC-005 will likely be in the top ten most violated standards for the forever. There is a fundamental flaw in
thinking about reliability of the BES. We are really not trying to eliminate the risk of a widespread blackout,
we are trying to reduce the risk of a widespread blackout. We plan and operate the system to single and
credible double contingencies and to finite operating and planning reserves. To eliminate the risk, we would
need to plan and operate to an infinite number of contingencies, and have an infinite reserve margin, which is
infeasible. Therefore, by definition, there is a finite risk of a widespread blackout that we are trying to reduce,
July 22, 2010
22
not eliminate, and, by definition, by planning and operating to single and credible double contingencies and
finite operating and planning reserves, we are actually defining the level of risk from a statistical basis we are
willing to take. With that in mind, it does not make sense to require 100% compliance to avoid a smaller risk
(relays) when we are planning to a specified level of risk with more major risk factors (single and credible
double contingencies and finite planning and operating reserves).
Segment: 3, 4, 5
Organization: Wisconsin Electric Power Marketing, Wisconsin Energy Corp., Wisconsin Electric Power Co.
Member: James R. Keller, Anthony Jankowski, Linda Horn
We Energies does not agree to the implementation plan proposed. While it makes common sense to proceed
with R1 prior to proceeding with implementing R2, R3, and R4, the timeline to be compliant for R1 is too
short. It will take a considerable amount of resources to migrate the maintenance plan from today’s standard
to the new standard in phase one. ATC recommends that time to develop and update the revised program be
increased to at least one year followed by a transition time for the entity to collect all the necessary field data
for the protection system within its first full cycle of testing. (In ATC’s case would be 6 years) To address
phase two, We Energies believes human and technological resources will be overburdened to implement this
revised standard as written. The transition to implementing the new program will take another full testing
cycle once the program has been updated. Increased documentation and obtaining additional resources to
accomplish this will be challenging. Implementation of PRC-005-2 will impact We Energies in the following
manner: a. Increase costs: double existing maintenance costs. b. Since there will be a doubling of human
Comment:
interaction (or more), it is expected that failures due to human error will increase, possibly proportionately. c.
Breaker maintenance may need to be aligned with protection scheme testing, which will always contain
elements that are include in the non-monitored table for 6 yr testing. d. We Energies is developing standards
for redundant bus and transformer protection schemes. This would allow We Energies to test the protection
packages without taking the equipment out of service. Further if one system fails, there is full redundancy
available. With the current version of PRC-005-2, We Energies would need to take an outage to test the
protection schemes for a transformer or a bus, there is not an incentive to install redundant schemes. We
Energies is working with a condition based breaker maintenance program. This program’s value would be
greatly diminished under PRC-005-2 as currently written. Consideration also needs to be given for other
NERC standards expected to be passed and in the implementation stage at the same time, such as the CIP
standards.
Segment: 4, 5
July 22, 2010
23
Organization: Florida Municipal Power Agency
Member: Frank Gaffney, David Schumann
FMPA recommends a negative vote on PRC-005-2, Project 2007-17, for three significant reasons 1. As
written, it opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries are not
able to accommodate all of the tests proscribed in the draft standard as explained by Steve Alexanderson in a
prior e-mail to the ballot pool. 2. The draft standard would cause NERC to regulate through the standards
battery testing, DC circuit testing, etc. on distribution elements with no significant improvement to BES
reliability, which is beyond the statutory scope of the standards 3. The standard unreasonably retains the
"100% compliance" paradigm for thousands, if not millions of protection system components. Will the
Standard Introduce Technical Feasibility Exceptions to PRC Standards? As described by Steve Alexanderson
in a prior e-mail to the ballot pool, a large proportion of the batteries (as high as 50% as reported by some
SMEs) are not able to accommodate all of the tests prescribed in the draft standard. Will this necessitate the
introduction of TFEs into the process unnecessarily? The Standard Reaches Beyond the Statutory Scope of the
Reliability Standards As written, the standard requires testing of batteries, DC control circuits, etc., of
distribution level protection components associated with UFLS and UVLS. UFLS and UVLS are different
than protection systems used to clear a fault from the BES. An uncleared fault on the BES can have an
Adverse Reliability Impact and hence; the focus on making sure the fault is cleared is important and
Comment:
appropriate. However, a UFLs or UVLS event happens after the fault is cleared and is an inexact science of
trying to automatically restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable
levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays with the same
function, there is no significant impact to the function of UFLS or UVLS. Hence, there is no corresponding
need to focus on every little aspect of the UFLS or UVLS systems. Therefore, the only component of UFLS or
UVLS that ought to be focused on in the new PRF-005 standard is the UFLS or UVLS relay itself and not
distribution class equipment such as batteries, DC control circuitry, etc., and these latter ought to be removed
from the standard. In addition, most distribution circuit are radial without substation arrangements that would
allow functional testing without putting customers out of service while the testing was underway, or at least
without momentary outages while customers were switched from one circuit to another. Therefore, as written,
we would be sacrificing customer service for a negligible impact on BES reliability. Perfection is Not A
Realistic Goal The standard allows no mistakes. Even the famous six sigma quality management program
allows for defects and failures (i.e., six sigma is six standard deviations, which means that statistically, there
are events that fall outside of six standard deviations). PRC-005 has been drafted such that any failure is a
violation, e.g., 1 day late on a single relay test of tens of thousands of relays is a violation. That is not in
July 22, 2010
24
alignment with worldwide accepted quality management practices (and also makes audits very painful
because statistical, random sampling should be the mode of audit, not 100% review as is currently being done
in many instances). FMPA suggests considering statistically based performance metrics as opposed to an
unrealistic performance target that does not allow for any failure ever. Due to the shear volume of relays, with
100% performance required, if the standards remain this way, PRC-005 will likely be in the top ten most
violated standards for the forever. There is a fundamental flaw in thinking about reliability of the BES. We are
really not trying to eliminate the risk of a widespread blackout, we are trying to reduce the risk of a
widespread blackout. We plan and operate the system to single and credible double contingencies and to finite
operating and planning reserves. To eliminate the risk, we would need to plan and operate to an infinite
number of contingencies, and have an infinite reserve margin, which is infeasible. Therefore, by definition,
there is a finite risk of a widespread blackout that we are trying to reduce, not eliminate, and, by definition, by
planning and operating to single and credible double contingencies and finite operating and planning reserves,
we are actually defining the level of risk from a statistical basis we are willing to take. With that in mind, it
does not make sense to require 100% compliance to avoid a smaller risk (relays) when we are planning to a
specified level of risk with more major risk factors (single and credible double contingencies and finite
planning and operating reserves).
Segment: 1
Organization: Keys Energy Services
Member: Stan T. Rzad
As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries are
not able to accommodate all of the tests proscribed in the draft standard. The draft standard would cause
NERC to regulate through the standards battery testing, DC circuit testing, etc. on distribution elements with
Comment:
no significant improvement to BES reliability, which is beyond the statutory scope of the standards The
standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of protection
system components.
Segment: 3
Organization: Municipal Electric Authority of Georgia
Member: Steven M. Jackson
Comment:
July 22, 2010
Station DC supply testing was set at three months. A six month time based testing interval is reasonable.
Maximum maintenance interval for a lead-acid vented battery is liste at six calendar years. This type of test
25
reduces battery life. A 10 to 12 year interval is reasonable. As written this rule would require a TFE that
should be administratively unnecessary. Additional clarification is needed in: Control and trip circuits
associated with UVLS and UFLS do not require tripping of the breakers but all other protection systems
require tripping. Please clarify. Digital relays have electromagnetic output relays - are they categorized as
electromechanical or solid state? There needs to be reasonable flexibility based on industry experience in
allowing less than 100% perfection in the testing of relays, etc.
Segment: 1
Organization: American Transmission Company, LLC
Member: Jason Shaver
ATC does not agree to the implementation plan proposed. While it makes common sense to proceed with R1
prior to proceeding with implementing R2, R3, and R4, the timeline to be compliant for R1 is too short. It will
take a considerable amount of resources to migrate the maintenance plan from today’s standard to the new
standard in phase one. ATC recommends that time to develop and update the revised program be increased to
at least one year followed by a transition time for the entity to collect all the necessary field data for the
protection system within its first full cycle of testing. (In ATC’s case would be 6 years) To address phase two,
ATC believes human and technological resources will be overburdened to implement this revised standard as
written. The transition to implementing the new program will take another full testing cycle once the program
has been updated. Increased documentation and obtaining additional resources to accomplish this will be
challenging. Implementation of PRC-005-2 will impact ATC in the following manner: a. Increase costs:
Comment: double existing maintenance costs. b. Since there will be a doubling of human interaction (or more), it is
expected that failures due to human error will increase, possibly proportionately. c. Breaker maintenance may
need to be aligned with protection scheme testing, which will always contain elements that are include in the
non-monitored table for 6 yr testing. d. ATC is developing standards for redundant bus and transformer
protection schemes. This would allow ATC to test the protection packages without taking the equipment out
of service. Further if one system fails, there is full redundancy available. With the current version of PRC005-2, ATC would need to take an outage to test the protection schemes for a transformer or a bus, there is not
an incentive to install redundant schemes. ATC is working with a condition based breaker maintenance
program. This program’s value would be greatly diminished under PRC-005-2 as currently written.
Consideration also needs to be given for other NERC standards expected to be passed and in the
implementation stage at the same time, such as the CIP standards.
Segment: 1
July 22, 2010
26
Organization: Tucson Electric Power Co.
Member: John Tolo
Comment: The mention of communication systems maintenance (M1.) needs more clarity as to the depth of the
maintenance required. Also, Table 1a, a 3-month interval to verify that the Protection System communications
system is functional is too frequent to be practical.
Segment: 4
Organization: Fort Pierce Utilities Authority
Member: Thomas W. Richards
Comment: The requirement for taking intracell readings is not possible for all batteries. Some minor rewording would
resolve this issue and make it applicable to those batteries that have internal cell-to-cell straps. I would
recommend changing the minimum requirement to take intracell resistance readings from the battery
terminals, since identifying the particular cell that is going bad is of little use. I imagine all utilities replace an
entire jar, not individual cells. The draft standard would cause NERC to regulate, through the standards
battery testing, DC circuit testing, etc. on distribution elements with no significant improvement to BES
reliability, which is beyond the statutary scope of the standards The standard unreasonably retains the "100%
compliance" paradigm for thousands, if not millions of protection system components. This becomes an
investigation, not an audit. There is no way an audit team will have the time to arrive at 100% compliance
with a large entity.
Segment: 1, 3, 6
Organization: Xcel Energy, Inc.
Member: Gregory L Pieper, Michael Ibold, David F. Lemmons
Xcel Energy believes the standard still contains many aspects that are not clearly understood by entities,
Comment: including what is needed to demonstrate a compliant PSMP. Comments have been submitted concurrently to
NERC via the draft comment response form.
Segment: 1, 3, 5, 6
Organization: Kansas City Power & Light Co.
Member: Michael Gammon, Charles Locke, Scott Heidtbrink, Thomas Saitta
Comment: The proposed changes in the Standard are far too prescriptive and does not take into account the multitude of
July 22, 2010
27
manufacturers equipment by establishing broad maintenance cycles and testing intervals.
Segment: 1
Organization: SCE&G
Member: Henry Delk, Jr.
While SCE&G believes the majority of the PRC-005-2 standard is ready to be affirmed there are still
Comment: inconsistencies with areas of the standard that need to be corrected prior to approval. These inconsistencies are
addressed in SCE&G’s comments which have been submitted for the current draft of this standard.
Segment: 1, 3, 4, 6
Organization: Seattle City Light
Member: Pawel Krupa, Dana Wheelock, Hao Li, Dennis Sismaet
Comment: Functional testing is impractical.
Segment: 6
Organization: Florida Power & Light Co.
Member: Silvia P Mitchell
Comment: This standard is too prescriptive and will result in many violations.
Segment: 5
Organization: Salt River Project
Member: Glen Reeves
SRP believes the requirements of the Standard are confusing and may be problematic in determining
compliance. We also believe the required functional testing of the breaker trip coil may potentially increase
maintenance outages of circuit breakers. In most cases, circuit breaker maintenance outages can be
Comment: coordinated such that Protection System maintenance and testing can be done simultaneously. However, in
some cases this may not be possible. Outages of any BES facility whether planned or unplanned can impact
system reliability. SRP suggests that trip coil monitoring devices be included as an acceptable means of
ensuring the trip coil is functioning properly. This will help to avoid unnecessary outages.
Segment: 3
Organization: Lakeland Electric
July 22, 2010
28
Member: Mace Hunter
Comment:
The proposed draft may introduce TFEs into the PRC standards, not a good thing. The proposed draft
reacheds beyound the statutory scope of the reliability standards. Perfection is not a realistic goal.
Segment: 1
Organization: PPL Electric Utilities Corp.
Member: Brenda L Truhe
PPL EU is voting negative because Rqmt 1.1 "Identify all Protection System components" is too broad and
Comment: must be clarified and the definition of Protective Relays is not limited to only those devices that use electrical
quantities as inputs (exclude pressure, temperature, gas, etc).
Segment: 1
Organization: Pacific Gas and Electric Company
Member: Chifong L. Thomas
We are concerned over R1.1, where all components must be identified, without a definition for the word
component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. We are concerned whether identification is
Comment: required for every individual component, such as each auxiliary relay, or is it sufficient that the auxiliary
relays are included within the scheme that is being tested and documented. Do the auxiliary relays need to be
documented within the maintenance database and/or on the actual test reports of schemes being tested? We
suggest that the FAQ definitions be included within the standard.
July 22, 2010
29
Consideration of Comments on Initial Ballot of PRC-005-2 – Protection System Maintenance
The Protection System Maintenance Standard Drafting Team (PSM SDT) thanks all those who participated in the initial ballot for the
proposed revisions to PRC-005 - Protection System Maintenance.
•
87.85% quorum
•
39.35 % weighted segment approval
All comments received with affirmative and negative ballots are included in this report.
All balloters are advised to review the comments and responses in this report as an aid in determining how to participate in the
recirculation ballot.
Both a clean and a redline version of the standard that shows the conforming revisions are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Many commenters objected to the establishment of maximum allowable intervals and offered comments on virtually every
individual activity and interval within the Tables. The SDT responded that “FERC Order 693 and the approved SAR assigned the SDT
to develop a Standard with maximum allowable intervals and minimum maintenance activities.” In an effort to provide more clarity,
the SDT also completely revised the Tables of maximum maintenance intervals/minimum maintenance activities, and made
numerous other changes throughout the draft Standard. Many commenters also indicated a preference for much of the information
that is currently contained within the reference documents to be included within the Standard itself. The SDT responded by
including the definitions of terms exclusively used within this standard, specifically “component type”, “component”, “segment”,
“maintenance correctable issue”, and “countable event”, , within the body of the standard. Numerous comments were also offered,
proposing that the VSLs allow for some amount of non-compliance with the Standard before incurring a violation. The SDT
responded by stating that: “The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.”
November 17, 2010
1
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process! If you feel there has been an error or omission, you can contact the Vice President and Director of
Standards, Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
November 17, 2010
2
Segment:
Organization:
Member:
Comment:
1
International Transmission Company Holdings Corp
Michael Moltane
While voting affirmative due to the improvements over the existing standards, we do have the following
comments. We hope the Standards Team can take these comments and suggested improvements into account
although we did not get our comments in during the official comment period due to confusion over the
overlapping comment/ballot period. The following are ITC Holdings comments corresponding the questions
on the comment form:
Regarding Question #1: ITC Holdings does not agree with the 6 year time interval for functional testing of
the control and trip circuits. It has been our experience that trip failures are rare and that our present 10 year
control, trip tests, and other related testing are sufficient in verifying the integrity of the scheme. A scheme
that is 100% microprocessor relays except for 1 electromechanical AR or SG relay would be forced to a 6
year interval instead of a 12 year interval. This seems unreasonable for schemes that are otherwise identical.
Comments on Question #4: ITC Holdings agrees with the measure and data retention requirements assuming
that the requirements only apply to test data after the effective date of the approved standard.
Comments on Question #7: It should clearly state in the definition or elsewhere in the standard that automatic
ground switches intended to protect the BES are to be considered interrupting devices. This is stated in the
Supplemental Reference but the Supplemental Reference is not part of the standard. Please consider splitting
the first row in Table 1a (Protective Relays) into 2 separate rows, one for relays other than microprocessor
and the other for microprocessor relays.
• Include the sentence “Verify that settings are as specified.” In both rows to be clear that this applies to
both categories. (The following is intended to be helpful information only not to be included in the
comments)
The following provides a clue as to what Time Horizon means: From:
http://www.nerc.com/docs/pc/ris/Order_890-A_pro_forma_Attachment_C.doc (1) A detailed description of
the specific mathematical algorithm used to calculate firm and non-firm ATC (and AFC, if applicable) for its
November 17, 2010
3
scheduling horizon (same day and real-time), operating horizon (day ahead and pre-schedule) and planning
horizon (beyond the operating horizon); See Definition at: http://www.nerc.com/files/Time_Horizons.pdf
Copy below: Time Horizons Time Horizons are used as a factor in determining the size of a sanction. If an
entity violates a requirement and there is no time to mitigate the violation because the requirement takes place
in real-time, then the sanction associated with the violation is higher than it would be for violation of a
requirement that could be mitigated over a longer period of time. When establishing a time horizon for each
requirement, the following criteria should be used: 1. Long-term Planning — a planning horizon of one year
or longer. 2. Operations Planning — operating and resource plans from day-ahead up to and including
seasonal. 3. Same-day Operations — routine actions required within the timeframe of a day, but not realtime. 4. Real-time Operations — actions required within one hour or less to preserve the reliability of the
bulk electric system. 5. Operations Assessment — follow-up evaluations and reporting of real time
operations.
Response:
Thank you for your comment.
Question #1 - The Tables have been rearranged and considerably revised to improve clarity. Please see new
Table 1-5. The SDT believes that mechanical solenoid-operated devices share performance attributes (and
failure modes) with electromechanical relays and need to be tested at similar intervals. Performance-based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
Question #4 – The SDT believes that entities cannot be expected to initially have data for requirements that
did not previously exist.
Question #7 – From a mandatory perspective, this is dependent on the regional BES definitions and on what
those definitions may describe to be “transmission Protection Systems.”
• The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 11.
Time Horizon – Thank you for your input.
Segment:
Organization:
Member:
November 17, 2010
5
U.S. Bureau of Reclamation
Martin Bauer
4
1. There is no reliability based justification to alter the standards to require practices of a subset of entities as
allowable intervals. It is incredible that the standard would suppose that requiring the use of weighted average
practice of some subset of all entities could reasonable. The purpose of a reliability standard is to ensure the
reliability of the BES. There is no indication that the existing standard has posed a threat to the reliability of
the BES. There is no data which indicates that the BES reliability is impacted because of certain maintenance
practices. The SDT has chosen an approach which has statistical merit and is good information for entities to
consider in reviewing their maintenance program. To force an entity to enhance its maintenance program
because some subsets of entities have a different program is contrary to the purpose authorized by the Energy
Policy Act of 2005. The variables of each entity faces when developing their maintenance practice intervals
cannot be calculated through statistical analysis. To presume that the end result (the interval itself) can be
applied to other entities ignores the sound decisions made internally to each entity that results in final
interval. The standard should return to addressing real reliability impacts as required by law. The desire to
improve maintenance programs offers a unique problem to the FERC and regulatory world. The knee jerk
reaction is to define a "universal" interval based on some statistical method. What happens if the solution is
bad, who will accept the consequences that narrow prescription was wrong and the interval caused a
reliability impact. It would no longer be the Entity. The standard does not make such an allowance. History is
Comment: replete with examples of this type of micro managing. Rather than fall into the same trap, and suffer the
consequences of the unknown, it is suggested to allow Entities to optimize their programs to ensure reliability
of the BES. If the NERC wants to create a reliability based standard that addresses reliability impacts, the
SDT is encouraged to create a standard of "disallowed" practices. These would be practices which have a
demonstrated impact on reliability. The SDT should spend to analyzing maintenance practices which have a
known impact on reliability (as evidenced by disturbance reports) and develop requirements which disallow
such practices or range of practices. In addition, if it is shown that an event in which BES reliability was
impacted by the utilities PSMP (as evidenced by disturbance reports), the utility would be required to submit
to the RRO a corrective action plan which addresses how the PSMP will be revised and when compliance
with that PSMP is to be achieved.
2. The intervals prescription for performance based PSMP virtually eliminates the capability of smaller
utilities that do not have a large equipment database to justify a performance based system that may be sound
based on their experience. This overly prescriptive approach should be eliminated and return to allowing
utilities to justify their programs.
3. The Time Horizons are too narrow for the implementation of the standard as written. The SDT appears to
November 17, 2010
5
have not accounted for the data analysis associated with performance based systems. The data collection,
analysis, and subsequent decisions associated development of a maintenance program and its justification do
not occur overnight especially with larger utilities. In addition, this new standard will require complete
rewrite of an entities internal maintenance programs. The internal processes associated with these vary based
on the size of the entity and its organizational structure.
4. Since this standard is so invasive into the internal decisions concerning maintenance, the standard should
allow at least 18 months for entities to rewrite their internal maintenance programs to meet the program
development requirements and 18 months to train the staff in the new program, incorporate the program into
the entities compliance processes, and to implement the new program.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
Thank you for your comment.
1. FERC directed the SDT to establish maximum time intervals between maintenance activities. The
SDT recognized that different types of equipment, different generations of equipment, different
failure modes of equipment, and different versions of time-based maintenance had to be considered.
The SDT agrees with the commenter that the Standard allows statistical analysis, and performancebased maintenance allows an entity to create time intervals that could exceed any “weightedaverages” time-based intervals. The Supplementary Reference adds a Section 9 to show how an
entity can create a performance-based maintenance interval.
2. FERC directed the SDT to establish maximum time intervals between maintenance activities. Smaller
entities may aggregate their component populations with other entities having similar programs – see
Section 9 of the Supplementary Reference document and FAQ IV.3.A. Entities are not required to
use performance-based PSMPs; this option is made available to entities who wish to use it.
3. Your comment appears to address the Implementation Plan, not Time Horizons. The Implementation
Plan for Requirement R1 has been extended from three months to twelve months. For performancebased programs, Attachment A specifies that there must first be acceptable results, and that a timebased program (per the Tables) must be used until then. See FAQ IV.3.B.
4. The Implementation Plan for Requirement R1 has been extended from three months to twelve months.
5
South Mississippi Electric Power Association
Jerry W Johnson
The proposed Standard is overly prescriptive and too complex to be practically implemented. An entity
6
making a good faith effort to comply will have to navigate through the complexities and nuances, as
illustrated by the extensive set of documents the SDT has provided in an attempt to explain all the
requirements and nuances. The need for an extensive “Supplementary Reference Document” and an
extensive “Frequently Asked Questions Document”, in addition to 13 pages of tables and an attachment in the
standard itself, illustrate that the proposal is too prescriptive and complex for most entities to practically
implement.
1. The descriptions for the "type of protection system components" do not appear to be consistent between
Tables, 1a, 1b and 1c.
2. The maximum maintenance interval for a lead-acid vented battery is listed at 6 calendar years for
performing a capacity test. This type of test has been proven to reduce battery life and an interval of 10 to
12 years would be better.
3. The maximum maintenance interval for "Station DC supply" was set at 3 months. This is too short of a
period and 6 months would be better.
4. The control and trip circuits associated with UVLS and UFLS do not require tripping of the breakers but
all other protection systems require tripping of the breakers, this appears to be inconsistent?
5. Digital relays have electromagnetic output relays. Do they fall into the electromechanical trip or solid
state trip?
6. Need for clarification: The standard indicates that only voltage and current signals need to be verified.
Does this mean that voltage and current transformers do not need to be tested by applying a primary
signal and verifying the secondary output?
7. With regard to DPs who own transmission Protection Systems, the standard is still very unclear on when
a DP owns a transmission Protection System. Many DPs own equipment that is included within the
definition of a Protection System; however, ownership of such equipment does not necessarily translate
directly into a transmission Protection System under the compliance obligations of this standard. DPs
need to know if this standard applies to them and right now, there is no certain way of determining that
from within this language or previous versions of this standard.
November 17, 2010
7
8. The phrase “Verify Battery cell-to-cell connection resistance” has entered the table where it did not exist
before. On some types of stationary battery units, this internal connection is inaccessible. On other types
the connections are accessible, but there is no way to repair them based on a bad reading. And bad cellto-cell connections within units will be detected by the other required tests. This requirement will cause
entities to scrap perfectly good batteries just so this test can be performed, with no corresponding
increase in bulk electric system reliability while taking an unnecessary risk to personnel and the
environment. And because buying battery units composed of multiple cells allows space saving designs,
entities may be forced to buy smaller capacity batteries to fit existing spaces. This may end up having a
negative effect on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the
table now.
9. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be
used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which
activities shall we use?
10. Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing. IEEE
battery maintenance standards call for quarterly inspections. These are targets, though, not maximums.
An entity wishing to avoid non-compliance for an interval that might extend past three calendar months
due to storms and outages must set a target interval of two months thereby increasing the number of
inspections each year by half again. This is unnecessarily frequent.
Response:
November 17, 2010
Thank you for your comments. FERC Order 693 and the approved SAR assign the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
2. The SDT disagrees.
3. The SDT disagrees.
4. Your observation is correct. The Tables have been rearranged and considerably revised to improve
clarity. Please see new Table 1-5. This is an intentional difference between UFLS/UVLS and the
remainder of the Protection Systems addressed within the Standard, because of the distributed nature
of UFLS/UVLS and because these devices are usually tripping distribution system elements
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-1.
6. Your observation is correct.
7. Your concern seems to be primarily related to the applicable regional BES definition.
8
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. “Cell” has been replaced with “cell/unit” to address this concern.
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
10. The SDT disagrees. You should complete the activities within the intervals specified.
Segment:
Organization:
Member:
5
RRI Energy
Thomas J. Bradish
For PRC-005-2, while there is nothing inherently wrong with the requirements, RRI voted affirmative with
concern. Our concern is we believe that rather than fixing the issues that caused the 2003 blackout, there is a
continual drift to extensive micro-management to take control of every aspect of the entire industry through
regulation in the name of reliability.
I believe the documentation required to demonstrate 100% compliance to this standard will be a serious
challenge to achieve uniformly for so many components across a widely dispersed fleet, especially in the
Comment: punitive, zero-tolerance compliance world that presently exists. It only takes the things we are in short
supply: time, money, and people. It will drive industry to better systems and performance, but there will be a
painful price, especially on the development side. An example of the impact of this standard: station power
plant batteries are sized to carry large DC loads with the protection system as only a small fraction of the load
profile. Rather than performing a risk assessment for station with low capacity factors (for example RRI has a
two unit station that had an average capacity factor in 2009 of 1.72%) after the battery slightly crosses over
its degradation threshold, there will be no choice but an immediate and expensive replacement. This type of
requirement will push many units into pre-mature retirement or mothballing.
Response:
Segment:
Thank you for your comment.
3
Organization:
Tampa Electric Co.
Member:
Ronald L Donahey
The level of DC circuit testing required every time the relay is tested represents potentially a negative impact
Comment: to reliability given the complicated control circuitry in an energized station. Even though you take out an
element out of service, the DC control circuits are often interconnected for functions such as breaker failure,
November 17, 2010
9
bus and transformer lockouts, etc. This level of testing needs to be done when initial construction but this
increase in testing is not justifiable given the reliability risk and cost. TEC's record for misoperations do to
circuitry failure does not support this need.
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5. The SDT believes that mechanical solenoid-operated devices share performance
attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals.
Performance-based maintenance is an option to increase the intervals if the performance of these devices
supports those intervals.
5
Salt River Project
Glen Reeves
SRP believes the requirements of the Standard are confusing and may be problematic in determining
compliance.
Comment:
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
We also believe the required functional testing of the breaker trip coil may potentially increase maintenance
outages of circuit breakers. In most cases, circuit breaker maintenance outages can be coordinated such that
Protection System maintenance and testing can be done simultaneously. However, in some cases this may not
be possible. Outages of any BES facility whether planned or unplanned can impact system reliability. SRP
suggests that trip coil monitoring devices be included as an acceptable means of ensuring the trip coil is
functioning properly. This will help to avoid unnecessary outages.
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5. The SDT believes that mechanical solenoid-operated devices share performance
attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals.
Performance-based maintenance is an option to increase the intervals if the performance of these devices
supports those intervals.
1, 3, 4, 6
Seattle City Light
Pawel Krupa, Dana Wheelock, Hao Li, Dennis Sismaet
Functional testing is impractical.
10
Response:
Segment:
Organization:
Member:
Thank you for your comment. Functional testing is not the only means of completing the required
maintenance, although it may be the most practical.
3
JEA
Garry Baker
JEA does not believe the standard adequately addresses issues like component, FAQ, etc as identified below:
1.
R1.1 Identify all Protections System components. What is meant by Protection System component?
Is a component a wire, contact, device, etc. A list of components as intended by the SDT would be
illustrative in understanding the SDT’s intent of what a component includes.
2.
Are the FAQ and Supplemental Reference going to be adopted as part of this standard? These
documents contain information that is critical to the proper understanding and interpretation of the
standard, thus either the standard needs to be rewritten to include this information, or the FAQ and
Supplemental Reference need to be adopted as part of this standard. Any inconsistencies between the
FAQ and the standard, as written, would need to be corrected.
3.
The maximum maintenance interval for a lead-acid vented battery is listed as 6 calendar years for
performing a capacity test. This type of test has been proven to reduce battery life and a longer
capacity test interval of 10 to 12 years would be better, allowing for longer battery life.
4.
The implementation period for R1.1 of 3 months is too short and should be extended to one calendar
year; of course this is dependent on the complexity of items listed as part of the definition of
“Protection System component.”
Comment:
Response:
Thank you for your comment.
1. A definition of “Component” has been added to the draft Standard. The SDT’s intent is that this
definition will be used only in PRC-005-2, and thus will remain with the Standard when approved,
rather than being relocated to the Glossary of Terms.
2. These documents provide supporting discussion, but are not part of the Standard. The SDT intends that
these be posted as Reference Documents, accompanying the Standard.
November 17, 2010
11
3. The SDT disagrees.
4. The Implementation Plan for Requirement R1 has been modified from three months to twelve months.
Segment:
Organization:
Member:
5
Public Utility District No. 1 of Lewis County
Steven Grega
1. As written PRC-005-2 does not recognize or accommodate the many type of batteries in use at substations.
To accommodate many of the prescribed tests, the batteries would have to be disassembled to conduct the test
with little valuable information gained. Suggest wording only saying the batteries should be periodically test
to assure that they perform as designed. Let the entities' engineers decide on what is most appropriate for their
batteries.
Comment:
2. Having a standard that requires 100% compliance on 1000's of components is a good way of assuring
many violations. Most protective system can function with half the protection in service. Typically most
engineers over design and have backup upon backup on critical elements. Suggest standard require a lesser
compliance rate; say 90% to 95% during an audit. The elements not in compliance could be followed by a 12
month plan to bring other elements into compliance but the entity at 90% to 95% would still be found
compliant. In summary, this proposed standard has gone beyond the reasonably level of regulation by NERC.
Therefore, I am voting not to affirm the revision to this standard.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
Segment:
Organization:
Member:
Comment:
November 17, 2010
3
City of Farmington
Linda R. Jacobson
As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries are
not able to accommodate all of the tests proscribed in the draft standard as explained by Steve Alexanderson
in a prior e-mail to the ballot pool. The draft standard would cause NERC to regulate through the standards
12
battery testing, DC circuit testing, etc. on distribution elements with no significant improvement to BES
reliability, which is beyond the statutory scope of the standards
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-4. “Cell” has been replaced with “cell/unit” to address this concern. The Standard
only addresses distribution-located devices to the degree that they address BES issues. UFLS and UVLS per
the relevant NERC Standards are frequently implemented on the distribution system.
1
Pacific Gas and Electric Company
Chifong L. Thomas
The requirements in the latest draft are confusing and at times seem to be in conflict with other requirements.
From a compliance and enforcement perspective, this confusion would make the standard difficult to audit.
1. We are concerned over R1.1, where all components must be identified, without a definition for the word
component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. We are concerned whether identification is
required for every individual component, such as each auxiliary relay, or is it sufficient that the auxiliary
relays are included within the scheme that is being tested and documented. Do the auxiliary relays need to be
documented within the maintenance database and/or on the actual test reports of schemes being tested? We
suggest that the FAQ definitions be included within the standard.
Comment:
November 17, 2010
2. We agree with most of the changes from the last draft in Table 1a, 1b and 1c. However, the phrase “Verify
Battery cell-to-cell connection resistance” has entered the table where it did not exist before. On some types
of stationary battery units, this internal connection is inaccessible. On other types the connections are
accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell connections within
units will be detected by the other required tests. This requirement will cause entities to scrap perfectly good
batteries just so this test can be performed, with no corresponding increase in bulk electric system reliability
while taking an unnecessary risk to personnel and the environment. And because buying battery units
composed of multiple cells allows space saving designs, entities may be forced to buy smaller capacity
batteries to fit existing spaces. This may end up having a negative effect on reliability. Suggest substituting
“unit-to-unit” wherever “cell-to-cell” is used in the table now.
13
3. The level 1 table regarding Control and trip circuits with electromechanical trip or auxiliary contacts now
includes exception for microprocessor relays, but there is no listing for the requirements for microprocessor
relays.
4. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be
used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which
activities shall we use?
5. Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
in consideration of your comment.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. “Cell” has been replaced with “cell/unit” to address this concern.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 and 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
5
Pacific Gas and Electric Company
Richard J. Padilla
The level of detail of this standard is over the top and currently conflicts with other standards and is open for
future conflicts. We recommend that the standard DT evaluate the basic rational for the standard and limit its
scope. Some examples are:
Comment:
November 17, 2010
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard as explained by Steve
Alexanderson in a prior e-mail to the ballot pool. The draft standard would cause NERC to regulate
through the standards battery testing, DC circuit testing, etc. on distribution elements with no significant
14
improvement to BES reliability, which is beyond the statutory scope of the standards
2. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components as written, the standard requires testing of batteries, DC control circuits,
etc., of distribution level protection components associated with UFLS and UVLS. UFLS and UVLS are
different than protection systems used to clear a fault from the BES. An uncleared fault on the BES can
have an Adverse Reliability Impact and hence; the focus on making sure the fault is cleared is important
and appropriate. However, a UFLs or UVLS event happens after the fault is cleared and is an inexact
science of trying to automatically restore supply and demand balance (UFLS) or restore voltages (UVLS)
to acceptable levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays
with the same function, there is no significant impact to the function of UFLS or UVLS. Hence, there is
no corresponding need to focus on every little aspect of the UFLS or UVLS systems. Therefore, the only
component of UFLS or UVLS that ought to be focused on in the new PRF-005 standard is the UFLS or
UVLS relay itself and not distribution class equipment such as batteries, DC control circuitry, etc., and
these latter ought to be removed from the standard.
3. In addition, most distribution circuit are radial without substation arrangements that would allow
functional testing without putting customers out of service while the testing was underway, or at least
without momentary outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES reliability
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. “Cell” has been replaced with “cell/unit” to address this concern. The Standard only addresses
distribution-located devices to the degree that they address BES issues. UFLS and UVLS per the
relevant NERC Standards are frequently implemented on the distribution system.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
3. Functional testing is not the only means of completing the required maintenance, although it may be
the most practical.
5
Indeck Energy Services, Inc.
Rex A Roehl
As discussed at the FERC Technical Conference on Standards Development, the goal of the standards
15
program is to avoid or prevent cascading outages--specifically not loss of load. The expansion of this
standard deviates significantly from its purpose of maintaining protective systems that affect BES reliability.
It doesn't recognize that not all relays affect reliability. If reliability is measured by a Reportable Disturbance,
then the threshold varies by control area--largest contingency. The standard should include a process, not
unlike the risk based assessment in CIP-002-2 R1, to include as "identified components" only those affecting
reliability. All of the various reliability criteria should be considered.
Response:
Segment:
Organization:
Member:
Thank you for your comment. “BES reliability” is more than simply avoiding “cascading outages” – as
illustrated by the approved definition of “Adequate Level of Reliability” as promulgated by the NERC
Planning and Operating Committees in response to a directive from FERC, and as described in Section 215 of
the Federal Power Act.
5
Black Hills Corp
George Tatar
1. Draft is confusing & seems to conflict with other requirements. Table 1b Maint. Activities needs to define
whether all protection logic or conditions would initiate a relay trip output are required to be simulated &
Comment: tested to the relay tripping output contact.
2. The Attachment A definition of "common factors" is way too broad to be utilized in defining a grouping of
protection system devices.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
2. The SDT is not clear whether your concern is about “common factors” as used in the definition of
“Segment.” See Section 9 of the Supplementary Reference document for a discussion of
performance-based maintenance.
4
Wisconsin Energy Corp.
Anthony Jankowski
1. Table 1a, Protective Relays:
Change 1st line to: “Test and calibrate if necessary the relays…”
16
Table 1a & 1b, Protective Relays: 3rd line:
Change “check the relay inputs…” to “verify the relay inputs…”
The term “check” is not defined, whereas “verify” is.
Tables 1a & 1b We agree that six / twelve years is an acceptable interval for relay maintenance.
Table 1a & 1b, Control & Trip Circuits: The proposed addition to require tripping circuit breakers during
Protection System maintenance will require outages and is therefore detrimental to BES reliability and should
be removed.
− Generating unit protection system maintenance is done during scheduled outages. The high voltage
breaker on a generating unit often remains energized to back feed and supply station auxiliaries when
the generator is offline. The proposed requirement will increase the amount of equipment requiring an
outage for maintenance, and possibly the length of the outage, resulting in significantly more
equipment out of service as well as increased costs. This requirement also results in greater
maintenance efforts and costs when there are redundant protection system equipment (breaker trip
coils, lockout relays, etc), which is contrary to good practice and reliability.
− Many of the breakers that We Energies, as the Distribution Provider, trips from its BES protection
systems are not owned by We Energies and are owned by a separate transmission company. The trip
testing and maintenance of the transmission company may not coincide with our relay maintenance
testing program. The standard shall have allowances for the entity to ONLY test or maintain
equipment that it OWNS!
Table 1a, Station dc supply:
− The activity to verify the state of charge of battery cells is too vague, and requires more specific
action. We assume that the drafting committee is recommending specific gravity measurements.
Specific gravity measurements have not been shown to be an accurate indicator of state of charge. In
addition, as shown in the nuclear power industry, there is no established corrective action that is taken
based on specific gravity results (eg. Don’t require a test where there is no acceptable corrective
action).
− The activities to “verify battery continuity” and “check station dc supply voltage” are also vague and
need to be more clearly specified what is intended.
− The 3 month time interval for battery impedance testing is too frequent. 18 month or annual testing is
more appropriate.
November 17, 2010
17
− The 3 calendar year performance or service test is too frequent and will actually remove life from a
battery and reduce reliability. Recommend capacity testing no more that every 5 years and more
frequent test if the capacity is within 10% of the end of life or design. This is consistent with the
nuclear power industry.
Table 1b, Station dc supply:
− Recommend a change or addition to Table 1b - Recommend a level 2 monitoring (not just a default to
the level 1 maintenance activities) which allows for the removal of quarterly “check” of electrolyte
levels, DC supply voltage, and DC grounds - if station DC supply (charger) voltage is continuously
monitored (eg. one should not have detrimental gassing of a battery if the float voltage of the battery
is properly set and monitored).
Table 1a, Associated communications systems: The requirement to verify functionality every three months is
excessive; verifying this every twelve months is adequate.
Tables 1a & 1b – Although the latest standard provided some additional clarification, more clarification is
required on what maintenance / testing is ONLY required for UFLS/UVLS protection systems vs. BES
protection systems (eg. UFLS / UVLS systems – Is a verification of proper voltage of the DC supply the only
battery or DC supply test required (e.g. no state of charge, float voltage, terminal resistance, electrolyte level,
grounds, impedance or performance test, etc.)
− The requirement to retain data for the two most recent maintenance cycles is excessive. The required
data should be limited to the complete data for the most recent cycle, and only the test date for the
previous cycle.
2. We Energies does not agree to the implementation plan proposed. While it makes common sense to
proceed with R1 prior to proceeding with implementing R2, R3, and R4, the timeline to be compliant
for R1 is too short. It will take a considerable amount of resources to migrate the maintenance plan
from today’s standard to the new standard in phase one. ATC recommends that time to develop and
update the revised program be increased to at least one year followed by a transition time for the
entity to collect all the necessary field data for the protection system within its first full cycle of
testing. (In ATC’s case would be 6 years)
To address phase two, We Energies believes human and technological resources will be
November 17, 2010
18
overburdened to implement this revised standard as written. The transition to implementing the new
program will take another full testing cycle once the program has been updated. Increased
documentation and obtaining additional resources to accomplish this will be challenging.
Implementation of PRC-005-2 will impact We Energies in the following manner:
a. Increase costs: double existing maintenance costs.
b. Since there will be a doubling of human interaction (or more), it is expected that failures due to
human error will increase, possibly proportionately.
c. Breaker maintenance may need to be aligned with protection scheme testing, which will always
contain elements that are include in the non-monitored table for 6 yr testing.
d. We Energies is developing standards for redundant bus and transformer protection schemes. This
would allow We Energies to test the protection packages without taking the equipment out of service.
Further if one system fails, there is full redundancy available. With the current version of PRC-005-2,
We Energies would need to take an outage to test the protection schemes for a transformer or a bus;
there is not an incentive to install redundant schemes. We Energies is working with a condition based
breaker maintenance program. This program’s value would be greatly diminished under PRC-005-2
as currently written.
3. Consideration also needs to be given for other NERC standards expected to be passed and in the
implementation stage at the same time, such as the CIP standards.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
2. The Implementation Plan for Requirement R1 has been changed from three months to twelve months.
3. This issue should be presented to the NERC Standards Committee.
Segment:
Organization:
Member:
3, 5
Wisconsin Electric Power Marketing, Wisconsin Electric Power Co.
James R. Keller, Linda Horn
1. Table 1a, Protective Relays: Change 1st line to: “Test and calibrate if necessary the relays…”
Comment:
Table 1a & 1b, Protective Relays:
November 17, 2010
19
3rd line: Change “check the relay inputs…” to “verify the relay inputs…” The term “check” is not defined,
whereas “verify” is.
Tables 1a & 1b We agree that six / twelve years is an acceptable interval for relay maintenance.
Table 1a & 1b, Control & Trip Circuits: The proposed addition to require tripping circuit breakers during
Protection System maintenance will require outages and is therefore detrimental to BES reliability and should
be removed.
Generating unit protection system maintenance is done during scheduled outages. The high voltage breaker
on a generating unit often remains energized to back feed and supply station auxiliaries when the generator is
offline. The proposed requirement will increase the amount of equipment requiring an outage for
maintenance, and possibly the length of the outage, resulting in significantly more equipment out of service
as well as increased costs. This requirement also results in greater maintenance efforts and costs when there
are redundant protection system equipment (breaker trip coils, lockout relays, etc), which is contrary to good
practice and reliability.
Many of the breakers that We Energies, as the Distribution Provider, trips from its BES protection systems
are not owned by We Energies and are owned by a separate transmission company. The trip testing and
maintenance of the transmission company may not coincide with our relay maintenance testing program. The
standard shall have allowances for the entity to ONLY test or maintain equipment that it OWNS!
Table 1a, Station dc supply:
− The activity to verify the state of charge of battery cells is too vague, and requires more specific
action. We assume that the drafting committee is recommending specific gravity measurements.
Specific gravity measurements have not been shown to be an accurate indicator of state of charge. In
addition, as shown in the nuclear power industry, there is no established corrective action that is taken
based on specific gravity results (eg. Don’t require a test where there is no acceptable corrective
action).
− The activities to “verify battery continuity” and “check station dc supply voltage” are also vague and
need to be more clearly specified what is intended.
− The 3 month time interval for battery impedance testing is too frequent. 18 month or annual testing is
more appropriate.
November 17, 2010
20
− The 3 calendar year performance or service test is too frequent and will actually remove life from a
battery and reduce reliability. Recommend capacity testing no more that every 5 years and more
frequent test if the capacity is within 10% of the end of life or design. This is consistent with the
nuclear power industry.
Table 1b, Station dc supply:
− Recommend a change or addition to Table 1b - Recommend a level 2 monitoring (not just a default to
the level 1 maintenance activities) which allows for the removal of quarterly “check” of electrolyte
levels, DC supply voltage, and DC grounds - if station DC supply (charger) voltage is continuously
monitored (eg. one should not have detrimental gassing of a battery if the float voltage of the battery
is properly set and monitored).
Table 1a, Associated communications systems: The requirement to verify functionality every three months is
excessive; verifying this every twelve months is adequate.
Tables 1a & 1b – Although the latest standard provided some additional clarification, more clarification is
required on what maintenance / testing is ONLY required for UFLS/UVLS protection systems vs. BES
protection systems (e.g. UFLS / UVLS systems – Is a verification of proper voltage of the DC supply the only
battery or DC supply test required (e.g. no state of charge, float voltage, terminal resistance, electrolyte level,
grounds, impedance or performance test, etc.)
2. The requirement to retain data for the two most recent maintenance cycles is excessive. The required
data should be limited to the complete data for the most recent cycle, and only the test date for the
previous cycle.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
2. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the
Compliance Monitor will need the data of the most recent performance of the maintenance, as well as
the data of the preceding one, as well as data to validate that entities have been in compliance since the
last audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data
November 17, 2010
21
retention in the posted Standard to establish this level of documentation.
Segment:
Organization:
Member:
1, 6
Great River Energy
Gordon Pietsch, Donna Stephenson
1. In Table 1a section-Station DC Supply – 18 calendar months, under Maintenance Activities column,
suggest changing under Verify: Battery terminal connection resistance To: Entire battery bank terminal
connection resistance (This could have been interpreted as individual batteries) And change: Battery
cell-to-cell connection resistance To: Battery cell-to-cell connection resistance, where an external
mechanical connection is available.
2. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid batteries) suggest
changing Max Maintenance Interval=3 Calendar Years or 3 Calendar Months to 4 Calendar Years or 12
Calendar Months. Our concern is that the insurance companies may push NERC maintenance intervals
on all battery banks not associated with the BES.
3. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max Maintenance Interval=6
Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade the
battery.
4. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max Maintenance
Comment:
Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may
degrade the battery.
5. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and trip circuitry)
we suggest the following change: If a trip circuit comprises multiple paths, at least one of those paths is
monitored. Alarming for loss of continuity or dc supply for trip circuits is reported to a location where
action can be taken.
6. While all tripping circuits are not completely monitored, the trip coils and the outdoor cable runs are
completely monitored. The only portion that would not be monitored is a portion of inter and intra-panel
wiring having no moving parts located in a control house. Our company has extremely low failure rate
of panel wiring and terminal lugging. I don’t think that there is provision for moving control and trip
circuitry to performance based maintenance? This control circuitry should be maintained less frequent
than un-monitored trip circuits (6 years).
November 17, 2010
22
Response:
Thank you for your comment.
1.The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. NERC Standards are limited to facilities and equipment related to the BES. How the Standard may be
otherwise used is outside the scope of NERC Standards.
3. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Vented
Lead Acid and Ni-Cad batteries. A properly maintained battery, according to various credible references
(from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle multiple deep discharges over its
expected life.
4. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Ni-Cad
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI,
various manufacturers, etc.), can easily handle multiple deep discharges over its expected life.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 156. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15. Nothing in the draft Standard (including Attachment A) precludes an entity from using performancebased maintenance for dc control circuits.
Segment:
Organization:
Member:
3
Great River Energy
Sam Kokkinen
1. In Table 1a section-Station DC Supply – 18 calendar months, under Maintenance Activities column,
suggest changing under Verify: Battery terminal connection resistance To: Entire battery bank terminal
connection resistance (This could have been interpreted as individual batteries) And change: Battery cell-tocell connection resistance To: Battery cell-to-cell connection resistance, where an external mechanical
Comment: connection is available.
2. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid batteries) suggest
changing Max Maintenance Interval=3 Calendar Years or 3 Calendar Months to 4 Calendar Years or 12
Calendar Months. Our concern is that the insurance companies may push NERC maintenance intervals on all
November 17, 2010
23
battery banks not associated with the BES.
3. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max Maintenance Interval=6
Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade the battery.
4. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max Maintenance
Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade
the battery.
5. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and trip circuitry) we
suggest the following change: If a trip circuit comprises multiple paths, at least one of those paths is
monitored. Alarming for loss of continuity or dc supply for trip circuits is reported to a location where action
can be taken.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 14. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. NERC Standards are limited to facilities and equipment related to the BES. How the Standard may be
otherwise used is outside the scope of NERC Standards.
3. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Vented
Lead Acid and Ni-Cad batteries. A properly maintained battery, according to various credible references
(from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle multiple deep discharges over its
expected life.
4. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Ni-Cad
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI,
various manufacturers, etc.), can easily handle multiple deep discharges over its expected life.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
Segment:
Organization:
November 17, 2010
5
Great River Energy
24
Member:
Cynthia E Sulzer
1. In Table 1a section-Station DC Supply – 18 calendar months, under Maintenance Activities column,
suggest changing under Verify: Battery terminal connection resistance To: Entire battery bank terminal
connection resistance (This could have been interpreted as individual batteries) And change: Battery cell-tocell connection resistance To: Battery cell-to-cell connection resistance, where an external mechanical
connection is available.
2. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid batteries) suggest
changing Max Maintenance Interval=3 Calendar Years or 3 Calendar Months to 4 Calendar Years or 12
Calendar Months. Our concern is that the insurance companies may push NERC maintenance intervals on all
battery banks not associated with the BES.
3. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max Maintenance Interval=6
Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade the battery.
Comment:
4. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max Maintenance
Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade
the battery.
5. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and trip circuitry) we
suggest the following change: If a trip circuit comprises multiple paths, at least one of those paths is
monitored. Alarming for loss of continuity or dc supply for trip circuits is reported to a location where action
can be taken.
6. While all tripping circuits are not completely monitored, the trip coils and the outdoor cable runs are
completely monitored. The only portion that would not be monitored is a portion of inter and intra-panel
wiring having no moving parts located in a control house. Our company has extremely low failure rate of
panel wiring and terminal lugging. I don’t think that there is provision for moving control and trip circuitry to
performance based maintenance? This control circuitry should be maintained less frequent than un-monitored
trip circuits (6 years).
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-
November 17, 2010
25
4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. NERC Standards are limited to facilities and equipment related to the BES. How the Standard may be
otherwise used is outside the scope of NERC Standards.
3. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Vented
Lead Acid and Ni-Cad batteries. A properly maintained battery, according to various credible references
(from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle multiple deep discharges over its
expected life.
4. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Ni-Cad
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI,
various manufacturers, etc.), can easily handle multiple deep discharges over its expected life.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
Nothing in the draft Standard (including Attachment A) precludes an entity from using performance-based
maintenance for dc control circuits.
Segment:
Organization:
1, 3, 5, 6
Dominion Virginia Power, Dominion Resources Services, Dominion Resources, Dominion Resources Inc.
Member: John K Loftis, Michael
F Gildea, Mike Garton, Louis S Slade
1. There is not enough clarity to clearly identify which protection system components are necessary to protect
the BES. We suggest that 4.2.1 be revised to read “protection systems that are designed to provide protection
for the BES.”
2. The Standard does not provide a grace period if an entity is unable to meet the maintenance requirement
for extenuating circumstances. For example if an entity has to divert maintenance resources to storm
Comment:
restoration. We do not believe the reliability of the Bulk Electric System will be compromised if an entities'
maintenance program slips by a few months due to extreme events, especially if it is brought back on track
within a short time frame.
3. We are opposed to the six calendar year maximum maintenance interval for microprocessor relays that
have auxiliaries.
November 17, 2010
26
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The SDT disagrees and believes that the Applicability is correct as stated.
2. “Grace periods” within the Standard are not measurable, and would probably lead to persistently
increasing intervals. However, an entity may establish an internal program with grace-period allowance,
as long as the entire program (including grace periods) does not exceed the intervals within the Standard.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
3
Allegheny Power
Bob Reeping
The draft standard expects 100% compliance for millions of protection system components at all times. The
standard should consider a statistically based performance metric instead of a performance target that expects
100% compliance.
Thank you for your comment. The NERC criteria for VSLs do not currently permit them to allow some level
of non-performance without being in violation.
1
Public Service Company of New Mexico
Laurie Williams
Overall, the inclusion of several types of protective relay systems into one standard is reasonable and should
include those associated with UVLS and UFLS. Even so, the standard is unmanageably cumbersome with far
too many details.
Although it has been said that protection systems include the instrument transformers, DC system and
sometimes the breaker trip coils it is equally as true to say that the protective relay systems depend on those
Comment: to effectively respond to the anomaly, typically a short circuit fault. With that said it is those item’s
maintenance that should potentially be moved to different standards to improve clarity. Their inclusion into
this standard by size and complexity overwhelms this standard. This standard should include only those items
that utilize similar equipment and techniques to maintain. In this case and at this time that means computercontrolled test sets that also generate the records necessary to prove compliance.
Even after distilling the standard to only protective relay systems the complexities and details used to explain
November 17, 2010
27
the non-time-based methodologies contribute to the confusion. But the availability of those methodologies is
important and probably cannot be in a different standard. It therefore seems imperative with the inclusion of
those methodologies that the DC support system maintenance and instrument transformer maintenance have
different standards. The inclusion of so much explanation inside the standard is distracting and perhaps
contributes to the confusion.
PNM also offers the following specific feedback on the proposed standard:
1. -R1.1: Uniquely identifying ‘Protection System components’ as asked for in R1.1 may be problematic
given protective systems may be logged in maintenance databases as packages rather than individual
elements. Because the elements within each package are tested as a group, the requirement to individually list
the components of the package and track them as such would provide no additional benefit to system
reliability.
2. -The activities outlined in Tables which begin on Page 9 of the proposed Standard are difficult to align
with the VSLs given in the standard.
3. -The Tables suggest that test trips of equipment are required as part of the scheduled program, but test trips
of equipment may pose a hazard to the BES if the equipment fails due to multiple test trips or mis-operates to
remove additional BES facilities from service (ex., breaker failure mis-operation during line relay trip
testing), which may pose a potential risk to the BES. An example would be 8 test trips of a generator breaker
in order to make it through the testing of all of the system components that have the ability to trip the
generator lockout and therefore the breaker. Suggest wording to be added that would include some sort of
breaker tripping simulation (test box, lockout simulator, etc.) that could be built into the circuit?
4. -It is still unclear how the audit of an entity’s compliance which occurs during the transition time will be
viewed if it chooses to immediately transition all of its components to the intervals defined in the standard,
but were out of the interval defined by the entity under PRC-005-1?
5. -From the Table 1a – “Verify proper function of the current and voltage signals” is not defined. Is the
verification visual? How is this easily measured on circuits with EM relays still in service?
6. -If exposure to BES is evident during a testing interval, how does the TO or GO coordinate with its
November 17, 2010
28
Reliability Coordinator to delay or push out testing that may compromise the testing due date? Example –
critical transmission circuit is removed from service under forced outage, testing due on adjacent or other
critical circuit where test tripping could compromise BES. What is the documentation procedure to get an
exception or coordinate with RC to mitigate? This has been a big hole in any testing program; there is no way
to file an exception due to unforeseen circumstances like this one.
7. -Is it recommended that there be on PSMP per Company no matter how many Entities they may have or
should there be one PSMP for each entity? Standard is unclear on this issue.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
in consideration of your comment.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5. The VSLs have been modified to correspond.
3. The Standard allows functional testing, if used, to be done in overlapping segments to avoid
specifically the situations you cite.
4. This is a concern that should be submitted to the compliance monitor.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-3. Also please see Section 15.2 of the Supplementary Reference and FAQ II.3.A, II.3.B, II.3.C, and
II.3.D.
6. It would seem prudent to schedule your maintenance to allow for such contingencies. “Grace
periods” within the Standard are not measurable, and would probably lead to persistently increasing
intervals. However, an entity may establish an internal program with grace-period allowance, as long
as the entire program (including grace periods) does not exceed the intervals within the Standard.
7. This is up to the entity. For example, you may choose to have one PSMP for a transmission function
and a separate one for a generation function.
1
PPL Electric Utilities Corp.
Brenda L Truhe
Comment:
PPL EU is voting negative because the definition of Protective Relays is not limited to only those devices that
use electrical quantities as inputs (exclude pressure, temperature, gas, etc).
Response:
Thank you for your comment. The Standard does not preclude entities from maintaining such devices or
November 17, 2010
29
including them in their PSMP.
Segment:
Organization:
Member:
1, 3
Platte River Power Authority
John C. Collins, Terry L Baker
The standard is very difficult to interpret even with all of the supplemental documentation and we believe this
will lead to more non-compliance of the standard without any increase to system reliability and in some cases
Comment:
the required testing will actually reduce system reliability by putting the system at unnecessary risk to
complete the testing.
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5.
1
Nebraska Public Power District
Richard L. Koch
Comment:
The negative vote is based upon functional trip checking and the affect that it will have on the BES.
Response:
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5, which no longer includes any specific requirements for functional testing.
Performance-based maintenance can also be applied to these functions.
Segment:
Organization:
Member:
Comment:
1
National Grid
Saurabh Saksena
1. National Grid does not agree with the proposed implementation plan. The time provided for the first phase
“at least six months” is too open ended and does not give entities a clear timeline. National Grid suggests 1
year for the first phase. National Grid also suggests phasing out the second phase in stages.
2. National Grid does not support the VSL criteria based on "total number of components". Calculating total
number of components will be hugely costly and does not enhance any reliability. It will also take away the
much needed resources required for maintenance.
Response:
November 17, 2010
Thank you for your comment.
30
1. This comment appears to be related to the Implementation Plan for the definition (which was
independent to the Standard), not to the Standard.
2. The SDT believes that the only alternative to these criteria is to provide a binary VSL, which would
mean that any non-compliance would be “Severe”.
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
3
Niagara Mohawk (National Grid Company)
Michael Schiavone
National Grid does not agree with the proposed implementation plan. The time provided for the first phase
“at least six months” is too open ended and does not give entities a clear timeline. National Grid suggests 1
year for the first phase. National Grid also suggests phasing out the second phase in stages.
Thank you for your comment. This comment appears to be related to the Implementation Plan for the
definition (which was independent to the Standard), not to the Standard.
1, 3
MidAmerican Energy Co.
Terry Harbour, Thomas C. Mielnik
For control and trip circuit maintenance the requirement includes “a complete functional trip test”. In order to
accomplish this type of testing given current design of lock-out relay and interrupting device trip circuitry
multiple breakers and line terminal outages would be required simultaneously. In addition this type of testing
has the potential to result in unintentional tripping of equipment that could cause equipment damage and
Comment: customer outages. Segmentation of trip circuits by lifting wires has the potential for incorrect restoration
following testing. This type of testing has the potential to degrade system reliability as multiple entities
schedule this work. An alternate to complete functional testing that does not potentially degrade system
reliability should be substituted.
Response:
November 17, 2010
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5, which no longer includes any specific requirements for functional testing.
Performance-based maintenance can also be applied to these functions. Electromechanical devices such as
aux or lockout relays remains at 6 years, as these devices contain “moving parts” which must be periodically
exercised to remain reliable.
31
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
1
Idaho Power Company
Ronald D. Schellberg
Monitoring the state of charge using current measurement methods would increase the workload and staffing
requirements beyond what we feel is necessary with little additional value to reliability beyond specific
gravity measurements.
Thank you for your comment. The Standard is requiring that state-of-charge be determined, but does not
specify how. Specific gravity testing (no longer required within the Tables) would be one method.
1
Commonwealth Edison Co.
Daniel Brotzman
1. Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission
(NRC). Each licensee operates in accordance with plant specific Technical Specifications (TS) issued
by the NRC which are part of the stations’ Operating License. TS allow for a 25% grace period that
may be applied to TS Surveillance Requirements. Referencing NRC issued NUREGs for Standard
Issued Technical Specifications (NUREG-143 through NUREG-1434) Section 3.0, "Surveillance
Requirement (SR) Applicability," SR 3.02 states the following: "The specified Frequency for each SR
is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as
measured from the previous performance or as measured from the time a specified condition of the
Frequency is met." The NRC Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness
of maintenance to ensure reliable operation of equipment within the scope of the Rule. Adjustments
are made to the PM (preventative maintenance) program based on equipment performance. The
Maintenance Rule program should provide an acceptable level of reliability and availability for
equipment within its scope. The NRC has provided grace periods for certain maintenance and
surveillance activities. Exelon strongly believes that SDT should consider providing this grace period
to be in agreement and be consistent with the NRC methodology. Not providing this grace period will
directly affect the existing nuclear station practices (i.e., how stations schedule and perform the
maintenance activities) and may lead to confusion as implementing dual requirements is not the
normal station process. Nuclear generating stations have refueling outage schedule windows of
approximately 18 months or 24 months (based on reactor type). If for some reason the schedule
32
window shifts by even a few days, an issue of potential non-compliance could occur for scheduled
outage-required tasks. The possibility exists that a nuclear generator may be faced with a potential
forced maintenance outage in order to maintain compliance with the proposed standard.
For the requirements with a maximum allowable interval that vary from months to years (including 18
Months surveillance activities), the SDT should consider an allowance for NRC-licensed generating
units to default to existing Operating License Technical Specification Surveillance Requirements if
there is a maintenance interval that would force shutting down a unit prematurely or face noncompliance with a PRC-005 required interval. Therefore, at a minimum, maintenance intervals should
include an allowance for any equipment specifically controlled within each licensee’s plant specific
Technical Specifications to implement existing Operating License requirements if such a conflict were
to occur.
2. Additionally we are requesting to have the first phase of implementation extended from 6 months to 1
year. This will provide adequate time for development of documentation, training for all personnel,
and testing the implementation of the new process (es).
Response:
Thank you for your comments.
1. The SDT understands that nuclear power plants are licensed and regulated by the NRC, has a general
understanding of the role that plant Technical Specifications (TS) and associated Surveillance
Requirements (SR) play in the facilities’ operating licenses, and has tried to be sensitive to potential
conflicts between PRC-005-2 and NRC requirements.
The SDT believes that the majority of components making up the Protection Systems for in-scope
generating facilities as discussed in Section 4.2.5 of the Standard would be considered balance of plant
equipment and, therefore, not subject to NRC issued TS and associated SR requirements. While
availability of plant auxiliary sources to the plant’s safety related equipment is addressed by TS and
associated SR requirements, these documents are focused on the effects that the availability of these
transformers have on reactor safety rather than specifying maintenance and testing requirements for the
Protection Systems for these transformers.
The SDT recognizes that some battery systems may serve as a source of DC power to both reactor
November 17, 2010
33
safety systems and to protection systems discussed in Section 4.2.5. The SDT acknowledges that there
might be plant TS and SR applicable to these batteries. However, the SDT believes that the 3-month
and 18-month inspection requirements called for in PRC-005-2 would be no more onerous than plant
TS requirements for routine online safety system battery inspections and, furthermore, would not
necessitate a plant outage. The SDT recognizes that the PRC-005-2 requirement for validating battery
design capability via battery capacity testing would require a plant outage. However, it is the opinion
of the SDT that the maximum allowed battery capacity testing intervals of not to exceed 6 calendar
years for vented lead acid or NiCad batteries (not to exceed 3 calendar years for VRLA batteries) could
easily be integrated within the plant’s routine 18 month to 2 year interval refueling outage schedule.
The SDT believes that PRC-005-2 is complimentary to the NRC Maintenance Rule in that PRC-005-2
requirements allow for the leveraging of the entire electrical power industry experience in establishing
minimum maintenance activities and maximum allowed maintenance intervals necessary to ensure
reliable protection system performance.
Please see Supplemental Reference Section 8.4 for further discussion for the SDT’s rationale for
exclusion of grace periods.
Please see FAQ IV.2.C for further discussion of impact of PRC-005-2 testing requirements on power
plant outage schedules. The challenge of integrating PRC-005-2 testing requirements with a plant’s
outage schedule is not unique to nuclear plants.
Finally, the SDT notes that an entity may build grace periods into its own PSMP as long as the
maximum allowed time intervals of PRC-005-2 are not exceeded. If an entity wishes to build a 25%
grace period into its program, it may do so by setting its program maintenance and testing intervals at
<80% of the PRC-005-2 maximum allowable time interval.
2. The Implementation Plan for R1 has been modified to 12 months.
Segment:
Organization:
Member:
November 17, 2010
1, 3, 6
Cleco Power LLC, Cleco Utility Group, Cleco Power LLC
Danny McDaniel, Bryan Y Harper, Matthew D Cripps
34
1. The revised definition to Protection System should include the following exception. "Devices that sense
non electrical conditions, such as thermal or transformer sudden pressure relays are not included." The
Drafting Team has included this note in the standard, but not in the definition. For consistence across the
standards, see PRC-004, which references System Protection, the same definition should be used.
2. See Table 1a, Station dc supply. One of the checks is to verify battery cell-to-cell connection resistance.
Comment: This is not possible in all battery sets.
3. As written, the standard requires testing of batteries, DC control circuits, etc., of distribution level
protection components associated with UFLS and UVLS. This is beyond the scope of the Reliability
Standards which should focus on the BES. Only include the UFLS or UVLS relays in the program.
4. Revise M1 to reference Protection System definition.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The definition of “Protection System” has been modified essentially as you suggest.
2. “Cell” has been replaced with “cell/unit.”
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-4 and 1-5.
1
BC Transmission Corporation
Gordon Rawlings
1. - Purpose unclear “affecting the reliability of the BES” is open to interpretation should read “applied on or
designed to provide protection of the BES”
2. - Monitoring levels (1, 2 and 3) are not clear
Comment:
3. - Maintenance activities are not well defined
4. - Some utilities base their maintenance program on a fiscal year where all scheduled maintenance for the
fiscal year must be completed by the end of the fiscal year. It would take considerable effort to switch to end
of calendar year with zero improvement in overall reliability.
November 17, 2010
35
5. - For maintenance scheduled in terms of a number of months, requiring that maintenance be completed by
the end of scheduled month does not leave much margin if maintenance is delayed for a legitimate reason.
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
Thank you for your comment.
1. The purpose can be general; Requirement R1 is worded as you suggest.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5. Various sections of the FAQ have provided suggestions about how to conduct the
activities in the tables.
4. With the vast array of entities subject to compliance monitoring, it would be very difficult for the
ERO to assess compliance for varying “years.” Additionally, the SDT understands that most
compliance monitors currently request data on a calendar year basis when assessing compliance.
5. The entity is encouraged to schedule the maintenance activities to allow for contingencies.
1
Associated Electric Cooperative, Inc.
John Bussman
There needs to be grace periods for the battery testing of 3 months. Testing a complete transmission system
over 3 states in every 3 months and not be one day past due will b a challenge.
Thank you for your comment. The 3-month maintenance for station dc supply is comprised of inspections
that don’t require testing.
1, 3, 5
Arizona Public Service Co., APS
Robert D Smith, Thomas R. Glock, Mel Jensen
1. The generator Facilities subsections 4.2.5.1 through 5 are too prescriptive and inconsistent with sections
4.2.1 through 4. Recommend this section be limited to description of the function as in the preceding
sections.
2. In addition, the associated maintenance activities in Table 1 are too prescriptive.
November 17, 2010
36
3. The activities needed to ensure the reliable service of the relay or device should be left up to the discretion
of the utility. One example, due to the change to the Protection System definition and establishing a new
PSMP with prescriptive maintenance activities relative to the voltage and current sensing devices has created
a situation where data from original or prior verification is not available or not at the interval to meet the data
retention requirement. Although, methods of determining the integrity of the voltage and current inputs into
the relays were used to ensure reliability of the devices met the utilities performance requirements, they may
not meet the interval requirement and would then be considered a violation due to changes in the standard.
4. For data requirements, an initial exemption is recommended for the two recent most recent performances
of maintenance activities in the first maintenance interval for this component due to the long maintenance
interval, the changes in the standard definitions and the prescriptive maintenance activities.
5. Clarification is needed on “Note 1” in Table 1a, which appears to be used to define a calibration failure.
How would it be used in Time Based Maintenance? In PRC-005-2 Attachment A: Criteria for a PerformanceBased Protection System Maintenance Program, a calibration failure would be considered an event to be used
in determining the effectiveness of Performance Based Maintenance. It is unclear in how it will be used in
time based maintenance.
Response:
November 17, 2010
Thank you for your comment.
1. The SDT believes that transmission lines, UFLS, UVLS, and SPS are clear without additional
granularity, but that the additional granularity regarding generation plants is necessary. This is
illustrated by numerous questions regarding “what is included for generation facilities” relative to
PRC-005-1.
2. FERC Order 693 and the approved SAR assigned the SDT to develop a Standard with maximum
allowable intervals and minimum maintenance activities.
3. FERC Order 693 and the approved SAR assigned the SDT to develop a Standard with maximum
allowable intervals and minimum maintenance activities. It seems reasonable that you cannot be held
accountable for a requirement before it becomes effective.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the
Compliance Monitor will need the data of the most recent performance of the maintenance, as well as
the data of the preceding one, as well as data to validate that entities have been in compliance since
the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified the
data retention in the posted Standard to establish this level of documentation. The Tables have been
rearranged and considerably revised to improve clarity, and the cited note removed. Please see new
37
Tables 1-5.
Segment:
Organization:
Member:
1
American Transmission Company, LLC
Jason Shaver
ATC does not support the existing 2nd Draft of PRC-005-2 Standard because it is our opinion that:
• There is a high probability that system reliability will be reduced with this revised standard.
• The number of unplanned outages due to human error will increase considerably.
Comment:
• Availability of the BES will be reduced due to an increased need to schedule planned outages for test
purposes (to avoid unplanned outages due to human error).
• To implement this standard, an entity will need to hire additional skilled resources that are not readily
available. (May require adjustments to the implementation timeline.)
• The cost of implementing the revised standard will approximately double our existing cost to perform this
work. ATC requests that relevant reliability performance data (based on actual data and/or lessons learned
from past operating incidents, Criteria for Approving Reliability Standards per FERC Order 672) be provided
to justify the additional cost and reliability risks associated with functional testing.
Response:
Segment:
Organization:
Member:
Thank you for your comment. The SDT believes that performing these maintenance activities will benefit the
reliability of the BES.
1, 5, 6
American Electric Power, AEP Service Corp, AEP Marketing
Paul B. Johnson, Brock Ondayko, Edward P. Cox
AEP supports the progress of this draft standard, largely supports much of the elements within. However, we
provide the following summary of the comments provided in response to the most recent (2nd) draft, which
Comment: we suggest the SDT consider.
1. In Table 1a for the component “Station dc Supply (used only for UVLS and UFLS)”, the interval
November 17, 2010
38
prescribed is "(when the associated UVLS or UFLS system is maintained)" and the activity is to "verify the
proper voltage of the dc supply". The description of the interval "(when the associated UVLS or UFLS
system is maintained)" needs to be changed. Relay personnel do not generally take battery readings. The
interval should read “according to the maximum maintenance interval in table 1a for the various types of
UFLS or UVLS relays". The testing does not need to be in conjunction with the relay testing, it is only the
test interval that is important, although relay operation during relay testing is a good indicator of sufficient
voltage of the battery.
2. The monitoring and/or maintenance activities listed for batteries are not appropriate in Tables 1b and 1c.
There are no commercial battery monitors that monitor and alarm for electrolyte level of all cells. Why not
move the electrolyte level to the 18 month inspection and actually open the possibility of condition
monitoring to commercially available devices? Or give an option to do the electrolyte check at other time
intervals (perhaps 12 months) by visual electrolyte inspection and still allow the monitoring of other
functions on the listed 6 year schedule using condition monitoring. It makes no sense to prescribe an
unattainable condition monitoring solution. The way that the tables are written, there is no advantage to use
the charger alarms since battery maintenance requirements are not reduced in any way.
3. In regards to "Measures and Data Retention", the measure includes the entire definition of "Protection
System". Remove the definition from the measure and let the definition stand alone in the NERC glossary.
4. In regards to Data Retention, this calls for past 2 distinct maintenance records to be kept. Since UFLS
interval can be 12 years, this would mean that we would need to keep records for 24 years. This is not
realistic and consideration should be given to choosing a reasonable retention threshold.
5. The "Supplementary Reference" and the "Frequently-Asked Questions" document should be combined into
a single document. This document needs to be issued as a controlled NERC approved document. AEP
suggests that the document be appended to the standard so it is clear that following directions provided by
NERC via the document are acceptable, and to avoid an entity being penalized during an audit if the auditor
disagrees with the document’s contents.
6. NiCAD batteries should not be treated differently from Lead-Acid batteries. NiCAD battery condition can
be detected by trending cell voltage values. Ohmic testing will also trend battery conditions and locate failed
cells (although will usually lag behind cell voltages). A required load test is detrimental to the NiCAD
November 17, 2010
39
manufacturer's business, and will definitely hurt the NiCAD business for T&D applications. Historically
NiCADs may have been put into service because of greater reliability, smaller space constraints, and wider
temperature operation range. “Individual cell state of charge” is a bad term because it implies specific gravity
testing. Specific gravity cannot be measured automatically (without voiding battery warranty or using an
experimental system), and when it is measured, it is unreliable due to stratification of the electrolyte and
differing depths of electrolyte taken for samples. “Battery state of charge” can be verified by measuring float
current. Once the charging cycle is over the battery current drops dramatically, and the battery is on float,
signaling that the battery has returned to full state of charge. This is an appropriate measure for Level 3
monitoring as float current monitoring is a commercially viable option and electrolyte level monitoring is not.
7. In Table 2b, why is Ohmic testing required if the battery terminal resistance is monitored? Cell to cell and
battery terminal resistance should not be monitored because they will be taken in 18 month intervals. This
further supports the argument that the battery charger alarms would be sufficient for level 2 monitoring, while
keeping an 18 month requirement for Ohmic testing, electrolyte level verification, and battery continuity
(state of charge). Automatic monitoring of the float current should be sufficient for level 3 monitoring as it
gives state of charge of the string, and battery continuity (detect open cells). Shorted cells will still be found
during the Ohmic testing and a greater interval is sufficient to locate these problems.
Response:
November 17, 2010
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
3. The SDT modified the Measure as you suggested.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the
Compliance Monitor will need the data of the most recent performance of the maintenance, as well as
the data of the preceding one, as well as data to validate that entities have been in compliance since
the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified the
data retention in the posted Standard to establish this level of documentation. The SDT disagrees that
the documents should be combined. The Supplementary Reference is a holistic presentation of
rationale and basis for the various elements of the Standard – discussing mostly the “what” behind the
requirements. The FAQ, on the other hand, presents responses to specific frequently asked questions,
and, as such, offers more-focused advice on specific subjects, and is more of an example/how-to
discussion. The FAQ is primarily a means of capturing some of the most prevalent comments offered
40
on the Standard by various entities, with the SDT’s response. The SDT believes that the format of the
FAQ is a more effective means of presenting the included information than it would be to include this
information within the text of the Supplementary Reference document.
5. The SDT believes that since the IEEE Stationary Battery Committee has determined that VRLA
batteries and Ni-Cad batteries are different enough to require separate IEEE Standards (IEEE 1188
and IEEE 1106, respectively), these battery technologies are different enough to be treated separately
within PRC-005-2. The SDT has drawn upon these IEEE Standards, as well as other sources (EPRI,
etc) to develop the requirements of PRC-005-2. The trending activity cited has not been shown to be
effective for Ni-Cad batteries (see FAQ II.5.G), and thus a performance test must be performed; the
performance test may take many forms. The Tables have been rearranged and considerably revised to
improve clarity, and all references to specific gravity have been removed. Please see new Table 1-4.
Determining the “state of charge” by monitoring the float voltage may be relevant to the overall
station battery, but does not provide an indication of the condition of individual cells as required
within the new Table 1-4.
6. Battery terminal resistance shows the condition of the external connections, but reveals nothing
regarding the internal condition of the individual cells. Measuring the internal cell/unit resistance
provides an opportunity to trend the cell condition over time by verifying the electrical path through
the electrolyte within the battery. The ohmic testing is not intended to look for open cells/units, but
instead at the ability of the individual cell/unit to perform properly. The new Table 1-4 clarifies that,
if the electrolyte level is monitored, the internal ohmic testing need only be performed every six years.
Please see FAQ II.5.B, II.5,C and II.5.D for a discussion about continuity.
Segment:
Organization:
Member:
1
Ameren Services
Kirit S. Shah
We commend the SDT for developing a generally clear and well documented second draft. The SDT
considered and adopted many industry comments on the first draft. It generally provides a well reasoned and
balanced view of Protection System Maintenance, and good justification for its maximum intervals. Ameren
Comment: generally agrees that this second draft will be beneficial to BES reliability, but several inconsistencies,
unclear items, and a couple issues need to be addressed before we will be able to support it.
(a)The tables still contain several inconsistencies and items needing clarification
November 17, 2010
41
(b)Implementation of the PSMP must align with the start of a calendar year
(c) The expectation of perfection in maintaining the extremely high volume of Protection System parts is
inconsistent with accepted engineering practice (a fundamental tenet is that tolerances must be allowed for)
(d)The Project 2009-17 interpretation that clarifies the transmission Protection System border must be
incorporated.
(e)Generating Plant system-connected Station Service transformers should not be included as a Facility
because they are serving load.
Thank you for your comment.
a. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
b. The SDT Guidelines, which were endorsed by the NERC Standards Committee in April 2009,
establishes that proposed effective dates “must be the first day of the first calendar quarter after
entities are expected to be compliant.” The Implementation Plan is in accordance with these
guidelines.
c. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
Response:
without being in violation.
d. When the interpretation (Project 2009-17) is approved, the SDT for PRC-005-2 will consider if the
interpretation is appropriate for PRC-005-2 and make associated changes.
e. The “load” being served by the Station Service Transformer may be essential to operation of the
generating plant, and therefore is not the same as general distribution system load. Therefore, the
SDT believes that these system components must remain within the Applicability section of the
Standard.
Segment:
Organization:
Member:
Comment:
November 17, 2010
3
Florida Power Corporation
Lee Schuster
Progress Energy does not believe that the definition should be implemented separately from and prior to the
implementation of PRC-005-2. We believe there should be a direct linkage between the definition’s effective
date to the approval and implementation schedule of PRC-005-2. Since this new definition should be directly
42
linked to the proposed revised standard, it would be premature to make this new definition effective prior to
the effective date of the new standard. We believe that changes to the maintenance program should be driven
by the revision of the PRC standard, not by the revision of a definition.
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Thank you for your comment. When the Board of Trustees was asked to approve an interpretation of PRC005-1 that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the
drafting team caused by the definition of "Protection System" and directed that work to close this reliability
gap should be given priority. To close this reliability gap the revised definition must be applied to PRC-0051 as soon as practical - not years from now. The Implementation Plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
1, 3, 5, 6
Bonneville Power Administration
Donald S. Watkins, Rebecca Berdahl, Francis J. Halpin, Brenda S. Anderson
Please see BPA's comments submitted during the concurrent formal NERC comment period ending July 16,
2010.
Thank you for your comment. Please see our responses on the Consideration of Comments from the cited
comment period.
6
Northern Indiana Public Service Co.
Joseph O'Brien
1. It appears that some batteries are not able to accommodate all of the tests required in this standard.
Comment:
Response:
2. The standard also unreasonably requires 100% compliance for millions of protection system components.
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
November 17, 2010
43
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
6
Lakeland Electric
Paul Shipps
As written, is opens the standard to Technical Feasibility Exceptions due to some batteries not being able to
accommodate all of the tests proscribed in the draft standard
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-4. “Cell” has been replaced with “cell/unit” to address this concern. The Standard
only addresses distribution-located devices to the degree that they address BES issues. UFLS and UVLS per
the relevant NERC Standards are frequently implemented on the distribution system.
4
Fort Pierce Utilities Authority
Thomas W. Richards
1. The battery test procedure that calls for intra-cell resistance cannot be performed on batteries that have
internal cell-to-cell straps. A brief rewording of the requirement would take care of this. We recommend the
minimum requirement be changed to measure the internal resistance at the battery terminal. The reading of
individual cells is of little use anyway since a bad reading will result in having to replace the entire jar.
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit testing,
etc. on distribution elements with no significant improvement to BES reliability, which is beyond the
statutory scope of the standards.
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components. The audit becomes an investigation at this point and is not feasible even for
mid-sized entities that have hundreds of components subject to this standard.
Response:
November 17, 2010
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. “Cell” has been replaced with “cell/unit” to address this concern.
2. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
44
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
Segment:
Organization:
Member:
5
PowerSouth Energy Cooperative
Tim Hattaway
The maintenance and testing requirements are too prescriptive and leave little room for an entity to make
decisions regarding what type maintenance and testing they deem appropriate. Some of the maintenance and
testing methods and intervals as defined in the standard, e.g. the standard calls for a maximum 3 month
testing interval for sealed station batteries if performing impedance testing, do not seem to improve reliability
Comment:
at all.
The migration from compliance with the present standard to version 2 as prescribed would be a monumental
administrative task
Response:
Segment:
Organization:
Member:
Thank you for your comment. FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
5
Liberty Electric Power LLC
Daniel Duff
Comment:
Required tasks are overly prescriptive.
Response:
Thank you for your comment. FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
Segment:
Organization:
Member:
Comment:
November 17, 2010
5
ExxonMobil Research and Engineering
Martin Kaufman
In the past, NERC has taken care to avoid instructing an entity on how to create its compliance program. The
draft standard PRC-005-2 departs from this tradition and partially defines a maintenance and testing program
that all entities will be required to follow until such a time that the entity has collected enough data to
45
implement the performance based method defined in Attachment A.
Additionally, some of the maintenance and testing intervals defined in the tables (e.g. station battery testing)
mimic industry recommended test intervals instead of defining maximum acceptable testing intervals.
Response:
Segment:
Organization:
Member:
Thank you for your comment. FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
4
Y-W Electric Association, Inc.
James A Ziebarth
From Question 1 on the comment form:
Many of the changes to the proposed standard are reasonable and improve the clarity of the standard and its
requirements. However, Y-WEA concurs with others on their comments regarding the testing of battery cellto-cell connection resistance. Many types of stationary batteries are actually blocks of two or more cells that
are internally connected. This requirement would necessitate either some sort of feasibility exception process
(which, as shown by the TFE process with the CIP standards can be very difficult, cumbersome, and timeconsuming to develop and administer) or replacement of the batteries in question, which would pose
enormous burdens on small entities that must comply with this standard. The language in this requirement
should be changed from “cell-to-cell” to “unit-to-unit” in order to avoid these issues.
From Question 7 on the comment form:
Comment: 1. Y-WEA concurs with others regarding the timing of required battery tests. The IEEE standards referenced
indicate target maintenance intervals. In order to remain reasonable, then, this compliance standard needs to
allow some buffer between a targeted maintenance and inspection interval and a maximum enforceable
maintenance and inspection interval. The suggestion of a four-month maximum window is reasonable and
should be incorporated into the standard.
2. Y-WEA is also concerned with R1.1’s language indicating that all components must be identified with no
defined “floor” for the significance of a component to the Protection System. The SDT cannot possibly
expect that a parts list containing every terminal block, wire and jumper, screw, and lug is going to be
maintained with every single part having all the compliance data assigned to it, but without clearly stating
this, that is exactly the degree of record-keeping that some overzealous auditor could attempt to hold the
registered entity to. The FAQ is much clearer as to what is and is not a component and should be considered
November 17, 2010
46
for the standard.
3. Y-WEA also concurs with others' comments regarding the testing of batteries and DC control circuits
associated with UFLS relaying. Many UFLS relays are installed on distribution equipment. Furthermore,
many distribution equipment vendors are including UFLS functions in their distribution equipment. For
example, many recloser controls incorporate a UFLS function in them. These controls and the reclosers they
are attached to, however, are strictly distribution equipment. 16 USC 824o (a)(1) limits the definition of the
Bulk-Power System to “not include facilities used in the local distribution of electric energy.” A distribution
recloser and its control clearly fall into this exclusion. 16 USC 824o (i) (1) prohibits the ERO from
developing standards that cover more than the Bulk-Power System. As such, the DC control circuitry and
batteries associated with many UFLS relaying installations are precluded from regulation under NERC’s
reliability standards and may not be included in this standard because they are distribution equipment and
therefore not part of the Bulk-Power System. The proposed standard needs to be rewritten to allow for this
exclusion and to allow for the testing of only the UFLS function of any distribution class controls or relays.
Response:
Thank you for your comment.
From Question 1 - The Tables have been rearranged and considerably revised to improve clarity. Please
see new Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or
unit-to-unit connection resistance (where available to measure)” to address this comment.
From Question 7 –
1. The SDT disagrees. You should complete the activities within the intervals specified.
2. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
in consideration of your comment.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-4 and 1-5.
Segment:
Organization:
Member:
Comment:
November 17, 2010
4
Old Dominion Electric Coop.
Mark Ringhausen
While the SDT has made progress, there are still some areas that need additional work:
47
1. Battery testing of the cell to cell should be unit to unit or some other words for battery system locations
that do not allow cell to cell testing.
2. Battery checks on a three months period seems to aggressive and should be moved to six months.
3. Clarify your intent to test the CTs and PTs as some commenters have read it that one does not have to test
these pieces of equipment per this standard.
4. Require UFLS and UVLS testing to trip the breaker/recloser when this can be done without tripping of
load (by-pass is available).
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The SDT disagrees. You should complete the activities within the intervals specified.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-3.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
3
Springfield Utility Board
Jeff Nelson
Comment:
Please see SUB's comments on the comment form
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
Comment:
Response:
November 17, 2010
3
Salem Electric
Anthony Schacher
The standard is getting better but leaves to many holes for utilities that do not have specific equipment and
would need to file a TFE to exempt their facilities.
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Tables 1-1 through 1-5.
48
Segment:
Organization:
Member:
3
Public Utility District No. 2 of Grant County
Greg Lange
Although this version is a significant improvement in several areas from the past version there are still several
things that need clarification or overhaul.
Comment:
1. We find an inconsistency between the component based approach to version 2 and the way protective
systems are maintained. The description of components still needs work as well.
2. It appears that in the new version battery chargers and cables could be professionally judged to be a part of
the circuitry. We don't believe this is the intent, but again leaves too much to the imagination of an
overzealous auditor. Truly most of our issues are with the definition, but until that is corrected we cannot vote
for either.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. A definition of “Component” has been added to the Standard and the Tables have been rearranged and
considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
2. The dc supply component specifically includes battery chargers within the new Table 1-4.
3
Public Utility District No. 1 of Chelan County
Kenneth R. Johnson
Comments:
1. It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are
included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that
particular standard to protection systems that sense electrical quantities, it is remains unclear in other
Comment: standards that use the defined term whether mechanical input protections are included.
2. We suggest that “Protective Relay” also be defined, and that the definition clearly exclude devices that
respond to mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG
request.
Response:
November 17, 2010
Thank you for your comment.
1. The definition of Protection System has been modified to specifically limit it to protective relays that
49
respond to electrical quantities.
2. IEEE has provided a definition of protective relay, and the SDT sees no need to repeat or change that
definition within this Standard.
Segment:
Organization:
Member:
3, 3
Municipal Electric Authority of Georgia, MEAG Power
Steven M. Jackson, Steven Grego
1. Station DC supply testing was set at three months. A six month time based testing interval is reasonable.
2. Maximum maintenance interval for a lead-acid vented battery is listed at six calendar years. This type of
test reduces battery life. A 10 to 12 year interval is reasonable. As written this rule would require a TFE that
should be administratively unnecessary.
Comment:
3. Additional clarification is needed in: Control and trip circuits associated with UVLS and UFLS do not
require tripping of the breakers but all other protection systems require tripping. Please clarify.
4. Digital relays have electromagnetic output relays - are they categorized as electromechanical or solid state?
5. There needs to be reasonable flexibility based on industry experience in allowing less than 100%
perfection in the testing of relays, etc.
Response:
Segment:
Organization:
November 17, 2010
Thank you for your comment.
1. The SDT disagrees.
2. The SDT disagrees.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-1.
5. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
3, 4, 5
Cowlitz County PUD
50
Member:
Russell A Noble, Rick Syring, Bob Essex
Cowlitz agrees with most of the changes; however there are many issues from the last comment round that
needs to be addressed with a response from the SDT. In particular, Cowlitz is concerned with the following:
1. Verify Battery cell-to-cell connection resistance” has entered the table where it did not exist before. On
some types of stationary battery units, this internal connection is inaccessible. On other types the connections
are accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell connections
within units will be detected by the other required tests. This requirement will cause entities to scrap perfectly
good batteries just so this test can be performed, with no corresponding increase in bulk electric system
reliability while taking an unnecessary risk to personnel and the environment. And because buying battery
units composed of multiple cells allows space saving designs, entities may be forced to buy smaller capacity
batteries to fit existing spaces. This may end up having a negative effect on reliability. Suggest substituting
“unit-to-unit” wherever “cell-to-cell” is used in the table now.
Comment:
2. The level two table regarding Protection Station dc supply states that level one maintenance activities are
to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level one; which
activities shall Cowlitz use? Same situation for Station DC Supply (battery is not used) where the 18 month
interval is missing.
3. IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not
maximums. An entity wishing to avoid non-compliance for an interval that might extend past three calendar
months due to storms and outages must set a target interval of two months thereby increasing the number of
inspections each year by half again. This is unnecessarily frequent. Cowlitz suggests changing the maximum
interval for battery inspections to six calendar months. For consistency, Cowlitz also suggests that all
intervals expressed as three calendar months be changed to six calendar months.
4. Cowlitz is concerned over R1.1, where all components must be identified, without a definition for the word
component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. Cowlitz believes this will allow REs to claim
non-compliance for every three inch long terminal jumper wire not identified in a trip circuit path. Cowlitz
suggests that the FAQ definitions be included within the standard.
5. Many Distribution Providers do not own Protection Systems on the transmission side that are active
devices, but rather are passive in nature, i.e., fuses. This Standard verbiage will make it necessary for all DPs
November 17, 2010
51
to have a PSMP even if they do not own active Protective Systems that at least states that they have a null
listing of components. This is useless paperwork.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
3. The SDT disagrees. You should complete the activities within the intervals specified.
4. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component
types” in consideration of your comment.
5. Fuses are not a Protection System component. The SDT is not addressing what an entity that owns no
relevant components must do to demonstrate that for compliance.
Segment:
3
Organization:
Consumers Energy
Member:
David A. Lapinski
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided,
Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented.
Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead to
provide operating flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will be very
cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely lead
to entities NOT installing the redundant schemes, resulting in decreased reliability.
Comment:
2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include
sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply),
what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not
present.” Similarly, it isn’t clear from the general description within the Tables that components possessing
different monitoring attributes within a single scheme may be distinguished such that differing relevant tables
November 17, 2010
52
can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.
Battery assemblies supplied by some manufacturers have the connections made internally, making this option
unavailable. Experience with ASME standards show that NERC and SDT members may be jointly and
separately liable for litigation by specifying methods that either prefer or prohibit use of certain technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“ conclude
with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
such activities therefore require tripping of circuit breakers or other interrupting devices?
5. Performance of the minimum activities specified within Table 1a for legacy systems, particularly regarding
control circuits, will require considerable disconnection and reconnection of portions of the circuits. Such
activities will likely cause far more problems on restoration-to-service than they will locate and correct. We
suggest that the SDT reconsider these activities with regard for this concern.
6. We do not agree that Footnotes within the Standard are an appropriate method of providing information
that is important to the application of the Standard. Important information should be provided within the
standard text.
Response:
Thank you for your comment.
1. The SDT believes that it is important that all parallel paths be maintained within the indicated interval,
and the prescribed interval already considers the reliability benefits of parallel tripping paths.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
3. The use of the term “cell/unit” acknowledges that individual cells may not be accessible, but that
assemblies of several cells (into units) may be available instead, and may be used to address this
requirement. An acceptable baseline value and follow-on tests may be acceptable for the entire station
battery as a single unit.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
November 17, 2010
53
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15. To the degree that performance history for the components within these systems is available, a
performance-based program per R3 and Attachment A may be useful in these cases.
6. The SDT removed all footnotes from the Standard.
Segment:
Organization:
Member:
5
Consumers Energy
James B Lewis
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided,
Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented.
Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead to
provide operating flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will be very
cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely lead
to entities NOT installing the redundant schemes, resulting in decreased reliability.
2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include
sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply),
what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not
Comment:
present.” Similarly, it isn’t clear from the general description within the Tables that components possessing
different monitoring attributes within a single scheme may be distinguished such that differing relevant tables
can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.
Battery assemblies supplied by some manufacturers have the connections made internally, making this option
unavailable. Experience with ASME standards show that NERC and SDT members may be jointly and
separately liable for litigation by specifying methods that either prefer or prohibit use of certain technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“ conclude
with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
November 17, 2010
54
such activities therefore require tripping of circuit breakers or other interrupting devices?
5. Performance of the minimum activities specified within Table 1a for legacy systems, particularly regarding
control circuits, will require considerable disconnection and reconnection of portions of the circuits. Such
activities will likely cause far more problems on restoration-to-service than they will locate and correct. We
suggest that the SDT reconsider these activities with regard for this concern.
5. We do not agree that Footnotes within the Standard are an appropriate method of providing information
that is important to the application of the Standard. Important information should be provided within the
standard text.
6. As for the definition, it is unclear whether “voltage and current sensing inputs” include the instrument
transformer itself, or does it pertain to only the circuitry and input to the protective relays.
7. As for the definition, it is not clear what is included in the component, “station dc supply” without
referring to other documents (the posted Supplementary Reference and/or FAQ) for clarification. The
definition should be sufficiently detailed to be clear.
8. If Protection Systems trip via AC methods, are those systems and the associated control circuitry included
in the definition and within the requirements of the Standard as expressed within the Tables?
Response:
Thank you for your comment.
1. The SDT believes that it is important that all parallel paths be maintained within the indicated interval,
and the prescribed interval already considers the reliability benefits of parallel tripping paths.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
3. The use of the term “cell/unit” acknowledges that individual cells may not be accessible, but that
assemblies of several cells (into units) may be available instead, and may be used to address this
requirement. An acceptable base-line value and follow-on tests may be acceptable for the entire
station battery as a single unit.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
November 17, 2010
55
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15. To the degree that performance history for the components within these systems is available, a
performance-based program per R3 and Attachment A may be useful in these cases.
6. The SDT removed all footnotes from the Standard.
7. The SDT removed all footnotes from the Standard.
8. “Control circuitry” has been revised to remove “dc” to generalize it such that “ac” tripping would be
included.
Segment:
4
Organization:
Consumers Energy
Member:
David Frank Ronk
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided,
Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented.
Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead to
provide operating flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will be very
cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely lead
to entities NOT installing the redundant schemes, resulting in decreased reliability.
2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include
sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on
Comment:
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply),
what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not
present.” Similarly, it isn’t clear from the general description within the Tables that components possessing
different monitoring attributes within a single scheme may be distinguished such that differing relevant tables
can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.
Battery assemblies supplied by some manufacturers have the connections made internally, making this option
unavailable. Experience with ASME standards show that NERC and SDT members may be jointly and
November 17, 2010
56
separately liable for litigation by specifying methods that either prefer or prohibit use of certain technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“conclude
with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
such activities therefore require tripping of circuit breakers or other interrupting devices?
5. Performance of the minimum activities specified within Table 1a for legacy systems, particularly regarding
control circuits, will require considerable disconnection and reconnection of portions of the circuits. Such
activities will likely cause far more problems on restoration-to-service than they will locate and correct. We
suggest that the SDT reconsider these activities with regard for this concern.
6. In the Standard, Footnote 2 and Footnote 3 are identical. We presume that some information has been
omitted.
7. We do not agree that Footnotes are an appropriate method of providing information that is important to the
application of the Standard. Important information should be provided within the standard text.
Response:
Thank you for your comment.
1. The SDT believes that it is important that all parallel paths be maintained within the indicated interval,
and the prescribed interval already considers the reliability benefits of parallel tripping paths.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
3. The use of the term “cell/unit” acknowledges that individual cells may not be accessible, but that
assemblies of several cells (into units) may be available instead, and may be used to address this
requirement. An acceptable base-line value and follow-on tests may be acceptable for the entire
station battery as a single unit.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15. To the degree that performance history for the components within these systems is available, a
performance-based program per R3 and Attachment A may be useful in these cases.
November 17, 2010
57
6. The SDT removed all footnotes from the Standard.
7. The SDT removed all footnotes from the Standard.
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
3
City of Bartow, Florida
Matt Culverhouse
The draft standard requires testing and maintenance on DC circuits of distribution systems that have no effect
on the reliability of the BES which we feel is outside of the bounds of the original intent of NERC.
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5.
2
Midwest ISO, Inc.
Jason L Marshall
We are abstaining because a number of our stakeholders do not agree with the definition of Protection
Systems and inclusion of UFLS and UVLS in a standard dealing with maintenance of protection systems.
Thank you for your comment. FERC Order 693 suggests combining these Standards, as does the approved
SAR for this project. The Tables have been rearranged and considerably revised to improve clarity. Please
see new Tables 1-4 and 1-5 for the constrained activities regarding UFLS and UVLS.
8
Organization:
Roger C Zaklukiewicz
Member:
Roger C Zaklukiewicz
There in insufficient clarity on the Protection System components that are considered Transmission
Protection System equipment which require a Distribution Provider (DP) to perform the required
maintenance and testing to ensure compliance with the Standard. In certain distribution substations,
Comment: components of the high voltage source that supply the distribution substation may be considered components
of the Electric Bulk System and their associated protection and control systems must be specified, installed,
maintained and tested in accordance with the Standard. Clear delineation of Transmission Protection Systems
is therefore critical to ensure the reliability of the EPS.
November 17, 2010
58
Response:
Segment:
Organization:
Member:
Thank you for your comment. This is properly a concern regarding your regional BES definition, and the
SDT is unable to respond to these concerns.
10
Northeast Power Coordinating Council, Inc.
Guy V. Zito
1. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate equipment
identified in the existing or proposed definition. However, not all such equipment translates into a
transmission Protection System. The definition needs clarification on when such equipment is a part of the
transmission protection system.
2. Also, the time provided for the first phase "at least six months" is too open ended and does not provide
entities with a clear timeline. It is suggested that one year is appropriate for the first phase phasing out the
second year in stages.
3. Regarding battery visuals, the suggestion for consideration is it should be changed from 3 months to 6
months. Electrolyte levels of today's lead-calcium batteries are relatively stable for a 6 month period
compared to lead-antimony batteries used in the past.
Comment:
4. The Implementation plan is too short - In many instances it will be impossible to meet, especially if entities
have to create, purchase and adopt new databases to track maintenance activities. Often new procedures will
have to be written and additional resources justified and hired. It would be more acceptable if a staged
approached was taken similar to the DME Standard.
5. Accounting for every component of a protection system will be an enormous overhead and will take away
resources from actually doing maintenance. Emphasis should be on systems and not individual components.
6. The Standard does not provide a grace period if an entity is unable to meet the maintenance requirement
for extenuating circumstances. For example if an entity has to divert maintenance resources to storm
restoration following a major event, slack built into a maintenance program can be eaten up and put the
maintenance over the prescribed period. Provision should be made for a mitigation plan to get back on track.
We do not believe the reliability of the Bulk Electric System will be compromised if an entities' maintenance
November 17, 2010
59
program slips by a few months due to extreme contingencies, especially if it is brought back on track within a
short time frame.
Response:
Thank you for your comment.
1. This is an issue related to the regional BES definition, and the DP needs to consider their equipment
in the context of this definition.
2. This comment appears to be related to the Implementation Plan for the definition (which was
independent to the Standard), not to the Standard.
3. The SDT disagrees; these activities should be completed as prescribed in the Standard.
4. A staged Implementation Plan is provided for all activities that have prescribed maximum allowable
intervals over one year. However, the SDT believes that a staged Implementation Plan for developing
the PSMP is impractical, in that an entity cannot reasonably implement a plan until they have
developed it.
5. The SDT believes that the only alternative to these criteria is to provide a binary VSL, which would
mean that any non-compliance would be Severe. A definition of Component and Component Types
have been added to the Standard, and Requirement R1, part 1.1, has been revised to state, “Address
all Protection System component types” to assist in this task.
6. “Grace periods” within the Standard are not measurable, and would probably lead to persistently
increasing intervals. However, an entity may establish an internal program with grace-period
allowance, as long as the entire program (including grace periods) does not exceed the intervals
within the Standard.
Segment:
Organization:
Member:
1, 3
Hydro One Networks, Inc.
Ajay Garg, Michael D. Penstone
Hydro One is casting a negative vote for the following reasons:
1. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify
which protection system components it does own and needs to maintain. Many DPs own and/or
Comment:
operate equipment identified in the existing or proposed definition. However, not all such equipment
translates into a transmission Protection System.
2. The proposed definition of Protection System needs clarification on when such equipment is a part of
November 17, 2010
60
the transmission protection system. Emphasis should be on systems and not individual components.
3. The time provided for the first phase "at least six months" is too open ended and does not provide
entities with a clear timeline. It would be more acceptable if a staged approach was taken.
4. The Standard does not provide a grace period if an entity is unable to meet the maintenance
requirement for extenuating circumstances. For example if an entity has to divert maintenance
resources to storm restoration following a major event, slack built into a maintenance program can be
eaten up and put the maintenance over the prescribed period. Provision should be made for a
mitigation plan to get back on track. We do not believe the reliability of the Bulk Electric System will
be compromised if an entities' maintenance program slips by a few months due to extreme
contingencies, especially if it is brought back on track within a short time frame.
5. Table 1a: UFLS/UVLS DC control and trip circuits – Due to the distributed nature of this program,
random failures to trip are not impactive to the overall operation of the UFLS protection. There should
be no requirement to check the DC portion of these protections any more often than the DC circuit
checks associated with that LV breaker.
6. Table 1c: some of the proposed maintenance intervals for station DC supply are too stringent and they
would not produce significant increase in reliability to justify associated incremental expenditure.
Response:
Thank you for your comment.
1. This is an issue related to the regional BES definition, and the DP needs to consider their equipment
in the context of this definition.
2. This is an issue related to the regional BES definition, and the DP needs to consider their equipment
in the context of this definition. It seems that Protection Systems logically need to be maintained on a
Component level; definitions of Component and Component Type have been added to assist.
3. This comment appears to be related to the Implementation Plan for the definition (which was
independent to the Standard), not to the Standard.
4. “Grace periods” within the Standard are not measurable, and would probably lead to persistently
increasing intervals. However, an entity may establish an internal program with grace-period
allowance, as long as the entire program (including grace periods) does not exceed the intervals
within the Standard.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
November 17, 2010
61
1-5 for constrained activities related to UFLS/UVLS.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
Segment:
Organization:
Member:
1, 1, 3, 6
Consolidated Edison Co. of New York, Northeast Utilities, Consolidated Edison Co. of New York,
Consolidated Edison Co. of New York
Christopher L de Graffenried, David H. Boguslawski, Peter T Yost, Nickesha P Carrol
1. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate equipment
identified in the existing or proposed definition. However, not all such equipment translates into a
transmission Protection System. The definition needs clarification on when such equipment is a part of the
Comment: transmission protection system.
2. Also, the time provided for the first phase "at least six months" is too open ended and does not provide
entities with a clear timeline. It is suggested that one year is appropriate for the first phase phasing out the
second year in stages.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. This is an issue related to the regional BES definition, and the Distribution Provider needs to consider
their equipment in the context of this definition.
2. This comment appears to be related to the Implementation Plan for the definition (which was
independent to the Standard), not to the Standard.
3
Allegheny Power
Bob Reeping
Comment:
The draft standard expects 100% compliance for millions of protection system components at all times. The
standard should consider a statistically based performance metric instead of a performance target that expects
100% compliance.
Response:
Thank you for your comment. The NERC criteria for VSLs do not currently permit them to allow some level
November 17, 2010
62
of non-performance without being in violation.
Segment:
Organization:
Member:
1, 1, 3, 6
Keys Energy Services, Lakeland Electric, Lakeland Electric, Florida Municipal Power Pool
Stan T. Rzad, Larry E Watt, Mace Hunter, Thomas E Washburn
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard.
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit testing,
etc. on distribution elements with no significant improvement to BES reliability, which is beyond the
Comment:
statutory scope of the standards
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
1
Gainesville Regional Utilities
Luther E. Fair
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard as explained by Steve
Comment: Alexanderson in a prior e-mail to the ballot pool.
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit testing,
November 17, 2010
63
etc. on distribution elements with no significant improvement to BES reliability, which is beyond the
statutory scope of the standards.
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components. These comments are the same as provided by FMPA which we support.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
1, 4, 5
Lake Worth Utilities, Florida Municipal Power Agency, Florida Municipal Power Agency
Walt Gill, Frank Gaffney, David Schumann
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some
batteries are not able to accommodate all of the tests proscribed in the draft standard
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit
testing, etc. on distribution elements with no significant improvement to BES reliability, which is
beyond the statutory scope of the standards
Comment:
November 17, 2010
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components.
4. Will the Standard Introduce Technical Feasibility Exceptions to PRC Standards? A large proportion
of the batteries (as high as 50% as reported by some SMEs) are not able to accommodate all of the
tests prescribed in the draft standard. Will this necessitate the introduction of TFEs into the process
unnecessarily?
5. The Standard Reaches beyond the Statutory Scope of the Reliability Standards As written, the
64
standard requires testing of batteries, DC control circuits, etc., of distribution level protection
components associated with UFLS and UVLS. UFLS and UVLS are different than protection systems
used to clear a fault from the BES. An uncleared fault on the BES can have an Adverse Reliability
Impact and hence; the focus on making sure the fault is cleared is important and appropriate.
However, a UFLs or UVLS event happens after the fault is cleared and is an inexact science of trying
to automatically restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable
levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays with the
same function, there is no significant impact to the function of UFLS or UVLS. Hence, there is no
corresponding need to focus on every little aspect of the UFLS or UVLS systems. Therefore, the only
component of UFLS or UVLS that ought to be focused on in the new PRF-005 standard is the UFLS
or UVLS relay itself and not distribution class equipment such as batteries, DC control circuitry, etc.,
and these latter ought to be removed from the standard.
6. In addition, most distribution circuit are radial without substation arrangements that would allow
functional testing without putting customers out of service while the testing was underway, or at least
without momentary outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES reliability.
7. Perfection is Not A Realistic Goal The standard allows no mistakes. Even the famous six sigma
quality management program allows for defects and failures (i.e., six sigma is six standard deviations,
which means that statistically, there are events that fall outside of six standard deviations). PRC-005
has been drafted such that any failure is a violation, e.g., 1 day late on a single relay test of tens of
thousands of relays is a violation. That is not in alignment with worldwide accepted quality
management practices (and also makes audits very painful because statistical, random sampling
should be the mode of audit, not 100% review as is currently being done in many instances). FMPA
suggests considering statistically based performance metrics as opposed to an unrealistic performance
target that does not allow for any failure ever. Due to the sheer volume of relays, with 100%
performance required, if the standards remain this way, PRC-005 will likely be in the top ten most
violated standards for the forever. There is a fundamental flaw in thinking about reliability of the
BES. We are really not trying to eliminate the risk of a widespread blackout; we are trying to reduce
the risk of a widespread blackout. We plan and operate the system to single and credible double
contingencies and to finite operating and planning reserves. To eliminate the risk, we would need to
plan and operate to an infinite number of contingencies, and have an infinite reserve margin, which is
infeasible. Therefore, by definition, there is a finite risk of a widespread blackout that we are trying to
reduce, not eliminate, and, by definition, by planning and operating to single and credible double
November 17, 2010
65
contingencies and finite operating and planning reserves, we are actually defining the level of risk
from a statistical basis we are willing to take. With that in mind, it does not make sense to require
100% compliance to avoid a smaller risk (relays) when we are planning to a specified level of risk
with more major risk factors (single and credible double contingencies and finite planning and
operating reserves).
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
4. No. The Tables have been rearranged and considerably revised to improve clarity. Please see new
Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unitto-unit connection resistance (where available to measure)” to address this comment.
5. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
6. The Standard does not require functional testing, although it may be the most practical method of
completing some of the required activities. There are other methods, too, of completing these.
7. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
4
Illinois Municipal Electric Agency
Bob C. Thomas
IMEA is supportive of the intent of PRC-005-2; however, based on monitoring of comments submitted to
date, IMEA would like to see concerns addressed before voting to affirm this proposed standard revision.
Comment:
IMEA supports the comments expressed during ballot pool communications that provisions need to be
included to avoid the possible necessity of having to use the burdensome TFE process and to avoid the
November 17, 2010
66
unrealistic expectation of perfection in recordkeeping and exactness of maintenance schedule dates.
Response:
Segment:
Organization:
Member:
Thank you for your comment. Responses have been provided to the various ballot comments.
1
Georgia Transmission Corporation
Harold Taylor, II
The SDT has made significant changes to the minimum maintenance activities and maximum allowable
intervals within Tables 1a, 1b, and 1c, particularly related to station dc supply and dc control circuits. Do you
agree with these changes? If not, please provide specific suggestions for improvement. Comments:
1. Do not agree with the 3 calendar months interval and suggest using quarterly. Both terms require a
minimum of four inspections per year have proven to be successful, but the term “quarterly” provides
a bit more flexibility than the term “3 calendar months”. Given a 3 month maximum interval an entity
would need to schedule these tasks every 2 months.
Comment:
2. As the current requirements are written in R1 of PRC-005-2 Draft, we disagree with the terms identify
all Protection System components.
We recommend a less prescriptive requirement as listed below.
R1.1 Identify BES substations or facilities containing Protection Systems.
R1.2 Identify whether Protection Systems per substation or facilities are addressed through timebased, condition-based, performance based or a combination based etc.
R1.3 For each substation/facility with Protection Systems include all maintenance activities etc.
3. Listing each individual Protection System component as current draft is onerous and impedes any
interpretation of application with very little value.
4. The standard as written will require a great deal of effort by the utilities to maintain 100% compliance as
listed. The concern is the power system design allows for some contingencies but the standard allows for no
errors. Failing to complete 1% of the maintenance by 1 day infers an entity is out of compliance or in
violation. The violations should start for more than a level of 5% not identified, or not maintained.
5. We feel the minor changes of wording as described in R1.1 – R1.3 as listed above will go a long way in
November 17, 2010
67
removing the concerns of the standard. We feel the intent of the standard is sound and request minor changes
to facilitate an interpretable standard that sensibly mitigates problems with the BES. As the standard written,
the interpretation seems to create a stringent environment with undue compliance requirements.
6. Lastly, the SDT should attempt to embrace Gerry Cauley’s vision of “results-based standards” and clearly
identify the “risk mitigation objectives, reliability result or outcome” of the revised requirements and allow
each entity to meet the outcome and mitigate the risk without writing in such a prescriptive manner which is
not preferred. The prescriptive details currently proposed in the standard could then be captured in a reference
document.
Response:
Segment:
Organization:
Member:
November 17, 2010
Thank you for your comment.
1. The SDT disagrees. Once per calendar quarter would allow up to six months between inspections,
while three calendar months limits the effective interval to four months (minus 2 days).
2. Modifying Requirement R1 as you suggest would make it so general that it would be difficult to
measure for compliance. Additionally, because of the variety of types of component within a
substation, it may be difficult to define a substation-wide (or facility-wide) PSMP that addresses all
components and intervals. A definition of Component has been added to the Standard, and
Requirement R1, part 1.1, has been revised to state, “Address all Protection System component
types”.
3. A definition of Component has been added to the Standard to assist; also, Requirement R1, part 1.1,
has been revised to state, “Address all Protection System component types” in consideration of your
comment.
4. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
5. As noted above, the SDT believes that Requirement R1 would no longer be measurable.
6. The SDT agrees that the SDT may effectively embrace the “results-based” approach within this
Standard; however, doing so at this time would delay development of this high-priority Standard.
This is reflected on pages 13-14 of the current draft Standards Development Plan that is out for
comment at this time.
3, 4
Georgia System Operations Corporation
R Scott S. Barfield-McGinnis, Guy Andrews
68
1. Do not agree with the 3 calendar months interval and suggest using quarterly. Both terms require a
minimum of four inspections per year have proven to be successful, but the term “quarterly” provides a bit
more flexibility than the term “3 calendar months”. Given a 3 month maximum interval an entity would need
to schedule these tasks every 2 months.
2. As the current requirements are written in R1 of PRC-005-2 Draft, we disagree with the terms identify all
Protection System components. We recommend a less prescriptive requirement as listed below.
-R1.1 Identify BES substations or facilities containing Protection Systems.
-R1.2 Identify whether Protection Systems per substation or facilities are addressed through time-based,
condition-based, performance based or a combination based etc.
-R1.3 For each substation/facility with Protection Systems include all maintenance activities etc.
3. The VRF for R1 ranking should be lower or no greater than R2, R3, and R4. The task of identifying
Protection System components has very little to do with increasing reliability of the BES. The
implementation of the PSMP most likely will cover all the specific functions of Protection System
components although the entity failed to identify all PS components. We recommend the above language
Comment: changes and agree the requirement adds some value but not a high-risk value to the BES.
4. After correcting the language we feel that a requirement of 100% maintenance on 100% of all components
as listed on page 6 of the standard for the VSLs leaves no room for error for systems designed with
contingences. The violations should start for more than a level of 5% not identified, not maintained, etc.
5. Listing each individual Protection System component as current draft is onerous and impedes any
interpretation of application with very little value. The standard as written will require a great deal of effort
by the utilities to maintain 100% compliance as listed. The concern is the power system design allows for
some contingencies but the standard allows for no errors. Failing to complete 1% of the maintenance by 1 day
infers an entity is out of compliance or in violation. The violations should start for more than a level of 5%
not identified, or not maintained.
6. We feel the minor changes of wording as described in R1.1 – R1.3 as listed above will go a long way in
removing the concerns of the standard. We feel the intent of the standard is sound and request minor changes
to facilitate an interpretable standard that sensibly mitigates problems with the BES. As the standard written,
the interpretation seems to create a stringent environment with undue compliance requirements.
November 17, 2010
69
7. Lastly, the SDT should attempt to embrace Gerry Cauley’s vision of “results-based standards” and clearly
identify the “risk mitigation objectives, reliability result or outcome” of the revised requirements and allow
each entity to meet the outcome and mitigate the risk without writing in such a prescriptive manner which is
not preferred. The prescriptive details currently proposed in the standard could then be captured in a reference
document.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
Thank you for your comment.
1. The SDT disagrees. Once per calendar quarter would allow up to six months between inspections,
while three calendar months limits the effective interval to four months (minus 2 days).
2. Modifying Requirement R1 as you suggest would make it so general that it would be difficult to
measure for compliance. Additionally, because of the variety of types of component within a
substation, it may be difficult to define a substation-wide (or facility-wide) PSMP that addresses all
components and intervals. A definition of Component has been added to the Standard, and
Requirement R1, part 1.1, has been revised to state, “Address all Protection System component
types”.
3. The VRFs have been revised.
4. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
5. A definition of Component has been added to the Standard to assist; also, Requirement R1, part 1.1,
has been revised to state, “Address all Protection System component types” in consideration of your
comment.
6. As noted above, the SDT believes that Requirement R1 would no longer be measurable.
7. The SDT agrees that the SDT may effectively embrace the “results-based” approach within this
Standard; however, doing so at this time would delay development of this high-priority Standard.
This is reflected on pages 13-14 of the current draft Standards Development Plan that is out for
comment at this time.
1, 3, 6
FirstEnergy Energy Delivery, FirstEnergy Solutions, Kevin Querry
Robert Martinko, Kevin Querry, Mark S Travaglianti
Please see FE comments for suggested enhancements submitted via the parallel comment period for this
standard.
70
Response:
Segment:
Organization:
Member:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
1, 3, 5, 6
Entergy Corporation, Entergy, Entergy Corporation, Entergy Services, Inc.
George R. Bartlett, Joel T Plessinger, Stanley M Jaskot, Terri F Benoit
The following are the reasons associated with our Negative Ballot.
1. Table 1a contains “Type of Protection System Component” entry “Control and trip circuits with
electromechanical trip or auxiliary contacts (except for microprocessor relays, UFLS or UVLS)”.
However, there is no Component entry for the exception (except for microprocessor relays, UFLS or
UVLS). Please add a Component entry with associated intervals and activities for: “Control and trip
circuits with electromechanical trip or auxiliary contacts” with a microprocessor relay application.
2. The term “check” has replaced “verify” for some maintenance activities. Replace “verify” with
“check” in all locations in the Tables.
3. Redefine “verification” to “A means of determining or checking that the component is functioning
properly or maintenance correctable issues are identified”.
Comment:
4. We support this project and believe it is a positive step towards BES reliability. However, we believe
the draft document needs additional work as per our comments. Also, as indicated by the amount of
industry input on the last version draft comments, we believe revisions are still needed to properly
address this technically complex standard.
5. If this standard is to deviate from the original project schedule and follow a fast track timeline for
approval, then we disagree with the 3 month implementation for Requirement 1 and ask for at least 12
months. The original schedule provided sufficient advance notice to work on an implementation plan
and it included the typical time required for NERC Board of Trustees and regulatory approvals. If the
project schedule and typical NERC Board of Trustees and regulatory approval times are to be
accelerated, the implementation plan should be extended. We reserve the right to include selected
reasons submitted by other Negative balloters for their Negative Ballot.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
November 17, 2010
71
1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
3. “Check” is not an element of the PSMP definition. This term, throughout the tables, has been
replaced with whatever term of the definition is relevant.
4. Thank you.
5. The Implementation Plan for Requirement R1 has been revised from three months to twelve months.
Segment:
Organization:
Member:
1
Empire District Electric Co.
Ralph Frederick Meyer
It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are
included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that
particular standard to protection systems that sense electrical quantities, it is remains unclear in other
Comment:
standards that use the defined term whether mechanical input protections are included. We suggest that
“Protective Relay” also be defined, and that the definition clearly exclude devices that respond to mechanical
inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG request.
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Protection System definition has been revised to explicitly include only
protective relays that respond to electrical quantities. This definition applies to all uses of this term within
NERC Standards. The SDT feels that the IEEE definition of protective relay is adequate and sees no need to
either repeat or change that definition.
1
Colorado Springs Utilities
Paul Morland
Comment:
CSU offers the following comments: With BES still not defined it is difficult to determine what the standard
applies to. Requirements are confusing at times, making the standard difficult to audit.
Response:
Thank you for your comment. This concern is a BES concern, and the SDT is unable to address or resolve it.
Segment:
November 17, 2010
1
72
Organization:
Avista Corp.
Member:
Scott Kinney
Avista has the following comments:
1. The modified definition of Protection System now refers to “functions” rather than “devices.” What are the
“functions?” This new term adds confusion without being defined in the standard.
2. Considering all the time spent by Regional Entities and utilities discussing what is meant by monthly,
quarterly, annual, etc., this standard should clearly define a Calendar Year and Calendar Month to eliminate
any confusion.
Comment:
3. In general, the requirements of the Standard are very prescriptive and granular which seem counter to the
newly adopted NERC philosophy of implementing “performance-based” or “results-based” standards.
Specifically, the relay testing requirements are very extensive and not entirely practical when it comes to
conducting actual breaker tripping for testing. Also, there are now different maintenance and testing
requirements for station batteries depending on the type of battery in service. What’s the real added reliability
to the BES to add this complexity to the maintenance program? Considering these observations, is there some
real historical research that has gone into determining these requirements? In general, how did the drafting
team arrive at the maximum allowable maintenance and testing intervals for inclusion in the Standard, i.e.,
what is the technical basis for their decisions regarding this?
Response:
Thank you for your comment.
1. “Functions” acknowledge that, while protective relays (or protective devices) is the most common
implementation, other devices are now used (particularly in SPSs) that provide these functions from
other than traditional relays.
2. A “calendar year” is a single number year on the Gregorian calendar; a calendar month is any one of
the twelve months within a single calendar year. Please see Section 8.3 of the Supplementary
Reference document.
3. Please see Section 8.3 of the Supplemental Reference document for a discussion of the determination
of relay and communications system intervals. For the other components, the SDT studied other
sources such as IEEE standard, EPRI documents, visited with various industry experts (such as within
IEEE), conducted informal surveys of existing practices, and adjusted to conform to concerns such as
generator outage intervals.
Segment:
November 17, 2010
3
73
Organization:
Member:
Comment:
Central Lincoln PUD
Steve Alexanderson
1. The SDT has made significant changes to the minimum maintenance activities and maximum allowable
intervals within Tables 1a, 1b, and 1c, particularly related to station dc supply and dc control circuits. Do you
agree with these changes? If not, please provide specific suggestions for improvement. 0 Yes X No
Comments:
We agree with most of the changes from the last draft. However, the phrase “Verify Battery cell-to-cell
connection resistance” has entered the table where it did not exist before. On some types of stationary battery
units, this internal connection is inaccessible. On other types the connections are accessible, but there is no
way to repair them based on a bad reading. And bad cell-to-cell connections within units will be detected by
the other required tests. This requirement will cause entities to scrap perfectly good batteries just so this test
can be performed, with no corresponding increase in bulk electric system reliability while taking an
unnecessary risk to personnel and the environment. And because buying battery units composed of multiple
cells allows space saving designs, entities may be forced to buy smaller capacity batteries to fit existing
spaces. This may end up having a negative effect on reliability. Suggest substituting “unit-to-unit” wherever
“cell-to-cell” is used in the table now.
2. The SDT has included VRFs and Time Horizons with this posting. Do you agree with the assignments that
have been made? If not, please provide specific suggestions for improvement. X Yes 0 No Comments:
3. The SDT has included Measures and Data Retention with this posting. Do you agree with the assignments
that have been made? If not, please provide specific suggestions for improvement. X Yes 0 No Comments:
4. The SDT has included VSLs with this posting. Do you agree with the assignments that have been made? If
not, please provide specific suggestions for change. 0 Yes X No Comments: It is possible that a component
that failed to be individually identified per R1.1 was included by entity A’s maintenance plan. This
documentation issue gets a higher VSL than entity B that identified a component without maintaining it. We
suggest the R1 VSL be change to Low, since we believe lack of maintenance to be more severe than
documentation issues.
5. The SDT has revised the “Supplementary Reference” document which is supplied to provide supporting
discussion for the Requirements within the standard. Do you agree with the changes? If not, please provide
November 17, 2010
74
specific suggestions for change. X Yes 0 No Comments:
6. The SDT has revised the “Frequently-Asked Questions” (FAQ) document which is supplied to address
anticipated questions relative to the standard. Do you agree with these changes? If not, please provide
specific suggestions for change. X Yes 0 No Comments:
7. If you have any other comments on this Standard that you have not already provided in response to the
prior questions, please provide them here. Comments:
The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be
used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which
activities shall we use?
8. Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing. IEEE
battery maintenance standards call for quarterly inspections. These are targets, though, not maximums. An
entity wishing to avoid non-compliance for an interval that might extend past three calendar months due to
storms and outages must set a target interval of two months thereby increasing the number of inspections
each year by half again. This is unnecessarily frequent. We suggest changing the maximum interval for
battery inspections to 4 calendar months. For consistency, we also suggest that all intervals expressed as 3
calendar months be changed to 4 calendar months.
9. We are concerned over R1.1, where all components must be identified, without a definition for the word
component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. We believe this will allow REs to claim noncompliance for every three inch long terminal jumper wire not identified in a trip circuit path. We suggest
that the FAQ definitions be included within the standard.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. Thank you.
3. Thank you.
4. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
and the VSL for Requirement R1 modified in consideration of your comment.
November 17, 2010
75
5. Thank you.
6. Thank you.
7. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
8. The SDT disagrees; the components should be maintained as specified within the new tables.
9. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
in consideration of your comment. Definitions were also added to the Standard for Component Type
and Component.
Segment:
Organization:
Member:
3, 5, 6
Lincoln Electric System
Bruce Merril, Dennis Florom, Eric Ruskamp
LES would like to thank the Drafting Team for its time and effort in developing the standard. However, the
standard as currently drafted raises concern as it relates to the identification of all Protection System
components. LES asks the Drafting Team to further examine the impact of implementing such a rigorous
maintenance program that could potentially impose unnecessary burden and reliability risk with an overly
prescriptive approach. Redundancy has been implemented in great detail throughout the history of protection
systems to ensure they function as intended. In addition to the comments submitted through the MRO NSRS
group comment form, LES would like to further emphasize the following points of contention:
Comment:
(1) Consider revising to consider maintenance activities on a communications channel basis in which
intermediate device functioning can be verified by sending a signal from one relay to another.
(2) R1, the statement “or are designed to provide protection for the BES” re-opens the argument about
transformer protection or breaker failure protection for transformer high-side breakers tripping BES breakers
being included in transmission protection systems.
(3) Table 1b “breaker trip coil, each auxiliary relay, and each lockout relay” should be changed from a 6 to 12
year interval similar to relay input and outputs. Experience has shown that these both have similar reliability.
(4) Include a detailed example of an Inventory List for voltage and current sensing input.
(5) Remove “proper functioning of” from the maintenance activities for voltage and current sensing inputs.
November 17, 2010
76
One is not verifying the functionality of the signals.
(6) Clarify why control circuitry is stated separately such as in “Control and trip circuits”. This implies that
close circuit DC paths are not subjects a PSMP when reclosing and closing of breakers have never before
been considered part of a Protection System.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-2. Functional end-to-end testing would be one method of completing the necessary verification.
2. This is an issue regarding your regional BES definition, and this SDT is unable to resolve such issues.
3. The SDT believes that mechanical solenoid-operated devices share performance attributes (and failure
modes) with electromechanical relays and need to be tested at similar intervals. Performance-Based
maintenance is an option to increase the intervals if the performance of these devices supports those
intervals.
4. The SDT does not understand this comment. The Protection System definition has been changed;
perhaps this will help.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-3.
6. This component of the definition is stated to apply as “associated with protective functions” and thus
excludes close/reclosing circuits. Please see FAQ II.1.A.
Segment:
Organization:
Member:
Comment:
4
Madison Gas and Electric Co.
Joseph G. DePoorter
1. The six implementation plan is too quick for some entities. A 1 year implementation is recommended.
2. With the addition of all UFLS in this standard, it is implied battery testing, DC circuit testing, etc. on
distribution elements are part of the BES. This may lead to every wire and component to be classified as
being a part of the BES.
Response:
November 17, 2010
Thank you for your comment.
1. This comment appears to be focused on the Implementation Plan for the definition, not for the
Standard.
77
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-4 and 1-5 for simplified maintenance activities relevant to UFLS.
Segment:
Organization:
Member:
Comment:
8
SPS Consulting Group Inc.
Jim R Stanton
1. I share the concerns expressed by FMPA that the overly prescriptive battery testing requirements will
require a TFE process that would be tedious to manage. The standard goes far beyond the scope of Reliability
Standards to protect the BES. Reliability Standards should state "what" needs to be done, not "how" to do it.
Such overly prescriptive requirements blunt the development of superior and more efficient processes by the
industry.
2. Table 1a column "Maintenance Activity" should be renamed "Suggested Maintenance Activity".
3. Tables 1a, b, and c should be reference documents and not referred to in the Requirements. This is
especially true since we find terms like "where applicable" and "physical condition" in the tables that forces
the Registered Entity to make judgment calls that may not align with the judgment of the auditors. This will
mean more interpretation requests and will make the standard extremely difficult to audit as the Registered
Entities and auditors compare their "judgments."
Response:
Segment:
Organization:
November 17, 2010
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment. The SDT has
prescribed “what,” not “how,” except for those rare cases where it is necessary to specify both.
2. The “activities” in the Tables are required, not suggested.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5. These Tables are made requirements by incorporation within Requirement R4, part
4.1, and therefore are not reference documents. They are created in response to FERC Order 693 and
the approved SAR which assigned the SDT to develop a Standard with maximum allowable intervals
and minimum maintenance activities.
10
Midwest Reliability Organization
78
Member:
Dan R. Schoenecker
Comment:
“The MRO’s NERC Standards Review Subcommittee believes the proposed implementation plan for R1 is
unreasonably short. It proposes that: “Entities shall be 100% compliant on the first day of the first calendar
quarter three months following applicable regulatory approvals, or in those jurisdictions where no regulatory
approval is required, on the first day of the first calendar quarter six months following Board of Trustees
adoption.” We believe the implementation periods should be expanded to twice what was proposed in the
implementation plan due to the sheer volume of equipment that will need to meet compliance. Thus, we
propose an alternate implementation plan for requirement R1, “Entities shall be 100% compliant on the first
day of the first calendar quarter six months following applicable regulatory approvals, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter twelve
months following Board of Trustees adoption.”
Response:
Thank you for your comment. The Implementation Plan for Requirement R1 has been modified from three
months to twelve months in consideration of your comment.
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
The Implementation Plan is unreasonably short, for the number of assets. The time period should be doubled
to be more practicable.
Thank you for your comment. The Implementation Plan for Requirement R1 has been modified from three
months to twelve months in consideration of your comment.
1, 3, 5, 6
Manitoba Hydro
Michelle Rheault, Greg C Parent, Mark Aikens, Daniel Prowse
Comment:
The proposed timelines are not reasonable. See submitted comments.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
November 17, 2010
10
Western Electricity Coordinating Council
Louise McCarren
79
Comment:
Lack of clarity or apparent conflict between certain requirements would make compliance assessment
difficult.
Response:
Thank you for your comment.
Segment:
Organization:
Member:
1
Clark Public Utilities
Jack Stamper
Comment:
My negative vote reflects the ambiguity and over-stepping issues discussed in many of the comments.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
1, 3, 5, 6
Kansas City Power & Light Co.
Michael Gammon, Charles Locke, Scott Heidtbrink, Thomas Saitta
Comment:
The proposed changes in the Standard are far too prescriptive and do not take into account the multitude of
manufacturers equipment by establishing broad maintenance cycles and testing intervals.
Response:
Thank you for your comment.
Segment:
Organization:
Member:
1
Public Utility District No. 1 of Chelan County
Chad Bowman
Comment:
The requirements are confusing and at times seem to be in conflict with or duplicative of other requirements.
From a compliance perspective, this confusion would make the standard difficult to interpret for compliance
and audit purposes.
Response:
Thank you for your comment. The Requirements and Tables have been rearranged and considerably revised
to improve clarity. Please see new Tables 1-1 through 1-5.
Segment:
Organization:
Member:
Comment:
November 17, 2010
3
Wisconsin Public Service Corp.
Gregory J Le Grave
The standard and associated definitions as written are too vague, which leave room for varying interpretation.
80
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Requirements, definitions, and Tables have been rearranged and
considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
1, 3
Tri-State G & T Association Inc.
Keith V. Carman, Janelle Marriott
Comment:
Clarification is needed to address the potentially onerous implementation, administration, audit of the
proposed revisions.
Response:
Thank you for your comment.
Segment:
Organization:
Member:
5
Tenaska, Inc.
Scott M. Helyer
Comment:
This standard has become too prescriptive and does too much to say "how" instead of "what" to do. Some of
the information in the various tables may or may not conflict with manufacturer recommended practices. It is
not clear at all whether such detail will lead to an increased level of reliability versus simply having
consistency for the sake of consistency.
Response:
Thank you for your comment. The SDT has prescribed “what,” not “how,” except for those rare cases where
it is necessary to specify both. Also, FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
Segment:
Organization:
Member:
6
Florida Power & Light Co.
Silvia P Mitchell
Comment:
This standard is too prescriptive and will result in many violations.
Response:
Thank you for your comment. FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
Segment:
Organization:
Member:
November 17, 2010
9
Oregon Public Utility Commission
Jerome Murray
81
Comment:
The requirements in the latest draft are confusing and at times seem to be in conflict with other requirements.
From a compliance and enforcement perspective, this confusion would make the standard difficult to audit.
Response:
Thank you for your comment. The Requirements, definitions, and Tables have been rearranged and
considerably revised to improve clarity. Please see new Table 1-5.
Segment:
Organization:
Member:
1, 6
SCE&G
Henry Delk, Jr., Matt H Bullard
Comment:
While SCE&G believes the majority of the PRC-005-2 standard is ready to be affirmed there are still
inconsistencies with areas of the standard that need to be corrected prior to approval. These inconsistencies
are addressed in SCE&G’s comments which have been submitted for the current draft of this standard.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
1, 3, 5, 6
Xcel Energy, Inc.
Gregory L Pieper, Michael Ibold, Liam Noailles, David F. Lemmons
Comment:
Xcel Energy believes the standard still contains many aspects that are not clearly understood by entities,
including what is needed to demonstrate a compliant PSMP. Comments have been submitted concurrently to
NERC via the draft comment response form.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
8
Utility Services LLC
Brian Evans-Mongeon
Comment:
See filed comments
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
November 17, 2010
1
Baltimore Gas & Electric Company
82
Member:
John J. Moraski
Comment:
Please refer to BGE comments submitted for Project 2007-17 / PRC-005-2 Draft 2, submitted on 7/16/2010.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
1, 3, 5, 6
Public Service Electric and Gas Co., PSEG Energy Resources & Trade LLC
Kenneth D. Brown, Jeffrey Mueller, David Murray, James D. Hebson
Comment:
Please reference comments submitted by the PSEG companies on the official comment form for this
standard.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
1, 3, 3, 3, 3, 5
Southern Company Services, Inc., Alabama Power Company, Georgia Power Company, Gulf Power
Company, Mississippi Power, Southern Company Generation
Member:
Horace Stephen Williamson, Richard J. Mandes, Anthony L Wilson, Gwen S Frazier, Don Horsley, William
D Shultz
Comment:
Comments for this ballot are included in the Southern Company submitted comment form - Project 2007-17:
Protection System Maintenance and Testing.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
1
Duke Energy Carolina
Douglas E. Hils
Comment:
Please see our responses in the comment form - thank you.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
Comment:
November 17, 2010
1
GDS Associates, Inc.
Claudiu Cadar
All comments included in the NERC comment form
83
Response:
Segment:
Organization:
Member:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
3
Louisville Gas and Electric Co.
Charles A. Freibert
Comment:
Comments will be submitte4d under the comment form
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
4, 5
Ohio Edison Company, FirstEnergy Solutions
Douglas Hohlbaugh, Kenneth Dresner
Comment:
Please see FE comments for suggested enhancements submitted via the parallel comment period for this
standard
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
5
PPL Generation LLC
Mark A. Heimbach
Comment:
Please see comments submitted by "PPL Supply" on 7/16/10.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
Comment:
Response:
4
Detroit Edison Company
Daniel Herring
1. The definition should clarify whether current and voltage transformers themselves are included.
2. This implementation plan and the one for PRC-005-2 should be consistent.
Thank you for your comment.
1. These devices are included in the modified definition. This component of the Protection System
definition is to generally include this functionality as a part of the Protection System. The detailed
applicability of this component within PRC-005-2 is addressed within the Standard.
November 17, 2010
84
2. This comment appears to be addressing the Implementation Plan for the Definition, not for the
Standard.
Segment:
9
Organization:
California Energy Commission
Member:
William Mitchell Chamberlain
Comment:
The current proposal does not require coordination within the interconnection.
1. The standard should require the PCs within an interconnection to coordinate a UFLS Design with all other
PCs within the interconnection and that the PCs should be required to develop a coordinated interconnection
wide UFLS Design. As proposed the standard could conceivably result in as many different UFLS plans
within WECC as there are Planning Coordinators. Additionally, the proposed standard fails to address UFLS
relays which are currently part of the existing program which are owned by the customer. Recognition of
customer owned relays is critical to have a successful program. To assure areas are covered the LSE needs to
be included in the Applicability section. A third concern is the proposed standard attempts to establish
continent wide frequency-time curves and eliminate discrete set points. This approach fails to recognize the
unique characteristics of the four individual interconnections. Frequency-time curves do not allow for
specific and defined measurements and will leave individual entities defaulting to the lowest common
denominator. If frequency-time curves are intended to define the boundaries, the determination of discrete set
points would fall into the hands of the PCs leading to disagreements among entities. In addition, to determine
the frequency-time curves through stability and dynamic modeling, one must establish discrete set points.
Frequency-time curves are reverse engineering and require justification and correlation to the reliability of
the interconnections – no such justification has been provided.
Response:
Thank you for your comment. Your comments appear to be directed to the NERC Standard addressing
development of UFLS programs. The Protection System Maintenance and Testing SDT is unable to address
these comments.
November 17, 2010
85
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Date of Second Ballot: 07/23/10 - 08/02/10
Summary Consideration: There were numerous comments opposing balloting the definition separately from the definition; the NERC BOT has
directed that a revised definition be approved as quickly as possible to close a reliability gap. Many other comments were offered relative to the
standard, not the definition, and the SDT noted this in its responses.
Some commenters suggested the “station dc supply” portion of the definition be modified to specifically address battery chargers; the SDT
modified the definition as suggested. The revised definition is shown below:
Protection System –
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply associated with protective functions (including station batteries, battery chargers, and non-battery-based dc supply), and
• Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting devices.
The SDT did not make any other modifications to the definition and did not make any modifications to the implementation plan based on
stakeholder comments submitted with ballots.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb
1
Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
1
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Kirit S. Shah
Entity
Ameren Services
Segment
1
Vote
Negative
Comment
1. Remove “devices providing” yielding ‘voltage and current
sensing inputs to protective relays’. This will match the SDT intent
with which we concur. "The definition has been changed for
clarity; the SDT intends that the output of these devices,
measured at the relay should properly represent the primary
quantities."
2. The 12 month implementation plan is an improvement, but will
result in multiple maintenance plan changes within a short time.
We believe that the implementation of the revised definition and
PRC-005-2 PSMP must align on the same date.
Response: Thank you for your comments.
1. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed applicability of this element of the definition
relative to maintenance within PRC-005-2 is addressed within the standard by specifying, “Verify that acceptable measurements of the current and voltage
signals are received by the protective relays”.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the
reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be
given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply
the new definition to PRC-005-1.
Terri F Benoit
Entergy Services, Inc.
6
Negative
2007-17 the definition - Negative with Comments: The following
are the reasons associated with our Negative Ballot.
1. We agree with the definition, however we do not agree with the
implementation plan. We believe implementation of the definition
needs to coincide with the implementation of Standard PRC-005-2.
To do otherwise, will cause entities to address equipment,
documentation, work management process, and employee training
changes needed for compliance twice within an unreasonably
short timeframe.
2. A 12 month minimum timeframe is need to implement this
definition
Response: Thank you for your comments.
September 10, 2010
2
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
1. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the reliability
gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply the
new definition to PRC-005-1.
2. The SDT modified the implementation plan to provide a 12-month implementation period with the previous posting.
Brenda L Truhe
PPL Electric Utilities Corp.
1
Affirmative
Although PPL EU previously voted against this definition, due to
the change in language, we now support this definition.
Although the applicable relays to which protective relays are
outlined in the NERC PRC-005-2 Protection system Maintenance
Draft Supplementary Reference dated May 27, 2010, they are not
defined in the NERC Glossary of terms. Until it is clearly defined
which relays are included inconsistencies will exists from region to
region in their audit approaches and which relays they will be
looking at. Also, there is still debate why the protective relays
would extend to mechanical devices such as the lock-out relay and
tripping for trip-free relays. In our system configuration we risk
reliability to customer load by testing the lock-out relays which we
feel out weights the benefit of testing devices that we see little to
no evidence of failure in.
Response: Thank you for your comments.
John C. Collins
Platte River Power
Authority
1
Negative
Terry L Baker
Platte River Power
Authority
3
Negative
Response: Thank you for your comments. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed
applicability of the definition relative to maintenance within PRC-005-2 is addressed within the standard. Your comments appear to be on the draft standard
PRC-005-2, rather than on the definition. Failure of a lock-out relay or tripping relay can keep a circuit (or multiple circuits) from clearing a fault. Routine
testing of these devices could find problems before the system needs them to clear a fault.
Mel Jensen
APS
5
Negative
Robert D Smith
Arizona Public Service
Co.
1
Negative
September 10, 2010
Although the SDT has made changes in trying to define the
Protection System the definition remains too prescriptive. In
particular, the devices providing current and voltage inputs as well
as the dc supply. These items are also used for other functions not
related to the reliability of the BES. They are critical to business
and operation of the generating systems and not solely dedicated
to protective relaying. Including them in the definition obligates
the utility to methods where there should be some discretion.
3
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments. The SDT is aware that many devices have multiple functions within the business of supplying power to loads.
Regardless of these other functions, if a device is a part of a Protection System then it must be maintained in accordance withPRC-005. The definition of
Protection System is for all applications of this term throughout NERC Standards. The detailed applicability of the definition relative to maintenance within PRC005-2 is addressed within the standard.
Stan T. Rzad
Keys Energy Services
1
Negative
As written, is opens up the PRC-005 standard to Technical
Feasibility Exceptions because some batteries are not able to
accommodate all of the tests proscribed in the draft standard. The
draft standard would cause NERC to regulate through the
standards battery testing, DC circuit testing, etc. on distribution
elements with no significant improvement to BES reliability, which
is beyond the statutary scope of the standards The standard
unreasonably retains the "100% compliance" paradigm for
thousands, if not millions of protection system components.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Joseph S.
Stonecipher
Beaches Energy Services
1
Negative
Thomas W. Richards
Fort Pierce Utilities
Authority
4
Negative
Because the definition changes the scope of what PRC-005 covers,
the definition should not be balloted separately from PRC-005 so
that the industry knows what is being committed to. What
happens if the standard is voted down but the definition change is
passed? For instance, the circuitry connecting the voltage and
current sensing devices to the relays is a scope expansion. Station
DC supply increases the scope to include the charger, etc. This
scope increase needs to have an appropriate implementation
period.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Paul Rocha
CenterPoint Energy
1
Negative
CenterPoint Energy does not support any Protection System
definition that includes the trip coils of the interrupting devices.
Response: Thank you for your comments. The current definition includes “DC Control Circuitry”; the SDT attempted to clarify the definition by stating which
September 10, 2010
4
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
of the many control circuits are included. Because the current definition is vague, it can certainly include the trip coils, close coils, and alarm circuits of the
interrupting device. The SDT believes that the electrically-operated trip coils are an important part of the control circuitry.
Christopher L de
Graffenried
Consolidated Edison Co.
of New York
1
Negative
Nickesha P Carrol
Consolidated Edison Co.
of New York
6
Negative
Comment: There is not enough clarity on whether a Distribution
Provider (DP) will be able to clearly identify which protection
system components it does own and needs to maintain. Many DPs
own and/or operate equipment identified in the existing or
proposed definition. However, not all such equipment translates
into a transmission Protection System. The definition needs
clarification on when such equipment is a part of the transmission
protection system. Also, the time provided for the first phase "at
least six months" is too open ended and does not provide entities
with a clear timeline. It is suggested that one year is appropriate
for the first phase phasing out the second year in stages.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to
ballot comments and the consideration of comments on the standard itself.
Regarding the comment that the definition needs to identify when equipment is part of the transmission system, this is properly an issue to address in the
various standards that use this definition.
Hugh A. Owen
Public Utility District No.
1 of Chelan County
6
Negative
Comments have convinced me that ambiguities in the
requirements will make compliance/enforcement difficult and the
testing procedures may not lead to greater reliability.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had
not completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Charles A. Freibert
Louisville Gas and
Electric Co.
3
Affirmative
Comments will be submitte4d under the comment form
Response: Thank you for your comments. There was no formal comment period with the second ballot of the proposed definition.
September 10, 2010
5
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Ralph Frederick
Meyer
Entity
Empire District Electric
Co.
Segment
1
Vote
Negative
Comment
Comments: It is still unclear whether relays that respond to
mechanical inputs, such as sudden pressure relays, are included in
the proposed definition as protective relays. While PRC-005-2 R1
limits the scope of that particular standard to protection systems
that sense electrical quantities, it is remains unclear in other
standards that use the defined term whether mechanical input
protections are included. We suggest that “Protective Relay” also
be defined, and that the definition clearly exclude devices that
respond to mechanical inputs in line with the NERC interpretation
of PRC-005-1 in response to the CMPWG request.
Response: Thank you for your comments. The definition has been modified to include only protective relays that respond to electrical quantities. The SDT
sees no need to either repeat or modify the IEEE definition of protective relays.
Michael J. Haynes
Seattle City Light
5
Negative
Control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices. - In
order to comply with this statement utilities would need to conduct
functional tests of their relay system. This type of test is
problematic. A better definition would be to test the output of the
relay.
Response: Thank you for your comments. This component of the Protection System definition is to generally include this functionality as a part of the
Protection System for all applications of the definition throughout NERC Standards. The detailed applicability of this component relative to maintenance within
PRC-005-2 is addressed within the standard, which defines the maintenance required relative to control circuits. The SDT agrees that testing will be required in
the standard itself.
Jim D. Cyrulewski
JDRJC Associates
8
Negative
1. Definition needs to be more specific. Case in point if the
drafting team wants to include battery chargers should
state so.
2. Also implementation plan does not appear to be in synch
with proposed changes.
Response: Thank you for your comments.
1. The current definition uses the term batteries in place of dc supply. The use of the term batteries was quite specific and as such excluded battery chargers.
The definition has been modified to specifically include battery chargers. Battery chargers are now expected to be covered within the proposed definition
and the term dc supply, so too are systems that do not use batteries and/or battery chargers.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the reliability
gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
September 10, 2010
6
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply the
new definition to PRC-005-1.
Daniel Brotzman
Commonwealth Edison
Co.
1
Affirmative
Exelon suggests that the definition further clarify protective relays
that are in scope by adding the following to the frequently asked
questions: 1. “devices providing inputs to protective relays” - this
is to clarify that testing for CTs and PTs will only ensure proper
voltage and current into the relay - therefore not requiring CT and
PT testing. 2. Elimination of “from the station dc supply” - the
intent here is that the DC is testing only the trip functionality to
ensure that certain relays actuate (e.g., 86 and 94 devices) and to
ensure that breaker trip coils are exercised on a 6 year periodicity.
Therefore, the ancillary wiring part of the controls will be on a
longer periodicity (e.g., 12 years)
Response: Thank you for your comments. Your comments appear to be relative to the FAQs for PRC-005-2, rather than the definition. The SDT will
consider these comments when it updates the FAQs.
Robert Martinko
FirstEnergy Energy
Delivery
1
Affirmative
Kevin Querry
FirstEnergy Solutions
3
Affirmative
Kenneth Dresner
FirstEnergy Solutions
5
Affirmative
Mark S Travaglianti
FirstEnergy Solutions
6
Affirmative
Douglas Hohlbaugh
Ohio Edison Company
4
Affirmative
September 10, 2010
FirstEnergy appreciates the hard work of the drafting team, but
ask that the team consider the following suggestions: It is our
understanding that the phrase "Station DC supply" in the definition
is intended to cover the Battery, Battery Charger, and other DC
supplies sources such as flywheels, fuel cells, and motor-generator
sets. However, since the current Protection System Maintenance
and Testing standard PRC-005-1 does not specify maintenance
activities, as does the proposed Version 2 of PRC-005, it therefore
does not provide compliance certainty related to mandatory
expectations. This is because the current standard only requires
that an entity develop a maintenance program and follows their
program. Therefore, it is not clear from the definition that Battery
Chargers must be included in the maintenance program developed
per PRC-005-1. As we stated in our Initial Ballot comments, the
phrase "Station DC supply" should be clarified. In response to our
Initial Ballot comments the SDT stated "Clarifications such as this
properly belong in supplementary materials. This is described in
the FAQ posted in June 2010 (FAQ II.5.A)". We do not agree that
supplementary materials should be relied upon to determine
7
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
"what" is required and should only give you guidance on "how" to
comply. The "what" should be described in the standard
requirements and definitions.
Response: Thank you for your comments. It is the intent of the SDT that battery chargers and other devices that supply power to Protection System devices be
included within the definition. As such, those devices have been included within the minimum maintenance activities of PRC-005-2. However, in the interim
before PRC-005-2 is accepted, under the present PRC-005-1 an entity must have a maintenance program that includes the devices within the definition. PRC005-1 does not prescribe the maintenance, only that the PSMP must include maintenance for the device. The definition has been modified to specifically include
battery chargers.
Pawel Krupa
Seattle City Light
1
Negative
Dana Wheelock
Seattle City Light
3
Negative
Hao Li
Seattle City Light
4
Negative
Functional testing is impractical.
Response: Thank you for your comments. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed
applicability of this element relative to maintenance within PRC-005-2 is addressed within the standard, which defines the maintenance required relative to
control circuits. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not completed the
consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to ballot
comments and the consideration of comments on the standard itself. The SDT agrees that testing will be required in the standard itself.
Dennis Sismaet
Seattle City Light
6
Negative
Functional testing is impractical. Control circuitry associated with
protective functions through the trip coil(s) of the circuit breakers
or other interrupting devices. - " In order to comply with this
statement utilities would need to functional test their relay system.
A better definition would be to test the output of the relay"
Response: Thank you for your comments. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed
applicability of this element relative to maintenance within PRC-005-2 is addressed within the standard, which defines the maintenance required relative to
control circuits. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not completed the consideration
of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to ballot comments and the
consideration of comments on the standard itself. The SDT agrees that testing will be required in the standard itself.
Mark Ringhausen
Old Dominion Electric
Coop.
September 10, 2010
4
Affirmative
I am voting Yes on the ballot, but I do have a small issue with the
wording of 'station DC supply'. In some of our UFLS locations, we
are not in a substation, but out on the feeder circuit and utilizing
the DC supply on the feeder recloser. I think my reading of this
definition would apply to this recloser DC supply as well as the
8
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
Station DC Supply.
Response: Thank you for your comments. Your concern is appreciated. A review of the standard itself shows that the dc supply maintenance activities are
minimal related to UFLS.
Jeff Mead
City of Grand Island
5
Negative
I echo MRO NSRS comments.
Response: Thank you for your comments. The station dc supply element has been modified essentially as you suggest. As to your suggestion regarding
inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
John Yale
Chelan County Public
Utility District #1
5
Negative
If the new definition is: The new proposed definition of Protection
System reads as follows: Protection System:
o Protective relays which respond to electrical quantities,
o Communications systems necessary for correct operation of
protective functions,
o Voltage and current sensing devices providing inputs to
protective relays,
o Station dc supply, and
o Control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices.
In this list format, it appears it is the entire station dc supply not
just that portion and circuitry associated with the protective
circuits. This is an unreasonable burden as many parts of the
station dc supply are used for non-protective functions.
Response: Thank you for your comments. The SDT has modified the definition in consideration of your comments. That bullet now reads: station dc supply
associated with protective functions (including station batteries, battery chargers, and non-battery-based dc supply)
Joseph O'Brien
Northern Indiana Public
Service Co.
6
Negative
1. It is still not clear whether battery chargers fall under this
definition.
2.
The implementation plan should be coordinated with the new
PRC-005-2, not -1.
3. It's not clear if a breaker trip has to be actuated to
test/maintain the control circuitry through the trip coils.
September 10, 2010
9
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments.
1. The definition has been modified to specifically include battery chargers.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the reliability
gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply the
new definition to PRC-005-1.
3. The draft standard PRC-005-2 includes the minimum maintenance activities. Until PRC-005-2 is approved, you need to define the activities and provide a
basis for those activities in accordance with PRC-005-1.
Thomas E Washburn
Florida Municipal Power
Pool
6
Negative
It is still unclear whether relays that respond to mechanical inputs,
such as sudden pressure relays, are included in the proposed
definition as protective relays. While PRC-005-2 R1 limits the
scope of that particular standard to protection systems that sense
electrical quantities, it is remains unclear in other standards that
use the defined term whether mechanical input protections are
included. We suggest that “Protective Relay” also be defined, and
that the definition clearly exclude devices that respond to
mechanical inputs in line with the NERC interpretation of PRC-0051 in response to the CMPWG request
Response: Thank you for your comments. The definition has been modified to include only protective relays that respond to electrical quantities. The SDT sees
no need to either repeat or modify the IEEE definition of protective relays.
Frank Gaffney
Florida Municipal Power
Agency
4
Affirmative
David Schumann
Florida Municipal Power
Agency
5
Affirmative
Richard L.
Montgomery
Florida Municipal Power
Agency
6
Affirmative
Bob C. Thomas
Illinois Municipal Electric
Agency
4
Affirmative
September 10, 2010
It is unclear in the Implementation Plan if the expectation is to
complete the first maintenance and testing cycle, or whether the
entities need to be auditably compliant within the one year
implementation plan, e.g., prove that they have performed
maintenance and testing within the interval defined in the
maintenance and testing program of R1, which essentially could
mean two maintenances and tests of the same component during
the first year for the components identified in the expansion of
scope of the definition of Protection System (e.g., battery
charger). We encourage the SDT to make this crystal clear, i.e.,, is
only the first maintenance and test needed as long as the end of
the maintenance and testing interval identified in the maintenance
10
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
and testing program of R1 has not been reached yet, or are two
maintenance and tests needed to be auditably compliant?
Response: Thank you for your comments. The SDT observes that the implementation plan for the definition requires that the entity implement the revised
program. The implementation plan also requires completion of maintenance within one full cycle of the revised program.
Martin Bauer P.E.
U.S. Bureau of
Reclamation
5
Negative
1. It is unfortunate that the definition did not retain
consistency in the terms. As an example, the definition
indicates it includes protective relays and communication
systems for the correct operation of protective functions.
It would have been better to use the term relays instead
of the term functions.
2. Now it is unclear what the communication systems are for,
since a different term was used rather than protective
relays. Since it is not clear what the communications have
to do with protective relays, as it may also include those
that do not just respond to electrical quantities, the
definition cannot be used to support the standard.
3. The change to insert the term "devices providing” when
referring to voltage and current sensing unfortunately
eliminates the circuitry form the voltage and current
sensing devices to the relays. This was caused by inserting
the word “devices”. I do not believe it was the SDT intent,
however, we are in a literal word world. Since we are
primarily focused on the performance of the device as a
function of the burden on the device, I cannot vote in
favor. My company believes the circuit from the PT and CT
must be a part of the Protection System and is arguably of
greater concern. Consider that if a PT or CT fails partially
or completely it will be known immediately. Maintenance
practices will rarely help that predict failure. On the other
hand, the circuitry from the voltage and current sensing
devices can have a problem that will affect relay
performance through instrument transformer error and in
most cases is only found through testing. Had you
changed “devices” to “circuits” I would agree with
providing the first issue addressed as well. The term
September 10, 2010
11
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
“circuits” could have included both (devices and circuits),
but as I explained, the latter is more important, more
variable, and has been attributed to many protection
system failures.
Response: Thank you for your comments.
1. “Protective relays which respond to electrical quantities” is a description intended to clarify which relays are excluded (those not responding to electrical
quantities are excluded). However a different descriptor was aimed at communications devices; after all there are many communication circuits employed
that are not used for protective functions (voice, alarm data, revenue data, etc.).
2. The term “communications systems necessary for correct operation of protective functions” was chosen to include all methods of conveying tripping,
permissive and blocking signals that are used now or may be used in the future. The SDT saw no need to include language that might result in the inclusion
of voice equipment.
3. The change to insert the term “devices providing” was to improve clarity while also excluding voltage and current measuring devices that provide data
exclusively to metering equipment as opposed to Protection Systems. The SDT agrees with the commenter that an appropriate maintenance activity is to
ensure that the measured voltage and current values correctly make it to the relays. The maintenance activity is a part of the standard. The absence of this
activity from the definition is not intended to lead one to believe that the activity is not important.
John J. Moraski
Baltimore Gas & Electric
Company
September 10, 2010
1
Negative
It seems not to be the intention of the SDT to require testing of
CT’s and PT’s beyond verifying that they that are delivering
acceptable signals to relays. Table 1 a of the standard includes: Voltage & Current Sensing Devices / 12 Calendar Years / Verify
proper functioning of the current and voltage circuit inputs from
the voltage and current sensing devices to the protective relays.
The FAQ’s are even clearer and say:
*********************************** 3. Voltage and Current
Sensing Device Inputs to Protective Relays A. What is meant by
“...verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays ...” Do we
need to perform ratio, polarity and saturation tests every few
12
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Amir Y Hammad
Entity
Constellation Power
Source Generation, Inc.
Segment
5
Vote
Negative
Comment
years? No. You must prove that the protective relay is receiving
the expected values from the voltage and current sensing devices
(typically voltage and current transformers). This can be as
difficult as is proposed by the question (with additional testing on
the cabling and substation wiring to ensure that the values arrive
at the relays); or simplicity can be achieved by other verification
methods. Some examples follow: - Compare the secondary values,
at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay
circuit. - Compare the values, as determined by the questioned
relay, to another protective relay monitoring the same line, with
currents supplied by different CTs. - Query SCADA for the power
flows at the far end of the line protected by the questioned relay,
compare those SCADA values to the values as determined by the
questioned relay. - Totalize the Watts and VARs on the bus and
compare the totals to the values as seen by the questioned relay.
The point of the verification procedure is to ensure that all of the
individual components are functioning properly; and that, an
ongoing proactive procedure is in place to re-check the various
components of the protective relay measuring systems.
*********************************** But the neither the
originally revised or newly revised definitions carry that implication
very well. Suppose the phrase in the definition were changed
from: “Voltage and current sensing devices providing inputs to
protective relays” to; “Voltage and current sensing device output
circuits and the associated circuits to the inputs of protective
relays”. This would make the whole definition read: Protection
System: Protective relays which respond to electrical quantities,
communication systems necessary for correct operation of
protective functions, voltage and current sensing device output
circuits and the associated circuits to the inputs of protective
relays, station dc supply, and control circuitry associated with
protective functions through the trip coil(s) of the circuit breakers
or other interrupting devices.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had
not completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
September 10, 2010
13
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
responses to ballot comments and the consideration of comments on the standard itself. You have put together a complete discussion of the fact that there is
more to a system than merely 5 listed devices.
Garry Baker
JEA
3
Negative
JEA believes the change in the definition should coordinate with
the new standard PRC-005-002.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
William Mitchell
Chamberlain
California Energy
Commission
9
Negative
Lack of clarity or apparent conflict between certain requirements
would make compliance assessment difficult.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had
not completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Bruce Merrill
Lincoln Electric System
3
Negative
Dennis Florom
Lincoln Electric System
5
Negative
Eric Ruskamp
Lincoln Electric System
6
Negative
LES would like to thank the Drafting Team for its time and effort in
developing the definition. However, at this time LES believes that
the implementation plan for the definition should be directly linked
to the approval and implementation schedule for PRC-005-2 and
the proposed definition of Protection System is incomplete as
written and remains open to interpretation.
LES offers the following Protection System definition for the SDT’s
consideration: “Protection System” is defined as: A system that
uses measurements of voltage, current, frequency and/or phase
angle to determine anomalies and trips a portion of the BES and
consists of 1) Protective relays, and associated auxiliary relays,
that initiate trip signals to trip coils, 2) associated communications
channels, 3) current and voltage transformers supplying protective
relay inputs, 4) dc station supply, excluding battery chargers, and
5) dc control trip path circuitry to the trip coils of BES connected
breakers, or equivalent interrupting device, and lockout relays.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
September 10, 2010
14
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
The SDT disagrees with several aspects of your suggested changes: Auxiliary relays are not a protective relay, but are instead a part of the dc control circuit;
“associated” communication systems is too vague to address existing concerns with the definition; battery chargers specifically should NOT be excluded; and “to
the trip coils” does not include trip coils as intended by the SDT. The SDT has made changes to the definition which may address other parts of your comment
Robert Ganley
Long Island Power
Authority
1
Affirmative
LIPA offers the following definition which we feel is clearer:
Protective relays which respond to electrical quantities,
communication systems required for operation of protective
functions, voltage and current sensing devices to protective relays,
station dc supply, and control circuitry from the associated
protective functions through the trip coil(s) of the circuit breakers
or other interrupting devices.
Response: Thank you for your comments. The SDT has adopted your suggestion regarding Protective Relays.
Saurabh Saksena
National Grid
September 10, 2010
1
Affirmative
National Grid suggests adding “Protection System Components
including” in the beginning. This is because the word
“components” has been used extensively throughout the standard
and there is no mention of what constitutes a protection system
component in the standard. The word “component” does find
mention in FAQs, however, it is recommended to mention it in the
main standard. Also, National Grid proposes a change in the
proposed definition (changing "voltage and current sensing inputs"
to "voltage and current sensing devices providing inputs"). The
revised definition should read as follows: Protective System
Components including Protective relays, communication systems
necessary for correct operation of protective functions, voltage
and current sensing devices providing inputs to protective relays
and associated circuitry from the voltage and current sensing
devices, station dc supply, and control circuitry associated with
protective functions from the station dc supply through the trip
coil(s) of the circuit breakers or other interrupting devices. The
time provided for the first phase “at least six months” is too open
ended and does not give entities a clear timeline. National Grid
15
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
suggests 1 year for the first phase. As a result, National Grid
suggests phasing out the second phase in stages.
Response: Thank you for your comments. The SDT believes that inclusion of the defined term within its own definition is not appropriate, and declines to adopt
your suggestion regarding the definition. The Implementation Plan and definition have both been modified in a manner that supports your comments.
Liam Noailles
Xcel Energy, Inc.
5
Negative
David F. Lemmons
Xcel Energy, Inc.
6
Negative
NERC has indicated that this definition is being processed to close
a reliability gap. It is not clear as to what gap this proposed
definition is closing. The use of the term “Station DC Supply”
actually introduces more confusion since some entities may view
this as only batteries, and not include chargers. It would appear
that the intent is to ensure that during a loss of substation service
power scenario that the source of power (whatever that may be)
to the Protection System is available and able to perform as
designed. Recommend the definition be re-written to make it clear
as to what components related to this assured source of power
are required to be maintained as part of the Protection System, or
alternatively define “Station DC Supply”.
Response: Thank you for your comments. The definition has been modified to specifically include battery chargers.
David H.
Boguslawski
Northeast Utilities
1
Negative
NU believes that a protection system includes: 1) Protective relays
which respond to electrical quantities, 2) Communications systems
necessary for correct operation of protective functions, 3) Voltage
and current sensing devices providing inputs to protective relays",
and associated circuitry from the voltage and current sensing
devices" 4) Station dc supply, and 5) Control circuitry associated
with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices The proposed definition
excludes "and associated circuitry from the voltage and current
sensing devices" from item 3. NU believes that the associated
circuitry for voltage and current sensing devices should be
included. It is our concern that the proposed definition implies
PRC-005 will apply specifically to the voltage and current sensing
devices and not include the AC circuitry between these devices
and the relay inputs.
Response: Thank you for your comments. The words of the definition were chosen to help clarify and exclude devices used exclusively for non-protective
functions (metering, etc.), while the maintenance standard itself has a minimum maintenance activity that seeks to demonstrate the importance of the entire
September 10, 2010
16
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
scheme.
Chifong L. Thomas
Pacific Gas and Electric
Company
1
Affirmative
PG&E believes the definition should identify that the protection
system is associated with direct BES electrical quantities with the
intention of protecting the BES from any device from propagating
a problem in one part of the BES to another. The definition should
not include associated systems, i.e. auxiliary systems including
their transformers, motors, etc. For generating stations the
protection included should only be the generator itself and its
associated main bank transformer that delivers the power to the
system. Likewise, for distribution substations, the protection
should only include equipment such as the main transformer that
draws power from the BES and not equipment such as distribution
feeders.
6
Affirmative
Please reference comments submitted by the PSEG companies on
the official comment form for this standard.
Response: Thank you for your comments.
James D. Hebson
PSEG Energy Resources
& Trade LLC
Response: Thank you for your comments. For this second ballot, there was no formal comment period.
Rebecca Berdahl
Bonneville Power
Administration
3
Negative
Please see BPA's comments submitted during the concurrent
formal comment period ending July 16, 2010.
Response: Thank you for your comments. The SDT changed the definition following the formal comment period that ended July 16, 2010.
Mark A Heimbach
PPL Generation LLC
5
Negative
Please see comments submitted by "PPL Supply" on 7/16/10.
Response: Thank you for your comments. The SDT changed the definition following the formal comment period that ended July 16, 2010.
Laurie Williams
Public Service Company
of New Mexico
1
Negative
PNM rejects this definition as too broad and not consistent with
the way utilities treat the various items in the definition, but
agrees with the proposed changes to the implementation plan.
Response: Thank you for your comments. Absent specific comments on the definition, the SDT is unable to respond to your concerns.
September 10, 2010
17
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Wayne Lewis
Entity
Progress Energy
Carolinas
Segment
5
Vote
Affirmative
Comment
Progress Energy does not believe that the definition should be
implemented separately from and prior to the implementation of
PRC-005-2. We believe there should be a direct linkage between
the definition’s effective date to the approval and implementation
schedule of PRC-005-2. Since this new definition should be directly
linked to the proposed revised standard, it would be premature to
make this new definition effective prior to the effective date of the
new standard. We believe that changes to the maintenance
program should be driven by the revision of the PRC standard, not
by the revision of a definition.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Kenneth D. Brown
Public Service Electric
and Gas Co.
1
Affirmative
PSE&G is now voting affirmative. Thanks to the drafting team for
improving the clarity of the definition.
10
Negative
Revise Protection System definition to: o BES Protective relays
which respond to electrical quantities, o Communications systems
necessary for correct operation of the BES protective functions, o
Voltage and current sensing devices providing inputs to BES
protective relays, o Battery and battery chargers that supply dc
to BES protective relays, communications, and control circuitry,
and o Control circuitry associated with the BES protective
functions through the trip coil(s) of the circuit breakers or other
interrupting devices.
Response: Thank you for your comments.
Dan R. Schoenecker
Midwest Reliability
Organization
Response: Thank you for your comments. The station dc supply component type has been modified essentially as you suggest. As to your suggestion
regarding inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
September 10, 2010
18
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Thomas C. Mielnik
Entity
MidAmerican Energy Co.
Segment
3
Vote
Negative
Comment
Revise Protection System definition to: BES Protective relays which
respond to electrical quantities, Communications systems
necessary for correct operation of the BES protective functions,
Voltage and current sensing devices providing inputs to BES
protective relays, Battery and battery chargers that supply dc to
BES protective relays, communications, and control circuitry, and
Control circuitry associated with the BES protective functions
through the trip coil(s) of the circuit breakers or other interrupting
devices.
Response: Thank you for your comments. The station dc supply component type has been modified essentially as you suggest. As to your suggestion
regarding inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
Brian EvansMongeon
Utility Services, Inc.
8
Negative
see filed comments
Response: Thank you for your comments. The SDT changed the definition following the formal comment period that ended July 16, 2010; there was no formal
comment period during the second ballot of the proposed definition.
Glen Reeves
Salt River Project
5
Affirmative
SRP believes the requirements of the Standard are confusing and
may be problematic in determining compliance. We also believe
the required functional testing of the breaker trip coil may
potentially increase maintenance outages of circuit breakers. In
most cases, circuit breaker maintenance outages can be
coordinated such that Protection System maintenance and testing
can be done simultaneously. However, in some cases this may not
be possible. Outages of any BES facility whether planned or
unplanned can impact system reliability. SRP suggests that trip coil
monitoring devices be included as an acceptable means of
ensuring the trip coil is functioning properly. This will help to avoid
unnecessary outages.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. The SDT provides the following response, in accordance with the
responses to comments on the standard itself.
James V. Petrella
Atlantic City Electric
Company
September 10, 2010
3
Affirmative
Suggested improvement: add "and associated circuitry" to
"Voltage and current sensing devices and associated circuitry
providing inputs to protective relays".
19
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments. Many other commenters have previously expressed concern with the definition as you suggest, and the SDT
believes that the definition as currently posted best expresses this portion of the definition.
Thomas R. Glock
Arizona Public Service
Co.
3
Negative
The change to the definition relative to the voltage and current
sensing devices is too prescriptive. Methods of determining the
integrity of the voltage and current inputs into the relays to ensure
reliability of the devices should be up to the discretion of the
utility.
Response: Thank you for your comments. Absent any specific comment regarding how the definition is too prescriptive, the SDT is unable to respond to your
concerns. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not completed the consideration of
comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to ballot comments and the
consideration of comments on the standard itself.
William D Shultz
Southern Company
Generation
5
Negative
The definition alone is acceptable, but the existing version of PRC005 does not guarantee any additional maintenance or testing will
occur with its ratification. Maintenance methodology documents
will have to be revised to include the new definition, but entities
may still dictate limited maintenance activities and lengthy
intervals which require no additional maintenance to be done. The
PRC-005-2 version of the standard includes this revised definition
and requires specific maintenance activities at specific intervals.
Establishing only a new definition does not close the perceived
reliability gap that is the basis for the current vote. The new
definition needs to be ratified along with the revised standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Raj Rana
American Electric Power
September 10, 2010
3
Negative
The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could
be construed by an auditor to include a lot of equipment and
infrastructure not intended by the PSMT SDT. For example, station
battery chargers are typically supplied by station auxiliary power
transformers, which in turn are supplied by primary-voltage bus
work, primary-voltage fuses, or primary-voltage circuit breakers.
20
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
An auditor for either PRC-005 or any other Standard referencing
"Protection System" could read that such primary-voltage
equipment is part of the Protection System and therefore subject
to certain requirements in either PRC-005 or any other Standard
referencing Protection System. The definition as drafted includes
"Communications systems necessary. . . ". Once again, this term
appears innocuous, but it is actually unclear. For example, if a
transfer-trip channel is carried on a microwave path, an auditor
may decide that the entire microwave equipment, microwave
building battery, and microwave building emergency generator are
all part of the Protection System, and thus subject to requirements
in either PRC-005 or other existing or future Standards that refer
to Protection System. AEP recommends that the term be phrased
"communications paths" opposed to "communications systems".
Similar to the above two items, we are concerned about the
inclusion of voltage and current-sensing "devices" in the Definition.
As written, applicability can be inferred to the entire device and
not merely its output quantities, not only for this Standard but any
other that references a Protection System. AEP recommends the
phrase "circuitry from voltage and current-sensing devices
providing inputs to protective relays" instead of "voltage and
current-sensing devices providing inputs to protective relays"
Response: Thank you for your comments. The definition has been modified to specifically include battery chargers. As to your other comments, it appears
that your comments apply more to the application of the definition within PRC-005-1 or PRC-005-2 than they do to the definition itself. Within the reference
materials associated with PRC-005-2, the SDT advises that equipment associated with microwave systems is part of the communications system. The SDT
believes that the proposed definition is less vague than the current definition on the issues you cite, and would improve the situation that you discuss from the
current level.
Michael Moltane
International
Transmission Company
Holdings Corp
1
Negative
The definition contained in this ballot really needs to be part and
parcel of the PRC-005-2 Standard Ballot, since the definition has
such a huge impact on the standard itself. It is problematic to vote
on a definition and on the standard independent of one another.
Therefore, ITC must vote negative on this Ballot.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
September 10, 2010
21
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Michael Schiavone
Niagara Mohawk
(National Grid Company)
3
Affirmative
The definition could be worded better
Response: Thank you for your comments. The SDT has modified the definition for improved clarity.
Kenneth Parker
Entegra Power Group,
LLC
5
Negative
The definition infers testing of CTs and PTs which should not be
necessary.
Response: Thank you for your comments. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed
applicability of this element of the definition relative to maintenance within PRC-005-2 is addressed within the standard by specifying, “Verify that acceptable
measurements of the current and voltage signals are received by the protective relays”.
Christopher Plante
Integrys Energy Group,
Inc.
4
Negative
1. The definition should state what is meant by “station dc
supply”. There continues to be questions in the industry
regarding if dc supply includes the battery charger. We
believe the charger is not included in station dc supply and
that the Definition of Protection System should specifically
address the point.
2. Also, the definition should specify BES relays, BES
protection functions and elements associated with BES
relays and functions.
Response: Thank you for your comments.
1. The definition has been modified to specifically include battery chargers.
2. This is properly an issue to address in the various standards that use this definition.
Terry Harbour
MidAmerican Energy Co.
September 10, 2010
1
Negative
The following changes should be incorporated in the definition to
insure it is used consistently in PRC-005 and any other standards
where it appears. Revise Protection System definition to: o BES
Protective relays which respond to electrical quantities, o
Communications systems necessary for correct operation of the
BES protective functions, o Voltage and current sensing devices
providing inputs to BES protective relays, o Battery and battery
chargers that supply dc to BES protective relays, communications,
and control circuitry, and Control circuitry associated with the BES
22
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
protective functions through the trip coil(s) of the circuit breakers
or other interrupting devices.
Response: Thank you for your comments. The station dc supply component type has been modified essentially as you suggest. As to your suggestion
regarding inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
Robert W. Roddy
Dairyland Power Coop.
1
Negative
The implementation of the revised definition should not take place
until the revised standard PRC-005-2 is in effect.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
John Tolo
Tucson Electric Power
Co.
1
Negative
The mention of communication systems maintenance (M1.) needs
more clarity as to the depth of the maintenance required. Also,
Table 1a, a 3-month interval to verify that the Protection System
communications system is functional is too frequent to be
practical.
Response: Thank you for your comments. Your comments do not seem relevant to the definition, but instead appear to be related directly to the revisions to
the draft PRC-005-2 itself. The SDT had not completed consideration of comments on the standard when the definition was re-posted. The SDT provides the
following response, in accordance with the responses to comments on the standard itself.
Scott Kinney
Avista Corp.
1
Negative
The modified definition of Protection System now refers to
“functions” rather than “devices.” What are the “functions?” This
new term adds confusion without being defined in the standard.
Response: Thank you for your comments. The reference to “functions” is intended to reflect that there is increasing use, particularly in SPS, of devices which
mimic protective relays but are not actually traditional relays.
Michael Gammon
Kansas City Power &
Light Co.
September 10, 2010
1
Negative
The proposed changes in the Standard are far too prescriptive and
do not take into account the multitude of manufacturers
23
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Charles Locke
Kansas City Power &
Light Co.
3
Negative
Scott Heidtbrink
Kansas City Power &
Light Co.
5
Negative
Thomas Saitta
Kansas City Power &
Light Co.
6
Negative
Comment
equipment by establishing broad maintenance cycles and testing
intervals.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. In Order 693, the
FERC directed that NERC establish maximum allowable intervals for maintenance of protection systems.
Jack Stamper
Clark Public Utilities
1
Negative
The proposed definition does not provide the level of clarity that is
needed.
Response: Thank you for your comments. The SDT has modified the definition for improved clarity.
Ajay Garg
Hydro One Networks,
Inc.
1
Affirmative
The proposed definition of Protection System needs clarification on
when such equipment is a part of the transmission protection
system. Emphasis should be on systems and not individual
components.
Response: Thank you for your comments. This issue is better addressed in the various standards that use the definition.
Mace Hunter
Lakeland Electric
3
Affirmative
The proposed draft may introduce TFEs into the PRC standards,
not a good thing. The proposed draft reaches beyond the
statutory scope of the reliability standards. Perfection is not a
realistic goal.
Response: Thank you for your comments. The SDT has modified the definition for improved clarity.
Kim Warren
Independent Electricity
System Operator
September 10, 2010
2
Affirmative
The proposed revision to the definition has removed the
"associated circuitry from the voltage and current sensing devices"
which we believe should be included since failure of this wiring will
render the Protection System inoperative. On this basis we
recommend the following change to once again include this
circuitry in the definition: “Protective relays which respond to
electrical quantities, communication systems necessary for correct
operation of protective functions, voltage and current sensing
devices AND ASSOCIATED CIRCUITRY [emphasis added] providing
inputs to protective relays, station dc supply, and control circuitry
24
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.”
Response: Thank you for your comments. The change to insert the term “devices providing” was to improve clarity while also excluding voltage and current
measuring devices that provide data exclusively to metering equipment as opposed to Protection Systems. The SDT agrees with the commenter that an
appropriate maintenance activity is to ensure that the measured voltage and current values correctly make it to the relays. The maintenance activity is a part of
the standard. The absence of this activity from the definition is not intended to lead one to believe that the activity is not important.
Roger C
Zaklukiewicz
8
Negative
The proposed rewording of the definition implies that the wiring
from the current transformers and voltage transformers to the
protective relay systems are independent of the protection system
being tested and that separate maintenance standards will have to
be established to test the integrity of the wiring and the Potential
device and current transformer. The definition of the Protection
System should not exclude the wiring and devices which generate
the current and voltage sources to the protective relays.
Response: Thank you for your comments. The change to insert the term “devices providing” was to improve clarity while also excluding voltage and current
measuring devices that provide data exclusively to metering equipment as opposed to Protection Systems. The SDT agrees with the commenter that an
appropriate maintenance activity is to ensure that the measured voltage and current values correctly make it to the relays. The maintenance activity is a part of
the standard. The absence of this activity from the definition is not intended to lead one to believe that the activity is not important.
Jim R Stanton
SPS Consulting Group
Inc.
8
Negative
The reference to "communication systems" should be deleted from
the definition. It is confusing to Registered Entities who do not
consider the circuits that connect components of a protection
system to be a communication "system" such as a telephone
system, postal service or computer network which is more
properly called a communication system. Suggest changing it to
"signal carrying circuitry."
Response: Thank you for your comments. The SDT believes that “Communication Systems” is a term that is generally well understood within the industry.
September 10, 2010
25
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Brock Ondayko
Entity
AEP Service Corp.
Segment
5
Vote
Negative
Comment
The term "station" should either be defined or removed from the
definition, as it implies transmission and distribution assets while
the term "plant" is used to define generation assets. It would
suffice to simply refer to the "DC Supply". As written, the
implementation plan only specifies a time frame for entities to
update their documentation for PRC-005-1 and PRC-005-2
compliance. The implementation plan also needs to give entities a
time frame to address any required changes to their
documentation for other standards that use the term "Protection
System", including but not limited to NUC-001-2, PER-005-1, PRC001-1, etc.
Response: Thank you for your comments. The term ‘station’ was used because it could include both a substation and a generation station while at the same
time excluded installations that were strictly communications repeater sites. As noted on the “Assessment of Impact of Proposed Modification to the Definition
of “Protection System” which was posted with the first comment period, the SDT believes that the bulk of the implementation of the new definition will be
regarding PRC-005 (generically) and that there will be very little implementation associated with the other standards that utilize this term.
Paul B. Johnson
American Electric Power
1
Negative
1. The term "station" should either be defined or removed from
the definition, as it implies transmission and distribution assets
while the term "plant" is used to define generation assets. It
would suffice to simply refer to the "DC Supply". As written, the
implementation plan only specifies a time frame for entities to
update their documentation for PRC-005-1 and PRC-005-2
compliance. The implementation plan also needs to give entities a
time frame to address any required changes to their
documentation for other standards that use the term "Protection
System", including but not limited to NUC-001-2, PER-005-1, PRC001-1, etc. we still support a "negative" ballot with the following
comments:
2. The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could
be construed by an auditor to include a lot of equipment and
infrastructure not intended by the PSMT SDT. For example, station
battery chargers are typically supplied by station auxiliary power
transformers, which in turn are supplied by primary-voltage
buswork, primary-voltage fuses, or primary-voltage circuit
September 10, 2010
26
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
breakers. An auditor for either PRC-005 or any other Standard
referencing "Protection System" could read that such primaryvoltage equipment is part of the Protection System and therefore
subject to certain requirements in either PRC-005 or any other
Standard referencing Protection System.
The definition as drafted includes "Communications systems
necessary. . . ". Once again, this term appears innocuous, but it is
actually unclear. For example, if a transfer-trip channel is carried
on a microwave path, an auditor may decide that the entire
microwave equipment, microwave building battery, and microwave
building emergency generator are all part of the Protection
System, and thus subject to requirements in either PRC-005 or
other existing or future Standards that refer to Protection System
Similar to the above two items, we are concerned about the
inclusion of voltage and current-sensing "devices" in the Definition.
As written, applicability can be inferred to the entire device and
not merely its output quantities, not only for this Standard but any
other that references a Protection System.
Response: Thank you for your comments.
1. The term ‘station’ was used because it could include both a substation and a generation station while at the same time excluded installations that were
strictly communications repeater sites. As noted on the “Assessment of Impact of Proposed Modification to the Definition of “Protection System” which
was posted with the first comment period, the SDT believes that the bulk of the implementation of the new definition will be regarding PRC-005
(generically) and that there will be very little implementation associated with the other standards that utilize this term.
2. The definition has been modified to specifically include battery chargers. As to your other comments, it appears that your comments apply more to the
application of the definition within PRC-005-1 or PRC-005-2 than they do to the definition itself. Within the reference materials associated with PRC-0052, the SDT advises that equipment associated with microwave systems is part of the communications system. The SDT believes that the proposed
definition is less vague than the current definition on the issues you cite, and would improve the situation that you discuss from the current level.
Peter T Yost
Consolidated Edison Co.
of New York
September 10, 2010
3
Negative
1. There is not enough clarity on whether a Distribution Provider
(DP) will be able to clearly identify which protection system
components it does own and needs to maintain. Many DPs
own and/or operate equipment identified in the existing or
proposed definition. However, not all such equipment
translates into a transmission Protection System. The
definition needs clarification on when such equipment is a part
of the transmission protection system.
27
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
2. Also, the time provided for the first phase "at least six months"
is too open ended and does not provide entities with a clear
timeline. It is suggested that one year is appropriate for the
first phase phasing out the second year in stages.
Response: Thank you for your comments.
1. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not completed the consideration of
comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to ballot comments
and the consideration of comments on the standard itself. “When such equipment is part of the transmission protection system” is properly a matter to
be resolved within the various standards that use this term.
2. The implementation period has been revised from six months to twelve months.
Greg Lange
Public Utility District No.
2 of Grant County
3
Negative
These systems are not always maintained at the component level.
ie. meggering from the relay input test switch through the cable
and the CT. This has not closed all the issues around professional
judgement (interpretations) that make us nervous when faced
with the human element of an audit. We need more specificity to
close that gap.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Silvia P Mitchell
Florida Power & Light Co.
6
Affirmative
This revision is better written.
Response: Thank you for your comments.
September 10, 2010
28
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Joseph G. DePoorter
Madison Gas and Electric
Co.
Segment
4
Vote
Negative
Comment
Upon review of the updated proposed “Protection System”
definition and its main use in describing PRC-005, which applies to
BES Protective Systems, the definition needs to incorporate BES
within it. Without BES used within the definition, it will be used to
interpret every protection system that the industry uses. This is
not the course that we wish to travel. Please note the following
recommended definition: o BES Protective relays which respond
to electrical quantities, o Communications systems necessary for
correct operation of the BES protective functions, o Voltage and
current sensing devices providing inputs to BES protective relays,
o Battery and battery chargers that supply dc power to BES
protective relays, communications, and control circuitry, and o
Control circuitry associated with the BES protective functions
through the trip coil(s) of the circuit breakers or other interrupting
devices.
Response: Thank you for your comments. The station dc supply component type has been modified essentially as you suggest. As to your suggestion
regarding inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
Richard J. Mandes
Alabama Power Company
3
Affirmative
Anthony L Wilson
Georgia Power Company
3
Affirmative
Gwen S Frazier
Gulf Power Company
3
Affirmative
Don Horsley
Mississippi Power
3
Affirmative
Horace Stephen
Williamson
Southern Company
Services, Inc.
1
Affirmative
We agree that the definition provides clarity and will enhance the
reliability of the Protection Systems to which it is applicable.
However, we feel that there needs to be a direct linkage of the
definition’s effective date to the approval and implementation
schedule of PRC-005-2. Since this new definition is directly linked
to the proposed revised standard, it would be premature to make
this definition effective prior to the effective date of the new
standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Jason L Marshall
Midwest ISO, Inc.
2
Abstain
We are abstaining because a number of our stakeholders have
concerns regarding the definition of Protection System.
Response: Thank you for your comments. The SDT responded to the individual stakeholder comments submitted.
September 10, 2010
29
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Claudiu Cadar
Entity
GDS Associates, Inc.
Segment
1
Vote
Negative
Comment
We do not agree with inclusion of the trip coil. The trip coil is not a
protective device; it does not sense voltage or current and
operates based on a faulted condition. It is supplied the necessary
input from the DC system which is based on protective relays
signaling and contact operation. The trip coil is part of the circuit
breaker; it is not separate equipment. Does this mean that the
circuit breaker is now part of the protection system?
Response: Thank you for your comments. The current definition includes “DC Control Circuitry”; the SDT attempted to clearly define which of the many control
circuits and the limit of the definition. While the current definition is vague, it can certainly include the trip coils and close coils and alarm circuits of the
interrupting device. The SDT believes that the electrically-operated trip coils are an important part of the control circuitry.
Anthony Jankowski
Wisconsin Energy Corp.
September 10, 2010
4
Negative
We Energies does not agree to the implementation plan proposed.
While it makes common sense to proceed with R1 prior to
proceeding with implementing R2, R3, and R4, the timeline to be
compliant for R1 is too short. It will take a considerable amount of
resources to migrate the maintenance plan from today’s standard
to the new standard in phase one. ATC recommends that time to
develop and update the revised program be increased to at least
one year followed by a transition time for the entity to collect all
the necessary field data for the protection system within its first
full cycle of testing. (In ATC’s case would be 6 years) To address
phase two, We Energies believes human and technological
resources will be overburdened to implement this revised standard
as written. The transition to implementing the new program will
take another full testing cycle once the program has been
updated. Increased documentation and obtaining additional
resources to accomplish this will be challenging. Implementation
of PRC-005-2 will impact We Energies in the following manner: a.
Increase costs: double existing maintenance costs. b. Since there
will be a doubling of human interaction (or more), it is expected
that failures due to human error will increase, possibly
proportionately. c. Breaker maintenance may need to be aligned
with protection scheme testing, which will always contain elements
that are include in the non-monitored table for 6 yr testing. d. We
Energies is developing standards for redundant bus and
transformer protection schemes. This would allow We Energies to
30
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
test the protection packages without taking the equipment out of
service. Further if one system fails, there is full redundancy
available. With the current version of PRC-005-2, We Energies
would need to take an outage to test the protection schemes for a
transformer or a bus, there is not an incentive to install redundant
schemes. We Energies is working with a condition based breaker
maintenance program. This program’s value would be greatly
diminished under PRC-005-2 as currently written. Consideration
also needs to be given for other NERC standards expected to be
passed and in the implementation stage at the same time, such as
the CIP standards.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had
not completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Linda Horn
Wisconsin Electric Power
Co.
5
Negative
James R. Keller
Wisconsin Electric Power
Marketing
3
Negative
We object strongly to the addition of the term "voltage and
current sensing devices...". This revised definition will make it a
requirement to perform actual tests on the voltage and current
transformers. The previous definition was "voltage and current
inputs to protective relays" and this is much preferred to allow the
needed flexibility in maintenance practices.
Response: Thank you for your comments. The current definition of Protection System uses the term “voltage and current sensing devices”. The current
standard PRC-005-1 requires the entity to have a PSMP for those devices. The proposed revision PRC-005-2 would require minimum maintenance activities that
verify other than an annual IR Scan of the voltage and current sensing devices. As there is no method listed in the standard, some of the process flexibility that
you seek has been maintained.
Brandy A Dunn
Western Area Power
Administration
1
Affirmative
Western agrees with the revised definition of a Protection System
and disagreese with the Implementation Plan under PRC-005-1.
The definition implementation should be delayed until approval of
PRC-005-2.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
September 10, 2010
31
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
entities time to apply the new definition to PRC-005-1.
Henry Delk, Jr.
SCE&G
1
Negative
While SCE&G believes the majority of the PRC-005-2 standard is
ready to be affirmed there are still inconsistencies with areas of
the standard that need to be corrected prior to approval. These
inconsistencies are addressed in SCE&G’s comments which have
been submitted for the current draft of this standard.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. Please see the response to your comments on the first draft of
the standard.
Richard J Kafka
Potomac Electric Power
Co.
1
Affirmative
While voting in the affirmative, PHI feels the definition could be
improved by adding and associated circuitry to the third item
Voltage and current sensing devices and associated circuitry
providing inputs to protective relays
Response: Thank you for your comments. The SDT agrees with the commenter of the importance of this as a maintenance activity and has attempted to
capture relevant maintenance activities within the revised standard itself.
David A. Lapinski
Consumers Energy
3
Negative
David Frank Ronk
Consumers Energy
4
Negative
Without the context of draft PRC-005-2, the changes to this
definition are difficult to understand and even more difficult to
implement. We therefore strongly recommend that this definition
NOT be approved independently from the draft of PRC-005-2, and
that development of both the definition and the standard proceed
as a single activity.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Gregory L Pieper
Xcel Energy, Inc.
1
Negative
Michael Ibold
Xcel Energy, Inc.
3
Negative
Xcel Energy believes the standard still contains many aspects that
are not clearly understood by entities, including what is needed to
demonstrate a compliant PSMP. Comments have been submitted
concurrently to NERC via the draft comment response form.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. Please see the response to your comments on the first draft of
September 10, 2010
32
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
the standard.
James A Ziebarth
Y-W Electric Association,
Inc.
4
Affirmative
Y-WEA thanks the SDT for clarifying what relays are and are not
included in this definition.
Response: Thank you for your comments.
September 10, 2010
33
Consideration of Comments on Protection System Maintenance & Testing —
Project 2007-17 – Definition of Protection System
The Protection System Maintenance & Testing Standard Drafting Team thanks all
commenters who submitted comments for the revised definition of “Protection System.”
The revised definition was posted for a 30-day public comment period from September 13,
2010 through October 12, 2010. Stakeholders were asked to provide feedback on the
definition through a special Electronic Comment Form. There were 27 sets of comments,
including comments from more than 62 different people from approximately 53 companies
representing 7 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
While several commenters made suggestions to further refine the definition of Protection
System, the team did not make any additional changes to the definition based on
stakeholder comments. The team did, however remove the proposed modification to PER005 from the implementation plan. No other changes were made.
•
Some commenters made suggestions for modifications to various portions of the
proposed definition of Protection System. There was no commonality to the
proposed revisions and these modifications did not seem to provide greater clarity
than was provided with the last version of the proposed definition posted for
comment and ballot. Since most stakeholders agreed with the latest version of the
proposed definition, no changes were made to the definition.
•
Several commenters questioned the applicability of the defined term “Protection
System” in PER-005; the SDT agreed and modified the Implementation Plan for the
definition of Protection System to remove the reference to PER-005.
•
Several commenters also used the comment period as a forum to show displeasure
with the NERC and regional BES definitions. Making modifications to the definition of
BES is outside the scope of work assigned to this drafting team.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is
a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Protection System Maintenance & Testing Definition of
Protection System — Project 2007-17
Index to Questions, Comments, and Responses
1.
Do you agree with the proposed definition of “Protection System?” If not, please
provide specific suggestions for improvement.…. ................................................. 8
October 28, 2010
2
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Mallory Huggins
Phil Tatro
NERC NA - Not Applicable NA
2.
Bob Cummings
NERC NA - Not Applicable NA
Additional Member Additional Organization Region
Phil Tatro
NERC NA - Not Applicable NA
2.
Bob Cummings
NERC NA - Not Applicable NA
Additional
Member
Additional
Organization
6
7
8
9
10
X
Northeast Power Coordinating Council
Region
Segment
Selection
1.
Alan Adamson
New York State Reliability Council,
LLC
NPCC
10
2.
Gregory Campoli
New York Independent System
Operator
NPCC
2
October 28, 2010
5
Segment
Selection
1.
Guy Zito
4
Segment
Selection
1.
Group
3
NERC Staff
Additional Member Additional Organization Region
2.
2
3
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
Kurtis Chong
Independent Electricity System
Operator
NPCC
2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5.
Chris de Graffenried
Consolidated Edison Co. of New York,
NPCC
Inc.
1
6.
Gerry Dunbar
Northeast Power Coordinating Council NPCC
10
7.
Dean Ellis
Dynegy Generation
NPCC
5
8.
Brian Evans-Mongeon
Utility Services
NPCC
8
9.
Mike Garton
Dominion Resources Services, Inc.
NPCC
5
10.
Brian L. Gooder
Ontario Power Generation
Incorporated
NPCC
5
11.
Kathleen Goodman
ISO - New England
NPCC
2
12.
Chantel Haswell
FPL Group, Inc.
NPCC
5
13.
David Kiguel
Hydro One Networks Inc.
NPCC
1
14.
Michael R. Lombardi
Northeast Utilities
NPCC
1
15.
Randy MacDonald
New Brunswick System Operator
NPCC
2
16.
Bruce Metruck
New York Power Authority
NPCC
6
17.
Lee Pedowicz
Northeast Power Coordinating Council NPCC
10
18.
Robert Pellegrini
The United Illuminating Company
NPCC
1
19.
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
20.
Saurabh Saksena
National Grid
NPCC
1
21.
Michael Schiavone
National Grid
NPCC
1
Peter Yost
Consolidated Edison Co. of New York,
NPCC
Inc.
3
22.
3.
Group
Denise Koehn
Additional
Member
1.
Additional
Organization
Dean Bender
October 28, 2010
X
Bonneville Power Administration
Region
BPA, Transmission SPC Technical
Svcs
2
3
X
4
5
X
6
7
8
9
X
Segment
Selection
WECC
1
4
10
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4.
Group
Steve Rueckert
2
3
4
5
6
7
8
9
X
WECC
Additional Member Additional Organization Region Segment Selection
1. Mary Rieger
WECC
WECC 10
2. John McGee
WECC
WECC 10
5.
Ben Li
Group
x
IRC Standards Review Committee
Additional Member Additional Organization Region Segment Selection
1. Matt Goldberg
ISO-NE
NPCC
2
2. Charles Yeung
SPP
SPP
2
3. Bill Phillips
MISO
MRO
2
4. Greg Van Pelt
CAISO
WECC 2
5. Patrick Brown
PJM
RFC
6. Steve Myers
ERCOT
ERCOT 2
7. Mark Thompson
AESO
WECC 2
8. James Castle
NYISO
NPCC
6.
Michael Gammon
Group
2
2
Kansas City Power & Light
x
x
x
x
x
x
x
x
Additional Member Additional Organization Region Segment Selection
1. Todd Moore
KCPL
SPP
1, 3, 5, 6
7.
Individual
Jana Van Ness
Arizona Public Service Company
8.
Individual
James Stanton
SPS Consulting Group Inc.
9.
Individual
Martin Bauer
US Bureau of Reclamation
10.
Individual
Karl Bryan
US Army Corps of Engineers
October 28, 2010
10
X
X
X
X
5
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
X
3
X
4
5
X
6
8
9
X
11.
Individual
Kirit S. Shah
Ameren
12.
Individual
Greg Froehling
Green Country Energy
X
13.
Individual
Dan Roethemeyer
Dynegy Inc.
X
14.
Individual
Paul Rocha
CenterPoint Energy
X
15.
Individual
Robert Ganley
LIPA
X
16.
Individual
Andrew Z. Pusztai
American Transmission Company
X
17.
Individual
Thad Ness
American Electric Power (AEP)
X
X
X
X
18.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
19.
Individual
Kathleen Goodman
ISO New England Inc.
20.
Individual
Patti Metro
NRECA
X
X
21.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
22.
Individual
Terry Harbour
MidAmerican Energy
X
23.
Individual
Michael Lombardi
Northeast Utilities
X
X
X
24.
Individual
Dan Rochester
Independent Electricity System Operator
X
25.
Individual
Jason L. Marshall
Midwest ISO
X
October 28, 2010
7
X
6
10
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
26.
Individual
Greg Rowland
Duke Energy
27.
Individual
Alice Murdock
Ireland
Xcel Energy
October 28, 2010
2
3
4
5
6
X
X
X
X
X
X
X
X
7
8
9
7
10
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
1. Do you agree with the proposed definition of “Protection System?” If not, please provide specific suggestions for
improvement.
Summary Consideration: Numerous commenters confused the definition with its applicability in various standards. Other
commenters made suggestions to modify various portions of the definition. No changes were made to the definition in response
to these comments. Several commenters questioned the applicability of the defined term “Protection System” in PER-005; the
SDT agreed and modified the Implementation Plan for the definition of Protection System to remove the reference to PER-005.
Several commenters also used the comment period as a forum to show displeasure with the NERC and regional BES definitions.
Making changes to the definition of Bulk Electric System is outside the scope of work assigned to this drafting team.
Organization
Yes or No
NERC Staff
No
Question 1 Comment
NERC staff does not support the phrase “voltage and current sensing devices providing input to protective
relays.” While no version of the definition has been all-inclusive with respect to this phrase, we believe that the
best phrase would be a combination of several drafts and should state the following: “voltage and current
sensing devices and associated circuitry from the voltage and current sensing devices to the protective relay
inputs.” As currently written, the definition represents a step backward from the language in the previous
definition (“voltage and current sensing inputs to protective relays and associated circuitry from the voltage and
current sensing devices”) and should be modified.
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is better supported by industry.
Northeast Power Coordinating
Council
No
This project addresses the definition of a Protection System. However, an ongoing issue that needs to be
addressed is clarification of when a Bulk Electric System transmission Protection System applies to a
Distribution Provider. An example would be for a tee-tap off a Bulk Power System 345kV line to a step down
transformer supplying distribution--would the relaying on the low side of the transformer be expected to comply
with the requirements of PRC-005-2? Would the protection system configuration be considered a Protection
System? Will this issue be addressed within the scope of Project 2007-17?
Response: Thank you for your comment. The SDT believes these questions are not within the scope of Project 2007-17 and should be addressed by
the Regional Entities.
WECC
The definition is generally acceptable. However, we believe that better language for the third bullet is as
follows: DC supply sources affecting the "Protection System" (including station batteries, battery chargers, and
non-battery-based dc supply), and...A definition of non-battery-based dc supply should be included to avoid
confusion and we offer the following: The inverter or rectifier in the circuit, dependent upon how the end use
quipment is designed. Uninterruptible power supply (UPS) such as on-line, line-interactive or standby that some
of the protection system could be on. The intent of the suggestion would consider that the entire protection
system has to operate in order to maintain the reliability of the BES. An example would be if the protective relay
October 28, 2010
8
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
and associated communications were on a UPS system and the intended device to operate were on station
batteries, this would be the best case scenario as the Micro processors relays and the newer associated
communications do not like the voltage drop when the station switches to the station batteries, hence the use of
UPS options. Micro processors relays do have internal battery backup to keep them up and running, though a
maintenance task would have to be included to be sure that they are properly maintained and tested, so the
UPS option is easier and has been “kind of” an industry standard in the past. In the end the UPS would have to
be on a maintenance schedule also.
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is better supported by industry. The term
“non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel cells, or any other
emerging technology which is capable of supplying dc power to the Protection System.
Kansas City Power & Light
No
The phrase, "non-battery-based dc supply" is ambiguous and not well defined. It is critical this definition be
clear in its intent and not introduce confusion to allow maintenance programs to be effective. Recommend this
phrase either needs additional definition or should be considered for removal.
Response: Thank you for your comment. The SDT believes the language is clear and supported by industry. The term “non-battery-based dc supply”
is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel cells, or any other emerging technology which is
capable of supplying dc power to the Protection System.
SPS Consulting Group Inc.
No
The revised definition perpetuates the confusion over "communications systems" embedded or otherwise
associated with Protection Systems. The term "communications components" is more accurate.
Response: Thank you for your comment. The SDT believes the language is clear and addresses relay communication systems currently used by
industry.
US Bureau of Reclamation
No
The term "protection functions" is ambiguous as it is not related to the protection function associated with the
protective relays. There are other protection functions not associated with protective relays that respond to
electrical quantities. The language for Communication systems should be changed to remove the ambiguity.
The following change would be clear, "Communication system necessary for the correct operation of the
protective relays" The input to the relays is from voltage and current sensing devices through their respective
circuits. Since the definition for protective relays separates the term "control circuitry" associated with
protective relays, it is clear that protective relays do not also include the "control circuitry". By the same token,
voltage and current sensing devices do not include their related circuits. The definition for voltage and current
sensing devices should be revised to include the term "circuits". The following language change would serve
make it clear: "Voltage and current sensing devices and their respective circuits providing inputs protective
relays".
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
US Army Corps of Engineers
October 28, 2010
No
The use of the term "protection functions" is not a defined NERC term and either the term should be defined or
it should not be used. At best the term is ambiguous and could lead to scope growth by auditors. Recommend
9
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
that the following changes be made: "Communication system necessary for the correct operation of the
protective relays." "Control circuitry associated with protective relays through the trip coil(s) of the circuit
breaker or other interrupting device." See the next paragraph for the proposed correction to the DC Supply part
of the definition. The input to the relay is from voltage and current sensing devices yet there is no mention of
the associated circuits. The same can be said about the station DC supply circuits. The definition should apply
to the circuits providing inputs or control power to the protective relays and from the output of the relays to the
tripping coils of the circuit breaker. Recommend the following: "Voltage and current sensing devices and their
respective circuits providing inputs to the protective relays." "Station DC supply associated with protective
relays (including station batteries, battery charger, non-battery-based DC supply circuitry to the protective
relays and from the relay to the trip coil(s)of the circuit breaker), and"
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
Dynegy Inc.
No
The majority of the definition is good; however, the term "non-battery-based dc supply' is still somewhat vague.
Can you please further define or provide some examples?
Response: Thank you for your comment. The SDT believes the language is clear and supported by industry. The term “non-battery-based dc supply”
is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel cells, or any other emerging technology which is
capable of supplying dc power to the Protection System.
CenterPoint Energy
No
(a) CenterPoint Energy believes the proposed re-definition of “Protection System” is technically incorrect due
to the inclusion of trip coils as part of the control circuitry. A protection system has correctly performed its
function if it provides tripping voltage up to the terminals of trip coils. From that point, the circuit breaker can fail
to timely interrupt fault current due to several factors, such as a binding mechanism, stuck mechanism, broken
pull rod, bad insulating medium, or bad trip coils. Local breaker failure protection, or remote backup protection,
is installed to address the various possible causes of circuit breaker failure. The proposed re-definition of
“Protection System” should be revised to indicate control circuitry associated with protective functions UP TO
THE TERMINALS OF the trip coil(s) of the circuit breakers or other interrupting devices.
(b) On the surface, the proposed re-definition of “Protection System” appears mainly applicable to PRC-005
based upon the Standards Announcement and proposed Implementation Plan. However, NERC standard
PRC-004-1 Analysis and Mitigation of Transmission and Generation Protection System Misoperations also
uses the capitalized term “Protection System”. CenterPoint Energy believes it is inappropriate to require
reporting of Misoperations of transmission Protection Systems and generator Protection Systems for bad trip
coils within a circuit breaker. For application to PRC-004-1, CenterPoint Energy recommends revising the
proposed re-definition to indicate control circuitry associated with protective functions UP TO THE TERMINALS
OF the trip coil(s) of the circuit breakers or other interrupting devices.
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is better supported by industry.
Midwest ISO
October 28, 2010
No
We have an issue with the implementation plan. The implementation plan proposes to capitalize the term
10
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
"protection system" in NUC-001-2, PER-005-1, and PRC-001-1. We disagree with capitalizing the term
because protection system was a defined term when these standards were written. Thus, if the drafting teams
of those standards intended for the definition in the NERC glossary of terms to apply, they would have
capitalized the term. Furthermore, capitalizing the term may fundamentally alter the meaning of the standard.
For PER-005-1, we believe the standard is altered because protection system as used in this standard actually
refers to special protection system or remedial action schemes.
Response: Thank you for your comment. The SDT agrees and will revise the Implementation Plan to remove PER-005 from the list of standards to be
modified. However, the SDT believes the term Protection System should be capitalized as described in the Implementation Plan for NUC-001-2 and
PRC-001-1.
American Electric Power (AEP)
October 28, 2010
No
1.
This change in definition needs to occur concurrently with other related projects (PRC-005-2). Neither
the SDT nor the SC should establish a practice of making changes to definitions outside the parameters of
changes to standards. This will introduce opportunities for confusion and does not provide the appropriate
signals to the Registered Entities to adjust their programs and make the appropriate changes. If this has to be
done faster than the pace of the current PRC-005-2 project, we suggest it still be paired with that project, but a
smaller scope be considered to allow for this to pass quickly as possible and then the remaining work can be
accomplished in PRC-005-3.
2.
We suggest that the SDT consider the creation of sub-definitions opposed to crafting a single term for
complex and diverse components that could make up the Protection System. As it stands, AEP cannot support
this as it still does not remove the degree of ambiguity that could result in interpretation challenges during later
enforcement and monitoring activities. We understand the urgency to make progress; however, the deliverables
of this team can have significant collateral impacts in the compliance process.
3.
The bullet for Protective relays should be further clarified with the addition of applied on or designed to
provide protection for the BES that responds to the electrical fault or disturbance conditions.
4.
Below are the comments that were provided in the second draft that were not adequately addressed in
the consideration of the comments. A. The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could be construed by an auditor to include a lot of
equipment and infrastructure not intended by the PSMT SDT. For example, station battery chargers are
typically supplied by station auxiliary power transformers, which in turn are supplied by primary-voltage bus
work, primary-voltage fuses, or primary-voltage circuit breakers. An auditor for either PRC-005 or any other
Standard referencing "Protection System" could read that such primary-voltage equipment is part of the
Protection System and therefore subject to certain requirements in either PRC-005 or any other Standard
referencing Protection System. B. The definition as drafted includes "Communications systems necessary. . . ".
Once again, this term appears innocuous, but it is actually unclear. For example, if a transfer-trip channel is
carried on a microwave path, an auditor may decide that the entire microwave equipment, microwave building
battery, and microwave building emergency generator are all part of the Protection System, and thus subject to
requirements in either PRC-005 or other existing or future Standards that refer to Protection System. AEP
11
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
recommends that the term be phrased "communications paths" opposed to "communications systems".
C. Similar to the above two items, we are concerned about the inclusion of voltage and current-sensing
"devices" in the Definition. As written, applicability can be inferred to the entire device and not merely its output
quantities, not only for this Standard but any other that references a Protection System. AEP recommends the
phrase "circuitry from voltage and current-sensing devices providing inputs to protective relays" instead of
"voltage and current-sensing devices providing inputs to protective relays."
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this
reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as
practical - not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
2. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
3. The SDT believes these questions are not within the scope of Project 2007-17 and should be addressed by the Regional Entities.
4A. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry. The definition of Protection System with
regards to dc supply has been modified and now reads: Station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply).
4B. The SDT believes your comment pertains to standards and requirements, and not the definition of Protection System.
4C. The SDT believes the current draft of the definition as balloted is better supported by industry.
Independent Electricity System
Operator
No
While we agree with the definition itself, we do have a concern about its application. An ongoing issue that
needs to be addressed is clarification of when a Bulk Electric System transmission Protection System applies to
a Distribution Provider. This was addressed in part in the interpretation request regarding transmission
Protection Systems, Project 2009-17. An example would be for a tee-tap off a Bulk Power System 345kV line to
a step down transformer supplying distribution -- would the relaying on the low voltage side of the transformer
be expected to comply with the requirements of PRC-005-2? Would the protection system configuration be
considered a Protection System? Will this issue be addressed within the scope of Project 2007-17?
Response: Thank you for your comment. This clarification is provided in each requirement that uses the term, “Protection System” by identifying the
responsible entity. The question relates to "application" of the definition, not to the definition."
NRECA
My comment is related to the Implementation plan which will modify the PER-005. I am specifically concerned
with changing in R3.1 “established operating guides or “protection systems” to mitigate IROL violations” to
“established operating guides or “Protection Systems” to mitigate IROL violations”. This modification changes
the intent of requirement PER-005 R3.1. The requirement was developed by the drafting team to address an
Order 693 directive to require the use of simulators by reliability coordinators, transmission operators and
balancing authorities that have operational control over a significant portion of load and generation. The System
Personnel Training SDT felt that the use of the phrase “established IROLs or has established operating guides
October 28, 2010
12
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
or protection systems to mitigate IROL violations” appropriately represents the impact of entities on the
reliability of the BES. In the context of PER-005 R3.1, this specific language was used to broadly include
anything that an entity utilizes to prevent an IROL which could be an “operating guide or a protection system”
like a RAS in WECC or an SPS in the Eastern Interconnection. It was not intended to include all the items
included in the term that is being defined in Project 2007-17.
Response: Thank you for your comment. The SDT agrees and will revise the Implementation Plan to remove PER-005 from the list of standards to be
modified.
MidAmerican Energy
No
The drafting team did not properly address previous comments to include BES references in each PRC-005
sub bullet definitions and left "DC system" wording in the definition with only a comment in parentheses. The
Protection System definition affects multiple standards and must stand alone across those standards.
Therefore: 1. BES references are still needed in each sub bullet definition to eliminate ambiguity and to create
clearly auditable requirements, meeting a basic standards drafting principal being requested both by FERC and
the industry. 2. "DC system" remains a wide open definition. Because regulators and auditors are auditing to
"zero" defect requirements and imposing their own interpretations, only specific wording is acceptable. The
term "DC system" needs to be replaced with explicit pieces of equipment such as "batteries, battery chargers,
and AC / DC converters". To be a credible audit process, both the auditor and audited entity must have a clear
understanding of what is being audited. DC system can be interpreted in many ways by an entity or auditor
and is not an acceptable term. Further, BES references are needed to create clear and auditable boundaries
for this definition.
Response: Thank you for your comments. These comments all relate to "application" of the definition; "auditable boundaries" and "auditable requirements" are
part of the standard.
Duke Energy
Yes
We agree with the revised definition. However the added language raises a question regarding how PRC-0052 would be applied to DC supply situations where the battery is the backup to the “normal” source of DC power.
Specifically, it’s unclear to us that Uninterruptible Power Supplies (UPS), rectifiers and motor-generator sets
that use batteries as a backup are included in the scope of Table 1.
Response: Thank you for your comment. The SDT believes your comment pertains to the standard PRC-005-2 and not the definition of Protection
Systems.
Xcel Energy
October 28, 2010
Yes
The Implementation Plan indicates that the lower case “protection system” in 3 other standards would be
replaced with the capitalized term “Protection System” to properly reflect its use in those standards. In PRC-001
the term “protective system” is also used, however the Implementation Plan does not indicate whether this term
will also be replaced. If not, then it would seem to imply that the term “protective system” has different meaning
than “protection system/Protection System”. There is concern that the use of “Protection System” in PRC-001
will require entities to ‘coordinate” changes to all elements of the Protection System, which could be of no value
for elements such as batteries, battery chargers. It is not clear as to if the intent that ALL elements of the
13
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
Protection System be coordinated when a new or changed Protection System occurs.
Response: Thank you for your comment. The term “protective system” is not a defined term in the NERC glossary and is not addressed by the
Implementation Plan.
LIPA
Yes
Station dc supply associated with protective functions (including station batteries, battery chargers, and nonbattery-based dc supply), and ....Change to Station dc supply associated with protective functions, and....
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is better supported by industry.
American Transmission Company
Yes
Manitoba Hydro
Yes
ISO New England Inc.
Yes
South Carolina Electric and Gas
Yes
Northeast Utilities
Yes
IRC Standards Review Committee
Yes
Bonneville Power Administration
Yes
Arizona Public Service Company
Yes
Ameren
Yes
Green Country Energy
Yes
October 28, 2010
None.
14
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Dates of Third Ballot: 10/2/10 - 10/14/10
Summary: A successive ballot of the definition of Protection System was conducted from October 2-14, 2010 and achieved a quorum and an
overall weighted segment approval of 84.52%.
Numerous balloters confused the definition with its applicability in various standards. Several balloters questioned the
applicability of this defined term in PER-005 and the SDT modified the Implementation Plan for the definition to remove the
reference to PER-005.
Several balloters used the ballot period as a forum to show displeasure with the NERC and Regional BES definitions. Modifying
the definition of Bulk Electric System is outside the scope of this drafting team.
Some balloters made suggestions to modify various portions of the definition, however most balloters supported the definition
as posted and the drafting team did not adopt any suggestions for further modifications to the definition.
Several balloters opposed this ballot because they felt the definition of Protection System should not have been balloted
separately from the draft standard PRC-005-2. When the Board of Trustees was asked to approve an interpretation of PRC005-1 that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by
the definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT directed that the revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan allows entities at least 12 months to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Segment
Entity
Member
1
American Electric
Power
Paul B. Johnson
5
AEP Service Corp.
Brock Ondayko
October 28, 2010
Ballot
Negative
Comments
1. This change in definition needs to occur concurrently with other
related projects (PRC-005-2). Neither the SDT nor the SC should
establish a practice of making changes to definitions outside the
parameters of changes to standards. This will introduce opportunities
for confusion and does not provide the appropriate signals to the
Registered Entities to adjust their programs and make the appropriate
1
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
6
Entity
AEP Marketing
Member
Edward P. Cox
Ballot
Comments
changes. If this has to be done faster than the pace of the current
PRC-005-2 project, we suggest it still be paired with that project, but a
smaller scope be considered to allow for this to pass quickly as
possible and then the remaining work can be accomplished in PRC005-3.
2. We suggest that the SDT consider the creation of sub-definitions
opposed to crafting a single term for complex and diverse
components that could make up the Protection System. As it stands,
AEP cannot support this as it still does not remove the degree of
ambiguity that could result in interpretation challenges during later
enforcement and monitoring activities. We understand the urgency to
make progress; however, the deliverables of this team can have
significant collateral impacts in the compliance process.
3. The bullet for Protective relays should be further clarified with the
addition of applied on or designed to provide protection for the BES
that responds to the electrical fault or disturbance conditions.
4. Below are the comments that were provided in the second draft that
were not adequately addressed in the consideration of the comments.
A. The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could be
construed by an auditor to include a lot of equipment and
infrastructure not intended by the PSMT SDT. For example, station
battery chargers are typically supplied by station auxiliary power
transformers, which in turn are supplied by primary-voltage bus work,
primary-voltage fuses, or primary-voltage circuit breakers. An auditor
for either PRC-005 or any other Standard referencing "Protection
System" could read that such primary-voltage equipment is part of the
Protection System and therefore subject to certain requirements in
either PRC-005 or any other Standard referencing Protection System.
B. The definition as drafted includes "Communications systems
necessary. . . ". Once again, this term appears innocuous, but it is
October 25, 2010
2
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
Comments
actually unclear. For example, if a transfer-trip channel is carried on a
microwave path, an auditor may decide that the entire microwave
equipment, microwave building battery, and microwave building
emergency generator are all part of the Protection System, and thus
subject to requirements in either PRC-005 or other existing or future
Standards that refer to Protection System. AEP recommends that the
term be phrased "communications paths" opposed to
"communications systems".
C. Similar to the above two items, we are concerned about the
inclusion of voltage and current-sensing "devices" in the Definition. As
written, applicability can be inferred to the entire device and not
merely its output quantities, not only for this Standard but any other
that references a Protection System. AEP recommends the phrase
"circuitry from voltage and current-sensing devices providing inputs to
protective relays" instead of "voltage and current-sensing devices
providing inputs to protective relays."
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this
reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as
practical - not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and
that should give entities time to apply the new definition to PRC-005-1.
2. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
3. The SDT believes these questions are not within the scope of Project 2007-17 and should be addressed by the Regional Entities.
4A. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry. The definition of Protection System
with regards to dc supply has been modified and now reads: Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply).
4B. The SDT believes your comment pertains to standards and requirements, and not the definition of Protection System.
4C. The SDT believes the current draft of the definition as balloted is better supported by industry.
October 25, 2010
3
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
1
Entity
Baltimore Gas &
Electric Company
Member
John J. Moraski
Ballot
Negative
Comments
The definition can be read to imply an obligation to test PTs and CTs in a way
that exceeds the apparent intention of the SDT as expressed in the FAQs. The
definition should be constructed so as to present no conflict with idea that the
standard can be met by verifying the correctness of signal delivered from PTs
and CTs to protective relays. Suggestive language included with the previous
ballot --- Protection System: Protective relays which respond to electrical
quantities, communication systems necessary for correct operation of
protective functions, voltage and current sensing device output circuits and
the associated circuits to the inputs of protective relays, station dc supply, and
control circuitry associated with protective functions through the trip coil(s) of
the circuit breakers or other interrupting devices.
Response: The SDT believes your comment is aimed at revising the definition so that it achieves a particular outcome when applied to specific
requirements in the proposed PRC-005. The team is trying to develop a definition that would be applicable for use in several standards, and does
not want to make modifications to the definition that would limit the term's applicability.
1
Colorado Springs
Utilities
Paul Morland
Negative
CSU feels that battery chargers should not be included in the "Protection
System" definition based on the following: Battery chargers are not a single
point of immediate failure. As long as real-time station battery monitoring is
provided, a reliable protection system will be maintained.
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now. The implementation plan now proposes at least 12 months for entities to apply the
new definition to PRC-005-1, and that should give entities time to apply the new definition to PRC-005-1.
1
FirstEnergy Energy
Delivery
Robert Martinko
3
FirstEnergy
Solutions
Kevin Querry
6
FirstEnergy
Solutions
Mark S
Travaglianti
October 25, 2010
Affirmative FirstEnergy supports the definition and thanks the drafting team for
incorporating our suggestion for clarification of the phrase "station dc supply".
4
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
Comments
4
Ohio Edison
Company
Douglas
Hohlbaugh
Response: The SDT appreciates your support.
1
MidAmerican
Energy Co.
Terry Harbour
Negative
The drafting team did not properly address previous comments to include BES
references in each PRC-005 sub bullet definitions and left "DC system"
wording in the definition with only a comment in parentheses. The Protection
System definition affects multiple standards and must stand alone across
those standards. Therefore:
1. BES references are still needed in each sub bullet definition to eliminate
ambiguity and to create clearly auditable requirements, meeting a basic
standards drafting principal being requested both by FERC and the industry.
2. "DC system" remains a wide open definition. Because regulators and
auditors are auditing to "zero" defect requirements and imposing their own
interpretations, only specific wording is acceptable. The term "DC system"
needs to be replaced with explicit pieces of equipment such as "batteries,
battery chargers, and AC / DC converters". To be a credible audit process,
both the auditor and audited entity must have a clear understanding of what
is being audited. DC system can be interpreted in many ways by an entity or
auditor and is not an acceptable term. Further, BES references are needed to
create clear and auditable boundaries for this definition.
Response: The SDT believes your comment is aimed at revising the definition so that it achieves a particular outcome when applied to specific
requirements in the proposed PRC-005. The team is trying to develop a definition that would be applicable for use in several standards, and does
not want to make modifications to the definition that would limit the term's applicability.
October 25, 2010
5
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
1
Entity
Nebraska Public
Power District
Member
Richard L. Koch
Ballot
Affirmative
Comments
1.
Please provide the reasoning for including the battery chargers.
Where do you draw the line of what is included. For example, should
the panel providing power to the chargers be included?
2. Better clarification is needed when defining the DC control circuit.
The trip coils are identified on one end of the circuit but nothing is
identified upstream of the trip coils. For example, control switches,
indicators, auxiliary relays, power supply breakers, etc.
Response: 1. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” The definition of Protection System with regards to dc supply has been
modified and now reads: Station dc supply associated with protective functions (including station batteries, battery chargers, and non-batterybased dc supply). The SDT believes this clearly limits the dc supply.
2. The SDT believes the balloted definition includes all the control circuitry essential for the Protection System to function properly.
1
Pacific Gas and
Electric Company
October 25, 2010
Chifong L. Thomas
Negative
We disagree with the drafting team response to comments that the term BES
should be included only in the standard. It is an essential part of the definition
as it pertains to the purpose of NERC Standards. As a result we have changed
our vote to negative. We view the basic intent of this definition is to identify
what protective systems in facilities are to be utilized to protect the BES from
two primary troubles 1) minimize interruption of the flow of electrical power
from one portion of the BES to another, and 2) to prevent the propagation of
BES trouble from one portion of the BES to another. While we agree that
protection systems for all transmission related components can be adequately
limited in scope by utilizing "electrical quantities", we do not feel that it is
adequate for generating facilities. There are multitudes of elements in
generating facilities that can remove the facility from service and impact the
power flow from the facility to other portions of the BES. The efforts utilized
thus far demonstrate that it is not desirable or realistically possible to address
all devices from an oversight point of view and that the current definition
which discriminates solely with the qualifier of "electrical quantities" is too
broad and leaves much open to interpretation to define what types of
protection are included in the definition. The definition, as it currently reads,
leaves many protective devices to the owner/operator to manage for
6
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
Comments
maximum reliability of the generating facility. In the interest of clarity the
definition should limit the scope for protective relays to those relays designed
to prevent the propagation of trouble from one portion of the BES to another.
We recommend changing the proposed definition to read as follows: A control
system designed to detect electrical faults or abnormal conditions in the
power system and initiate corrective action(s). A protection system consists of
the following components: 1. Protective relays which protect: a) Transmission
BES elements, including generating facility step up transformers, and respond
to power system electrical quantities such as voltage and current, b)
Generating facilities by responding to power system electrical quantities, such
as voltage and current, and are designed to protect against potential
problems in the BES on the high side of the generator step up transformer. 2.
Communications systems necessary for correct operation of protective
functions, 3. Voltage and current sensing devices which transform high level
power system quantities to low level inputs for protective relays, and the
associated circuitry to the inputs for protective relays. 4. Station DC supply
associated with protective relay power supplies and control functions
(including station batteries, battery chargers, and non-battery-based DC
supply), and 5. Control circuitry associated with protective relay functions
(including auxiliary relays) through the trip coil(s) of the circuit breakers or
other interrupting devices.
Response: The SDT believes your comment is aimed at revising the definition so that it achieves a particular outcome when applied to specific
requirements in the proposed PRC-005. The team is trying to develop a definition that would be applicable for use in several standards, and does
not want to make modifications to the definition that would limit the term's applicability. The applicability of the definition of Protection System will
be addressed in the various standards which utilize the definition. The SDT believes the current draft of the definition as balloted is better supported
by industry.
1
Seattle City Light
Pawel Krupa
3
Dana Wheelock
4
Hao Li
5
Michael J. Haynes
October 25, 2010
Affirmative Seattle supports this definition with the understanding that issues that have
been previously addressed through comment will be considered during the
Standard development process.
7
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
6
Member
Ballot
Comments
Dennis Sismaet
Response: The SDT appreciates your support.
1
Tri-State G & T
Association, Inc.
3
Keith V. Carman
Janelle Marriott
Negative
2nd bullet - Add communication-aided before protective functions. We think
that this is important because you can have correct operation of protective
functions without the communication-aided tripping functions operating
correctly, especially with POTT or DCUB schemes.
5th bullet - replace through with including. We think that the phrase through
the trip coil could be misinterpreted to mean protective functions that cause
current to flow through the trip coil rather than the inclusive meaning such as
from A through Z. If the intent of the drafting team is to exclude the trip coil,
then we think it should be changed to control circuitry associated with
protective functions required to operate the trip coil(s) of the circuit breakers
or other interrupting devices.
Response: The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
October 25, 2010
8
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
1
Western Area
Power
Administration
Brandy A Dunn
Negative
5
U.S. Bureau of
Reclamation
Martin Bauer P.E.
Negative
October 25, 2010
Comments
The term "protection functions" is ambiguous as it is not related to the
protection function associated with the protective relays. There are other
protection functions not associated with protective relays that respond to
electrical quantities.
The language for Communication systems should be changed to remove the
ambiguity. The following change would be clear, "Communication system
necessary for the correct operation of the protective relays" The input to the
relays is from voltage and current sensing devices through their respective
circuits. Since the definition for protective relays separates the term "control
circuitry" associated with protective relays, it is clear that protective relays do
not also include the "control circuitry". By the same token, voltage and
current sensing devices do not include their related circuits. The definition for
voltage and current sensing devices should be revised to include the term
"circuits". The following language change would serve make it clear: "Voltage
and current sensing devices and their respective circuits providing inputs
protective relays,".
The term "protection functions" is ambiguous as it is not related to the
protection function associated with the protective relays. There are other
protection functions not associated with protective relays that respond to
electrical quantities.
The language for Communication systems should be changed to remove the
ambiguity. The following change would be clear, "Communication system
necessary for the correct operation of the protective relays" The input to the
relays is from voltage and current sensing devices through their respective
circuits. Since the definition for protective relays separates the term "control
circuitry" associated with protective relays, it is clear that protective relays do
not also include the "control circuitry". By the same token, voltage and
current sensing devices do not include their related circuits. The definition for
voltage and current sensing devices should be revised to include the term
"circuits". The following language change would serve make it clear: "Voltage
and current sensing devices and their respective circuits providing correct
inputs to protective relays."
9
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
Comments
Response: The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
2
Midwest ISO, Inc.
Jason L Marshall
Negative
We disagree with the implementation plan. The implementation plan calls for
capitalizing protection system in NUC-001-2 and PER-005-1. Because
Protection System had been included in the NERC Glossary of Terms before
the development of these standards, we believe the drafting teams would
have capitalized those terms in these standards if they had intended for the
Protection System definition to apply. Furthermore, we believe the use of
protection system PER-005-1 was actually intended to be special protection
systems or remedial actions schemes. To capitalize protection system in PER005-1 will fundamentally alter the requirement in which it is contained.
Response: The SDT agrees and will revise the Implementation Plan to remove PER-005 from the list of standards to be modified. However, the SDT
believes the term Protection System should be capitalized as described in the Implementation Plan for NUC-001-2.
3
Consumers Energy
David A. Lapinski
4
David Frank Ronk
5
James B Lewis
Negative
We understand that this posting is intended to address perceived flaws in the
currently approved definition. However, since this change, if approved, is
likely to result in changes to an entity's PRC-005-1 maintenance program, we
feel that it is inappropriate to approve this definition without simultaneous
approval of the revised PRC-005-2 which will clarify the related changes to
maintenance programs.
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now. The implementation plan now proposes at least 12 months for entities to apply the
new definition to PRC-005-1, and that should give entities time to apply the new definition to PRC-005-1.
3
MidAmerican
Energy Co.
Thomas C. Mielnik
Negative
BES references are needed in each sub bullet definition to eliminate ambiguity
and to create clearly auditable requirements. The term "DC system" needs to
be replaced with explicit pieces of equipment such as "batteries, battery
chargers, and AC / DC converters".
Response: The SDT believes these comments relative to BES are not within the scope of Project 2007-17 and should be addressed by the Regional
Entities; and that the current draft of the definition as balloted is clear, concise, and contains the specific dc systems equipment you mention.
October 25, 2010
10
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
3
Entity
San Diego Gas &
Electric
Member
Scott Peterson
Ballot
Comments
Affirmative SDG&E believes that the following changes should be incorporated. Third
item: DC supply sources affecting the "Protection System" (including station
batteries, battery chargers, and non-battery-based dc supply), and SDG&E also
believe that a definition of non-battery-based dc supply should be included to
avoid confusion and recommend the following: "The inverter or rectifier in the
circuit, dependent upon how the end use equipment is designed.
Uninterruptible power supply (UPS) such as on-line, line-interactive or standby
that some of the protection system could be on."
Response: The SDT appreciates your support, and believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
3
Wisconsin Electric
Power Marketing
James R. Keller
4
Wisconsin Energy
Corp.
Anthony
Jankowski
5
Wisconsin Electric
Power Co.
Linda Horn
Negative
1. The Protection System definition needs to indicate that the listed
items after relays are intended to be associated with relays. As
written, most of the items apply to undefined "protective functions".
The Implementation Plan's change to PER-005-1 R3.1 restricts where
R3.1 applies. For example, changing "protection systems" to
"Protection Systems" will exclude an SPS that does not operate relays.
Replace term "voltage & current sensing devices" with "voltage &
current sensing inputs to protective relays".
2. Remove the battery chargers from the definition and make reference
to station batteries only. There needs to be improved coordination
between proposed changes and definitions and the associated
proposed changes and testing.
Response: 1. The drafting team does not believe that the additional language is needed in the definition. The SDT agrees with the comment on
PER-005 and will revise the Implementation Plan to remove PER-005 from the list of standards to be modified.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged
the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and directed that
work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC005-1 as soon as practical. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
October 25, 2010
11
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
4
Entity
Madison Gas and
Electric Co.
Member
Joseph G.
DePoorter
Ballot
Comments
Affirmative Believe that Communication systems necessary for correct operation of
protective "relay" functions be considered as an enhancement to the
definition. This would also need to be added within the Station dc supply and
Control circuitry bullets. This will provide clarity to exactly what the definition
is describing.
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry.
5
Constellation
Power Source
Generation, Inc.
October 25, 2010
Amir Y Hammad
Negative
Constellation has previously voted against these revised definitions because
as written, it implies that the testing of PTs and CTs in PRC-005 is required.
This latest proposal is no different. Constellation agrees with the SDT in that
current and voltage sensing devices are an important aspect of the Protection
System. However, by including PTs and CTs in the definition, auditors have
been interpreting that as stating that dielectric testing and other tests are
necessary on them. This does not seem to be the intention of the SDT. The
intention of the SDT seems to be to verify that the sensing devices are
delivering acceptable signals to relays. Table 1 a of the PRC-005-2 standard
includes: Voltage & Current Sensing Devices / 12 Calendar Years / Verify
proper functioning of the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays. The FAQ for PRC-005-2 is
even clearer in stating that ensuring the protection system is receiving the
expected values from current and voltage sensing devices. But neither the
originally revised or newly revised definitions carry that implication very well.
The definitions are still including the devices themselves and not their
outputs. To make the definition less ambiguous with PTs and CTs,
Constellation proposes the following change in the definition: Voltage and
current sensing devices providing inputs to protective relays to; Voltage and
current sensing device output circuits and the associated circuits to the inputs
of protective relays.
12
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
6
Entity
Member
Ballot
Constellation
Energy
Commodities
Group
Brenda Powell
Negative
Comments
Constellation has previously voted against these revised definitions because
as written, it implies that the testing of PTs and CTs in PRC-005 is required.
This latest proposal is no different. Constellation agrees with the SDT in that
current and voltage sensing devices are an important aspect of the Protection
System. However, by including PTs and CTs in the definition, auditors have
been interpreting that as stating that dielectric testing and other tests are
necessary on them. This does not seem to be the intention of the SDT. The
intention of the SDT seems to be to verify that the sensing devices are
delivering acceptable signals to relays. Table 1 a of the PRC-005-2 standard
includes: Voltage & Current Sensing Devices / 12 Calendar Years / Verify
proper functioning of the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays. The FAQ for PRC-005-2 is
even clearer in stating that ensuring the protection system is receiving the
expected values from current and voltage sensing devices. The definitions are
still including the devices themselves and not their outputs. To make the
definition less ambiguous with PTs and CTs, Constellation proposes the
following change in the definition: Voltage and current sensing devices
providing inputs to protective relays to; Voltage and current sensing device
output circuits and the associated circuits to the inputs of protective relays.
Response: The SDT believes your comment is aimed at revising the definition so that it achieves a particular outcome when applied to specific
requirements in the proposed PRC-005. The team is trying to develop a definition that would be applicable for use in several standards, and does
not want to make modifications to the definition that would limit the term's applicability.
5
Dynegy Inc.
Dan Roethemeyer
Affirmative Please clarify "non-battery-based dc supply". It is vague.
Response: The SDT appreciates your support, and believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
October 25, 2010
13
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
5
Entity
Indeck Energy
Services, Inc.
Member
Rex A Roehl
Ballot
Negative
Comments
Neither batteries nor battery chargers are part of protection systems. They
may be included in protection system maintenance procedures, but are not
part of a protection system. Similarly, current and voltage measuring devices
that are used for metering or monitoring and not exclusively for protection,
are not part of the protection system, but may be included in protection
system maintenance. THE SDT seems to have tried to incorporate some of the
PRC standards with this definition rather than focusing on the one element
being defined.
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now.
5
Liberty Electric
Power LLC
Daniel Duff
Negative
Battery chargers are not protection system elements. This part of the
definition should be redacted.
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now.
5
Public Utility
District No. 1 of
Lewis County
Steven Grega
Negative
Do not support the expanded definition of the protection system. Battery
chargers are not part of the protection system.
Response: : When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now.
October 25, 2010
14
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
5
Entity
RRI Energy
Member
Thomas J. Bradish
Ballot
Negative
Trent Carlson
6
Comments
It is not appropriate to define the battery or chargers as protection system
elements. For DC circuits or supply, the definition and subsequent boundary
of the protection system should end at the fuses or circuit breakers of the
sources supplying the individual DC control circuits of the protection system.
For a typical power plant station battery, the percent of the battery capacity
sized for the protection system is very small. The battery and chargers are
power source elements, not protection elements. Likewise, all intermediate
power distribution elements between the battery, chargers, and dedicated
protection system branch circuits, do not belong in the definition of the
Protection System.
Response: : When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now.
5
TransAlta Centralia
Generation, LLC
Joanna LuongTran
Negative
To increase the clarity of the definition, TransAlta proposes the following:
Control circuitry associated with protective functions through to and including
the trip coil(s) of the circuit breakers or other interrupting devices
Response: The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
October 25, 2010
15
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
8
Entity
SPS Consulting
Group Inc.
Member
Ballot
Jim R Stanton
Negative
Comments
The term "Communication System" remains in the definition, despite the
reality that at least for most generators, there is no communication system
within the Protection System. Communication from device to device, such as a
protective relay to a trip coil or alarm, it not a "system" per se but merely a
wire connecting the devices. Keeping this definition as is perpetuates the
confusion of generators when they design, modify and execute their
protection system maintenance and testing program as the definition of the
Protection System requires addressing a "communication system" which they
do not have. Keeping the definition as is could lead to confused auditors who
insist on literal adherence to the requirement language, clouding the audit
and imposing ad hoc and perhaps inconsistent interpretations for audits, spot
checks and self reports. What will most surely happen if this definition is
approved is a quick request for interpretation by one or more entities seeking
clarification on the requirement to include "communication systems" within
their maintenance and testing program when they in fact have no such
system. All this can be avoided by changing the term "communication
systems" to "communication components." This is a primary example of fixing
something on the front end so we don't have to go through interpretations
and revisions to fix an ambiguity. This definition would also not pass a Quality
Review due to the ambiguity of terms.
Response: The SDT believes the language is clear and addresses relay communication systems currently used by industry.
8
Utility Services,
Inc.
Brian EvansMongeon
Negative
While the language by itself is supportable, the definition is not complete. The
SDT has still not addressed the question of when the definition will apply to
Distribution Providers. Many DPs own and or operate the elements listed in
the definition; however, the definition lacks clarity when such ownership or
operation is subject to the performance obligations under the standard.
Response: This clarification is provided in each requirement that uses the term, “Protection System” by identifying the responsible entity. The
comment relates to "application" of the definition, not to the definition.
October 25, 2010
16
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
9
Entity
California Energy
Commission
Member
William Mitchell
Chamberlain
Ballot
Comments
Affirmative The proposed definition is generally acceptable. However, a slight
modification to the third bullet in the definition would be an improvement to
the proposed wording: "DC supply sources affecting the 'Protection System'
(including station batteries, battery chargers, and non-battery-based dc
supply), and " In addition, a definition of non-battery-based dc supply should
be included to avoid confusion we recommend the following: "The inverter or
rectifier in the circuit, dependent upon how the end use equipment is
designed. Uninterruptible power supply (UPS) such as on-line, line-interactive
or standby that some of the protection system could be on."
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
9
Oregon Public
Utility Commission
Jerome Murray
Affirmative Although I voted yes, I recommend the following proposed wording for the
third bullet: DC supply sources affecting the "Protection System" (including
station batteries, battery chargers, and non-battery-based dc supply), and
Also the definition of non-battery-based dc supply should be included to avoid
confusion. I recommend the following: The inverter or rectifier in the circuit,
dependent upon how the end use equipment is designed. Uninterruptible
power supply (UPS) such as on-line, line-interactive or standby that some of
the protection system could be on.
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
10
Midwest Reliability
Organization
Dan R.
Schoenecker
Affirmative Suggest the second bullet language replace the term correct with the
intended. Communications systems necessary for the intended operation of
protective functions.
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry.
October 25, 2010
17
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
10
Entity
Western Electricity
Coordinating
Council
Member
Louise McCarren
Ballot
Comments
Affirmative The definition is generally acceptable. However, we believe that better
language for the third bullet is as follows: DC supply sources affecting the
"Protection System" (including station batteries, battery chargers, and nonbattery-based dc supply), and A definition of non-battery-based dc supply
should be included to avoid confusion and we offer the following: The inverter
or rectifier in the circuit, dependent upon how the end use equipment is
designed. Uninterruptible power supply (UPS) such as on-line, line-interactive
or standby that some of the protection system could be on. The intent of the
suggestion would consider that the entire protection system has to operate in
order to maintain the reliability of the BES. An example would be if the
protective relay and associated communications were on a UPS system and
the intended device to operate were on station batteries, this would be the
best case scenario as the Micro processors relays and the newer associated
communications do not like the voltage drop when the station switches to the
station batteries, hence the use of UPS options. Micro processors relays do
have internal battery backup to keep them up and running, though a
maintenance task would have to be included to be sure that they are properly
maintained and tested, so the UPS option is easier and has been kind of an
industry standard in the past. In the end the UPS would have to be on a
maintenance schedule also.
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
October 25, 2010
18
Consideration of Comments on Protection System Maintenance [Project
2007-17]
The Protection System Maintenance Drafting Team thanks all commenters who submitted
comments on the 3rd draft of the standard for Protection System Maintenance and Testing.
These standards were posted for a 30-day public comment period from November 17, 2010
through December 17, 2010. The stakeholders were asked to provide feedback on the
standards through a special Electronic Comment Form. There were 44 sets of comments,
including comments from more than 81 different people from approximately 82 companies
representing 9 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Extensive changes were made to Requirements R1 and R3 of the Standard, and
also to the Tables referenced within the Requirements. Of particular note,
Requirement R1, Part 1.5 (which required entities to define their acceptance
criteria for maintenance of components), and the associated discussion within
Requirement R4, Part 4.2 were removed. Requirement R2 was removed because it
was duplicative of Requirement R1, Part 1.4. Also, Table 1-4, addressing
maintenance of Station DC Supply, was split into six separate sub-tables
addressing the various specific technologies within this component.
Some commenters continued to object to various requirements within the
standard. Where the standard was not revised in response to these comments,
the SDT explained their rationale within the consideration-of-comments.
Based on the level of consensus on this posting, the SDT will post the Standard
and associated documents for an additional 30-day comment period with
concurrent ballot in the final 10-days of that comment period.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition,
there is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Index to Questions, Comments, and Responses
1.
The SDT has restructured the tables to improve clarity, but did not appreciably
change the content. Do you agree that the restructured tables are clearer? If
not, please provide specific suggestions for improvement.…. ..........................9
2.
The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do
you agree with the changes? If not, please provide specific suggestions for
improvement.…. ............................................................................................. 16
3.
The SDT has provided the “Supplementary Reference” document to provide
supporting discussion for the Requirements within the standard. Do you have
any specific suggestions for improvements?…. .............................................. 24
4.
The SDT has provided the “Frequently-Asked Questions” (FAQ) document to
address anticipated questions relative to the standard. Do you have any
specific suggestions for improvements?…. ..................................................... 31
5.
If you have any other comments on this Standard that you have not already
provided in response to the prior questions, please provide them here.…. .....38
2
Consideration of Comments on Protection System Maintenance [Project 2007-17]
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
David K Thorne
Pepco Holding Inc & Affilates
Additional Member Additional Organization Region
Carlton Bradshaw
RFC
1
2.
Carl Kinsley
RFC
1
3.
Bob Reuter
RFC
3
4.
Mike Mayer
RFC
3
5.
Jim Petrella
RFC
3
Group
Additional Member
Steve Alexanderson
Pacific Northwest Small Public Power Utility
Comment Group
Additional Organization
3
4
5
6
7
8
9
10
X
Segment
Selection
1.
2.
2
X
X
Region Segment Selection
1. Russell Noble
Cowlitz County PUD No. 1
WECC 3, 4, 5
2. Dave Proebstel
Clallam County PUD
WECC 3
3. Ronald Sporseen
Blachly-Lane Electric Cooperative
WECC 3
4. Ronald Sporseen
Central Electric Cooperative
WECC 3
5. Ronald Sporseen
Consumers Power
WECC 3
3
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6. Ronald Sporseen
Clearwater Power Company
WECC 3
7. Ronald Sporseen
Douglas Electric Cooperative
WECC 3
8. Ronald Sporseen
Fall River Rural Electric Cooperative
WECC 3
9. Ronald Sporseen
Northern Lights
WECC 3
10. Ronald Sporseen
Lane Electric Cooperative
WECC 3
11. Ronald Sporseen
Lincoln Electric Cooperative
WECC 3
12. Ronald Sporseen
Raft River Rural Electric Cooperative
WECC 3
13. Ronald Sporseen
Lost River Electric Cooperative
WECC 3
14. Ronald Sporseen
Salmon River Electric Cooperative
WECC 3
15. Ronald Sporseen
Umatilla Electric Cooperative
WECC 3
16. Ronald Sporseen
Coos-Curry Electric Cooperative
WECC 3
17. Ronald Sporseen
West Oregon Electric Cooperative
WECC 3
18. Ronald Sporseen
Pacific Northwest Generating Cooperative WECC 5
19. Ronald Sporseen
Power Resources Cooperative
3.
Group
Additional Member
Dave Davidson
Additional Organization
Tennessee Valley Authority
SERC
NA
2. Paul Baldwin
TOM Support
SERC
NA
3. David Thompson
Hydro Production Engineering SERC
NA
4. Frank Cuzzort
Nuclear Engineering
NA
5. Robert Mares
Fossil Engineering
Additional Member
Guy Zito
4
5
6
7
8
9
10
X
X
Region Segment Selection
TOM Support
Group
3
WECC 3
1. Rusty Hardison
4.
2
SERC
NA
Northeast Power Coordinating Council
Additional Organization
X
Region Segment Selection
1. Al Adamson
New York State Reliability Council, LLC
2. Gregory Campoli
New York Independent System Operator
NPCC 2
10
3. Kurtis Chang
Independent Electricity System Operator
NPCC 2
4. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
5. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7. Dean Ellis
Dynegy Generation
NPCC 5
8. Brian Evans-Mongeon Utility Services
NPCC 8
9. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
11. Kathleen Goodman
ISO - New England
NPCC 2
12. Chantel Haswell
FPL Group, Inc.
NPCC 5
13. David Kiguel
Hydro One Networks Inc.
NPCC 1
14. Michael R. Lombardi
Northeast Utilities
NPCC 1
15. Randy MacDonald
New Brunswick System Operator
NPCC 2
16. Bruce Metruck
New York Power Authority
NPCC 6
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
18. Robert Pellegrini
The United Illuminating Company
NPCC 1
19. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
20. Saurabh Saksena
National Grid
NPCC 1
21. Michael Schiavone
National Grid
NPCC 1
22. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
5.
Group
Deborah Schaneman
Additional Member Additional Organization
Platte River Power Authority System
Maintenance
Region
X
2
3
4
5
6
X
X
X
7
8
9
10
Segment
Selection
1.
Scott Rowley
Platte River Power Authority WECC
1, 3, 5, 6
2.
Gary Whittenberg
Platte River Power Authority WECC
1, 3, 5, 6
3.
Aaron Johnson
Platte River Power Authority WECC
1, 3, 5, 6
6.
Group
Mike Garton
Electric Market Policy
X
X
X
X
7.
Group
Denise Koehn
Bonneville Power Administration
X
X
X
X
5
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
8.
Group
Terry L. Blackwell
Santee Cooper
9.
Group
Mallory Huggins
NERC Staff
10.
Group
Sam Ciccone
11.
Group
2
3
4
5
6
X
X
X
X
FirstEnergy
X
X
X
X
Frank Gaffney
Florida Municipal Power Agency
X
X
X
X
Group
Kenneth D. Brown
PSEG Companies ("Public Service Enterprise
Group Companies")
X
X
X
X
Group
Carol Gerou
MRO's NERC Standards Review
Subcommittee
14.
Individual
Brandy A. Dunn
Western Area Power Administration
15.
Individual
Joanna Luong-Tran
TransAlta Centralia Generation Partnership
12.
13.
X
7
8
9
10
X
X
X
X
6
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
X
3
4
X
5
6
16.
Individual
Silvia Parada Mitchell
NextEra Energy
X
X
17.
Individual
Reza Ebrahimian
City of Austin DBA Austin Energy
18.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
19.
Individual
JT Wood
Southern Company Transmission
X
X
20.
Individual
Jack Stamper
Clark Public Utilities
X
21.
Individual
John Bee
Exelon
X
22.
Individual
Joe Petaski
Manitoba Hydro
X
23.
Individual
Dan Roethemeyer
Dynegy Inc.
24.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
25.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
26.
Individual
Scott Berry
Indiana Municipal Power Agency
27.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
28.
Individual
Ed Davis
Entergy Services
X
X
X
X
29.
Individual
Greg Rowland
Duke Energy
X
X
X
X
30.
Individual
Dale Fredrickson
Wisconsin Electric Power Company
31.
Individual
Dan Rochester
Independent Electricity System Operator
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
7
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
X
X
X
X
6
32.
Individual
Thad Ness
American Electric Power
X
33.
Individual
Michael Moltane
ITC
X
34.
Individual
Kathleen Goodman
ISO New England Inc.
35.
Individual
Rick Koch
Nebraska Public Power District
X
36.
Individual
Armin Klusman
CenterPoint Energy
X
37.
Individual
Andrew Pusztai
American Transmission Company
X
38.
Individual
Eric Salsbury
Consumers Energy
39.
Individual
Bill Shultz
Southern Company Generation
40.
Individual
Martin Bauer
US Bureau of Reclamation
41.
Individual
Kenneth A. Goldsmith
Alliant Energy
42.
Individual
Martyn Turner
LCRA Transmission Services Corporation
X
43.
Individual
Terry Harbour
MidAmerican Energy
X
X
X
X
44.
Individual
Kirit Shah
Ameren
X
X
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
8
Consideration of Comments on Protection System Maintenance [Project 2007-17]
1. The SDT has restructured the tables to improve clarity, but did not appreciably change the content. Do you agree that the
restructured tables are clearer? If not, please provide specific suggestions for improvement.
Summary Consideration: Generally, commenters indicated that the rearrangement of the Tables was beneficial.
Several commenters questioned the arrangement of Table 1-4 and the SDT responded by revising this Table. A
few commenters suggested further rearrangement of the Tables; the SDT observed that there are many potential
ways to organize the Tables and declined to adopt these suggestions. The SDT made minor changes to Table 1-3
and Table 2 verbiage based on stakeholder comments.
Organization
Yes or No
Pepco Holding Inc & Affiliates
Yes
Pacific Northwest Small Public
Power Utility Comment Group
Yes
Tennessee Valley Authority
Yes
Northeast Power Coordinating
Council
No
Question 1 Comment
The wording “Component Type” is not necessary in each title. Just the equipment category should be listed-what is now shown as “Component Type - Protective Relay”, should be Protective Relay. However,
Protective Relay is too general a category. Electromechanical relays, solid state relays, and microprocessor
based relays should have their own separate tables. So instead of reading Protective Relay in the title, it
should read Electromechanical Relays, etc. This will lengthen the standard, but will simplify reading and
referring to the tables, and eliminate confusion when looking for information. The “Note” included in the
heading is also not necessary. “Attributes” is also not necessary in the column heading, “Component”
suffices.
Response: Thank you for your comments. The SDT believes that the table headings are appropriate as reflected in the draft standard.
Platte River Power Authority
System Maintenance
Yes
Electric Market Policy
Yes
Dominion does not feel that clarity has been added to the tables.
1. A numbering structure should be added to the table for referencing each task prescribed.
9
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
2. The tables should more clearly designate and separate time based versus performance based tasks.
3. Additionally, Table 1-4 contains, in several places, an activity to “Verify that the station battery can
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery
baseline.” This seems to suggest that each time the batteries are checked, the measured cell/unit
internal ohmic value should agree with some baseline value. This appears to be overly prescriptive as
the values reading-to-reading should fall within the tolerances established per Requirement R1.5, not
equal a baseline. The activities for other component types are not this prescriptive.
Response: Thank you for your comments.
1. The SDT believes that numbering the tasks within the Tables as you suggest would make the Tables more complex and would not add clarity.
2. Performance-based maintenance requires that the same tasks be completed, but at intervals determined per Attachment A.
3. The station battery baseline value is up to the entity to determine. Please see Section 15.4.1 of the Supplementary Reference for a discussion of
this. The SDT has determined that the fundamental concerns of R1 part 1.5 and the associated changes are addressed within the PSMP definition,
and that R1 part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address various related
concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a
discussion of this.
Bonneville Power Administration
Yes
Santee Cooper
Yes
NERC Staff
Yes
FirstEnergy
Yes
While we agree that the clarity of the tables has improved, there are still items that warrant further clarity.
1.In Table 1-1, references to "Verify acceptable measurement of power system input values" is made for
microprocessor relays on 6 and 12 calendar year intervals. Wouldn't this also be prudent on nonmicroprocessor based relays as well on the 6 year interval?
2. Also, in Table 1-3, "Verify that acceptable measurement of the current and voltage signals are received by
the protective relays" is shown on a 12 calendar year interval. What is the difference between this activity
and the similar activity performed in Table 1-1?
3. In Table 1-4, this table is complex and the detailed maintenance activities in this particular table is puzzling
when compared to the more generic detail in the other tables within this section. For example, an incorrect
operation due to a deteriorated signal from a CT or VT has a higher probability than a failure of a battery bank
10
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
to perform when called upon.
4. In Table 1-5, Please provide clarity on the "Unmonitored Control circuitry associated with protective
functions" component attribute. This would most likely be an FAQ item.
Response: Thank you for your comments.
1. For non-microprocessor relays, this activity is fundamentally performed as a part of the calibration process.
2. This activity is used to verify the performance of the voltage and current sensing devices, where the activity in Table 1-1 is used to verify that the
protective relay is performing properly. In some cases, the activity in Table 1-1 may also serve to satisfy the requirement in Table 1-3.
3. Table 1-4 is more detailed than the other tables because of the variability in the technologies of the station dc supply.
4. The draft definition of Protection System establishes “Control circuitry” as “…control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices”. Please see Section 15.3 of the Supplementary Reference for a discussion of this.
Florida Municipal Power Agency
Yes
PSEG Companies ("Public
Service Enterprise Group
Companies")
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Western Area Power
Administration
Yes
TransAlta Centralia Generation
Partnership
Yes
NextEra Energy
Yes
City of Austin DBA Austin Energy
PacifiCorp
Yes
11
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Southern Company Transmission
Yes or No
Yes
Question 1 Comment
The Standard Drafting Team should be commended for making the tables much easier to understand
Response: Thank you for your support.
Clark Public Utilities
No
The SDT has greatly improved the clarity of this document in the areas of relays, communication systems,
voltage and current sensing devices, control circuitry, and alarming paths. The recommendations on station
dc supply are still confusing.
First, there are five different attribute categories for unmonitored dc supply. Are these five categories
mutually exclusive? Are we supposed to follow just the category applicable to the type of battery? Are we
supposed to follow the first category and any of the subsequent four battery type categories as they apply? I
suspect some of the 3 month and 18 month items in the first category are considered to be necessary by the
SDT regardless of battery type. The current categorization is confusing. If we are required to perform the 3
month and 18 month activities listed in the first category regardless of battery type AS WELL AS the other
applicable battery type activities, please indicate this in Table 1-4. As a different option, just eliminate the first
category entirely and place the appropriate 3 month and 18 month verification and inspection requirements in
the four battery type specific categories. It may be repetitive but clarity is paramount in this standard. Second,
the FAQ examples seem to indicate that the SDT views the performance of an internal ohmic battery test or a
battery performance test as valid forms for verifying the individual battery cell states (i.e. state of charge of the
individual battery cells/units, battery continuity, battery terminal connection resistance, and battery internal
cell-to-cell or unit-to-unit connection resistance). It would be helpful if this were more obviously stated in table
1-4. Currently it could be interpreted that we need to do all of the individual cell-cell verification in addition to
the ohm test or the full performance test. I don’t believe this is the intent of the SDT (based on the FAQ
examples) but we need to see the intent in Table 1-4.Third, does a monitored dc supply have to monitor some
or all of each of the different line items listed? The FAQ examples indicate that if only some are monitored,
the dc supply can still be treated as monitored as long as the unmonitored items are verified. This means that
for a VLA battery with a low voltage alarm and unintentional ground alarm, all that is needed is to check
electrolyte level every 3 months, check float voltage and battery rack every 18 months and perform either an
internal ohm check at 18 months or a battery performance test at 6 years. Also battery alarms need to be
verified at 6 years. This is not clear in Table 1-4 and it could be interpreted by some that a monitored station
dc supply monitors ALL of the listed items not just SOME. The FAQs imply that partial monitoring is
acceptable but Table 1-4 does not indicate this very clearly. I do wish to say once again that this proposed
standard is much easier to understand and that with a little more clarification in the dc supply section I would
vote in the affirmative.
Response: Thank you for your comments. Table 1-4 has been modified in consideration of your comments. Specifically, Table 1-4 has been revised to
12
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
remove “state of charge” from the activities.
Exelon
Manitoba Hydro
No
The maintenance requirements for batteries listed in Table 1-4 do not appear to be consistent with example 1
in Section V, 1A of the FAQ. Specifically the FAQ does not mention the state of charge of the individual
battery cells/units, the battery continuity, the battery terminal connection resistance, the battery internal cellto-cell or unit-to-unit connection resistance, or the cell condition, which are indicated as 18 month interval
tasks in table 1-4.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove
“state of charge” from the activities.
Dynegy Inc.
Yes
Oncor Electric Delivery Company
LLC
Yes
Ingleside Cogeneration LP
Yes
The tables clearly tie to each component type in a Protection System. This is consistent with the required
PSMP format, making it straight forward to incorporate the intervals and to demonstrate compliance.
Response: Thank you for your support.
Indiana Municipal Power Agency
Yes
South Carolina Electric and Gas
Yes
Entergy Services
No
The tables are generally much clearer and the SDT is to be commended on their efforts.
However, we believe the Alarming Point Table needs additional clarification with regard to the Maximum
Maintenance Interval. If an “alarm producing device” is considered to be a device such as an SCADA RTU,
individual entity intervals for such a device would differ, and there isn’t necessarily a maximum interval
established as there is for Protection System components.
Also, if an entity’s alarm producing device maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum intervals for the alarm producing
13
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
device of that entity.
On that basis, we suggest the interval verbiage be revised to “When alarm producing device or system is
verified, or by sections as per the monitored component/protection system specified maximum interval as
applicable”. Alternately, if the intention is to establish maximum intervals as simply being no longer than the
individual component maintenance intervals as we suggest for inclusion above, then the verbiage should be
revised to “When alarm producing component/protection system segment is verified”.
In either case are we to interpret monitored components with attributes which allow for no periodic
maintenance specified as not requiring periodic alarm verification?
Response: Thank you for your comments. For clarity, the ‘Maximum Maintenance Interval’ column entry in Table 2 has been revised to state, “When
alarm producing Protection System component is verified”.
Duke Energy
Yes
Wisconsin Electric Power
Company
Yes
Independent Electricity System
Operator
American Electric Power
No
1. Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12 years for unmonitored control
circuitry, yet other portions of control circuitry have a maximum interval of 6 years. AEP does not
understand the rationale for the difference in intervals, when in most cases, one verifies the other.
2. Also, unmonitored control circuitry is capitalized in row 4 such that it infers a defined term.
3. In the first row of table 1-4 on page 16, it is difficult to determine if it is a cell that wraps from the previous
page or is a unique row. This is important because the Maximum Maintenance Intervals are different (i.e.
18 months vs. 6 years). It is difficult to determine to which elements the 6 year Maximum Maintenance
Interval applies.
4. AEP suggests repeating the heading “Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2):” for the bullet points on this page.
Response: Thank you for your comments.
1. The 6-year activities are all related to components with “moving parts”, and the 12-year activities are related to the other portions of the control
14
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
circuitry.
2. The capitalized term has been corrected.
3. Table 1-4 has been modified in consideration of your comments.
4. Table 1-4 has been modified in consideration of your comments.
ITC
Yes
The following question concerns Table 1-3.
1. Our testing program includes “impedance testing” of the current transformers (CTs) along with insulation
testing of the wiring and CT secondary. Impedance testing involves impressing an increasing voltage on the
secondary of the CT (with primary open circuited) until 1 (one) ampere flows. This method determines the
“knee” of the saturation curve that is used as a benchmark for comparison to previous testing and other CTs.
This procedure has successfully identified CT problems over the past several decades. We believe this
procedure to be adequate. Does the SDT agree that this method is sufficient to meet the testing
requirements of Table 1-3 and that a current comparison is not needed in addition to this testing?
2. Another variation of this is for voltage device compliance. Table 1-3 indicates that we should verify the
correct voltages are received by the relay. This means that the VT would need to be energized and we would
measure the secondary voltages to compare with others. Power plant relay testing is normally performed
during plant outages when this measurement cannot be done. Some plants do not allow any testing while the
unit is on line. It would seem that the standard would be written to allow some other type of testing to be
performed other than the measurement test.
3. For Table 1-1 Row 1, we believe the intent is to verify that settings are as specified for non-microprocessor
relays and microprocessor relays alike. If this is the case, consider adding “Verify that settings are as
specified” as a bullet under the headings for non-microprocessor relays and microprocessor relays.
4. Splitting the tables into separate sections for Protective Relays, Communication Systems, VT and CTs,
and Station D.C. Supply helped the clarity.
Response: Thank you for your comments.
1. Table 1-3 has been revised in consideration of your comments. Also, please see Section 15.3 of the Supplementary Reference Document. The SDT
has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document. Your
comments will be considered within that activity.
2. Table 1-3 has been revised in consideration of your comments. Also, please see Section 15.3 of the Supplementary Reference Document. The SDT
has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document. Your
comments will be considered within that activity.
15
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
3. “Verify that settings are as specified” is specified as an activity that applies to all Protective Relays, regardless of technology. The SDT has
decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document. Your
comments will be considered within that activity.
4. Thank you for your support.
ISO New England Inc.
No
The wording “Component Type” is not necessary in each title. Just the equipment category should be listed-what is now shown as “Component Type - Protective Relay”, should be Protective Relay. However,
Protective Relay is too general a category. Electromechanical relays, solid state relays, and microprocessor
based relays should have their own separate tables. So instead of reading Protective Relay in the title, it
should read Electromechanical Relays, etc. This will lengthen the standard, but will simplify reading and
referring to the tables, and eliminate confusion when looking for information. The “Note” included in the
heading is also not necessary. “Attributes” is also not necessary in the column heading, “Component”
suffices.
Response: Thank you for your comments. The SDT believes that the table headings are appropriate as reflected in the draft standard.
Nebraska Public Power District
Yes
CenterPoint Energy
Yes
American Transmission
Company
Yes
Consumers Energy
Yes
Southern Company Generation
Yes
US Bureau of Reclamation
No Comment
Alliant Energy
Yes
LCRA Transmission Services
Corporation
No
1. It would help to add a column to the left labeled Category. I.E. a relay could be classified under Category
1 attributes unmonitored or Cat 2, Cat 3.
2. Table 1-4, Station DC is very difficult to follow.
16
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. Table 1-4 has been modified in consideration of your comments.
MidAmerican Energy
Yes
Ameren
Yes
Xcel Energy
Yes
17
Consideration of Comments on Protection System Maintenance [Project 2007-17]
2. The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do you agree with the changes? If not, please provide
specific suggestions for improvement.
Summary Consideration: Several commenters objected to the “percentage” steps in several VSLs. The SDT
observes that the ‘percentage’ steps follow the VSL Guidelines which can be found on the NERC website in the
‘Resource Documents’ area of the ‘Reliability Standards’ section. Other commenters requested that the VSLs
permit some level of non-compliance before incurring a ‘Low’ VSL, again the SDT notes that this is not acceptable
per the VSL Guidelines.
Organization
Yes or No
Pepco Holding Inc & Affiliates
Yes
Pacific Northwest Small Public
Power Utility Comment Group
Yes
Tennessee Valley Authority
No
Question 2 Comment
1. There is no allowance for deferral of maintenance because of factors beyond the control of the TO, GO, or
DP. These include the unavailability of customer outages, generation outages, system configuration, high risk
of loss of generation or customer load or impact to power quality.
Proposed Change: Provide a process for acceptable deferral of maintenance activities.
2. Table 1-4 The requirement to perform cell internal ohmic resistance measurements every 18 months for
vented lead-acid batteries is excessive. Our normal battery life is 20+ years. A 3-year internal resistance test
frequency is adequate to prove battery integrity. IEEE 1188 recommends verification of internal ohmic
resistance to be on a quarterly basis. It appears other intervals take into account recommended inspection
interval plus some grace period.
Proposed Change: Change maintenance interval from 3 months to 6 months.
3. Section: R1.5 This new requirement will require significant documentation with no known improvement to
the reliability of the BES. What data is being used to determine the need for this requirement? How far does
this requirement go?
4. Table 1-4 requires the inspection of “physical condition of battery rack” What are “identify calibration
tolerance or other equivalent parameters” for this task? You already have verified, test, inspect, and calibrate
defined. Leave out R1.5 which requires more than meeting the definitions.
Response: Thank you for your comments.
18
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
1. FERC Order 693 directs NERC to establish maximum allowable intervals. A “deferral process” would not satisfy this directive.
2. The SDT disagrees, and believes that 18-months is the proper interval for this activity.
3. The SDT has determined that the fundamental concerns of R1 part 1.5 and the associated changes are addressed within the PSMP definition, and
that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address various
related concerns noted within comments. Please see Supplementary Reference Document, Section 8 for a discussion of this. The associated VSL
has also been revised.
4. The SDT has determined that the fundamental concerns of R1 part 1.5 and the associated changes are addressed within the PSMP definition, and
that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address various
related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document, Section 8
for a discussion of this.
Northeast Power Coordinating
Council
No
1. Because all the requirements deal with protective system maintenance and testing, violations could
directly cause or contribute to bulk electric system instability, etc., the VRFs should all be “High”.
2. The Time Horizons should all be “Operations Planning” because of the immediacy of a failure to meet the
requirements.
3. For the R1 Lower VSL, include a second part to read: Failed to identify calibration tolerances or other
equivalent parameters for one Protection System component type that establish acceptable parameters
for the conclusion of maintenance activities. For the R1 Moderate VSL, suggest similar wording as for the
Lower VSL but specifying two Protection System component types. For the R1 High VSL, suggest
changing the wording of the 3rd part to be similar to the Lower VSL to match the requirement and to cater
for more than two Protection System component types.
4. For the R3 Severe VSL, in part 3, replace “less” with fewer.
Response: Thank you for your comments.
1. Consideration of the VRFs, in association with the VRF Guidelines, yields the VRFs as established within the draft Standard.
2. The SDT has reviewed the time horizons, and feels that R1 is properly assigned a Long-Term Planning time horizon, as the activities to develop a
program and to determine the monitoring attributes of components is performed within the related time period. The SDT had concluded that
Requirement R2 is redundant with Requirement R1, Part 1.4, and has deleted R2 (together with the associated Measure and VSL).
3. The SDT has determined that the fundamental concerns of R1 part 1.5 and the associated changes are addressed within the PSMP definition, and
that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The associated VSL has also been revised.
4. The SDT believes that your suggestion is similar to the existing text, and declines to modify the standard.
19
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Platte River Power Authority
System Maintenance
Yes or No
No
Question 2 Comment
The 5%, 10%, and 15% levels for R2 & R4 exaggerate the severity levels for small companies. A small DP
with only 9 relays in a protection system would only have to be missing 1 record for a severe VSL.
Response: Thank you for your comments. The percentage levels for Requirement R4 are consistent with many other NERC Standards and are also
consistent with the guidance within the VSL Guidelines. The SDT concluded that Requirement R2 was redundant with Requirement R1, Part 1.4, and
deleted Requirement R2 (together with the associated Measure and VSL).
Electric Market Policy
No
VSL R3. How do you measure a percentage of countable events over a period of time? How are you to
determine what the total population to be considered? An entity should not be penalized if they are following
their program, correcting issues, and documenting all actions, even if there is a high failure rate in an
instance.
Response: Thank you for your comments. Attachment A, to which Requirement R3 refers, specifies that countable events are assessed on the basis
of ” for the greater of either the last 30 components maintained or all components maintained in the previous year.”
Bonneville Power Administration
Yes
Santee Cooper
NERC Staff
FirstEnergy
No
The VSL for R2 need to be adjusted since "Condition Based Maintenance" has been removed from the
standard.
Response: Thank you for your comments. The SDT concluded that Requirement R2 was redundant with Requirement R1, Part 1.4, and deleted
Requirement R2 (together with the associated Measure and VSL).
Florida Municipal Power Agency
No
The VRF of R1 should be Low since the attached tables are essentially the PSMP.
Response: Thank you for your comments. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the
establishment of an entities’ individual PSMP.
PSEG Companies ("Public
Service Enterprise Group
Companies")
No comment
20
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
MRO's NERC Standards Review
Subcommittee
Yes
Western Area Power
Administration
Yes
TransAlta Centralia Generation
Partnership
No
Question 2 Comment
Please provide acronyms list and its explanations in the standard.
Response: Thank you for your comments. In accordance with established NERC custom, acronyms are either established at the first use of the term,
or are general acronyms used throughout NERC Standards.
NextEra Energy
Yes
City of Austin DBA Austin Energy
PacifiCorp
Yes
Southern Company Transmission
No
We disagree with the inclusion of the VSLs, VRFs, and time Horizons associated with the new Requirements
1.5 and 4.2
Response: Thank you for your comments. The SDT determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Clark Public Utilities
Yes
Exelon
Manitoba Hydro
No
The high VSL for R1 “Failed to include all maintenance activities relevant for the identified monitoring
attributes specified in Tables 1-1 through 1-5” may be interpreted in different ways and should be further
clarified.
Response: Thank you for your comments. The SDT does not understand your concern; further details are needed.
21
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Dynegy Inc.
Yes or No
No
Question 2 Comment
For R4, the VRF has been changed to high. We question the need to change to high since there are
numerous elements that will still protect the system while repairs are being made.
Response: Thank you for your comments. Requirement R4 addresses implementation of the overall PSMP; that is – maintaining all devices within the
program. This VRF is consistent with the “high” assigned to R2 of PRC-005-1.
Oncor Electric Delivery Company
LLC
No
Oncor strongly disagrees with the modification to the Violation Severity Levers (VSL) table under the High
VSL column where it states that it is a high VSL for “Failed to establish calibration tolerance or equivalent
parameters to determine if components are within acceptable parameters.” Oncor feels modifying the
standard by adding a requirement that requires a Transmission Owner, Generation Owner or Distribution
Provider to “identify calibration tolerances or other equivalent parameters for each Protection System
component type that establish acceptable parameters for the conclusion of maintenance activities” is too
intrusive and divisive for what it brings to the reliability of the BES. The requirement (Requirement R1 part
1.5) and its associated High VSL should be removed from PRC-005-2.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Ingleside Cogeneration LP
Indiana Municipal Power Agency
No
IMPA does not agree with the percentage in the VSL table for R4. For smaller entities that have six or less of
any one type of Protection System Component and they fail, for whatever reason (even if it's a matter of
incomplete documentation), to complete scheduled program maintenance on that component they will be
subjected to the severe VSL penalty Matrix.
Consideration should be given to entities having less than say, 100 of a component. There should be some
type of tiered sub table within the VSL matrix for this consideration - registered entities having a certain
component in quantities greater than or equal to 100 and registered entities having quantities of that certain
component of less than 100.
Response: Thank you for your comments. The percentage levels within Requirement R4 are consistent with many other NERC Standards, and are also
consistent with the guidance within the VSL Guidelines. The SDT concluded that Requirement R2 was redundant with Requirement R1, Part 1.4, and
deleted Requirement R2 (together with the associated Measure and VSL).
South Carolina Electric and Gas
Yes
22
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Entergy Services
Yes or No
Question 2 Comment
No
R1.5 calls for “identification of calibration tolerances or equivalent parameters...” whereas the associated VSL
references “failure to establish calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply “identify” or document such calibration
tolerances would be analogous to the severity level(s) of a “failure to specify one (or the severity level should
be consistent with the other elements of R1. Both cases appear to be more of a documentation issue as
opposed to a failure to implement. Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4?
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Duke Energy
No
1. R1.3 appears to be missing from the VSL for R1.
2. Also, it’s unclear to us what the expectation is for compliance documentation for “monitoring attributes and
related maintenance activities” in R1.4 and “calibration tolerances or other equivalent parameters” in R1.5.
This is fairly straightforward for relays, but not for other component types.
3. R4 - More clarity must be provided on the expectation for compliance documentation. This is a High VRF
requirement, and there may only be a small number of maintenance-correctable items, hence a significant
exposure to an extreme penalty.
Response: Thank you for your comments.
1. The High VSL for Requirement R1 has been revised in consideration of your comment.
2. The SDT concluded that Requirement R2 was redundant with Requirement R1, Part 1.4, and deleted R2 (together with the associated Measure and
VSL).
3. Examples of compliance documentation are included within Measure M4 and discussed within Section 15.7 of the Supplementary Reference
Document.
Wisconsin Electric Power
Company
Independent Electricity System
Operator
No
1. R1 Lower - We suggest including a second part as follows: “Failed to identify calibration tolerances or
other equivalent parameters for one Protection System component type that establish acceptable
parameters for the conclusion of maintenance activities. “
23
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
2. R1 Moderate - We suggest similar to the Lower VSL but catering for two Protection System component
types.R1 High - We suggest changing the wording of the 3rd part to match the requirement and to cater
for more than two Protection System component types.
3. Editorial Comment to Severe VSL for R3: In part 3, replace “less” with “fewer”.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The associated VSL has also been revised.
2. The ‘Moderate’ VSL for Requirement R1 appears to be similar to the ‘Lower’ VSL for Requirement R1 as you suggest. The SDT believes that, if
more than two Protection System component types are not addressed, the ‘Severe’ VSL is appropriate.
3. Thank you. The SDT elected not to change the VSL for Requirement R3 as suggested.
American Electric Power
No
1. The VSL table should be revised to remove the reference to the Standard Requirement 1.5 in the R1
“High” VSL.
2. All four levels of the VSL for R2 make reference to a “condition-based PSMP.” However, no where in the
standard is the term “condition-based” used in reference to defining ones PSMP. The VSL for R2 should
be revised to remove reference to a condition-based PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard Requirements and Table 1.
3. In multiple instances, Table 1 uses the phrase “No periodic maintenance specified” for the Maximum
Maintenance Interval. Is this intended to imply that a component with the designated attributes is not
required to have any periodic maintenance? If so, the wording should more clearly state “No periodic
maintenance required” or perhaps “Maintain per manufacturers recommendations.” Failure to clearly
state the maintenance requirement for these components leaves room for interpretation on whether a
Registered Entity has a maintenance and testing program for devices where the Standard has not
specified a periodic maintenance interval and the manufacturer states that no maintenance is required.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The associated VSL has also been revised.
2. The SDT concluded that Requirement R2 is redundant with R1, Part 1.4, and deleted Requirement R2 (together with the associated Measure and
VSL).
3. If the indicated monitoring attributes are present, no “hands-on” periodic maintenance is required, as the monitoring of the component is
24
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
providing a continuing indication of its functionality.
ITC
Yes
ISO New England Inc.
No
1. Because all the requirements deal with protective system maintenance and testing, violations could
directly cause or contribute to bulk electric system instability, etc., the VRFs should all be “High”.
2. The Time Horizons should all be “Operations Planning” because of the immediacy of a failure to meet the
requirements.
3. For the R1 Lower VSL, include a second part to read: Failed to identify calibration tolerances or other
equivalent parameters for one Protection System component type that establish acceptable parameters
for the conclusion of maintenance activities.
4. For the R1 Moderate VSL, suggest similar wording as for the Lower VSL but specifying two Protection
System component types.
5. For the R1 High VSL, suggest changing the wording of the 3rd part to be similar to the Lower VSL to
match the requirement and to cater for more than two Protection System component types.
6. For the R3 Severe VSL, in part 3, replace “less” with fewer.
Response: Thank you for your comments.
1. The SDT set the VRFs in accordance with the FERC’s and NERC’s VRF guidance.
2. The SDT has reviewed the time horizons, and feels that Requirement R1 is properly assigned a Long-Term Planning time horizon, as the activities
to develop a program and to determine the monitoring attributes of components is performed within the related time period. The SDT concluded
that Requirement R2 was redundant with Requirement R1, Part 1.4, and deleted Requirement R2 (together with the associated Measure and VSL).
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The associated VSL has also been revised.
4. The ‘Moderate’ VSL for Requirement R1 appears to be similar to the ‘Lower’ VSL for Requirement R1 as you suggest.
5. The SDT believes that, if more than two Protection System component types are not addressed, the ‘Severe’ VSL is appropriate.
6. The SDT believes that your suggestion is similar to the existing text, and declines to modify the standard.
Nebraska Public Power District
No
VRF’s:
1. The definition of a Medium Risk Requirement included on page 8 of the SAR states: "A requirement that,
25
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system." The PSMP does not "directly" affect the
electrical state or the capability of the bulk electric system. A failure of a Protection System component is
required to "directly" affect the BES. Therefore, the PSMP has only an "indirect" affect on the electrical
state or the capability of the BES. Requirements R1 through R3 and their subparts are administrative in
nature in that they are comprised entirely of documentation. Therefore, I recommend changing the
Violation Risk Factor of Requirements R1, R2, and R3 to Lower to be consistent with the Violation Risk
Factors defined in the SAR.
VSL’s:
2. R2: Tables 1-1 through 1-5 refers to time-based maintenance programs. I recommend changing
"condition-based" to "time-based" in all four severity levels.
3. SAR Attachment B - Reliability Standard Review Guidelines states that violation severity levels should be
based on the following equivalent scores: Lower: More than 95% but less than 100% compliant
Moderate: More than 85% but less than or equal to 95% compliant High: More than 70% but less than
equal to 85% compliant Severe: 70% or less complaint recommend revising the percentages of the
violation severity levels to be consistent with the SAR.
4. R3: The performance-based maintenance program identified in PRC-005 Attachment A provides the
requirements to establish the technical justification for the initial use of a performance-based PSMP and
the requirements to maintain the technical justification for the ongoing use of a performance-based
PSMP. However, it appears the VSLs for Requirement R3 only addresses the ongoing use of the
technical justification.
a. I recommend revising the VSLs for R3 to include the initial use of the technical justification. Item
2) of R3 Severe VSL is a duplicate of Item 2) of R3 Lower VSL. This item is administrative in
nature therefore I recommend deleting Item 2) from R3 Severe VSL.
b. The first and third bullets of item 4) of R3 Severe VSL are administrative in nature and should be
moved to the Lower VSL
c.
R4: SAR Attachment B - Reliability Standard Review Guidelines states that violation severity
levels should be based on the following equivalent scores: Lower: More than 95% but less than
100% compliant Moderate: More than 85% but less than or equal to 95% compliant High:
More than 70% but less than equal to 85% compliant Severe: 70% or less complaint
recommend revising the percentages of the violation severity levels to be consistent with the
SAR.
26
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comments.
1. Requirements R1, R2, and R3 are not administrative; they are foundational. Without the fundamental development of a PSMP, an entity is unlikely
to actually implement a PSMP that satisfies the reliability needs of the BES. The SDT had concluded that Requirement R2 is redundant with
Requirement R1, Part 1.4, and deleted Requirement R2 (together with the associated Measure and VSL).
2. The SDT concluded that Requirement R2 is redundant with Requirement R1, Part 1.4, and deleted Requirement R2 (together with the associated
Measure and VSL).
3. The guidelines within the SAR have been superseded by subsequent revisions to the VSL Guidelines. The VSLs in the draft standard adhere to the
latest VSL Guidelines and to the June 19, 2008 FERC order on VSLs in Docket No RR08-04-000.
4. Part a – The VSL for Requirement R3 has been modified in consideration of your comments.
Part b – These requirements are not administrative; they are foundational. Without compliance with these requirements, an entity does not have an
effective performance-based PSMP, and may be detrimentally affecting reliability.
Part c – The latest VSL Guidelines also provide examples of VSLs similar to those in the draft standard.
CenterPoint Energy
American Transmission
Company
Yes
Consumers Energy
Yes
Southern Company Generation
Yes
US Bureau of Reclamation
Yes
The tables rely on a reference document which is not a part of the standard and as such may be altered
without due process. Either the relevant text from the reference needs to be inserted into the standard or the
reference itself incorporated into the standard. Specific References such as
Response: Thank you for your comments. The Tables do not provide a reference to either the Supplementary Reference Document. An entity must
comply with the standard when approved. The reference documents provide additional explanation, discussion, and rationale, but are not part of the
mandatory standard. Since the reference documents are being developed to accompany the standard, the NERC Standard Development Procedure
requires that they be posted with the draft standard and undergo stakeholder review, both initially and with any revision of the standard.
Alliant Energy
Yes
27
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
LCRA Transmission Services
Corporation
Yes
MidAmerican Energy
Yes
Ameren
No
Question 2 Comment
(1)The Lower VSL for all Requirements should begin above 1% of the components. For example for R4:
“Entity has failed to complete scheduled program on 1% to 5% of total Protection System components.”
PRC-005-2 unrealistically mandates perfection without providing technical justification. A basic premise of
engineering is to allow for reasonable tolerances, even Six Sigma allows for defects. Requiring perfection
may well harm reliability in that valuable resources will be distracted from other duties.
Response: Thank you for your comments. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
Xcel Energy
Yes
28
Consideration of Comments on Protection System Maintenance [Project 2007-17]
3. The SDT has provided the “Supplementary Reference” document to provide supporting discussion for the Requirements within the
standard. Do you have any specific suggestions for improvements?
Summary Consideration: Some commenters questioned whether the Supplementary Reference Document was a
part of the Standard and thus mandatory and enforceable; the SDT responded that this document is not a part of
the standard but instead offers guidance/rationale to assist in the implementation of the standard. Various other
comments were offered regarding the content of the Supplementary Reference Document, to which the SDT
responded accordingly.
Organization
Yes or No
Pepco Holding Inc & Affiliates
Yes
Pacific Northwest Small Public
Power Utility Comment Group
No
Tennessee Valley Authority
No
Northeast Power Coordinating
Council
No
Platte River Power Authority
System Maintenance
No
Electric Market Policy
Yes
Question 3 Comment
The document on page 3 states that data available from EPRI (et.al) was utilized by the Standard Drafting
Team; however, there are no references to EPRI documents in Section 16. Suggest including EPRI
references for completeness.
Response: Thank you for your comments. Page 3 of the Supplementary Reference Document has been revised to remove reference to EPRI
documents.
Bonneville Power Administration
Santee Cooper
No
29
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
NERC Staff
Yes or No
Question 3 Comment
Yes
1. In section 2.3, NERC staff recommends noting that the present NERC Glossary definition of Bulk Electric
System will be revised in response to FERC Order No. 743.
2. In Section 2.4, NERC staff recommends changing the phrase “relays that use measurements of voltage,
current, frequency and/or phase angle” with “protective relays that respond to electrical quantities” for
consistency with recent changes to the proposed definition of Protection System.
Response: Thank you for your comments.
1. The SDT believes that it is not advisable to reference future activities, but notes that the standard will be applicable to whatever is defined to be the
BES, either today or in the future.
2. The Supplementary Reference Document has been revised as suggested.
FirstEnergy
Yes
The discussions surrounding implementing the PSMP on pages 10 and 11 of the clean copy are troublesome
for the following reasons.
1. On Pg. 10, under Sec. 8.1, the 4th bullet item states "If your PSMP (plan) requires more activities then you
must perform and document to this higher standard". This statement's use of the word "must" implies that an
entity will be audited to their documented maintenance practices, even if those practices exceed the
requirements of the PRC-005 standard. The PRC-005 standard, and any standard, details the minimum
requirements that must be met to achieve a certain reliability goal. For example, if an entity's program states
that it will do maintenance on a relay every 4 years, but the standard only requires maintenance every 6
years, the entity shall be held compliant to the standard's 6 year interval. If the entity in this example decides
that in year 4 it must delay its maintenance to year six, that should be allowable since the standard PRC-0052 requires maintenance every 6 years.
2. Since the standard no longer discusses Condition Based Maintenance, it should be removed from the
reference document for consistency.
Response: Thank you for your comments.
1. This text is in the Supplementary Reference Document as a caution to entities that they may be expected to be held accountable for their entire
documented PSMP, even if it exceeds the minimum requirements of the standard.
2. The Supplementary Reference Document discusses condition-based maintenance in a conceptual manner, as a generally-recognized term. The
SDT did make some changes within the Supplementary Reference document to clarify the manner in which condition-based maintenance is
discussed.
30
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Florida Municipal Power Agency
Yes
PSEG Companies ("Public
Service Enterprise Group
Companies")
Yes
Question 3 Comment
Figure 2 “typical generation system” shows a typical auxiliary medium voltage bus, in addition to the color
coded elements suggest that a very distinct line of demarcation (dark dotted line) be added to the figure that
defines the elements associated with the MV bus protection served by the station Aux Transformer and unit
aux transformer are not part of the BES- PSMP PRC5 requirements. Also see comment 5 below; we suggest
that the station service transformer must be connected to BES for inclusion in standard requirements.
Suggest adding an explanation note to figure 2 to clarify this.
Response: Thank you for your comments. Figure 2 is intended to provide an example to users, not to describe the entire applicability of the draft
standard. As such, the SDT does not believe that this figure needs to reflect all possible arrangements, nor does it need to suffice to describe the
entire applicability. As for your comment regarding the unit auxiliary transformer, please see the SDT response to your more detailed comments in
Question 5.
MRO's NERC Standards Review
Subcommittee
No
Western Area Power
Administration
No
TransAlta Centralia Generation
Partnership
No
NextEra Energy
No
City of Austin DBA Austin Energy
PacifiCorp
Southern Company Transmission
Yes
1. Page 11 and 12, (Additional Notes for Table 1-1 through 1-5)
Comment ->> The standard does not reference these notes. Should these notes be referenced and
included in the Standard?
2. Page 12, Additional Notes for Table 1, item #7 (“performing an operational trip test”)
31
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
Comment ->> Standard does not state that an operational/full functional test is required. Please clarify.
3. Page 22, 15.3, Control Circuitry Functions, paragraph 1 (“verify, with a volt-meter, the existence of proper
voltage at the open contacts”
Comment ->> The example of measuring the proper voltage with a volt-meter at the open contacts to
verify the circuit indicates that the 12-year “full functional” trip test of control circuits is not required.
Please clarify.
4. Page 22, 15.3, Control Circuitry Functions, paragraph 3 (“UVLS or UFLS scheme are excluded from the
tripping requirement, but not from the circuit test requirements”)
Comment ->> This indicates to me that measuring the proper voltage with a volt-meter at the open
contacts will verify the circuit. Please confirm. Please clarify - If a suitable monitoring system is installed
that verifies every parallel trip path then the manual-intervention testing of those parallel trip paths can be
“extended beyond 12 years”. Standard indicates that no periodic maintenance is required. Consider
changing “extended beyond 12 years” to “eliminated”.
5. Page 23, 15.3, Control Circuitry Functions, paragraph 5 (“When verifying the operation of the 94 and 86
relays each normally-open contact that closes to pass a trip signal must be verified as operating
correctly.”)
Comment ->> This indicates that we must verify that trip and auxiliary device contacts change state.
Please confirm. The standard does not state that the contacts must be verified to change states. If this is
required, please add to the standard.
Response: Thank you for your comments.
1. These notes are provided as application guidance relative to the Tables, which as you note, does not reference them.
2. This note has been revised within the Supplementary Reference Document in consideration of your comment.
3. This example is stated within the Supplementary Reference Document as an example method of testing the dc control circuitry. The draft standard
no longer requires a “functional trip test”, although it does require that lockout relays and auxiliary relays be operated at least once every 6 years
to verify that they function properly.
4. The Supplementary Reference Document has been revised as suggested.
5. The draft standard specifies “Verify electrical operation” of these components every 6 years. This seems implicitly to require a change of state of
the contacts. However, it may be possible to verify electrical operation without having to check the change of state of the individual contacts, but
the contacts will have to be checked as part of the 12-year full test. The cited clause/paragraph Supplementary Reference Document has been
revised to clarify.
32
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Clark Public Utilities
Yes or No
Question 3 Comment
No
Exelon
Manitoba Hydro
No
Dynegy Inc.
No
Oncor Electric Delivery Company
LLC
No
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration, LP, believes that the Section 15.5 of the Supplementary Reference “Associated
communications equipment (Table 1-2)” properly reflects the intent of the validation of relay-to-relay
communications. It states that any “evidence of operational test or documentation of measurement of signal
level, reflected power or data-error rates can fulfill the requirements.” However, Table 1-2 - which will be the
ultimate reference used by audit teams - only clearly allows for the measurement of channel parameters.
Although the newer technology relays provide read-outs of signal level or data-error rates that do not require
intrusive testing, older relays do not. The tools required to perform such testing are not easily available - and
may leave the communications channel in worse shape after testing than it was prior to testing.
We believe that Table 1-2 should be updated to clearly state that an operational test is sufficient for the
testing of relay-to-relay communication - consistent with the Supplementary Reference.
Response: Thank you for your comments. The standard does not explicitly require measurement of channel parameters, but instead specifies that
they may be verified. The Supplementary Reference Document has been revised to remove the discussion of operational testing of the
communications channel.
Indiana Municipal Power Agency
No
South Carolina Electric and Gas
No
Entergy Services
Yes
R1.5 calls for “identification of calibration tolerances or equivalent parameters for each Protection System
Component Type....”. We believe the Supplementary Reference document should provide additional
information and examples of calibration tolerances or equivalent parameters which would be expected for the
various component types. Especially for any “equivalent” parameters which would be required for compliance
33
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
for a component type besides protective relays.
Response: Thank you for your comments. The SDT determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Duke Energy
No
Wisconsin Electric Power
Company
No
Independent Electricity System
Operator
No
American Electric Power
Yes
With such a complex standard as this, the FAQ and Supplementary Reference documents do aid the
Protection System owner in demystifying the requirements. But AEP holds strong doubt on how much weight
the documents carry during audits. It would be better to include them as an appendix in the actual standard,
but in a more compact version with the following modifications:
1. Section 5 of the Supplementary Reference, refers to “condition-based” maintenance programs. However,
no where in the standard is the term “condition-based” used in reference to defining ones PSMP. The
Supplementary Reference should be revised to remove reference to a condition-based PSMP;
alternatively the Standard could be revised to include the term “condition-based” within the Standard
Requirements and Table 1.
2. Section 15.7, page 26, appears to have a typographical error “...can all be used as the primary action is
the maintenance activity...”
3. Figure 2 is difficult to read. The figure is grainy and the colors representing the groups are similar enough
that it is hard to distinguish between groups.
Response: Thank you for your comments. The discussion within the Supplementary Reference Document and FAQ are informative, not normative,
and thus do not belong as part of the standard.
1. The Supplementary Reference Document discusses condition-based maintenance in a conceptual manner, as a generally-recognized term. The
SDT did make some changes within the Supplementary Reference Document to clarify the manner in which condition-based maintenance is
discussed.
2. This clause has been corrected.
34
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
3. A higher-quality version of Figure 2 has been substituted.
ITC
Yes
1. Auxiliary Relay Testing: We repeat our objection to the 6 year requirement for testing of auxiliary relays.
The STD response to our previous objection was:
Please see new Table 1-5. The SDT believes that mechanical solenoid-operated devices share
performance attributes (and failure modes) with electromechanical relays and need to be tested at similar
intervals. Performance-based maintenance is an option to increase the intervals if the performance of
these devices supports those intervals. Auxiliary relays are, of course, electromechanical relays, but
much less complicated than impedance, differential or even time-overcurrent electromechanical relays. It
has been our experience that trip failures are rare and that our present 10 year control, trip tests, and
other related testing are sufficient in verifying the integrity of the scheme. Section 8.3 of the
Supplementary Reference notes statistical surveys were done to determine the maintenance intervals.
Were auxiliary relays included in these surveys in a such a way to verify that they indeed require a 6 year
maintenance interval? We recommend they be considered part of the control circuitry, with a 12 year test
cycle.
2. High Speed Ground Switch Testing: We repeat our recommendation that the standard state that a high
speed ground switch is an interrupting device. We also recommend that testing requirements for HighSpeed ground switches be clearly stated in the standard.
Section 15.3 of the Supplementary Reference contains the following: It is necessary, however, to classify
a device that actuates a high-speed auto-closing ground switch as an interrupting device if this ground
switch is utilized in a Protection System and forces a ground fault to occur that then results in an
expected Protection System operation to clear the forced ground fault. The SDT believes that this is
essentially a transferred-tripping device without the use of communications equipment. If this high-speed
ground switch is “...applied on, or designed to provide protection for the BES...” then this device needs to
be treated as any other Protection System component. The control circuitry would have to be tested
within 12 years and any electromechanically operated device will have to be tested every 6 years. If the
spring-operated ground switch can be disconnected from the solenoid triggering unit then the solenoid
triggering unit can easily be tested without the actual closing of the ground blade.
We disagree that a high-speed ground switch can be adequately tested by disconnecting the solenoid
triggering unit. The ability of the trip coil to “operate the circuit breaker” must be verified per Table 1-5
Row 1. The ability of the “solenoid triggering unit” to operate the ground switch should be required also.
A high-speed ground switch is a unique device. Its maintenance requirements should be specifically
included in the standard itself. Based on Draft 3 of the standard, this is a electromechanically operated
device and would have to be tested every 6 years. A logical location would be in Table 1-5. Is there test
35
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
data to support the test method of disconnecting the solenoid triggering unit?
Response: Thank you for your comments.
1. The SDT believes that the appropriate interval for electromechanical devices such as aux or lockout relays should remain at 6 years, as these
devices contain “moving parts” which must be periodically exercised to remain reliable.
2. PRC-005-2 includes high-speed grounding switch trip coils within the dc control circuitry to the degree that the initiating Protection Systems are
characterized as “transmission Protection Systems”. There is currently an unapproved interpretation response (project 2009-17) addressing what
is a “transmission protection system.” When this interpretation is approved, the SDT will incorporate it within PRC-005-2. Section 15.3 of the
Supplementary Reference Document will be revised to clarify the discussion of testing of the ground-switch trip coil.
ISO New England Inc.
No
Nebraska Public Power District
Yes
The Supplementary Reference Documents identified are unapproved and in draft form. I believe that only
approved documents should be referenced in the Standard. Therefore, I recommend updating the
Supplementary Reference Documents section with approved versions of the documents.
Response: Thank you for your comments. The SDT revised the Supplementary Reference Document section of the draft Standard.
CenterPoint Energy
American Transmission
Company
No
Consumers Energy
No
Southern Company Generation
Yes
1. On Page 4, Paragraph 2.2 is no longer proposed - the paragraphs just before 2.2 need to be revised.
2. On Page 12, item 7, the phrase “operational trip test” is not used in the standard. Please consider using
this phrase in the standard.
3. On Pages 14-15, several paragraphs describing the contents of Sections 9, 10, 11, & 13 are given –
these appear to be out of place and don’t seem to belong here (just before “9. Performance-Based
Maintenance Process).
4. On Page 24, correct the bulleted Protection System Definition to match the most recent definition.
36
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
5. On Page 29, please improve the clarity of Figure 2.
6. On Page 31, please revise the flowchart references to R4.4.1 and R4.4.2.
7. Please correct the following formatting: Page 2, Table of Contents; Page 18, the bulleted item list; Page
23, add a space before the last paragraph.
Response: Thank you for your comments.
1. This Section of the Supplementary Reference Document has been corrected.
2. This Section of the Supplementary Reference Document has been revised.
3. The Supplementary Reference Document has been revised to address your comment.
4. The Supplementary Reference Document has been revised to address your comment.
5. The Supplementary Reference Document has been revised to address your comment.
6. The Supplementary Reference Document has been revised to address your comment.
7. The Supplementary Reference Document has been revised to address your comment.
US Bureau of Reclamation
Yes
The Supplementary reference provides significant clarity to the intent and application of standard; however, in
doing so, it reveals conflicts and ambiguity in the text of the standard. It is suggested that some of the
clarifying language be inserted into the text of the standard.
Response: Thank you for your comments. To the extent possible, the clarifying language of the Supplementary Reference Document will be
incorporated into the next version of PRC-005 when the standard is drafted in the Results-based format.
Alliant Energy
No
LCRA Transmission Services
Corporation
Yes
Well written and helpful document. In Section 8.1, the document states that if your PSMP requires activities
more often than the Tables maximum, then you must perform to that higher standard. While it is
understandable that an entity may desire to maintain their PRS at a higher level, they should not be fined or
penalized for achieving less than their standard but within the intervals stated in the Tables. This point should
be clarified, preferably within the standard itself.
Response: Thank you for your comments. Requirement R1, Part 1.3 and Requirement R4 within the Standard has been revised in a manner which
addresses your comment. However, the SDT re-emphasizes that entities may be expected to be held to their PSMP developed in accordance to
37
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
Requirement R1, whether it minimally addresses the remainder of the requirements in the standard or exceeds those requirements.
MidAmerican Energy
Yes
The Supplementary Reference should have clear disclaimers indicating that nothing in the reference is
mandatory and enforceable.
Response: Thank you for your comments. NERC establishes that only the Standard is mandatory and enforceable, and Section F of the standard
introduces the Supplementary Reference Document as presenting supporting discussion. The introductory area of the Supplementary Reference
Document will be revised to clarify this.
Ameren
No
Xcel Energy
Yes
1. Requirement R1 of the standard has been changed and no longer states that only relays which sense
current, voltage, and phase angle to detect anomalies are in scope. However, it is noted that the new
definition of Protection System states “Protective Relays which respond to electrical parameters.” Does
Section 2.4 of the Supplementary Reference and, in particular, the last sentence of this section, still align
with the standard such that sudden pressure devices are not classified as a relay requiring calibration per
Table 1-1? Is the tripping path through the Sudden Pressure Device included as DC Control Circuitry per
Table 1-5? FAQ II.4.F would indicate testing of trips from 63 devices are also not required. If so, perhaps
this should be restated in Section 2.4 of the Supplementary reference.
2. Section 2.4 could be read to imply that “applicable relays” includes IEEE device #86, lockout relays and
IEEE device #94, tripping or trip free relays. However, it is apparent from Table 1-1 “Component Type –
Protective Relays” that there are no maintenance activities applicable to 86 or 94 devices. On the other
hand, Table 1-5 “Component Type - Control Circuitry” does include maintenance activities for
electromechanical trip or auxiliary devices. Thus the tables of the standard imply that 86 and 94 devices
would be more accurately classified as DC control circuitry rather than relays. We suggest that Section 2.4
be written to clarify the SDT’s intent for the component type classification of devices 86 and 94. Note that
auditors of PRC-005-1 frequently ask for a list of in scope relays and it would nice to have a definite rationale
for excluding 86 and 94 devices from these relay lists.
Response: Thank you for your comments.
1. The Supplementary Reference Document has been revised to clarify this point.
2. The SDT re-emphasizes that auxiliary and lockout relays are included within the standard as mechanical-operating devices that must be verified to
operate within a 6-year interval, and also as devices which must be verified within the verification of all paths of the trip circuits on a 12-year
interval. It is left to the entity to determine how to best demonstrate compliance with that requirement to the compliance monitor. The
38
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
Supplementary Reference Document has been revised to clarify this point.
39
Consideration of Comments on Protection System Maintenance [Project 2007-17]
4. The SDT has provided the “Frequently-Asked Questions” (FAQ) document to address anticipated questions relative to the standard.
Do you have any specific suggestions for improvements?
Summary Consideration: Commenters suggested corrective language and requested additional discussions within
the FAQ document. The SDT decided to eliminate the FAQ document and incorporate its contents into the
Supplementary Reference Document as appropriate. The SDT considered all commenters’ suggestions during that
activity.
Organization
Yes or No
Pepco Holding Inc & Affiliates
Yes
Pacific Northwest Small Public
Power Utility Comment Group
Yes
Question 4 Comment
WECC does not use the definition of the BES that NERC supplied to FERC via
http://www.nerc.com/docs/docs/ferc/RM06-16-6-14-07CompFilingPar77ofOrder693FINAL.pdf,so the answer
to III.1.3 (page 19-20) is not accurate.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Tennessee Valley Authority
No
Northeast Power Coordinating
Council
Yes
See response to Question 5 below.
Response: Thank you for your comments. Please see our response to your comments in Question 5.
Platte River Power Authority
System Maintenance
No
Electric Market Policy
Yes
The FAQ’s do not appear to have kept up with the current draft Standard.
1. For example, Question B under Section 2 for Protective Relays, refers to the use of the word
“Restoration” in the definition of a Protection System Maintenance Program. The current definition uses
the word “Restore.”
2. Additionally, Answers B, I, and J under Section 2 for Protective Relays each refer to Requirement R4.3,
40
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
which in not in the current Standard. Suggest a final edit of the FAQ’s to clean-up these type of issues.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Bonneville Power Administration
Santee Cooper
No
NERC Staff
Yes
1. At a minimum, the response to Question II.1.A should be revised to reflect the present revision of
Requirement R1. In the current proposed response to the FAQ, the answer refers to text that was deleted
from Requirement R1 in the current posting of the standard; i.e., this standard covers protective relays
“that use measurements of voltage, current and/or phase angle to determine anomalies and to trip a
portion of the BES.” The removal of this text from Requirement R1 makes it less clear whether the
standard applies to reclosing functions and protective functions used to supervise automatic or manual
closing of a circuit breaker to ensure the voltage magnitude and phase angle difference are within
specified tolerances. The drafting team also should consider whether additional specificity is required to
ensure applicability is clearly defined within the standard.
2. In the response to Question II.2.H, NERC staff notes that the word “than” should be changed to “then” in
the phrase “If the component no longer performs Protection System functions than...”
3. In the response to Question II.2.I, NERC staff recommends noting that “When a failure occurs in a
protection system, power system security may be compromised, and notification of the failure must be
conducted in accordance with relevant NERC standard(s).” The recommended text is included in the
Supplementary Reference Document and inclusion in the FAQ response provides consistency and
highlights obligations in other standards necessary for BES reliability.
4. In the response to Question III.1.A, NERC staff recommends noting that the present NERC Glossary
definition of Bulk Electric System will be revised in response to FERC Order No. 743.
5. In the response to Question III.3.A, NERC staff recommends a more generic reference to NERC UFLS
requirements in place of the reference to PRC-007-0, as PRC-007 will be retired pending FERC approval
of PRC-006-1.In the response to Question IV.1.A (third paragraph), NERC staff recommends changing
the phrase “that are certainly coming to the industry” to “may be coming to the industry” for consistency
with the change to the response to Question V.4.A. Both questions appear to address the same or similar
concerns.
41
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
FirstEnergy
No
Florida Municipal Power Agency
Yes
PSEG Companies ("Public
Service Enterprise Group
Companies")
Yes
Suggest that the section 5 - station DC supply have some specific examples added that would be acceptable
methods for verifying the “state of charge” as required by standard table 1-4.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove
“state of charge” from the activities.
MRO's NERC Standards Review
Subcommittee
No
Western Area Power
Administration
No
TransAlta Centralia Generation
Partnership
No
NextEra Energy
No
City of Austin DBA Austin Energy
PacifiCorp
Southern Company Transmission
Yes
1. Page 7, L. (“verify operation of the relay inputs ...”)
Comment ->> Clarification needed. Standard states that each input should be “picked up” or “turned on
and off”. Do you have to change states of the input contact(s) or can you just jumper positive to the
input(s) to verify that the microprocessor relay verifies this change of state?
42
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
2. Page 10, 4.E (“What does functional (or operational) trip test include?”)
Comment ->> The words “functional (or operational) trip test” are not in the Standard. Is this required? If
so, please clarify this in Standard. If not, please remove. (Reference comment regarding “verify all paths
of the control and trip circuits” on page 17 of standard.)
3. Page 18, 7. (Distributed UVLS and UFLS system.) and Page 19 8. (Centralized UVLS and UFLS system.)
Comment ->> Standard does not specify “distributed” or “centralized” UVLS and UFLS systems. Please
consider combining section 7 & 8, omitting items 7.C., 8.E., and omitting “distributed” and “centralized”
references on pages 18 and 19.
Response: Thank you for your comments.
The standard does explicitly require that auxiliary relays, lockout, and trip coils of interrupting devices be verified to have electrically operated every 6
years, and this is the only place in the standard that currently requires this sort of activity.
The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The
SDT considered your comments during this activity.
Clark Public Utilities
Yes
Provide answers to the following questions.
Does the completion of a battery ohm test or a battery performance test satisfy the verification requirements
for state of charge of the individual battery cells/units, battery continuity, battery terminal connection
resistance, and battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)?
Response: Thank you for your comments. The activities described do not satisfy all of the requirements (at the established intervals) listed in your
comment. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as
appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove “state of charge” from the activities.
Exelon
Yes
1. Clarify what kind of testing is required on lockout relays/86 devices. Specifically, whether functional testing
is adequate or if simple calibration, similar to protective relays, is all that is are required.
2. Clarify if protective relays that trip equipment (e.g., a condensate pump that would in turn cause a main
generator trip) are also included in the scope of this Standard.
3. Clarify if relays which result in generator run back, but do not trip the generator, are included in the scope
of this Standard.
Response: Thank you for your comments.
43
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
1. For lockout relays, the standard requires that they be electrically operated every 6 years, and that the trip path be verified every 12 year. No
calibration/etc is specified.
2. As described in FAQ III.2.A, protective relays which trip equipment within the plant which may eventually result in tripping of the generator, but do
not trip the generator (either directly or via a generator lockout relay) , are not included.
3. If the generator run back scheme is characterized as a Special Protection System within your region, these relays would be included as part of that
system (Section 4.2.6- Applicability of the draft Standard).
The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The
SDT considered your comments during this activity.
Manitoba Hydro
Yes
As previously stated, the maintenance requirements for batteries listed in Table 1-4 do not appear to be
consistent with example 1 in Section V, 1A of the FAQ. Specifically the FAQ does not mention the of the
individual battery cells/units, the battery continuity, the battery terminal connection resistance, the battery
internal cell-to-cell or unit-to-unit connection resistance, or the cell condition which are indicated as 18 month
interval tasks in table 1-4.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove
“state of charge” from the activities.
Dynegy Inc.
No
Oncor Electric Delivery Company
LLC
Yes
There is still confusion in Table 1-4 concerning the “Monitored Station dc supply.” The uncertainty is over
whither an Owner must have all seven (7) monitoring activities (Station dc supply voltage, State of charge of
the individual battery cell/units, Battery continuity of station battery, Cell-to-cell and battery terminal
resistance, Electrolyte level of all cells in station battery, Unintentional dc grounds, and Cell/unit internal
ohmic values of station battery) listed in the table or just one of them to take advantage of forgoing the
maximum maintenance interval for an activity and going to the 6 year maximum maintenance interval to verify
that the monitoring device is calibrated. A FAQ concerning this question would be beneficial to those who are
concerned that they must monitor all seven activities in order to take advantage of condition based
maintenance for the station dc supply. Also an explanation of how each of the 7 monitoring activities relates
to a specific station dc supply maintenance activity might be beneficial.
Response: Thank you for your comments. Table 1-4 has been further revised to address your concern (see Table 1-4(f)). The SDT decided to eliminate
the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The SDT considered your
comments during this activity. Table 1-4 has been revised to remove “state of charge” from the activities.
44
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
Ingleside Cogeneration LP
Indiana Municipal Power Agency
No
South Carolina Electric and Gas
No
Entergy Services
Yes
Section II.2.B references R4.3 which has been revised to R4.2.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Duke Energy
Yes
There are typographical errors on the FAQ Requirements Flowchart (should be R4.1.1 and R4.1.2 instead of
R4.4.1 and R4.4.2).
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Wisconsin Electric Power
Company
Yes
Table 1-4 requires an activity to verify the state of charge of battery cells. There are no possible options for
meeting this requirement listed in the FAQ document. Unlike other terms used in the standard, this term is
not mentioned or defined in the FAQ. To comply with this standard, the SDT needs to provide more
guidance. For example, for VLA batteries the measured specific gravity could indicate state of charge. For
VRLA batteries, it is not as clear how to determine state of charge, but possibly this can be determined by
monitoring the float current.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove
“state of charge” from the activities.
Independent Electricity System
Operator
No
American Electric Power
Yes
With such a complex standard as this, the FAQ and Supplementary Reference documents do aid the
Protection System owner in demystifying the requirements. But AEP holds strong doubt on how much weight
the documents carry during audits. It would be better to include them as an appendix in the actual standard,
but in a more compact version with the following modifications:
45
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
1. The section “Terms Used in PRC-005-2” is blank and should be removed as it adds no value.
2. Section I.1 and Section IV.3.G reference “condition-based” maintenance programs. However, no where
in the standard is the term “condition-based” used in reference to defining ones PSMP. The FAQ should
be revised to remove reference to a condition-based PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard Requirements and Table 1.
3. The second sentence to the response in Section I.1 appears to have a typographical error “... an entity
needs to and perform ONLY time-based...”.
Response: Thank you for your comments. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do
not belong as part of the standard. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
ITC
No
ISO New England Inc.
Yes
See response to Question 5 below.
Response: Thank you for your comments. Please see our response to your comments in Question 5.
Nebraska Public Power District
No
CenterPoint Energy
Yes
The need for an FAQ document, in addition to an extensive Supplementary Reference document, illustrates
the complexity and impracticality of the proposed Standard. CenterPoint Energy does not support the
development of an additional type of document, that is, the FAQ document. CenterPoint Energy recommends
eliminating the FAQ document and using only a Supplementary Reference” document. This would also
provide the benefit of not having contradictory information in the two documents.
Response: Thank you for your comments. The SDT believes that entities should be able to implement the standard without either the FAQ or
Supplementary Reference. However, the SDT is also convinced that many entities may find the supporting discussion/rationale useful, particularly to
assist them in implementing the standard in an efficient manner. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents
into the Supplementary Reference Document as appropriate.
American Transmission
Company
Yes
1. FAQ Protective Relays 2.D: The last sentence is not consistent with the discussions at the “March 2010,
Standard Drafting Team Meeting, Project 2007-17”. The understanding from that meeting was that the
relay settings would be verified that the “as left” settings were the same as the “as found” settings and that
the intent was not to verify the settings against a Master Record. Therefore the intent is that the tester will
46
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
verify that no setting changes were made as part of the testing process.
Please include this clarification with the language in the standard.
2. FAQ Group by Type of Maintenance Program 2.B: We agree with the use of either the in-service date
or the commissioning date to start the initial due date calculation for maintenance.
Please include this clarification with the language in the standard.
Response:
1. The intent is that the settings of the component be as specified at the conclusion of maintenance activities, whether those settings may have
“drifted” since the prior maintenance or whether changes were made as part of the testing process.
2. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part of the standard. The
SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The
SDT considered your comments during this activity.
Consumers Energy
No
Southern Company Generation
Yes
1. On Page 3, please revise the flow chart references to R4.4.1 and R4.4.2. Also, add (Attachment A) to the
“Performance Based” label.
2. On Page 7, Section I, correct the reference of R4.3 to R4.2.
3. Also, revise the last paragraph in Section I to the following: The entity should assure that the component
performance is acceptable at the conclusion of the maintenance activities or initiate resolution of any
indentified maintenance correctable issues.
4. On Page 7, Section J, correct the reference of R4.3 to R4.2.
5. On Page 10, Section D, a reference is made to “trip test” Table 1. Should this be Table 1-5? The exact
phrase “trip test” is not used in the standard. Should it be?
6. On Page 10, Section e, the phrase “functional (or operational) trip test” is not used in the standard –
should it be?
7. On Page 11, Section 5A, correct the reference of Table 1 to Table 1-4 in the Station Battery and
Emerging Technologies paragraph.
8. On Page 12, Section B, correct the reference of Table 1 to Table 1-4. (2X)
47
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
9. On Page 13, Section F, correct the reference of Table 1 to Table 1-4. (1X)
10. On Page 14, Section G, correct the reference of Table 1 to Table 1-4. (3X)
11. On Page 14, Section G, change the text “The first maintenance activity” to The capacity testing activity”.
12. On Page 14, Section G, change the text “The second maintenance activity”, to The internal ohmic
measurement activity”.
13. On Page 14, Section H, correct the reference of Table 1 to Table 1-4. (1X)
14. On Page 17, Section C, correct the reference of Table 1 to Table 1-5. (1X)
15. Please address what is meant by “Battery terminal connection resistance” on Page 14, Table 1-4 of the
standard.
Response: Thank you for your comments. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do
not belong as part of the standard. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
US Bureau of Reclamation
No Comment
Alliant Energy
No
LCRA Transmission Services
Corporation
Yes
MidAmerican Energy
Yes
The Frequently Asked Questions should have clear disclaimers indicating that nothing in the reference is
mandatory and enforceable.
Response: Thank you for your comments. NERC establishes that only the Standard is mandatory and enforceable, and Section F of the standard
introduces this (and the Supplementary Reference Document) as presenting supporting discussion. The SDT decided to eliminate the FAQ document
and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The introductory area of the Supplementary
Reference Document will be revised to address your concern.
Ameren
No
This document is helpful.
Xcel Energy
Yes
The changes in the standard and edit attempts on the FAQ have created some problems and confusion.
Examples; The new FAQ I.1 answer does not make sense “An entity needs to and perform ONLY time-based
48
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
. . .” FAQ II.1.A: Requirement R1 no longer contains the statement that “use voltage, current, or phase angle
to detect anomalies” so the answer to this FAQ is now out of synch with the standard. FAQ II.2.B –
“Restoration” is no longer in the PMSP and has been changed to “Restore” and R4.3 no longer exists. FAQ
II.2.I and II.2.J answers also references non-existent requirement R4.3. These are just some examples of
fidelity issues that have been created by the most recent edit of PRC-005-2 – we did not perform a review of
the entire document. The SDT should be commended for its efforts on the FAQ document as it is exceedingly
helpful and well written. However, it needs to be brought back into alignment with the Standard. It is
apparent that this fidelity check between the standard and the FAQ was not done prior to this posting. Finally,
it seems some FAQs would be warranted to help explain the intent of new requirements R1.5 and R4.2
especially in regards to non-quantifiable maintenance results such as battery visual inspection as well as to
provide examples of “other equivalent parameters” acceptance criteria for the various component types
included in the Protection System definition
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
49
Consideration of Comments on Protection System Maintenance [Project 2007-17]
5. If you have any other comments on this Standard that you have not already provided in response to the prior questions, please
provide them here.
Summary Consideration: Many commenters disagreed with Requirement R1, Part 1.5 which was added in the
previous draft; in response, the SDT removed Requirement R1, Part 1.5 from the standard. Commenters also
observed that Requirement R1, Part 1.4 was redundant with Requirement R2, and the SDT removed R2 in
response to these comments. Many commenters objected to 4.2.5.5 in the Applicability Section; the SDT removed
this clause.
Organization
Pepco Holding Inc & Affiliates
Yes or No
Question 5 Comment
Yes
1. What "specific statistical data" was used to validate that unmonitored communication systems are 24 times
more prone to failure than unmonitored protective relays? Comments were previously submitted that the 3
month interval for verifying unmonitored communication systems was much too short. The SDT declined to
change the interval and in their response stated: "The 3 month intervals are for unmonitored equipment and
are based on experience of the relaying industry represented by the SDT, the SPCTF and review of IEEE
PSRC work. Relay communications using power line carrier or leased audio tone circuits are prone to channel
failures and are proven to be less reliable than protective relays." The 3 month interval is very burdensome
and our experience does not appear to justify. A longer interval should be reconsidered.
Response: Thank you for your comments. The SDT reasserts that the 3 month intervals are for unmonitored equipment and are based on experience
of the relaying industry represented by the SDT, the SPCTF and review of IEEE PSRC work. Relay communications using power line carrier or leased
audio tone circuits are prone to channel failures and are proven to be less reliable than protective relays. If an entity’s experience is that these
components require less-frequent maintenance, a performance-based program in accordance with R3 and Attachment A is an option.
Pacific Northwest Small Public
Power Utility Comment Group
No
Tennessee Valley Authority
Yes
1R4 - “Identification of the resolution” and “Initiation of the resolution” are very distinct activities. In other
places in this standard the requirement is for the resolution to be initiated, that is identified in a corrective
maintenance work order, “identification of a resolution” requires technical expertise and can be difficult to
track and might change over time for a particular problem.
Proposed Change: Change “identification” to “initiation” in phrase “including identification of the resolution...”.
Overall: NERC is making significant changes to this sizeable standard and only allowing minimum comment
period. While this is a good standard that has clearly taken many hours to develop, we are primarily voting
50
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
“NO” because of the hurried fashion it is being commented, voted, and reviewed.
Response: Thank you for your comments. Requirement R4 has been revised.
Northeast Power Coordinating
Council
Yes
1. In general, the standard is overly prescriptive and complex. It should not be necessary for a standard at
this level to be as detailed and complex as this standard is. Entities working with manufacturers, and
knowledge gained from experience can develop adequate maintenance and testing programs.
2. Why are “Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation)...” not included? The output contacts from these devices
are oftentimes connected in tripping or control circuits to isolate problem equipment.
3. Due to the critical nature of the trip coil, it must be maintained more frequently if it is not monitored. Trip
coils are also considered in the standard as being part of the control circuitry. Table 1-5 has a row
labeled “Unmonitored Control circuitry associated with protective functions”, which would include trip coils,
has a “Maximum Maintenance Interval” of “12 Calendar Years”. Any control circuit could fail at any time,
but an unmonitored control circuit could fail, and remain undetected for years with the times specified in
the Table (it might only be 6 years if I understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure, then the system must be
operated in real time assuming that that breaker will not trip for a fault or an event, and backup facilities
would be called upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker unable to trip),
instead of one line tripping, you might have many more lines deloaded or tripped because of a bus having
to be cleared because of a breaker failure initiation. The bulk electric system would have to be operated
to handle this contingency.
4. In reference to the FAQ document, Section 5 on Station dc Supply, Question K, clarification is needed
with respect to dc supplies for communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation, would the standard apply to
these batteries or not?
5. To define terms only as they are used in PRC-005-2 is inviting confusion. Although they may be unique
to PRC-005-2, some or all of them may be used in future standards, some already may be used in
existing standards, and may or may not be deliberately defined. Consistency must be maintained, not
only for administrative purposes, but for effective technical communications as well.
6. What is the definition of “Maintenance” as used in the table column “Maximum Maintenance Interval”?
Maintenance can range from cleaning a relay cover to a full calibration of a relay.
7. A control circuit is not a component, it is made up of components.
51
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
8. Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify calibration tolerances or other
equivalent parameters...” means, and may be subject to different interpretations by entities and
compliance enforcement personnel.
9. In the Implementation plan for Requirement R1, recommend changing “six” to fifteen. This change would
restore the 3-month time difference that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require regulatory approval. It will ensure
equity for those entities located in jurisdictions that do not require regulatory approval, as is the case in
Ontario.
10. The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It seems to continue to the next
page to a new box. There are multiple activities without clear delineation.
11. Regarding station service transformers, Item 4.2.5.5 under Applicability should be deleted. The purpose
of this standard is to protect the BES by clearing generator, generator bus faults (or other electrical
anomalies associated with the generator) from the BES. Having this standard apply to generator station
service transformers, that have no direct connection to the BES, does meet this criteria. The FAQs
(III.2.A) discuss how the loss of a station service transformer could cause the loss of a generating unit,
but this is not the purpose of PRC-005. Using this logic than any system or device in the power plant that
could cause a loss of generation should also be included. This is beyond the scope of the NERC
standards.
12. The Drafting Team must respond to the following concerns raised in the FERC NOPR, Docket No. RM105-000, Interpretation of Protection System Reliability Standard, December 16, 2010) to “prevent a gap in
reliability”.
a. Any component that detects any quantity needed to take an action, or that initiates any control
action (initial tripping, reclosing, lockout, etc.) affecting the reliability of the Bulk-Power System
should be included as a component of a Protection System, as well as any component or device
that is designed to detect defective lines or apparatuses or other power system conditions of an
abnormal or dangerous nature and to initiate appropriate control circuit actions.
b. The exclusion of auxiliary relays will result in a gap in the maintenance and testing of Protection
Systems affecting the reliability of the Bulk-Power System.
c.
Excluding the maintenance and testing of reclosing relays will result in a gap in the maintenance
and testing of relays affecting the reliability of the Bulk-Power System.
d. Not establishing the specific requirements relative to the scope and/or methods for a
maintenance and testing program for the DC control circuitry that is necessary to ensure proper
52
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
operation of the Protection System, including voltage and continuity.
Response: Thank you for your comments.
1. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently monitored for
compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that minimum activities also need be
prescribed. If an entity’s experience is that components require less-frequent maintenance, a performance-based program in accordance with
Requirement R3 and Attachment A is an option.
2. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection System definition.
Also, there is currently no technical basis for the maintenance of the devices which respond to non-electrical quantities on which to base
mandatory standards related either to activities or intervals. Absent such a technical basis, we are currently unable to establish mandatory
requirements, but may do so in the future if such a technical basis becomes available.
3. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year interval. As a regional
entity, you can specify Supplementary regional requirements to maintain these devices more frequently if you desire.
4. With respect to dc supply associated only with communications systems, we prescribe, within Table 1-2, that the communications system must be
verified as functional every 3 months, unless the functionality is verified by monitoring. The specific station dc supply requirements (Table 1-4) do
not apply to the dc supply associated only with communications systems. The SDT has decided to eliminate the FAQ and incorporate topics and
discussion from the FAQ within the Supplementary Reference Document. Your comments will be considered within that activity.
5. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms, either now or in the
future, may not be consistent with the terms as used here. They are defined only for clarify within this standard. The SDT will confirm with NERC
staff that this approach is acceptable.
6. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are specified in the Activities
column. The term is capitalized in the column title in conformance with normal editorial practice as a title, rather than as a definition
7. For purposes of this standard, the control circuit IS defined as one component type.
8. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary. Therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
9. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making it consistent with
the remainder of the Implementation Plan.
10. Table 1-4 has been further modified for clarity
11. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
53
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
12. The FERC NOPR is a notice-of-proposed-rulemaking and is not yet a directive. At such a time as a directive is published, NERC will take the
necessary actions to address it.
Platte River Power Authority
System Maintenance
Yes
1. Please clarify what is required by R1.5: Identify calibration tolerances or other equivalent parameters for
each Protection System component type that establish acceptable parameters for the conclusion of
maintenance activities required. Is the intent a brief summary for each component type in the PSMP that
would cover all equipment within that component type, or is it a detailed list of each piece of equipment
within each component type?
2. The inclusion of dated check-off lists in M4 provides much needed clarity to the list of evidence.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address
various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document,
Section 8 for a discussion of this.
2. Thank you for your support.
Electric Market Policy
Yes
1. The draft to PRC-005-2 contains defined terms that upon approval will remain with the standard rather than
being moved to the Glossary of Terms. These terms when used in the Requirements are not designated in
any way (e.g., capitalization, bold, etc.) to point the reader back to the in-standard definition.
2. Need to explicitly state the intent of the SDT to either (1) use the newly defined term “Protection System
(modification)” only in this standard (PRC-005-2) or (2) replace the existing definition of the existing term in
the “Glossary of Terms Used in NERC Reliability Standards” with the proposed definition for the existing term.
3. The language used in Footnote 1 on Attachment A does not agree with the definition of Countable events
provided elsewhere in the draft standard. Suggest footnote be removed.
4. Requirement R1.5 uses the phrase “or other equivalent parameters” which is confusing. Suggest replacing
with “or acceptance criteria.” Requirement R1.5 should read as follows: “Identify calibration program.” The
currently proposed language focuses on specific calibration tolerances and acceptance parameters. These
tolerances are developed on a per device, per location basis and would be captured at a procedural level, not
a program level. To add this at a program level would only complicate the program and would not lend any
improvement to the reliability of the bulk electric system. We recommend maintaining a general calibration
requirement, similar to what is stated above, for an entity to develop their calibration program.
5. Requirement 2 Component should be replaced with Component Type. Creating a program to monitor the
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equipment at this level of equipment would not add any value to the bulk electric system as all components
should already be included in component type maintenance tasks. Recommend removing the definition of
Component.
6. The requirement to address “monitoring attributes” in Requirement 2 for time based maintenance program
is unclear, onerous and unnecessary for a reliable protection system program.
7. Requirement (R4) should identify correctible maintenance issues not the resolution of these issues. The
language in R4.2 should strike correcting maintenance issues related to R1.5 and instead state: Any
maintenance correctible issues found during the maintenance activity should be identified”
8. Table 1.2 change time frame from 3 months to 3 years.
Response: Thank you for your comments.
1. The standard capitalizes defined terms only when they refer to terms which are (or will be) in the NERC Glossary of Terms. Terms will generically
be capitalized when appearing at the beginning of a sentence or within a title, in accordance with common editorial practice.
2. The statement of the definition has been revised in the standard as “NERC Board of Trustees Approved Definition”, but will remain in the posted
draft standard until it is successfully balloted for the convenience of stakeholders.
3. The footnote has been removed.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address
various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document,
Section 8 for a discussion of this.
5. The SDT disagrees; monitoring attributes must be present on the individual components as actually installed, not to the overall component type.
6. The SDT believes that the verifiable presence of the monitoring attributes on the individual components as installed is a necessary element of
using the extended maintenance intervals that result from the monitoring. If you consistently use specific monitoring attributes on all components
within a group, they may be able to address these attributes on a global basis. If an entity does not wish to document these attributes, they are
free to apply the maintenance intervals and activities specified for the unmonitored components.
7. Requirement R4 has been revised. The SDT believes it important that the entity initiate resolution of maintenance correctable issues, in addition to
simply identifying them.
8. The SDT believes that the 3-month interval is proper for verification of the functionality of unmonitored communications systems.
Bonneville Power Administration
Yes
Some of the maintenance tasks need to be defined:
1. The state of charge of each individual cell may need to be better defined. There are means to verify the
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state of charge of the entire bank, but not each individual cell.
2. Battery continuity needs to be defined.- There is no mention to what the limits are for the "other equivalent
parameters" when performing maintenance activities, just that they need to be identified. There are a
large number of battery models which creates a large contrast of parameters, which cannot be grouped
together. It is also difficult to get baseline values for older battery models which could result in moving
baselines until they become more accurate as the database is populated.
3. If corrective actions are required, is there a maximum allowable duration for when they need to be
resolved?
4. The maximum allowable maintenance for station batteries (impedance testing and performance/service
testing) is too frequent and suggest an extension or alternative testing methods to stay in compliance.
The frequency with which BPA performs the 18 month maintenance tasks as prescribed in the standard
are on a 24 month interval along with visual inspections and voltage measurements monthly.BPA has
seen success with this maintenance program with the ability to identify suspect cells or entire banks with
adequate time to perform corrective actions such as repairs or replacements.
5. BPA also does not perform routine capacity testing, this is an as required maintenance task to
confirm/validate our other test results if needed. BPA would like to see clarification for these issues before
we can fully support this standard.
Response: Thank you for your comments.
1. Table 1-4 has been revised to remove “state of charge” from the activities.
2. This is thoroughly discussed in Section 15.4 of the Supplementary Reference Document.
3. No. The SDT appreciates that some corrective actions for maintenance correctable issues may take an extended period of time to complete, and
has therefore not included completion of the corrective actions within PRC-005-2.
4. The SDT believes that the 18-month interval is proper for these activities.
5. For vented lead-acid and valve-regulated lead batteries, alternative activities are specified if desired instead of capacity tests. If Ni-Cad batteries
are used, capacity tests are required.
Santee Cooper
No
We do not agree with the addition of Requirements 1.5 and 4.2 without work on or review by the Power
System Maintenance and Testing Drafting Team. While some maintenance activities on some component
types (such as calibration testing of electromechanical relays) translate inherently well into these
requirements, the requirements of tolerances and documentation do not fit as well to all maintenance
activities on other types of equipment considered part of the protective system. These requirements need to
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be worked on through the drafting team to make them viable and effective for all protective system
component types.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
NERC Staff
Yes
1. Commissioning (Initial) Testing: During development of PRC-005-2, NERC staff has observed a trend in
system disturbances involving Protection System problems that should have been identified and corrected
during commissioning (initial) testing. While NERC staff recognizes that the addition of commissioning
testing may be unrealistic at this stage in the standard drafting process, we want to emphasize its
importance. If the SDT chooses to leave commissioning testing out at this juncture, we plan to pursue other
avenues to ensure its eventual inclusion through a separate standards project.
NERC staff agrees with the SDT’s opinion that without commissioning testing, a registered entity
responsible for compliance with this standard cannot provide proof of its interval testing period as required
by the standard. As soon as the entity puts the protective scheme into service, time “0” for interval testing
begins. The next testing interval would be some specific number of years in the future from time “0.
”An entity’s failure to properly commission new protection system equipment has caused or exacerbated
several recent events, greatly impacting BPS reliability. The following are examples of errors that were not
detected during commissioning. These undetected errors were observed by NERC staff during event
analysis and investigation activities:
oFailure to apply correct relay settings. This has occurred repeatedly and has been due to improper
procedures, poor document control, misapplication or miscalibration of the relay, or a combination of
the above.
oFailure to install the proper CT or PT ratio occurred due to poor document control practices and
resulted in an undesired protection system response after the equipment was placed in service.
oFailure to conduct a functional test of new control circuits to the schematic diagram resulted in an
undesired protection system response after equipment was placed in service.
oAn incorrect CT ratio was not detected during commissioning, and the equipment was subsequently
placed in service. Because in-service testing was not performed, the error remained undetected until
the relay misoperated during a fault.
Many of the above conditions can remain undetected for extended periods, until they are revealed by a
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relay misoperation during fault or heavy load conditions. The affects resulting from these cases could have
been prevented with proper commissioning testing. We believe that by requiring commissioning testing for
new protection system equipment, the reliability of BPS would be improved.
2. Requirement 2:In Requirement 2, it is unclear what is meant by “shall verify those components possess
the monitoring attributes identified in Tables 1-1 through 1-5 in its PSMP” because the use of terms in the
Requirement is not consistent with the column headings used in Tables 1-1 through 1-5. It also is not
clear that components need not possess all attributes; rather, they must possess all attributes consistent
with the Maximum Maintenance Interval specified in an entity’s PSMP.
NERC staff recommends revising R2 to provide additional clarity as follows:”Each Transmission Owner,
Generator Owner, and Distribution Provider that uses maintenance intervals for monitored Protection
Systems described in Tables 1-1 through 1-5, shall verify those components possess the monitoring
attributes Component Attributes identified in the first column of Tables 1-1 through 1-5 consistent with the
Maximum Maintenance Interval specified in its PSMP.”
Response: Thank you for your comments.
1. Thank you for your comments.
2. Requirement R2 of the standard has been modified as you suggested.
FirstEnergy
Yes
REQUIREMENTS
1. Requirement R1 - Subpart 1.5 - We do not support this subpart for the following reasons and offer the
following suggestions:
To satisfy R1.5, a calibration tolerance or other equivalent parameter would have to be established for each
item included in the definition. Many devices which may have similar functionality may also have different
performance criteria that would preclude the use of a "one size fits all" calibration tolerance. Many of these
criteria are provided by the manufacturer and often vary by manufacturer for a similar device. It would be very
difficult to specify in your program all of the calibration tolerances or other equivalent parameters associated
with the protection system components. Therefore, we suggest the team delete Subpart 1.5 of Req. R1, and
revise Subpart 4.2 of Req. R4 to read: "Initiate resolution of any identified maintenance correctable issues at
the conclusion of maintenance activities for Protection System components."
IMPLEMENTATION PLAN
2. On pg. 2 of the implementation plan, under "Retirement of Existing Standards", the statement "The
existing standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired upon regulatory
approval of PRC-005-2" is not accurate. Since the new PRC-005-2 standard allows for at least 12 months
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to become compliant with Requirement R1 - establish a Protection System Maintenance Program (PSMP)
-the existing standards are still effective during this time. Additionally, we have concerns with the
"General Considerations" describing protocols for compliance audits conducted during the allowed 12
month development period of the PSMP and that entities could specify for "each component type"
whether maintenance of that component is being performed according to its maintenance program under
the "retired" PRC maintenance standards or the new PRC-005-2 standard. In our view, this creates a
level of compliance complexity for both the Registered Entity and Regional Entity that should be avoided
in the transition to PRC-005-2. FirstEnergy proposes that the Implementation Plan state that the existing
standards remain in effect for one year past applicable approval (NERC Board or Regulatory) and that
they are retired coincident with the one-year transition to Requirement R1 of PRC-005-2 which would
establish all Registered Entities having a new PSMP per the expectations of PRC-005-2. At that time all
entities would be required to be under the new PRC-005-2 standard and begin implementing their PSMP
per the phased-in Implementation Plan for the remaining requirements. To summarize, per our above
discussion we propose the team perform the following:1. Revise the Implementation Plan section titled
"Retirement of Existing Standards" section to read as follows: "The existing Standards PRC-005-1, PRC008-0, PRC-011-0 and PRC-017-0 shall be retired on the first day of the first calendar quarter twelve
months following applicable regulatory approvals, or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter 12 months following the Board of Trustees
adoption"2. Remove the entire "General Considerations" section from the Implementation Plan.
3. The bulleted item under the section titled "Implementation plan for R1" has a discrepancy in the time
allowed to implement R1 between entities applicable to regulatory approval of the standard versus those
in jurisdictions where no regulatory approval is needed and base their adherence per the Board of
Trustee adoption. Please revise to reflect a 12 month transition period for each.
DEFINITIONS
4. Maintenance Correctable Issue - This is a maintenance standard and this concept gets into the long term
repair activities. Is this really appropriate in this standard? If NERC feels repairing is critical to BES
reliability, then they should probably initiate a standard in that area.
5. Component - Regarding the phrase "local zone of protection", why is this in quotes? Is there a narrow
definition for this? If so, this term should be defined also.
DATA RETENTION SECTION
6. 1.3 Regarding the data retention for Req. R3 and R4, it is not practical to keep potentially 24 years of data
for components that are maintained every 12 years. We suggest rewording this to "For R3 and R4,
Transmission Owner, Generator Owner, and Distribution Provider shall each keep documentation of the most
recent performances of each distinct maintenance activity for the Protection System components, or to the
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previous scheduled audit date, whichever is longer".
7. ATTACHMENT A - FOOTNOTE 1This footnote regarding countable events needs to be revised to match the
definition of countable events found at the beginning of the standard.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. The SDT had concluded that Requirement R2 is redundant with Requirement R1, Part 1.4, and has deleted Requirement R2 (together with the
associated Measure and VSL).
3. The Implementation Plan for Requirement R1 has been modified as you suggest.
4. The SDT believes that the activities necessary to restore a Protection System component to proper service is an essential part of the PSMP.
Please note that the related requirements only address initiation of the corrective actions, not completion, in deference to the extended period of
time that some of these activities may take.
5. The quotes have been removed from the definition of component. However, the SDT believes that this term is a commonly-understood term within
the industry.
6. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding one to validate that entities have been in compliance since the last
audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data retention in the posted standard to establish
this level of documentation. This seems to be consistent with the current practices of several Regional Entities.
7. This footnote has been removed.
Florida Municipal Power Agency
Yes
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC-008/011 as
being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other protection system
components, e.g., communications (probably not applicable), voltage and current sensing devices (e.g.,
instrument transformers), Station DC supply, control circuitry. What's key about this is that these
components are all part of distribution system protection, so, these activities would not be covered by
other BES protection system maintenance and testing. I'm sure we are testing batteries and the like, but,
we are probably not testing battery chargers and control circuitry, and, in many cases distribution circuits
are such that it is very difficult, if not impossible, to test control circuitry to the trip coil of the breaker
without causing an outage of the customers on that distribution circuit. There is no real reliability need for
this either. Unlike Transmission and Generation Protection Systems which are needed to clear a fault and
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may only have one or two back-up systems, there are thousands and thousands of UFLS relays and if
one fails to operate, it will not be noticeable to the event. It does make sense to test the relays themselves
in part to ensure that the regio0nsl UFLS program is being met, but, to test the other protection system
components is not worthwhile. Note that DC Supplies and most of the control circuitry of distribution lines
are "tested" frequently by distribution circuits clearing faults such as animals, vegetation blow-ins,
lightning, etc., on distribution circuits, reducing the value of testing to just about null. However, this version
is better than prior versions because it essentially requires the entity to determine it's own period of
maintenance and testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of "transmission
Protection System" and should state: "Protection Systems applied on, or designed to provide protection
for a BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes non-electrical
protection (e.g., sudden pressure relays) and auxiliary relays. Because the definition of Protection
System (recently approved) does not clearly exclude "non-electrical" protection, the Applicability section
should. For instance, a vibration monitor, steam pressure, etc. protection of generators, sudden pressure
protection of transformers, etc. should not be included in the standard. An alternative is to change the
definition of Protection System to make sure it only includes electrical
4. Table 1-4 requires a comparison of measured battery internal ohmic value to battery baseline. Battery
manufacturers typically do not provide this value and one manufacturer states that the baseline test are to
be performed after the battery has been in regular float service for 90 days. It is unclear how to comply
with the requirement for the initial 90 days. Additionally, we would recommend that this requirement be
modified to permit an entity to establish a “baseline” value based on statistical analysis of multiple test
results specific to a given battery manufacturer/model. Several commenters previously expressed their
concerns with performing capacity tests. While this may just be an entity’s preference, allowing an entity
to establish a baseline at some point beyond the initial installation period would give entities the option of
using the internal resistance test in lieu of a capacity test.
5. Small entities with only one or two BES substations may not have enough components to take advantage
of the expanded maintenance intervals afforded by a performance-based maintenance program.
Aggregating these components across different entities doesn’t seem too logical considering the
variations at the sub-component level (wire gauge, installation conditions, etc.)
6. Trip circuits are interconnected to perform various functions. Testing a trip path may involve disabling
other features (i.e. breaker failure or reclosing) not directly a part of the test being performed. Temporary
modifications made for testing introduce a chance to accidentally leave functions disabled, contacts
shorted, jumpers lifted, etc. after testing has been completed. Trip coils and cable runs from panels to
breaker can be made to meet the requirements for monitored components. The only portions of the
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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circuitry where this may not be the case is in the inter- and intra-panel wiring. Because such portions of
the circuitry have no moving parts and are located inside a control house, the exposure is negligible and
should not be covered by the requirements. Entities will be at increased compliance risk as they struggle
to properly document the testing of all parallel tripping paths. The interconnected nature of tripping circuits
will make it difficult to count the number of circuits consistently for the purpose of calculating a VSL.
Response: Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained relative to similar
activities for Protection Systems in general. Regardless, without proper functioning of these component types, UFLS and UVLS will not respond
as expected, and will therefore degrade BES system reliability, particularly during the stressed system conditions for which UFLS and UVLS are
installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and UVLS from maintenance activities relate to the interrupting device
trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC-005-2
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees and will soon be
filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As for auxiliary relays, the interpretation
to which you refer states that they are not explicitly included, but are included to the degree that an entity’s Protection System control circuitry
addresses them (which has been identified as a reliability gap), and are being added to PRC-005-2 to resolve that gap.
4. Typical baseline values for various types of lead-acid batteries can be obtained from the test equipment manufacturer, perhaps the battery vendor,
and perhaps other sources for batteries that are already in service. For new batteries, the initial battery baseline ohmic values should be measured
upon installation and used for trending.
5. Entities are not required to use performance-based maintenance programs. Requirement R3 and Attachment A are provided for the use of entities
that can (and desire to) avail themselves of this approach.
6. The requirement relative to control circuitry does not explicitly require trip or functional testing of the entire path; it requires that entities verify all
paths without specifying the method of doing so. Please see Section 15.5 of the Supplementary Reference Document for a detailed discussion.
PSEG Companies ("Public
Service Enterprise Group
Companies")
Yes
1. The facilities listed in 4.2.5.5 include protection systems for “system connected” station service
transformers associated with generators that are part of the BES. If a station service transformer is
connected to a non BES bus then it would still fall under the PRC5 applicability requirements as written.
The FAQs discuss relays associated with station auxiliary loads as not included in the program
requirements. The non BES connected transformers should be included in that same category of
equipment.
2.
From the FAQ’s - “Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel
handling equipment, etc., need not be included in the program even if the loss of the those loads could
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result in a trip of the generating unit. Furthermore, relays which provide protection to secondary unit
substation (SUS) or low switchgear transformers and relays protecting other downstream plant electrical
distribution system components are not included in the scope of this program even if a trip of these
devices might eventually result in a trip of the generating unit.” Suggest the following added details be
considered to be consistent with intent of BES connected facilities.
Revise Description 4.2.5.5 as follows: “Protection systems for BES system connected station service
transformers connected for generators that are part of the BES”.
3. With respect to DC supply systems (batteries, chargers),the implementation plan is too aggressive.
Some battery checks will have to be done on a 3 month interval, and entities will be required to be
compliant with this new frequency in 1 Calendar year. This timeframe is unreasonable and needs to be
pushed back to at least 2 years.
4. PSEG is also asking for clarification to the Supplementary reference document: On page 4, section 2.3 it
states that the standard is designed to ONLY include “relays that detect a fault on the BES and take
action in response to that fault”. If PSEG is interpreting this correctly, this is a massive shift from the
existing PRC-005-1 standard. The existing PRC-005-1 includes all distribution relays that trip a BES
breaker to be part of the scope. In this revision, PRC-005-2 would exclude those distribution relays if they
are designed to act for faults on the distribution system. PSEG would fully support this interpretation.
PSEG would like this clarified and confirmed. This is very important.
Response: Thank you for your comments.
1. The Applicability of the draft Standard had been revised to remove “system-connected station service transformers”.
2. The FAQs have been merged into the Supplementary Reference Document; this discussion has been revised.
3. The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
4. Section 2.3 of the Supplementary Reference Document has been extensively revised, and the sentence to which you refer is no longer present. As
for your comment, “The existing PRC-005-1 includes all distribution relays that trip a BES breaker to be part of the scope,” the SDT believes that
this is an element of a Regional practice regarding PRC-005-1, and entities should expect to comply with PRC-005 as established within the NERC
Standard and further defined by Regional practice.
MRO's NERC Standards Review
Subcommittee
Yes
1. In the Purpose statement delete “affecting” and replace it with “protecting”. The purpose of the standard
deals with systems that protect the BES.
2. In sections R1 and R4.2.1 delete “applied on” as unneeded and potentially confusing. The goal is to
cover Protection Systems designed to protect the BES.
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3. The NSRS believes that Article 1.4 needs to be deleted from the standard. It is redundant and serves not
purpose.
4. The NSRS believes that Article 1.5 needs to be deleted from the standard. There is a major concern on
what an “acceptable parameter” is and how it would be interpreted by the Regional Entities.
5. The NSRS believes that Article 4.2 needs to be deleted from the standard. There is no need for this
article if Article 1.5 is deleted.
6. Section 4.2 Applicable Facilities:
We are concerned with this paragraph being interpreted differently by the various regions and thereby
causing a large increase in scope for Distribution Provider protection systems beyond the reach of UFLS
or UVLS.4.2.1 Protection Systems applied on, or designed to provide protection for, the BES.
The description is vague and open for different interpretations for what is “applied on” or “designed to
provide protection”. According to the November 17, 2010 Draft Supplementary Reference page 4, the
Standard will not apply to sub-transmission and distribution circuits, but will apply to any Protection
System that is designed to detect a fault on the BES and take action in response to the fault. The
Standard Drafting Team does not feel that Protection Systems designed to protect distribution substation
equipment are included in the scope of this standard; however, this will be impacted by the Regional
Entity interpretations of ‘protecting” the BES. Most distribution protection systems will not react to a fault
on the BES, but are caught up in the interpretation due to tripping a breaker(s) on the BES.
7. Section F Supplementary Reference Documents: The references listed in this section refer to 2009 dates
and do not match with the 2010 reference documents supplied for comment.
8. Table 1-4 Component Type Station dc Supply: o “Any dc supply for a UFLS or UVLS system” - This
should not tied to the same testing interval as control circuits. The dc supply system is significantly
different from control circuits and should have a maximum maintenance period as other dc supplies do.
9. Replace the words “perform as designed” on page 14 of Table 1-4 with “operate within defined
tolerances.”
10. Table 1-5 Component Type Control Circuitry:
a. This table allows for unmonitored trip coils for UFLS or UVLS breakers to have “no periodic
maintenance”. “Unmonitored control circuitry associated with protective functions” should also
have an exclusion for UFLS and UVLS circuitry that would allow for “no periodic maintenance”.
b. There is a concern that requiring the electrical testing and maintenance of Electromechanical trip
or Auxiliary devices will force entire bus outages to be scheduled, which will compromise the BES
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reliability more by forcing utilities across the US to unnecessarily take multiple non-faulted BES
elements out of service. Such testing is also likely to introduce human error that will cause
outages such as items outlined in the NERC lessons learned” and therefore such testing will
result in more outages than actual failures.
Response: Thank you for your comments.
1. The “Purpose” is defined by the SAR.
2. Requirement R1 and Requirement R4, Part 4.2.1 have been modified as you suggested.
3. The SDT disagrees; Requirement R1, Part 1.4 supports Requirement R1, Part 1.2, and seems necessary to assure that entities have appropriately
applied the longer intervals associated with monitored components.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. Please see Supplementary Reference Document, Section for a discussion of this. The
associated VSL has also been revised.
5. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
6. Applicability 4.2.1 has been revised to remove ‘applied on”. The SDT believes that this addresses your concern. Applicability 4.2.2 and 4.2.3,
respectively, address UFLS and UVLS specifically, and are not related to Applicability 4.2.1. The Supplementary Reference Document has been
revised to clarify.
7. The date in Clause F of the standard related to the Supplementary Reference Document has been revised.
8. The SDT disagrees. Station dc supply for UFLS/UFLS only is limited in its impact, and the SDT believes that using the same intervals as for the
related control circuits.
9. “Tolerances” does not fully describe the parameters for maintenance of station dc supply; “perform as designed” is far more inclusive.
10. a. The SDT intends that tripping of the interrupting device for UFLS/UVLS is not required, but that the other portions of the dc control circuitry still
shall be maintained. See Section 15.3 of the Supplementary Reference Document.
b. The SDT believes that mechanical solenoid-operated devices share performance attributes (and failure modes) with electromechanical relays
and need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these
devices supports those intervals
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Western Area Power
Administration
No
TransAlta Centralia Generation
Partnership
No
NextEra Energy
Yes
Question 5 Comment
The draft standard is too prescriptive.
1. Requirement R1, Part 1.5 would be overwhelming if approved. Requirement R1, Part 1.5 should be
deleted.
2. Requirement R4, Part 4.2 phrase "established in accordance with Requirement R1, Part 1.5" should be
deleted. The standard without these additional requirements would be sufficient to establish that the
Protection System is maintained and protects the BES.
3. Table 1-2 Component Type Communications Systems Maximum Maintenance Interval of 3 Calendar
Months to verify that the communications system is functional for any unmonitored communications
system is unyielding. Most communication failures are caused by power supply failures which Next Era
does monitor. Based on experience and monitoring of communication power supplies, 12 calendar
months would be adequate. The maximum maintenance interval should be changed from 3 calendar
months to 12 calendar months.
4. Table 1-4, Component Type Station dc Supply Maximum Maintenance Interval of 3 Calendar Months to
inspect electrolyte levels on “Any unmonitored station dc supply not having the monitoring attributes of a
category below. (excluding UFLS and UVLS)” is too stringent. Verifying battery charger float voltage
every 18 calendar months is sufficient to prevent excessive gassing and water loss of battery cells. The
maximum maintenance interval should be changed from 3 calendar months to 6 calendar months.
5. Table 1-4, Component Type Station dc Supply Maximum Maintenance Interval of 3 Calendar Months to
measure the internal ohmic values on “Unmonitored Station dc supply with Valve Regulated Lead-Acid
(VRLA) batteries that does not have the monitoring attributes of a category below. (excluding UFLS and
UVLS)” is too stringent. With the standard’s requirement to verify the float voltage every 18 calendar
months, measuring the internal ohmic values every 6 calendar months would be adequate. The
maximum maintenance interval should be changed from 3 calendar months to 6 calendar months.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
3. The activity to which you refer is an inspection-based activity based on overall functionality, and addresses functionality of various
communications technologies. If an entity monitors the power supply (as suggested), doing so addresses one portion of the functionality, but
does not address channel integrity, etc.
4. The SDT disagrees, and believes that the specified activities, at the specified intervals, are appropriate.
5. Table 1-4(b) has been revised as you suggested.
City of Austin DBA Austin Energy
Yes
1. The Requirement R1.5. is vague and the intent is not well understood. We recommend it be rewritten to
clarify the intent.
2. In the Requirement R2. the phrase “... shall verify those components possess the monitoring attributes ...”
is too vague and not easily understandable. We recommend this requirement be rewritten.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. The SDT had concluded that Requirement R2 is redundant with Requirement R1, Part 1.4, and has deleted Requirement R2 (together with the
associated Measure and VSL).
PacifiCorp
Southern Company Transmission
Yes
1. Page 5, 4.2. (“or initiate resolution”)
Comment ->> Standard does not specify to “follow through” to completion. Is record of completion
required?
2. Page 5, 1.5. (1.5. Identify calibration tolerances or other equivalent parameters for each Protection
System component type that establish acceptable parameters for the conclusion of maintenance
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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Yes or No
Question 5 Comment
activities.)
Comment ->> This is too vague, broad, general and all encompassing. For example, what is the
calibration tolerance for “control circuitry” which is made up of many things such as wiring, auxiliary
relays, trip coils, etc. We currently have calibration tolerances on electromechanical relays but not on all
components of a protection system (communications systems, voltage and current sensing devices,
station dc supply, control circuitry). To try to identify calibration tolerances or other equivalent parameters
for each of these components would be extremely difficult and time consuming. Clarification is needed on
what components or parts of components require calibration tolerances. Another option is to remove this
requirement.
3. Page 5, 4.5. (4.2. Either verify that the components are within the acceptable parameters established in
accordance with Requirement R1, Part 1.5 at the conclusion of the maintenance activities, or initiate
resolution of any identified maintenance correctable issues.)Comment ->>
See comments above on 1.5. Clarification is needed on what is required to verify that the components
are within acceptable parameters. We feel it should be adequate to provide a simple way to verify this
requirement such as to include this in our maintenance procedure (equipment is to be left within
tolerance), provide closed work order, show “checked” check box, provide a simple statement that this
was completed, or etc. We feel that having to provide detailed data such as “as found” / “as left” values is
too complicated and time consuming. Please clarify or consider removing this requirement.
4. Page 6, M.4. (“and initiated resolution”)
Comment ->> Standard does not specify to “follow through” to completion. Is record of completion
required?
5. Page 10, F.1 (July 2009) & F.2 (DRAFT 1.0 - June 2009)
Comment ->> Need new dates and draft number.
6. Page 11 (For microprocessor relays, verify operation of the relay inputs and outputs that are essential ...)
Comment ->> Does this require changing the state of the input contacts or can you just jumper voltage to
the inputs and verify that the microprocessor relays acknowledged the change?
7. Page 17 (“Verify electrical operation(1)of EM trip and auxiliary devices(2).”)
Comment ->> (1) Is it required to verify that trip and auxiliary device contacts change state? If so, please
state as a requirement.(2) We recommend that this requirement only includes EM aux LO / tripping relays
that trip interrupting devices directly. Other EM aux relays such as BFI aux. relays should be excluded.
Please state this clearly in the Standard. Note that these aux relays such as BFI aux relays are included
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
in the “unmonitored control circuitry associated with protective functions” requirement and will be verified
on a 12 year interval. (3) Please consider including an elementary diagram to show what is included.
8. Page 17 (Verify all paths of the control and trip circuits.)
Comment ->> Clarification needed. Is it required to perform a full functional test, i.e. trip breakers? Or is
reading DC across trip contacts all that is required?
9. Page 14 (Table 1.4) Change the maintenance interval for unmonitored station dc supply from “3 Calendar
Months” to “4 times annually”. This facilitates compliance to the standard by creating completion
milestones for batteries at the end of each quarter of the year.
10. Page 15 (Table 1.4The standard requires the establishment of a battery baseline for cell/unit internal
ohmic values and the comparison of impedance readings every 18 calendar months to that baseline. Due
to the lack of original impedance readings at the time of installation of the battery. Since in many cases no
such data is available; it needs to be made clear that establishing a baseline from , from manufacturer’s
data, the most recent impedance test, or the first impedance test completed after the adoption of the new
standard is acceptable
Response: Thank you for your comments.
1. No. Full resolution of maintenance correctable issues may require extensive work; the SDT intends that INITIATION of the resolution is all that is
required per PRC-005-2.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
4. No. Full resolution of maintenance correctable issues may require extensive work; the SDT intends that INITIATION of the resolution is all that is
required per PRC-005-2.
5. The date has been revised.
6. The SDT believes that it would be sufficient to apply voltage to the input and observe that the relay responds accordingly.
7. 1 – “Verify” means “Determine that the component is functioning correctly”. The SDT intends that the device be electrically operated, but not that
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
additional verification be conducted during the electrical operation. However, the 12-year activity for unmonitored control circuitry would require
verification of full functionality, including all of the related contacts. 2- The standard has been modified in consideration of your comment. 3 – An
elementary diagram would be inappropriate in the standard. Additionally, the design of the control circuitry varies so widely from one application
to another that it seems (to the SDT) that it would not be effective to include such an example in the Supplementary Reference Document.
8. The control circuitry can be tested in overlapping segments. It seems to the SDT that it is not necessary to trip the breakers with the functional
test, as long as the entity performs the activities necessary to demonstrate that all overlapping segments will function properly.
9. The SDT believes that your suggestion would not be effective in assuring periodic maintenance of the dc supply.
10. The station battery baseline value is up to the entity to determine. Please see Clause 15.4.1 of the Supplementary Reference Document for a
discussion of this.
Clark Public Utilities
No
Exelon
Yes
1. In response to Exelon’s comments provided to drafts 1 and 2 of PRC-005, the SDT did not explain why a
conflict with an existing regulatory requirement is acceptable. The SDT responded that a conflict does not
exist and that the removal of grace periods simply is there to comply with FERC Order directive 693. This
response does not answer or address dual regulation by the NRC and by the FERC. Specifically, the
request has not been adequately considered for an allowance for NRC-licensed generating units to
default to existing Operating License Technical Specification Surveillance Requirements if there is a
maintenance interval that would force shutting down a unit prematurely or become non-compliant with
PRC-005. Therefore, Exelon requests that the SDT communicate with the NRC and with the FERC to
ensure a conflict of dual regulation is not imposed on a nuclear generating unit without the necessary
evaluation.
2. In addition, although Exelon Nuclear agrees with the SDT that the maximum allowed battery capacity
testing intervals of not to exceed 6 calendar years for vented lead acid or NiCad batteries (not to exceed 3
calendar years for VRLA batteries) could be integrated within the plant’s routine 18 month to 2 year
interval refueling outage schedule, the SDT has not considered that nuclear refueling outages may be
extended past the 18 month to 2 year "normal" periodicity. There are some unique factors related to
nuclear generating units that the SDT has not taken into consideration in that these units are typically
online continuously between refueling outages without shutting down for any other required maintenance.
Historically, generating units have at times extended planned refueling outage shutdown dates days and
even weeks due to requests from transmission operations, fuel issues and electrical demand. Without the
grace period exclusion currently allowed by existing maintenance programs, a nuclear plant will be forced
to either extend outage duration to include testing on an every other refueling outage (i.e., every four
years to ensure compliance for a typical boiling water reactor) or leave the testing on a six year periodicity
with the vulnerability of a forced shut down simply to perform maintenance to meet the six year periodicity
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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Yes or No
Question 5 Comment
or a self report of non-compliance. To ensure compliance, the nuclear industry will be forced to schedule
battery testing on a four year periodicity to ensure the six year periodicity is met, thus imposing a
requirement on nuclear generating units that would not apply to other types of generating units.
3. In addition, Exelon has the following technical comments
a. Sections 4.2.5.4 and 4.2.5.5 need to clearly state that only protection which affects the BES is
within the scope of the PRC-005.
b. There is not enough clarity in the statement “each protection system component type” for one to
stay at the component level vs. dropping to sub-component level. If sub-components reviews are
required, the effort becomes unmanageable. Therefore the Standard should identify calibration
tolerances or other equivalent parameters. Suggest rewording to "each protection system major
component type”
Response: Thank you for your comments.
1. If several different regulatory agencies have differing requirements for similar equipment, it seems that the entity must be compliant with the most
stringent of the varying requirements. In the cited case, an entity may need to perform maintenance more frequently than specified within the
requirements to assure that they are compliant.
2. The 18-month (and shorter) interval activities are activities that can be completed without outages – primarily inspection-related activities. An
entity may need to perform maintenance more frequently than specified within the requirements to assure that they are compliant.
3. a. Applicability 4.2.5.5 has been removed. Generator-connected station service transformers are essential to the continuing operation of the
generating plant; therefore, protection on these system components is included within PRC-005-2 if the generation plant is a BES facility.
b.The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
Manitoba Hydro
Yes
1) We disagree with the requirements for battery maintenance outlined in table 1-4. In particular the
requirement for a 3 month check on electrolyte level seems too frequent based on our experience. We would
like to point out that although IEEE std 450 (which seems to be the basis for table 1-4) does recommend
intervals it also states that users should evaluate these recommendations against their own operating
experience.
2) Also, the Implementation Plan is not consistent for areas requiring regulatory approval and areas requiring
regulatory approval. The 6 month time frame proposed for R1 for areas not requiring regulatory approval is
not achievable and is not consistent with areas requiring regulatory approval. To be consistent, the effective
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
date for R1 in jurisdictions where no regulatory approval is required should be the first day of the first calendar
quarter 12 months after BOT approval.
Response: Thank you for your comments.
1. The SDT believes that the 3-month interval specified in the standard is appropriate.
2. In consideration of your comment, “6” has been modified to “12” in the Implementation Plan for Requiremnet R1.
Dynegy Inc.
Yes
For R1.5, we feel to much is being asked for since this information is not easilly controlled and the tolerances
vary over time.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
Oncor Electric Delivery Company
LLC
Yes
Comment A: Oncor believes that Requirement R1 Part 1.5 of this Standard should be removed. It is too
vague, intrusive, and divisive for what it brings to the reliability of the BES. Specifically it burdens all
Transmission Owners, Generation Owners or Distribution Providers with the impossible task of having to
“identify calibration tolerances or other equivalent parameters for each Protection System component type
that establish acceptable parameters for the conclusion of maintenance activities.” By definition a Protection
System component type is “any one of the five specific elements of the Protection System definition” and “a
component is any individual discrete piece of equipment included in a Protection System, such as a protective
relay or current sensing device.” What Requirement R1 part 1.5 with its associated High VSL in the Standard
would decree is that all Transmission Owners, Generation Owners and Distribution Providers who “failed to
establish calibration tolerance or equivalent parameters to determine if every individual discrete piece of
equipment in a Protection System is within acceptable parameters” would be in violation of the Standard with a High VSL. Oncor with over 98 years of Protection System maintenance experience feels that most
Owners including itself would be non-compliant with this unclear, meddling and disruptive requirement no
matter how long the implementation plan for the Standard is.
Comment B: Oncor believes that in light of Comment “A” above Requirement R4 Part 4.2 must be modified to
remove all references to Requirement R1 Part 1.5 of the Standard. The new requirement should be modified
to read “Either verify that the components are within acceptable parameters at the conclusion of the
maintenance activities or initiate any necessary activities to correct maintenance correctable issues.” Also in
order to assist both the owners and the compliance authorities who may question how one verifies that the
components are within acceptable parameters the FAQ document should be modified to discuss how many
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
utilities are doing this with results that indicate either a pass or fail certified by the qualified persons
performing maintenance.
Comment C: Oncor feels that the wording “no less frequently than” found in Requirement R4 Parts 4.1.1 and
4.1.2 should be chanced back to the wording in the previous version of the Standard “not to exceed.”
Comment D: Oncor recommends that in light of Comment “A” above Measure M1 be modified to remove all
reference to Requirement R1 Part 1.5.
Comment E: Oncor, as stated in Comment “B” above, recommends that the FAQ document be modified to
provide more information on what could be used for evidence that the Transmission Owner, Generation
Owner or Distribution Provider has “initiated resolution of identified maintenance correctable issues.” This will
assist both the owners and the compliance authorities in answering the question of what constitutes proof that
a maintenance correctable issue was identified.
Comment F: The second and third paragraphs added under Compliance 1.3 Data Retention provide more
information as to what data is required to be retained. Oncor feels that these two paragraphs will help the
compliance authorities, the Transmission Owners, Generation Owners and Distribution Providers needed
guidance of what is required for data retention.
Response: Thank you for your comments.
A. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the
PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been redrafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
B. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the
PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been redrafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
C. “No less frequently than” was adopted on recommendation of NERC Staff as the preferred method of addressing this requirement.
D. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the
PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been redrafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
E. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference
Document. Your comments will be considered within that activity.
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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Yes or No
Question 5 Comment
F. Thank you for your comment.
Ingleside Cogeneration LP
The latest version of PRC-005-2 includes a new requirement (R1.5) to identify calibration tolerances or
equivalent parameters that must be verified before a maintenance activity is considered complete. Although
we understand the project team’s intent, Ingleside Cogeneration LP is concerned that this requirement will
lead to multiple interpretations of which tolerances or parameters are the most important. In addition, audit
teams may expect to see certain values based upon their own sense of reliability. This is exactly the
ambiguity that PRC-005-2 is trying to eliminate.
In addition, calibration tolerances and reliability parameters may vary by equipment manufacturer or by
configuration. It is not clear that documenting every scenario to demonstrate regulatory compliance is a
benefit to BES reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
Indiana Municipal Power Agency
Yes
Standard PRC-005-2 Draft 3 contains a section of "Definitions of Terms Used in Standard" that includes newly
defined or revised terms uses in this proposed standard. There are a number of references made to these
Terms in the Standard that are not capitalized. IMPA would propose that anywhere that the terms included in
the "Definition of Terms Used" are used in the standard that they be capitalized. When any word is not
capitalized in a standard then the common practice is to use the Webster Dictionary meaning. IMPA does not
know why the SDT is reluctant to put these terms in the NERC Glossary of Terms, but by putting the terms in
the glossary it would eliminate any confusion. When these terms are capitalized all registered entities will
know that these are defined terms and will be able to consistently apply the definition without confusion.
For example: 1.1 Address all Protection System component types would become1.1 Address all Protection
System Component Types.
If these terms are not capitalized in the standard (meaning they are not referring to the defined term) then the
meaning of these terms could vary not only from utility to utility but also from Region to Region.
Response: Thank you for your comments. The standard capitalizes defined terms only when they refer to terms which are (or will be) in the NERC
Glossary of Terms. Terms will generically be capitalized when appearing at the beginning of a sentence or within a title, in accordance with common
editorial practice. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms, may
change them in a fashion inconsistent with the intended usage within PRC-005-2.
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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Yes or No
Question 5 Comment
Yes
Adding Requirement 1.5 is a significant revision and raises questions as to how broadly an accuracy or
equivalent parameter requirement and associated documentation would need to be addressed by entities
and/or will be measured for compliance. Discussion on this new requirement does not seem to be addressed
anywhere in the FAQ or Supplementary Reference documents. Additionally, to the best of our knowledge,
the need for such a requirement was not brought up as a concern or comment on the prior draft version of this
standard, and in the context of a requirement need, we don’t believe it has been attributed to or actually
poses any significant reliability risk. We do not believe this requirement is justified.
South Carolina Electric and Gas
Entergy Services
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
Duke Energy
Yes
1. We have previously commented that the FAQ and Supplementary Reference documents should be
made part of this standard. If that cannot be done, then more of the information in those documents
needs to be included in the requirements in the standard to provide clarity. Compliance will only be
measured against what is in the standard, and we need more clarity.
2. R1.4 and R1.5 need more information to provide clarity for compliance. It’s unclear to us what the
expectation is for compliance documentation for “monitoring attributes and related maintenance
activities” in R1.4 and “calibration tolerances or other equivalent parameters” in R1.5. This is fairly
straightforward for relays, but not for other component types. Either provide clarity or delete these
requirements.
3. R4.2 - it is critical that more clarity be provided for R1.5 so that we can also understand what the
compliance expectation is for R4.2
4.
M4 - Need to clarify that these pieces of evidence are all “or”, not “and” (i.e. any of the listed examples
are sufficient for compliance). We reiterate the need for additional clarity on R1.5 and R4.2 such that
compliance can be demonstrated for all component types.
5. Table 2 - We are fairly clear on the expectation for relays, but need more clarity on the expectation for
other component types. Also, need to change the phrase “corrective action can be taken” to “corrective
action can be initiated”, consistent with the Supplementary Reference document.
Response: Thank you for your comments.
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Yes or No
Question 5 Comment
1. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document.
The SDT believes that entities should be able to implement the standard without the Supplementary Reference. However, the SDT is also
convinced that many entities may find the supporting discussion/rationale/etc useful, particularly to assist them in implementing the standard in an
efficient manner.
2. Requirement R1, Part 1.4 has been modified for clarity. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been
removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also
been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
4. The SDT has provided examples of the sort of evidence that may serve to demonstrate compliance. The degree to which any single evidence type
is sufficient is dependent on the completeness of the evidence itself. The Measure has been modified to clarify this point.
5. Table 2 has been modified to be clearer. “Taken” has been replaced with “initiated” in consideration of your comment.
Wisconsin Electric Power
Company
Independent Electricity System
Operator
Yes
1. Requirement R1, Part 1.5 is vague and needs clarification. It is not clear what “Identify calibration
tolerances or other equivalent parameters” means and this may be subject to different interpretations by
entities and compliance enforcement personnel.
2. Additionally, in the Implementation plan for Requirement R1, we recommend changing “six” to “fifteen” to
restore the 3-month time difference between the durations of the implementation periods for jurisdictions
that do and don’t require regulatory approval, which existed in the previous draft. This change will ensure
equity for those entities located in jurisdictions that do not require regulatory approval as is the case here
in Ontario. More importantly it supports the IESO’s strong belief in the principle that reliability standards
should be implemented in an orderly and coordinated fashion across regions to ensure system reliability
is not compromised.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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Yes or No
Question 5 Comment
Document, Section 8 for a discussion of this.
2. In consideration of your comment, “6” has been modified to “12” in the Implementation Plan for Requirement R1.
American Electric Power
1. Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2 should be removed. Specifying
calibration tolerances for every protection system component type, while a seemingly good idea,
represents a substantial change in the direction of the standard. It would be very onerous for companies
to maintain a list of calibration tolerances for every protection system component type and show evidence
of such at an audit. AEP believes entities need the flexibility to determine what acceptance criteria is
warranted and need discretion to apply real-time engineering/technician judgment where appropriate.
2. Three different types of maintenance programs (time-based, performance-based and condition-based)
are referenced in the standard or VSLs, yet the time-based and condition-based programs are neither
defined nor described. Certain terms defined within the definition section (such as Countable Event or
Segment) only make sense knowing what those three programs entail. These programs should be
described within the standard itself and not assume knowledge of material in the Supplementary
Reference or FAQ.
3. ”Protective relay” should be a defined term that lists relay function for applicability. There are numerous
‘relays’ used in protection and control schemes that could be lumped in and be erroneously included as
part of a Protection System. For example, reclosing or synchronizing relays respond to voltage and
hence could be viewed by an auditor as protective relays, but they in fact perform traditional control
functions versus traditional protective functions.
4. The Data Retention requirement of keeping maintenance records for the two most recent maintenance
performances is a significant hurdle for any owners to abide by during the initial implementation period.
The implementation plan needs to account for this such that Registered Entities do not have to provide
retroactive testing information that was not explicitly required in the past.
Response: Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. The term, “condition-based” has been removed from the draft standard. The other terms are used, but are clear in the context in which they are
used.
3. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition within PRC-005. Further,
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the applicability of generically-described protective relays is defined by the Applicability clause of PRC-005-2.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding one to validate that entities have been in compliance since the last
audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data retention in the posted standard to establish
this level of documentation. This seems to be consistent with the current practices of several Regional Entities.
ITC
Yes
1. We would like some further clarification on PRC-005-2 Draft 3, specifically on the statement in Table 1-4 for
unmonitored station DC supply with VLA batteries. In the table it is mentioned that we are to perform either a
capacity test every six years or verify that the station battery can perform as designed by evaluating the
measured cell/unit internal ohmic values to station battery baseline, the latter statement is a little vague and
needs further clarification with regards to the expectations from the standard. Please describe an acceptable
method of establishing a baseline “measured cell/unit internal ohmic value” We would like to know what
exactly is required. We measure the cell internal ohmic value on an annual basis every 12 months, is that
enough? What are the comparison parameters with regards to battery baseline? At what percent should we
look to replace the cell?
2. Is a battery system that only supplies the SCADA RTU considered part of the protective system if alarms
for the monitored protective systems utilize that SCADA RTU?
Response: Response: Thank you for your comments.
1. The station battery baseline value is up to the entity to determine. Please see Section 15.4.1 of the Supplementary Reference for a discussion of
this.
2. No. The Applicability of the standard limits the standard to only those devices within the Protection.
ISO New England Inc.
1. In general, the standard is overly prescriptive and complex. It should not be necessary for a standard at
this level to be as detailed and complex as this standard is. Entities working with manufacturers, and
knowledge gained from experience can develop adequate maintenance and testing programs.
2.
Why are “Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation)...” not included? The output contacts from these devices
are oftentimes connected in tripping or control circuits to isolate problem equipment.
3. Due to the critical nature of the trip coil, it must be maintained more frequently if it is not monitored. Trip
coils are also considered in the standard as being part of the control circuitry. Table 1-5 has a row
labeled “Unmonitored Control circuitry associated with protective functions”, which would include trip coils,
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has a “Maximum Maintenance Interval” of “12 Calendar Years”. Any control circuit could fail at any time,
but an unmonitored control circuit could fail, and remain undetected for years with the times specified in
the Table (it might only be 6 years if I understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure, then the system must be
operated in real time assuming that that breaker will not trip for a fault or an event, and backup facilities
would be called upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker unable to trip),
instead of one line tripping, you might have many more lines deloaded or tripped because of a bus having
to be cleared because of a breaker failure initiation. The bulk electric system would have to be operated
to handle this contingency.
4. In reference to the FAQ document, Section 5 on Station dc Supply, Question K, clarification is needed
with respect to dc supplies for communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation, would the standard apply to
these batteries or not?
5. To define terms only as they are used in PRC-005-2 is inviting confusion. Although they may be unique
to PRC-005-2, some or all of them may be used in future standards, some already may be used in
existing standards, and may or may not be deliberately defined. Consistency must be maintained, not
only for administrative purposes, but for effective technical communications as well.
6. What is the definition of “Maintenance” as used in the table column “Maximum Maintenance Interval”?
Maintenance can range from cleaning a relay cover to a full calibration of a relay.
7. A control circuit is not a component, it is made up of components.
8. Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify calibration tolerances or other
equivalent parameters...” means, and may be subject to different interpretations by entities and
compliance enforcement personnel.
9. In the Implementation plan for Requirement R1, recommend changing “six” to fifteen. This change would
restore the 3-month time difference that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require regulatory approval. It will ensure
equity for those entities located in jurisdictions that do not require regulatory approval, as is the case in
Ontario.
10. The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It seems to continue to the next
page to a new box. There are multiple activities without clear delineation.
Response: Thank you for your comments.
1. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently monitored for
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compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that minimum activities also need be
prescribed. If an entities’ experience is that components require less-frequent maintenance, a performance-based program in accordance with R3
and Attachment A is an option.
2. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection System definition.
Also, there is currently no technical basis for the maintenance of the devices which respond to non-electrical quantities on which to base
mandatory standards related either to activities or intervals. Absent such a technical basis, we are currently unable to establish mandatory
requirements, but may do so in the future if such a technical basis becomes available.
3. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year interval. You are free to
maintain these devices more frequently if you desire.
4. With respect to dc supply associated only with communications systems, we prescribe, within Table 1-2, that the communications system must be
verified as functional every 3 months, unless the functionality is verified by monitoring. The specific station dc supply requirements (Table 1-4) do
not apply to the dc supply associated only with communications systems. The SDT has decided to eliminate the FAQ and incorporate topics and
discussion from the FAQ within the Supplementary Reference Document. Your comments will be considered within that activity.
5. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms, either now or in the
future, may not be consistent with the terms as used here. They are defined only for clarify within this standard. The SDT will confirm with NERC
staff that this approach is acceptable.
6. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are specified in the Activities
column. The term is capitalized in the column title in conformance with normal editorial practice as a title, rather than as a definition
7. For purposes of this standard, the control circuit IS defined as one component type.
8. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
9. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making it consistent with
the remainder of the Implementation Plan.
10. Table 1-4 has been further modified for clarity
Nebraska Public Power District
Yes
Definitions:
1. The PSMP definition inappropriately extends the maintenance program to include corrective
maintenance. The first bullet of the Detailed Description section of the SAR specifically states: "Analysis
of correct operations or misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard." The comment in the SAR was
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directed toward the Purpose of PRC-017 since it is the only one of the applicable PRC standards that
included corrective measures in its Purpose. However, the concept of not including corrective
maintenance in a maintenance standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC SPCTF Assessment of
Standards referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment of the Standards
identified the need to expand the maintenance and testing program to include corrective maintenance. I
recommend deleting the words "and proper operation of malfunctioning components is restored." from the
first sentence of the PSMP definition. I believe that failure to do so exceeds the scope of the SAR.
2. The definition of a Countable Event should clearly state whether or not multiple conditions on a single
component will count as a single Countable Event or as multiple Countable Events. For example, a
single relay fails its undervoltage setting and its under frequency setting. Is this one Countable Event or
two Countable Events?
3. Applicability Part 4.2.2:The ERO does not establish underfrequency load-shedding requirements. Those
requirements will be established by Reliability Standard PRC-006-1 when it is approved by FERC. I
recommend changing Accountability Part 4.2.2. to "...installed to provide last resort system preservation
measures." (Note this wording is consistent with the Purpose of PRC-006-0.)Applicability Part 4.2.5.4 and
4.2.5.5:
4. Station Service transformers provide energy to plant loads and not the BES. If these plant transformers
are included, why not include the rest of the plant systems? I recommend deleting Applicability Part
4.2.5.4 and 4.2.5.5.
5. Requirement R1 Part 1.2: The wording of the first sentence is unclear about what information is required.
For example, I could state in my PSMP that: "All Protection System component types are addressed
through time-based, performance-based, or a combination of these maintenance methods" and be
compliant with the Requirement. I recommend re-wording the first sentence to state: "Identify which
maintenance method is used to address each Protection System component type. Options include timebased, performance-based (per PRC-005 Attachment A), or a combination of time-based and
performance-based (per PRC-005 Attachment A)." Note that PRC-005 Attachment A does not address a
combination of maintenance methods and therefore the second reference in the first sentence should be
removed if the original wording is retained.
6. Requirement R1 Part 1.4: The column titles in Tables 1-1 through 1-5 have been revised to “Component
Attributes” and “Activities”. I recommend changing "monitoring attributes" to "component attributes" and
"maintenance activities" to "activities" to be consistent with the Tables.
7. Requirement R1 Part 1.5: Maintenance acceptance criteria for a given Protection System component type
may very depending on the manufacturer, model, etc.. Including all acceptance criteria in the PSMP
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document will over-complicate the program document. I recommend clarifying Part 1.5 to allow the
incorporation of device-specific acceptance criteria in the applicable evidentiary documentation. One
possible option is to add a second sentence as follows: "The calibration tolerances or other equivalent
parameters may be included with the maintenance records." Note that a personal preference would be to
use the phrase “acceptance criteria” instead of “calibration tolerances or other equivalent parameters”.
8. Requirement R4:The PSMP definition inappropriately extends the maintenance program to include
corrective maintenance. The first bullet of the Detailed Description section of the SAR specifically states:
"Analysis of correct operations or misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard." The comment in the SAR was
directed toward the Purpose of PRC-017 since it is the only one of the applicable PRC standards that
included corrective measures in its Purpose. However, the concept of not including corrective
maintenance in a maintenance standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC SPCTF Assessment of
Standards referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment of the Standards
identified the need to expand the maintenance and testing program to include corrective maintenance. I
recommend deleting the words "including identification of the resolution of all maintenance correctable
issues" from the first sentence of the Requirement. I believe that failure to do so exceeds the scope of
the SAR.
9. Requirement R4 Part 4.2: What is considered sufficient verification of parameters? Does this require an
engineer or technician signature or simply an indication of pass/fail? The PSMP definition inappropriately
extends the maintenance program to include corrective maintenance. The first bullet of the Detailed
Description section of the SAR specifically states: "Analysis of correct operations or misoperations may
be an integral part of condition-based maintenance processes, but need not be mandated in a
maintenance standard." The comment in the SAR was directed toward the Purpose of PRC-017 since it
is the only one of the applicable PRC standards that included corrective measures in its Purpose.
However, the concept of not including corrective maintenance in a maintenance standard should apply to
all of the applicable PRC standards. The same statement from the SAR identified above was also
included in the NERC SPCTF Assessment of Standards referenced in the SAR. Neither the SAR nor the
NERC SPCTF Assessment of the Standards identified the need to expand the maintenance and testing
program to include corrective maintenance. I recommend re-wording Requirement 4, Part 4.2 to state:
"Verify that the components are within the acceptable parameters established in accordance with
Requirement R1, Part 1.5 at the conclusion of the maintenance activities." I believe that failure to do so
exceeds the scope of the SAR.
10. Measurement M2: Can a single specification document suffice for similar relay types such as one
document for SEL relays? For trip circuit monitoring can a standard document be used for a group of
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similar schemes ?
11. Measurement M4:I assume this is not an all inclusive list of potential forms of evidence. Please clarify
what is meant by "such as". Does this mean that: 1) Any one item is sufficient?; 2) Certain combinations
of evidence are necessary? If so, what combinations?; 3) Are other items that are not identified here
acceptable?
12. Measurement M4 repeatedly refers to "dated" evidence. However, current audit expectations include
either performer signatures or initials on the evidence in addition to the dates. Please revise
Measurement M4 to clearly state the expectations regarding performer signatures or initials on the
evidence documents.
13. The PSMP definition inappropriately extends the maintenance program to include corrective
maintenance. The first bullet of the Detailed Description section of the SAR specifically states: "Analysis
of correct operations or misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard." The comment in the SAR was
directed toward the Purpose of PRC-017 since it is the only one of the applicable PRC standards that
included corrective measures in its Purpose. However, the concept of not including corrective
maintenance in a maintenance standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC SPCTF Assessment of
Standards referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment of the Standards
identified the need to expand the maintenance and testing program to include corrective maintenance. I
recommend deleting the words: "and initiated resolution of identified maintenance correctable issues"
from the last sentence of Measurement M4. I believe that failure to do so exceeds the scope of the SAR
14. .Compliance Part 1.3: Tables 1-1 through 1-5 refers to time-based maintenance programs. I recommend
changing "performance-based" to "time-based" in the last sentence of the third paragraph.
15. The last paragraph of Part 1.3 of the Compliance Section states: "The Compliance Enforcement Authority
shall keep the last periodic audit report and all requested and submitted subsequent compliance records."
This appears to be a requirement of the Compliance Enforcement Authority however they are not
identified in Section 4 Applicability of the Standard. It is also in conflict with the SAR Attachment B Reliability Standard Review Guidelines which states on page SAR-10: "Do not write any requirements for
the Regional Reliability Organization. Any requirements currently assigned to the RRO should be reassigned to the applicable functional entity." I recommend deleting the last paragraph of Part 1.3 of the
Compliance Section to avoid conflict with the SAR.
16. Table 1-1: The Activity of row 1 states: “Verify operation of the relay inputs and outputs that are essential
to ...” Please clarify what is meant by “operation of” the relay inputs and outputs. What is the criteria to
determine if something is “essential”? The first line of row 2 has a double colon. Please delete one of
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them.
17. For the second bullet of row 2 column 1, please clarify what is meant by the last part of this sentence "that
are also performing self monitoring and alarming" and how it relates to the voltage and current sampling
required. It appears the self monitoring is required in the first bullet.
18. For the first bullet of row 2 column 3, many relay settings may not be essential to the protective function of
the relay. I recommend revising the first bullet to: “Settings that are essential to the proper function of the
protection system are as specified.”
19. The format of the Activities column for all three rows is different. Please reformat them to be consistent.
My preference is the second row.
20. Table 1-2: Row 1 Column 2, verifying the functionality of communications systems on a 3 calendar
months basis is excessive and unnecessary. Suggest changing the Maximum Maintenance Interval to
either 6 calendar months or semi-annual.
21. Row 2 Column 1, please provide examples of typical communications systems that fit into this category,
e.g. Mirror Bit or Guard systems?
22. The words “such as” are used repeatedly. Please clarify what is meant by "such as". Is this left up to the
Utility to define in their PSMP?
23. Table 1-5: The Activity for row 1 requires verification that each trip coil is able to operate the device. If a
control circuitry contains multiple trip coils, it is not always possible to determine which trip coil energized
to trip the device. I recommend changing "each trip coil" to "at least one trip coil".
24. Please clarify what is meant by an "Electromechanical trip" device in row 3.
25. Row 3 column 3, does this mean verify the trip contact on the device operates properly but not verify the
trip circuit wiring from this contact to the trip coil since the trip circuit is tested in the row below? It is
difficult to separate the meaning in these two rows.
26. Row 4 column 3 requires verification of all paths of the control and trip circuits. Please clarify if this
includes the control circuitry of Protection Systems located at the other end of a line if the device utilizes a
remote trip scheme?
Response: Response: Thank you for your comments.
1. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues (discovered during
maintenance activities) is included. The SDT considers this inclusion to be appropriate and necessary as part of the maintenance program.
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2. The example cited would be one countable event. The definition has been modified to clarify.
3. Underfrequency load shedding requirements, whether established by Regional Entities (current practice) or by NERC, are ERO requirements.
4. Clause 4.2.5.5 has been removed. Generator-connected station service transformers are essential to the continuing operation of the generating
plant; therefore, protection on these system components is included within PRC-005-2 if the generation plant is a BES facility.
5. Requirement R1, Part 1.2 has been modified essentially as you suggest.
6. “Monitoring attributes” are used within the respective tables; “Component attributes” can include monitoring or not. The Tables have been revised
to specify “Maintenance Activities”.
7. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
8. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues (discovered during
maintenance activities) is included. The SDT considers this inclusion to be appropriate and necessary as part of the maintenance program.
9. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
10. Yes. However, the degree to which any single evidence type is sufficient is dependent on the completeness of the evidence itself. The Measure
has been modified to clarify this point. The Measure M2 to which you refer has been deleted in conjunction with the deletion of the accompanying
requirement.
11. Yes. The SDT has provided examples of the sort of evidence that may serve to demonstrate compliance. The degree to which any single evidence
type is sufficient is dependent on the completeness of the evidence itself. “Such as” was not intended to be an all-inclusive list; additional
examples are provided in Section 15.7 of the Supplementary Reference Document. The Measure has been modified to clarify this point.
12. Signatures, initials, etc, may not apply to all forms of evidence. “Dated” is more universal.
13. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues (discovered during
maintenance activities) is included. The SDT considers this inclusion to be appropriate and necessary as part of the maintenance program.
14. The portion of “Compliance” that referred to the Tables has been deleted.
15. The text to which you refer is part of the standard language for NERC Standards and reflects a general responsibility of the Compliance
Enforcement Authority. The Compliance Enforcement Authority does not need to be indentified as an Applicable Entity.
16. If proper operation of an input or output is required such that the Protection System operate properly, it is “essential”. “Verify operation …” means
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to determine that the component functions properly. The typo has been corrected.
17. The text to which you refer has been deleted in consideration of your comment.
18. The SDT disagrees; settings beyond those “essential for proper function of the relay” may be essential to proper functioning of the monitoring,
etc, which is used to extend the maximum maintenance interval of the relay.
19. The SDT has arranged the format of each of the cells within the Maintenance Activities column for the best clarity within each individual cell.
20. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
21. Examples such as you suggest may violate the NERC Anti-Trust Guidelines by appearing to favor specific proprietary technologies. Some
examples may be found in Section 15.5 of the Supplementary Reference Document.
22. “Such as” refers to examples pertinent to various equipment technologies, and thus are equipment-dependent, as opposed to entity-selectable.
Some examples may be found in Section 15.5 of the Supplementary Reference Document.
23. The SDT believes that each individual trip coil needs to be verified as required within PRC-005-2.
24. “Electromechanical” refers to any device which has moving parts that respond to electrical signals, such as lockout relays and auxiliary relays.
This row in Table 1-5 has been modified.
25. Yes. The verification of the entire control circuitry is performed according to the following row in the Table, on a less-frequent interval.
26. The testing of the “remote trip scheme” seems best characterized as testing of a “Communications System”. Accordingly, testing of the remote
station control circuitry is an independent activity.
CenterPoint Energy
Yes
(a) CenterPoint Energy cannot support this proposed Standard. Any standard that requires a 35 page
Supplementary Reference document and a 37 page FAQ - Practical Compliance and Implementation
document, in addition to extensive tables in the Standard, is much too prescriptive and complex to be
practically implemented.
(b) CenterPoint Energy is opposed to approving a standard that imposes unnecessary burden and reliability
risk by imposing an overly prescriptive approach that in many cases would “fix” non-existent problems. To
clarify this last point, CenterPoint Energy is not asserting that maintenance problems do not exist. However,
requiring all entities to modify their practices to conform to the inflexible approach embodied in this proposal,
regardless of how existing practices are working, is not an appropriate solution. Among other things,
requiring entities to modify practices that are working well to conform to the rigid requirements proposed
herein carries the downside risk that the revised practices, made solely to comply with the rigid requirements,
degrade reliability performance.
(c) CenterPoint Energy is very concerned that a large increase in the amount of documentation will be
required in order to demonstrate compliance - with no resulting reliability benefit. CenterPoint Energy
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believes this Standard could actually result in decreasing system reliability, as the Standard proposes
excessive maintenance requirements. The following is included in the Supplementary Reference document
(page 8): “Excessive maintenance can actually decrease the reliability of the component or system. It is not
unusual to cause failure of a component by removing it from service and restoring it.” System reliability can
be even further reduced by the number of transmission line and autotransformer outages required to perform
maintenance.
(d) The following is included in the FAQ - Practical Compliance and Implementation document: “PRC-005-2
assumes that thorough commission testing was performed prior to a protection system being placed in
service. PRC-005-2 requires performance of maintenance activities that are deemed necessary to detect and
correct plausible age and service related degradation of components such that a properly built and
commission tested Protection System will continue to function as designed over its service life.” CenterPoint
Energy believes some proposed requirements, such as wire checking a relay panel, do not conform to this
statement. CenterPoint Energy’s experience has been that panel wiring does not degrade with age and
service and that problems with panel wiring, after thorough commissioning, is not a systemic issue.
Response: Response: Thank you for your comments.
a. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference
Document.
b. FERC Order 633 directed that NERC establish maximum maintenance intervals. Additionally, the SDT is directed to develop a measurable,
effective continent-wide standard. Entities may continue their current practices as long as those practices meet the minimum requirements
of this standard.
c. FERC Order 633 directed that NERC establish maximum maintenance intervals. The documentation required should not expand
dramatically from the documentation currently required to demonstrate compliance. An entity may minimize hands-on maintenance by
utilizing monitoring to extend the intervals.
d. The standard does not require “wire-checking”, but instead generically specifies “verification” – however an entity chooses to do so.
American Transmission
Company
Yes
ATC recognizes the substantial efforts that the SDT has made on PRC-005 and appreciate the SDT’s
modifications to this Standard based on previous comments made. ATC looks forward to continuing to have
a positive influence on this process via the comment process, ballots and interaction with the SDT. ATC was
very close to an affirmative vote on this Standard prior to the unanticipated changes that appeared in this
most recent posting. These changes introduce a significant negative impact from ATC’s perspective.
Therefore, ATC is recommending a negative ballot in the hope that our concerns regarding R 1.5 and R 4.2
and other clarifications will be included with the standard The two items within the proposed Standard that we
take exception to are not directly related to implementing FERC Order 693. Rather, it is the overly
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prescriptive nature with respect to the “how” as outlined in the proposed Standard that ATC takes exception...
To improve and find the proposed Standard acceptable, ATC would like to see the following modifications:
1. Change the text to require the actuation of a single trip coil (row 1 of table 1.5). This would satisfy
the intent to exercise the mechanism on a regular schedule, given that the mechanism binding is a
much more likely source of a coil failure. The balance of trip coils could then be tested as part of
routine breaker maintenance.
2. Eliminate the additional requirements introduced by the addition of R1.5 and the associated
modifications to R4.2. The additional documentation required for the range of each element is typically
incorporated into the pass/fail mechanism of the existing test equipment (which is reflective of the
manufacturer recommendations) used to conduct these tests. Therefore, requiring the assembly of this
additional documentation from each entity would:
a. Be duplicative and voluminous as it would require us to track thousands of additional data
points due to the variability in element ranges by relay manufacturer, model number and
vintage.
b. Not add to the reliability of the system as this function is already being performed on a
collective basis.
Response: Response: Thank you for your comments.
1. The SDT believes that each individual trip coil needs to be verified as required within PRC-005-2.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
Consumers Energy
Yes
1. Table 1-3 states, “are received by the protective relays”. Does this require that the inputs to each individual
relay must be checked, or is it sufficient to verify that acceptable signals are received at the relay panel, etc?
2. Relative to Table 1-5, the activities will likely require that system components be removed from service to
complete those activities. If the changes to the BES definition (per the FERC Order) causes system elements
such as 138 kV connected distribution transformers to be considered as BES, these components can not be
removed from service for maintenance without outaging customers. The standard must exempt these
components from the activities of Table 1-5 if the activity would result in deenergizing customers.
3. For the component types addressed in Tables 1-3 and 1-5, the requirements may cause entities to identify
components very differently than they are currently doing, and doing so may take several years to complete.
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The Implementation Plan for R1 and R4 is too aggressive in that it may not permit entities to complete the
identification of discrete components and the associated maintenance and implement their program as
currently proposed. We propose that the Implementation Plan specifically address the components in Table
1-3 and 1-5 with a minimum of 3 calendar years for R1 and 12 calendar years after that for R4.
4. As for the interval in Table 1-4 regarding the battery terminal connection resistance, we believe that an 18month interval is excessively frequent for this activity, and suggest that it be moved to the 6-calendar-year
interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections every 4-years, rather than
measuring the terminal connection resistance to determine if the connections are sound. Disregarding the
interval, would this activity satisfy the “verify the battery terminal connection resistance” activity?
Response: Response: Thank you for your comments.
1. The SDT intends that the voltage and current signals properly reach each individual relay, but there may be several methods of accomplishing this
activity.
2. This concern seems more properly to be one to be addressed during the activities to develop the new BES definition, rather than within PRC-005-2.
3. The Implementation Plan for Requirement R1 has been modified from 6 months to 12 months. The Standard has also been modified (Requirement
R1, Part 1.1) to not specifically require identification of all individual Protection System components. The Implementation Plan for Requirement R4
has been revised to add one year to all established dates.
4. IEEE 450, 1188, 1106 all recommend this activity at a 12-month interval. Please see Section 15.4.1 of the Supplementary Reference Document for a
discussion of this activity.
5. Re-torqueing the battery terminals would not meet this requirement.
Southern Company Generation
Yes
1. Please consider retaining the definitions stated to be moved to the NERC Glossary - they would be
valuable to entities in the standard.
2. On Page 5, Section 1.2, please consider changing “or a combination of these maintenance methods (per
PRC-005-Attachment A).” to “or a combination of these two maintenance methods.”
3. On Page 5, Section 1.5: recommend deleting this section - the subjectivity of what is an acceptable
value for component testing makes this requirement un-valuable.
4. On Page 5, Section 4.2, it is recommended that the requirement be the following: Either verify that the
component performance is acceptable at the conclusion of the maintenance activities or initiate
resolution of any identified maintenance correctable issue.
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5. On Page 5, Measure M1, replace 1.5 with 1.4 (after eliminating Requirement 1.5)
6. On Page 6, Section 1.3, replace the existing Data Retention text with the following: The TO, GO, and DP
shall each retain documentation for the longer of the these time periods: 1) the two most recent
performances of each distinct maintenance activity for the Protection System component, or (2) all
performances of each distinct maintenance activity for the Protection System component since the
previous scheduled audit date. The Compliance Enforcement Authority shall keep the last periodic audit
report and all requested and submitted subsequent compliance records.
7. On Page 10, Section F, please correct the revision information for the documents listed.
8. On Pages 14 & 15, Table 1-4, move the bottom row to the next page so that it is easier to see that the
maintenance activities are an “either/or” option.
9. On Page 17, Table 1-5, it seems that the 12 calendar year interval activities would automatically be
included in the 6 calendar year activity for verifying the electrical operation of electromechanical trip and
auxiliary devices. Is the 12 year requirement superfluous?
10. On Page 19, Attachment A, it is recommended to delete the footnote #1 since the definition is given
already on Page 2.
Response: Response: Thank you for your comments.
1. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms, may change them in a
fashion inconsistent with the intended usage within PRC-005-2.
2. Requirement R1, Part 1.2 has been modified.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
5. Measure M1 has been modified as you suggest.
6. The Data Retention section has been modified essentially as you suggest.
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7. The Reference information has been corrected.
8. Table 1-4 has been revised.
9. The 12-year interval activities are more extensive than the 6-year interval activities.
10. Footnote #1 has been removed.
US Bureau of Reclamation
Yes
1. The concept of including definitions in this standard that are not a part of the Glossary of Terms will create
a conflict with other standards that choose to use the term with a different meaning. This practice should
be disallowed. If a definition is be introduced it should be added to the Glossary of Terms. This concept
was not provided to industry for comment when the modifications to the Definition of Protection System
were introduced. Additional related to this practice are included later on.
2. The Term "Protective Relays" is overly broad as it is not limited to those devices which are used to protect
the BES. In the reference provided to the standard, the SDT defined "Protective Relays" as "These relays
are defined as the devices that receive the input signal from the current and voltage sensing devices and
are used to isolate a faulted portion of the BES. " The Definition for "Protective Relays" as well as the
components associated with the them should be associated with the protection of the BES in the
definition.
3. The Section 2.4 of the attached reference and the recent FERC NOPR are in conflict with the definition of
"Protective Relays" which include lockout relays and transfer trip relays "The relays to which this standard
applies are those relays that use measurements of voltage, current, frequency and/or phase angle and
provide a trip output to trip coils, dc control circuitry or associated communications equipment.
4. This Draft 2: April3: November 17, 2010 Page 5 definition extends to IEEE device # 86 (lockout relay) and
IEEE device # 94 (tripping or trip-free relay) as these devices are tripping relays that respond to the trip
signal of the protective relay that processed the signals from the current and voltage sensing devices."
The definition should be revised to reflect that is really intended. The SDT as created an implied definition
by specifically defining DC circuits associated with the trip function of a "Protective Relay" but failing to
specifically define voltage and current sensing circuits providing inputs to "Protective Relays". The team
clearly intended the circuits to be included but the definition does not since it only refers the "voltage and
current sensing devices".
5. Starting with the Definitions and continuing through the end of the document, terms that have been
defined are not capitalized. This leaves it ambiguous as to whether the defined term is to be applied or it
is a generic reference. Only defined terms "Protection System Maintenance Program" and "Protection
System" are consistently capitalized.
6. Protection System Maintenance Program (PSMP) definition: The Restore bullet should be revised to read
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as follows: "Return malfunctioning components to proper operation by repair or calibration during
performance of the initial on-site activity."Add the following at the end of the PSMP definition: “NOTE:
Repair or replacement of malfunctioning Components that require follow-up action fall outside of the
PSMP, and are considered Maintenance Correctable Issues.”
7. Protection System (modification) definition: The term "protective functions" that is used herein should be
changed to "protective relay functions" or what is meant by the phrase should become a defined term, as
it is being used as if it is a well known well defined, and agreed upon term. The first bullet text should be
revised to read as follows: "Protective relays that monitor BES electrical quantities and respond when
those quantities exceed established parameters,” the last two bullets should be reversed in order and
modified to read as follows: o control circuitry associated with protective relay functions through the trip
coil(s) of the circuit breakers or other interrupting devices, and o station dc supply (including station
batteries, battery chargers, and non-battery-based dc supply) associated with the preceding four bullets.
8. Statement between the Protection System (modification) definition and the Maintenance Correctable
Issue definition; Is this a NERC accepted practice? There does not appear to be a location in the
standard for defining terms. Having terms that are not contained in the "Glossary of Terms used in NERC
Reliability Standards," and are outside of the terms of the standards, and yet are necessary to understand
the terms of the Requirements is not acceptable. They would become similar to the reference
documents, and could be changed without notice.
9. Maintenance Correctable Issue definition: The last sentence should be modified to read as follows:
"Therefore this issue requires follow-up corrective action which is outside the scope of the Protection
System Maintenance Program and the Standard PRC-005-2 defined Maximum Maintenance Intervals."
The definition could also be easily clarified to read "Maintenance Correctable Issue - Failure of a
component to operate within design parameters such that it cannot be restored to functional order by
repair or calibration; therefore requires replacement." This ensures that any action to restore the
equipment, short of replacement, is still considered maintenance. Otherwise ambiguity is introduced as
what "maintenance" is.
10. Countable Event definition: An explanation should be made that this is a part of the technical justification
for the ongoing use of a performance-based Protection System Maintenance Program for PRC-005.
11. Insert the phrase "Standard PRC-005-2" before the term "Tables 1-1..."
12. Applicability: 4.2. Facilities: 4.2.5.4 and 4.2.5.5: Delete these two parts of the applicability. Station service
transformer protection systems are not designed to provide protection for the BES. Per PRC-005-2
Protection System Maintenance Draft Supplementary Reference, Nov. 17 2010, Section 2.3 - Applicability
of New Protection System Maintenance Standards: “The BES purpose is to transfer bulk power. The
applicability language has been changed from the original PRC-005: “...affecting the reliability of the Bulk
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Electric System (BES)...”To the present language:”... and that are applied on, or are designed to provide
protection for the BES.”The drafting team intends that this Standard will not apply to “merely possible”
parallel paths, (sub-transmission and distribution circuits), but rather the standard applies to any
Protection System that is designed to detect a fault on the BES and take action in response to that
fault.”Station Service transformer protection is designed to detect a fault on equipment internal to a power
plant and not directly related to the BES. In addition, many Station Service protection ensures fail over to
a second source in case of a problem. Thus station service transformer protection system is a power
plant reliability issue and not a BES reliability issue. As such station service transformer protection should
not be included in PRC 005 2.In addition; the SDT appears to have targeted generation station service
without regard to transmission systems. If generating station service transformers are that important,
then why are substation/switchyard station service transformers not also important?
13. B. Requirements Should the sub requirements have the "R" prefix?
14. R4.Change the phrase "... PSMP, including identification of the resolution of all ..." to read "...PSMP
including identification, but not the resolution, of all ...".
15. General comment PRC005-2 is very specific in listing the maximum maintenance interval but is still very
vague in listing the specific components to test. Suggest adding the following to the standard.
a. A sample list of devices or systems that must be verified in a generator to meet the requirements
of this Maintenance Standard:
b. Examples of typical devices and relay systems that respond to electrical quantities and may
directly trip the generator, or trip through a lockout relay may include but are not necessarily
limited to:
Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
Loss-of-field relays
Volts-per-hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator-ground relays
Communications-based protection systems such as transfer-trip systems
Generator differential relays
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Reverse power relays
Frequency relays
Out-of-step relays
Inadvertent energization protection
Breaker failure protection o lockout or tripping relays
c.
For generator step up transformers, operation of any the following associated protective relays
frequently would result in a trip of the generating unit and, as such, would be included in the
program:
Transformer differential relays o Neutral overcurrent relay
Phase overcurrent relays
16. In the Lower, Moderate and Severe VSL descriptions, in addition to not being capitalized, the defined
term Maintenance Correctable Issues should not be hyphenated.
17. In Attachment A Section 2 Page 51 should be modified as follows:
2. Maintain the components in each segment according to the time-based maximum allowable intervals
established in Tables 1-1 through 1-5 until results of maintenance activities for the segment are available
for a minimum of either 30 individual components of the segment or a significant statistical population of
the individual components of a segment." Without the modification the requirement unfairly target smaller
entities. This will allow smaller entities to determine adjust its time based intervals if its experience with
an appropriate number of components supports it. In Attachment A Section 5 Page 51 should be modified
as follows:
5. Determine the maximum allowable maintenance interval for each segment such that the segment
experiences countable events on no more than 4% of the components within the segment, for the greater
of either the last 30 components maintained or a significant statistical population of the individual
components of a segment maintained in the previous year. Without the modification the requirement
unfairly target smaller entities. This will allow smaller entities to determine adjust its time based intervals
if its experience with an appropriate number components supports it.
18. In Attachment A Section 5 Page 52 should be modified as follows:
5. Using the prior year’s data, determine the maximum allowable maintenance interval for each segment
such that the segment experiences countable events on no more than 4% of the components within the
segment, for the greater of either the last 30 components maintained or a significant statistical population
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of the individual components of a segment components maintained in the previous year. Without the
modification the requirement unfairly target smaller entities. This will allow smaller entities to determine
adjust its time based intervals if its experience with an appropriate number of components supports it.
Response: Thank you for your comments.
1. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms, may change them in a
fashion inconsistent with the intended usage within PRC-005-2.
2. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition within PRC-005. Further,
the applicability of generically-described protective relays is defined by the Applicability clause of PRC-005-2.
3. The issues raised by the FERC NOPR will be addressed as part of the response to the NOPR (and ultimately the Order). The extension to auxiliary
and lockout relays is not part of the protective relay (addressed within Table 1-1), but instead as part of the control circuitry (Table 1-5).
4. The extension to auxiliary and lockout relays is not part of the protective relay (addressed within Table 1-1), but instead as part of the control
circuitry (Table 1-5).
5. Definitions from the NERC Glossary of Terms (or those intended for the Glossary) are consistently capitalized (Protection System and Protection
System Maintenance Program fall within this category). As for terms defined only for use within this standard, these terms are NOT capitalized,
since they are not in the Glossary of Terms.
6. The “restore” portion of PSMP specifically addresses returning malfunctioning components to proper operation. The requirements regarding
maintenance correctable issues are further addressed within that definition (for use only within PRC-005-2).
7. The SDT is currently not planning on further modifying the most recent NERC BOT-approved definition of Protection System.
8. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms, may change them in a
fashion inconsistent with the intended usage within PRC-005-2.
9. Identifying problems, but not fixing them, does not constitute an effective program. In deference to the time that may be necessary to
repair/replace defective components, the SDT has decided to require only initiation of resolution of maintenance correctable issues, not to
demonstrate completion of them.
10. Since this term is used only in Attachment A, it seems unnecessary to provide the explanation requested.
11. The SDT has elected not to change the reference to the Tables throughout the standard.
12. Applicability 4.2.5.5 has been removed. Generator-connected station service transformers (4.2.5.4) are essential to the continuing operation of the
generating plant; therefore, protection on these system components is included within PRC-005-2 if the generation plant is a BES facility.
13. The current style guide for NERC Standards does not preface the subparts with an “R”.
14. Identifying problems, but not fixing them, does not constitute an effective program. In deference to the time that may be necessary to
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repair/replace defective components, the SDT has decided to require only initiation of resolution of maintenance correctable issues, not to
demonstrate completion of them.
15. The various specific components you suggest are addressed within the Facilities portion of the Applicability 4.2.5, as well as other components
that satisfy the attributes within 4.2.5. These examples are in the Supplementary Reference Document (Section 8.1.3).
16. Within the VSLs, the hyphenated term has been corrected.
17. The SDT has determined that 30 individual components is the minimum acceptable statistically-significant population for use to establish
performance-based intervals. Multiple entities may aggregate component populations to establish this component population, provided that the
programs are sufficiently similar to make the aggregation valid. See Supplementary Reference Document Section 9 for a discussion.
18. The SDT has determined that 30 individual components is the minimum acceptable statistically-significant population for use to establish
performance-based intervals. Multiple entities may aggregate component populations to establish this component population, provided that the
programs are sufficiently similar to make the aggregation valid. See Supplementary Reference Document Section 9 for a discussion.
Alliant Energy
Yes
1. In the Purpose statement delete “affecting” and replace it with “protecting”. The purpose of the standard
deals with systems that protect the BES.
2. In sections R1 and R4.2.1 delete “applied on” as unneeded and potentially confusing. The goal is to
cover Protection Systems designed to protect the BES.
3. Alliant Energy believes that Article 1.4 needs to be deleted from the standard. It is redundant and serves
no purpose.
4. Alliant Energy believes that Article 1.5 needs to be deleted from the standard. There is a major concern
on what an “acceptable parameter” is and how it would be interpreted by the Regional Entities.
5. Section 4.2 Applicable Facilities: We are concerned with this paragraph being interpreted differently by
the various regions and thereby causing a large increase in scope for Distribution Provider protection
systems beyond the reach of UFLS or UVLS.4.2.1 Protection Systems applied on, or designed to provide
protection for, the BES. The description is vague and open for different interpretations for what is “applied
on” or “designed to provide protection”. According to the November 17, 2010 Draft Supplementary
Reference page 4, the Standard will not apply to sub-transmission and distribution circuits, but will apply
to any Protection System that is designed to detect a fault on the BES and take action in response to the
fault. The Standard Drafting Team does not feel that Protection Systems designed to protect distribution
substation equipment are included in the scope of this standard; however, this will be impacted by the
Regional Entity interpretations of ‘protecting” the BES. Most distribution protection systems will not react
to a fault on the BES, but are caught up in the interpretation due to tripping a breaker(s) on the BES. We
request clarification that the examples listed below do not constitute components of a BES Protection
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System:
1. Older distribution substations that lack a transformer high side interrupting device and therefore trip a
transmission breaker or a portion of the transmission system or bus, or
2. Newer distribution substations that contain a transformer high side interrupting device but also
incorporate breaker failure protection that will trip a transmission breaker or a portion of the transmission
system or bus.
6. Since distribution provider systems are typically radial and do not contain the level of redundancy of
transmission or generation protection systems, it is not cheap, safe, maintaining BES reliability, or easy to
coordinate companies to test these protection systems to the level of PRC-005-2 draft recommendations.
7. Section F Supplementary Reference Documents: The references listed in this section refer to 2009 dates
and do not match with the 2010 reference documents supplied for comment.
8. Table 1-4 Component Type Station dc Supply:
a.
“Any dc supply for a UFLS or UVLS system” - This should not have the same testing interval as
control circuits, but should have a maximum maintenance period as other dc supplies do.
b. Replace the words “perform as designed” on page 14 of Table 1-4 with “operate within defined
tolerances.”Table 1-5 Component Type Control Circuitry:
c.
This table allows for unmonitored trip coils for UFLS or UVLS breakers to have “no periodic
maintenance”. The PRC-005-2 Supplementary Frequently Asked Question #7B and #7C give
excellent reasoning for not requiring maintenance on the trip coil component due to the larger
number of failures that would be required to have any substantial impact to the BES as well as
the statement that distribution breakers are operated often on just fault clearing duty already. We
believe that the unmonitored control circuitry has the same level of minimal BES impact and is
also being tested each time the distribution breaker undergoes fault clearing duty. With this logic,
we do not see why there would be different maintenance requirements for these two components.
d. Alliant Energy is concerned that the addition of mandatory 86 and 94 auxiliary lockout relays
(Electromechanical trip or Auxiliary devices) will force entire bus outages that will compromise the
BES reliability more by forcing utilities across the US to unnecessarily take multiple non-faulted
BES elements out of service. Such testing is also likely to introduce human error that will cause
outages such as items outlined in the NERC lessons learned” and therefore such testing will
result in more outages than actual failures. An equivalent non-destructive test needs to be
identified to allow entities to sufficiently trace and test trip paths without taking multiple substation
line outages to physically test a lockout or breaker failure scheme.
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Response: Thank you for your comments.
1. The “Purpose” is defined by the SAR.
2. Requirement R1 and Requirement R4, Part 4.2.1 have been modified as you suggested.
3. The SDT instead elected to remove Requirement R2.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
5. Applicability 4.2.1 has been revised to remove ‘applied on”. The SDT believes that this addresses your concern. Applicability 4.2.2 and 4.2.3,
respectively, address UFLS and UVLS specifically, and are not related to 4.2.1. The Supplementary Reference Document has been revised to
clarify. PRC-005-2 would appear to apply to both cited examples.
6. This is properly a concern to be addressed within the current SDT that is developing a revised definition of Bulk Electric System.
7. The date in Clause F of the standard related to the Supplementary Reference Document has been revised.
8. a. The SDT disagrees. Station dc supply for UFLS/UFLS only is limited in its impact, and the SDT believes that using the same intervals as for the
related control circuits.
b. “Tolerances” does not fully describe the parameters for maintenance of station dc supply; “perform as designed” is far more inclusive.
c. The SDT intends that tripping of the interrupting device for UFLS/UVLS is not required, but that the other portions of the dc control circuitry still
shall be maintained. See Section 15.3 of the Supplementary Reference Document.
d. The SDT believes that mechanical solenoid-operated devices share performance attributes (and failure modes) with electromechanical relays
and need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these
devices supports those intervals
LCRA Transmission Services
Corporation
No
MidAmerican Energy
Yes
1. MidAmerican remains concerned that including requirements for testing of electromechanical trip or
auxiliary devices (Table 1-5 Row 3) will in some cases require entire bus outages that will compromise
the BES reliability due to the need for entities across the US to take multiple BES elements out of service
during the testing. If this requirement is retained additional time should be included in the implementation
plan to allow for system modifications, such as the installation of relay test switches, to potentially allow
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for this testing while minimizing testing outages.
2. Clarify that in the definition of Component Type that Transmission Owners are allowed the latitude to
designate their own definitions for each of the Component Types, not just control circuits.
3. In the implementation schedule time periods are provided within which compliance deadlines and
percentages of compliance are given. The following clarifications are recommended:
1. In calculating percentage of compliance for purposes of demonstrating progress on the implementation
plan the percentages are calculated based on the total population of the protection system components
that an entity has that fit the component category and allowable interval.
2. To obtain compliance with the percentage completion requirements of the implementation schedule an
entity needs to have completed at least one prescribed maintenance activity of that component type and
interval.
4.
In the purpose statement delete “affecting” and replace it with “protecting”. The purpose of the standard
deals with systems that protect the BES.
5.
In sections R1 and R4.2.1 delete “applied on or” as unneeded and potentially confusing. The goal is to
cover protection systems designed to protect.
6.
Clarify the meaning of “state of charge” on page 14 in Table 1-4.
7.
In Table 1-4 Component Type Station dc Supply, “Any dc supply for a UFLS or UVLS system” should
have the same maximum maintenance period as other dc supplies.
8.
Table 1-5 Component Type Control Circuitry, the table allows for unmonitored trip coils for UFLS or UVLS
breakers to have “no periodic maintenance”. The PRC-005-2 Supplementary Frequently Asked
Question #7B and #7C give excellent reasoning for not requiring maintenance on the trip coil
component due to the larger number of failures that would be required to have any substantial impact to
the BES as well as the statement that distribution breakers are operated often on just fault clearing duty
already. We believe that the unmonitored control circuitry has the same level of minimal BES impact
and is also being tested each time the distribution breaker undergoes fault clearing duty. With this
logic, we do not see why there would be different maintenance requirements for these two components.
Response: Thank you for your comments.
1. The SDT believes that mechanical solenoid-operated devices share performance attributes (and failure modes) with electromechanical relays and
need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices
supports those intervals.
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2. For components other than control circuitry, the SDT believes that identification of the components as established within the draft Standard is
appropriate. There is no latitude regarding component types.
3. The SDT believes that the Implementation Plan clearly agrees with your interpretation, and no clarification seems necessary.
4. The “Purpose” is defined by the SAR.
5. Requirement R1 and Requirement R4, Part 4.2.1 have been modified as you suggested.
6. Table 1-4 has been revised to remove “state of charge” from the activities.
7. The SDT disagrees. Station dc supply for UFLS/UVLS only is limited in its impact, and the SDT believes that using the same intervals as for the
related control circuits is appropriate.
8. For the control circuitry of UFLS/UVLS, the relatively frequent breaker operations may not be reflective of proper functioning for UFLS/UVLS
function. Therefore, minimal maintenance activities are necessary for these cases.
Ameren
Yes
(1) We believe that R1.5 and R4.2 “Calibration tolerances or other equivalent parameters” requirements
should be removed. Neither the Supplement nor the FAQ address the expectation for them. While we agree
that tolerances are needed and used, they need not be specified as part of this standard.
(2) The Data retention is too onerous (a) For those components with numerous cycles between on-site audits,
retaining and providing evidence of the two most recent distinct maintenance performances and the date of
the others should be sufficient. Additionally, we are subject to self-certification, spot audits and/or inquiries at
any time between on-site audits as well. (b) For those components with cycles exceeding on-site audit
interval, retaining and providing evidence of the most recent distinct maintenance performance and the date
of the preceding one should be sufficient. Auditors will have reviewed the preceding maintenance record.
Retaining these additional records consumes resources with no reliability gain.
(3) Definition of the BES perimeter should be included in accordance with Project 2009-17 Interpretation.
(a)Facilities Section 4.2.1 “or designed to provide protection for the BES” needs to be clarified so that it
incorporates the latest Project 2009-17 interpretation. The industry has deliberated and reached a conclusion
that provides a meaningful and appropriate border for the transmission Protection System; this needs to be
acknowledged in PRC-005-2 and carried forward.
(4)System-connected station service transformers (4.2.5.5) should be omitted, because (a) Generating Plant
system-connected Station Service transformers should not be included as a Facility because they are serving
load. Omit 4.2.5.5 from the standard. There is no difference between a station service transformer and a
transformer serving load on the distribution system. This has no impact on the BES, which is defined as the
system greater than 100 kV. (b) system-connected station service transformers in the same table as well as
from table-to-table can be overwhelming. This would help keep Regional Entities and System Owners from
100
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
making errors.
(5) Retention of maintenance records for replaced equipment should be omitted. FAQ II 2B final sentence
states that documentation for replaced equipment must be retained to prove the interval of its maintenance.
We disagree with this because the replaced equipment is gone and has no impact on BES reliability; and
such retention clutters the data base and could cause confusion. For example, it could result in saving lead
acid battery load test data beyond the life of its replacement.
(6) Battery inspection every 4 months is sufficient. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for an
interval that might extend past three calendar months due to storms and outages must set a target interval of
two months thereby increasing the number of inspections each year by half again. This is unnecessarily
frequent. We suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar
months.
(7) PSMP Implement Date should commence at the beginning of a Calendar year. This is the most practical
way to transition assets from our existing PRC-005-1 plans.
(8) Please clarify the meaning of “state of charge” for batteries. Does this mean specific gravity testing or
what?
(9) Please clarify that instrument transformer itself is excluded. Please clarify that the instrument transformer
itself is excluded. The standard indicates that only voltage and current signals need to be verified in Table 13, but the recently approved Protection System definition wording can be mis-interpreted to mean they are
included. FAQ 11.3.A is helpful.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding one to validate that entities have been in compliance since the last
audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data retention in the posted standard to establish
this level of documentation. This seems to be consistent with the current practices of several Regional Entities.
3. When the interpretation (Project 2009-17) is approved, the SDT for PRC-005-2 will consider if the interpretation is appropriate for PRC-005-2 and
101
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
make associated changes.
4. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
5. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document.
Your comments will be considered within that activity. The SDT believes that entities should retain the evidence necessary to demonstrate
compliance for the entire period reflected within Data Retention, and the discussion within the Supplementary Reference Document suggests that
this includes records of retired equipment.
6. The SDT believes that the 3-month interval specified in the Standard is appropriate.
7. The guidance provided to the SDT provides that the implementation dates should begin on the first day of a calendar quarter.
8. Table 1-4 has been revised to remove “state of charge” from the activities.
9. The SDT intends that the instrument transformer and associated circuitry be verified to be functional, but believes that customary apparatus
maintenance (dielectric, infrared, etc) are not relevant to PRC-005-2. The SDT has decided to eliminate the FAQ and incorporate topics and
discussion from the FAQ within the Supplementary Reference Document.
Xcel Energy
Yes
1. Requirement R1.4 in part requires that the entity’s PSMP includes all monitoring attributes to include those
specified in Tables 1-1 through 1-5. Requirement R2 requires that entities that use maintenance intervals for
monitored Protection Systems shall verify those components possess the monitoring attributes identified in
Tables 1-1 through 1-5. The intent and differences between these 2 requirements is unclear. If an entity
does not choose to use monitored intervals, it makes no sense to require them to include the monitoring
attributes identified in Tables 1-1 through 1-5 within their PSMP. Furthermore if an entity fails to meet
requirement R1.4 for including identified monitoring attributes in its program, it will by default also have
violated R2. There seems the possibility of double jeopardy between R1.4 and R2. The intent of R2 is fairly
obvious but the intent of including monitoring attributes in R1.4 is not evident. Please provide a discussion
within the FAQ to better explain the differences between these two requirements as they relate to monitoring
attributes.
2. As written, requirement R1.5 and application of R1.5 acceptance criteria via requirement R4.2 would open
entities up to vague interpretations by compliance personnel as to what constitutes adequate acceptance
criteria – particularly in the area of subjective inspection results – e.g., battery cell visual inspections. We
recommend that R1.5 be re-stated to clarify that acceptance criteria need only be provided for numerically
measurable parameters. FAQs should be written to better explain the intent of R1.5 and to provide examples
of acceptance criteria and to hopefully drive consistency amongst compliance personnel interpretation of
acceptance criteria requirements. Consideration should be given to identifying which maintenance
requirements in the Tables would generate quantifiable and measurable test results for which acceptance
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
criteria would be expected.
Response: Thank you for your comments.
1. The SDT had concluded that Requirement R2 is redundant with Requirement R1, Part 1.4, and has deleted R2 (together with the associated
Measure and VSL).
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
END OF REPORT
103
Consideration of Comments on Non-binding Poll of VRFs and VSLs
associated with PRC-005-2 – Protection System Maintenance
(Project 2007-17)
The Project 2007-17 Drafting Team thanks all commenters who submitted comments on the
non-binding poll of VRFs and VSLs associated with the proposed revisions to PRC-005-2.
The standard and associated VRFs and VSLs were posted for a 30-day public comment
period from November 17, 2010 through December 17, 2010, with a 10-day ballot
beginning on December 10, 2010 through December 21, 2010. The stakeholders were
asked to provide feedback on the VRFs and VSLs. There were 28 sets of comments,
including comments from more than 46 different people from approximately 26 companies
representing 6 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_200717.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition,
there is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
2
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
1
Ameren Services
Kirit S. Shah
The Lower VSL for all Requirements should begin above 1% of the components. For example for
R4: “Entity has failed to complete scheduled program on 1% to 5% of total Protection System
components.” PRC-005-2 unrealistically mandates perfection without providing technical
justification. A basic premise of engineering is to allow for reasonable tolerances, even Six Sigma
allows for defects. Requiring perfection may well harm reliability in that valuable resources will be
distracted from other duties.
Thank you for your comments. The NERC criteria for VSLs do not currently permit them to
allow some level of non-performance without being in violation.
1,3,6
American Electric Power, AEP Marketing
Paul B. Johnson, Raj Rana, Edward P. Cox
1. The VSL table should be revised to remove the reference to the Standard Requirement 1.5
in the R1 “High” VSL.
2. All four levels of the VSL for R2 make reference to a “condition-based PSMP.” However,
nowhere in the standard is the term “condition-based” used in reference to defining ones
PSMP. The VSL for R2 should be revised to remove reference to a condition-based PSMP;
alternatively the Standard could be revised to include the term “condition-based” within the
Standard Requirements and Table 1.
3. In multiple instances, Table 1 uses the phrase “No periodic maintenance specified” for the
Maximum Maintenance Interval. Is this intended to imply that a component with the
designated attributes is not required to have any periodic maintenance? If so, the wording
should more clearly state “No periodic maintenance required” or perhaps “Maintain per
manufacturers recommendations.” Failure to clearly state the maintenance requirement for
these components leaves room for interpretation on whether a Registered Entity has
maintenance and testing program for devices where the Standard has not specified a
periodic maintenance interval and the manufacturer states that no maintenance is required.
4. Three different types of maintenance programs (time-based, performance-based and
condition-based) are referenced in the standard or VSLs, yet the time-based and conditionbased programs are neither defined nor described. Certain terms defined within the
definition section (such as Countable Event or Segment) only make sense knowing what
3
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
those three programs entail. These programs should be described within the standard itself
and not assume knowledge of material in the Supplementary Reference or FAQ.
Response
Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5
and the associated changes are addressed within the PSMP definition, and that
Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted
within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
2. The SDT concluded that Requirement R2 is redundant with Requirement R1, Part 1.4,
and has deleted Requirement R2 (together with the associated Measure and VSL).
3. If the indicated monitoring attributes are present, no “hands-on” periodic
maintenance is required, as the monitoring of the component is providing a
continuing indication of its functionality.
4. The term, “condition-based” has been removed from the draft standard. The other
terms are used, but are clear in the context in which they are used.
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
1
Beaches Energy Services
Joseph S. Stonecipher
The VRF of R1 should be Low since the attached tables are essentially the PSMP.
Thank you for your comments. The SDT disagrees; the Tables establish the intervals and
activities, and Requirement R1 addresses the establishment of an entity’s individual PSMP.
3
City of Green Cove Springs
Gregg R Griffin
4
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
1. Small entities with only one or two BES substations may not have enough components to
take advantage of the expanded maintenance intervals afforded by a performance-based
maintenance program. Aggregating these components across different entities doesn’t seem
too logical considering the variations at the sub-component level (wire gauge, installation
conditions, etc.)
2. Trip circuits are interconnected to perform various functions. Testing a trip path may
involve disabling other features (i.e. breaker failure or reclosing) not directly a part of the
test being performed. Temporary modifications made for testing introduce a chance to
unknowingly leave functions disabled, contacts shorted, jumpers lifted, etc. after testing has
been completed. Trip coils and cable runs from panels to breaker can be made to meet the
requirements for monitored components. The only portions of the circuitry where this may
not be the case is in the inter and intra-panel wiring. Because such portions of the circuitry
have no moving parts and are located inside a control house, the exposure is negligible and
should not be covered by the requirements. Entities will be at increased compliance risk as
they struggle to properly document the testing of all parallel tripping paths.
3. Table 1-4 requires a comparison of measured battery internal ohmic value to battery
baseline. Since battery manufacturers do not provide this value, it is unclear what the
“baseline” values ought to be if an entity recently began performing this test (assuming it’s
several years after the commissioning of the battery.) Would it be acceptable for an entity
to establish baseline values based on statistical analysis of multiple test results specific to a
given battery manufacturer and design?
4. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC008/011 as being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other
protection system components, e.g., communications (probably not applicable), voltage and
current sensing devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution system
protection, so, these activities would not be covered by other BES protection system
maintenance and testing. I'm sure we are testing batteries and the like, but, we are
probably not testing battery chargers and control circuitry, and, in many cases distribution
circuits are such that it is very difficult, if not impossible, to test control circuitry to the trip
coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one or two backup systems, there are thousands and thousands of UFLS relays and if one fails to operate, it
will not be noticeable to the event. It does make sense to test the relays themselves in part
to ensure that the regio0nsl UFLS program is being met, but, to test the other protection
system components is not worthwhile. Note that DC Supplies and most of the control
5
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
circuitry of distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits, reducing the
value of testing to just about null. However, this version is better than prior versions
because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry.
5. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of
"transmission Protection System" and should state: "Protection Systems applied on, or
designed to provide protection for a BES Facility and that trips a BES Facility"
6. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the
definition of Protection System (recently approved) does not clearly exclude "non-electrical"
protection, the Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of transformers, etc.
should not be included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical the VRF of R1 should be Low since
the attached tables are essentially the PSMP.
Thank you for your comments.
1. Entities are not required to use performance-based maintenance programs.
Requirement R3 and Attachment A are provided for the use of entities that can (and
desire to) avail themselves of this approach.
2. The requirement relative to control circuitry does not explicitly require trip or functional
testing of the entire path; it requires that entities verify all paths without specifying the
method of doing so. Please see Section 15.5 of the Supplementary Reference Document
for a detailed discussion.
3. Typical baseline values for various types of lead-acid batteries can be obtained from the
test equipment manufacturer, the battery vendor, and perhaps other sources for
batteries that are already in service. For new batteries, the initial battery baseline ohmic
values should be measured upon installation and used for trending.
4. For UFLS and UVLS, the maintenance activities related to station dc supply and control
circuitry are somewhat constrained relative to similar activities for Protection Systems in
general. Regardless, without proper functioning of these component types, UFLS and
UVLS will not respond as expected, and will therefore degrade BES system reliability,
particularly during the stressed system conditions for which UFLS and UVLS are
installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and UVLS
from maintenance activities relate to the interrupting device trip coil.
5. This interpretation is not yet approved. When this interpretation is approved, the SDT will
6
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
incorporate it within PRC-005-2. However, the SDT has made changes to Applicability
4.2.1.
6. The recently-balloted revision of the definition of Protection System, which has been
approved by the NERC Board of Trustees and will soon be filed with FERC for approval,
clearly includes only protective relays that respond to electrical quantities. As for auxiliary
relays, the interpretation to which you refer states that they are not explicitly included, but
are included to the degree that an entity’s Protection System control circuitry addresses
them (which has been identified as a reliability gap), and are being added to PRC-005-2 to
resolve the gap.
Segment
Organization
Member
Comment
Response
1, 5, 6
Consolidated Edison Co. of New York
Christopher L de Graffenried, Wilket (Jack) Ng, Nickesha P Carrol
VSL/VRF Ballot Comments: The Modified VSL’s and VRF’s –
1. Because all the requirements deal with protective system maintenance and testing,
violations could directly cause or contribute to bulk electric system instability, etc., the VRFs
should all be “High”.
2. The Time Horizons should all be “Operations Planning” because of the immediacy of a
failure to meet the requirements.
3. For the R1 Lower VSL, include a second part to read: Failed to identify calibration tolerances
or other equivalent parameters for one Protection System component type that establish
acceptable parameters for the conclusion of maintenance activities.
4. For the R1 Moderate VSL, suggest similar wording as for the Lower VSL but specifying two
Protection System component types.
5. For the R1 High VSL, suggest changing the wording of the 3rd part to be similar to the
Lower VSL to match the requirement and to cater for more than two Protection System
component types.
6. For the R3 Severe VSL, in part 3, replace “less” with fewer.
Thank you for your comments.
1. Consideration of the VRFs, in association with the VRF Guidelines, yields the VRFs as
established within the draft Standard.
2. The SDT has reviewed the time horizons, and believes that Requirement R1 is
properly assigned a Long-Term Planning time horizon, as the activities to develop a
program and to determine the monitoring attributes of components are performed
within the related time period. The SDT concluded that Requirement R2 is redundant
to Requirement R1 and has deleted Requirement R2 (together with the Measure and
7
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
VSL).
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5
and the associated changes are addressed within the PSMP definition, and that
Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The
associated VSL has also been revised.
4. Requirement R1 ‘Moderate’ appears to be similar to Requirement R1 ‘Lower’ as you
suggest.
5. The SDT believes that, if more than two Protection System component types are not
addressed, the ‘Severe’ VSL is appropriate.
6. The SDT believes that your suggestion is similar to the existing text, and declines to
modify the standard.
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
5
Constellation Power Source Generation, Inc.
Amir Y Hammad
The VRFs and VSLs still do not take into account smaller generation facilities that do not have as
many protection system components as other facilities. They are penalized much more heavily.
Thank you for your comments. The percentage levels within Requirement R4 are consistent
with many other NERC Standards, and are also consistent with the guidance within the NERC
VSL Guidelines.
4
Consumers Energy
David Frank Ronk
1. Table 1-3 states, “are received by the protective relays”. Does this require that the inputs to each
individual relay must be checked, or is it sufficient to verify that acceptable signals are received at
the relay panel, etc?
2. Relative to Table 1-5, the activities will likely require that system components be removed from
service to complete those activities. If the changes to the BES definition (per the FERC Order)
causes system elements such as 138 kV connected distribution transformers to be considered as
BES, these components can not be removed from service for maintenance without outaging
customers. The standard must exempt these components from the activities of Table 1-5 if the
activity would result in deenergizing customers.
3. For the component types addressed in Tables 1-3 and 1-5, the requirements may cause entities
to identify components very differently than they are currently doing, and doing so may take several
years to complete. The Implementation Plan for R1 and R4 is too aggressive in that it may not
8
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
permit entities to complete the identification of discrete components and the associated
maintenance and implement their program as currently proposed. We propose that the
Implementation Plan specifically address the components in Table 1-3 and 1-5 with a minimum of 3
calendar years for R1 and 12 calendar years after that for R4.
4. As for the interval in Table 1-4 regarding the battery terminal connection resistance, we believe
that an 18-month interval is excessively frequent for this activity, and suggest that it be moved to
the 6-calendar-year interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections every 4-years, rather
than measuring the terminal connection resistance to determine if the connections are sound.
Disregarding the interval, would this activity satisfy the “verify the battery terminal connection
resistance” activity?
Response
Thank you for your comments.
1. The SDT intends that the voltage and current signals properly reach each individual
relay, but there may be several methods of accomplishing this activity.
2. This concern seems more properly to be one to be addressed during the activities to
develop the new BES definition, rather than within PRC-005-2
3. The Implementation Plan for Requirement R1 has been modified from 6 months to 12
months. The Standard has also been modified (Requirement R1, Part 1.1) to not
specifically require identification of all individual Protection System components. The
Implementation Plan for Requirement R4 has been revised to add one year to all
established dates.
4. IEEE 450, 1188, 1106 all recommend this activity at a 12-month interval. Please see
Section 15.4.1 of the Supplementary Reference Document for a discussion of this
activity.
5. Re-torqueing the battery terminals would not meet this requirement.
Segment
Organization
Member
Comment
Response
Segment
5
Consumers Energy
James B Lewis
The issues raised in our comments to the proposed Standard need to be addressed.
Thank you for your comments. Please see our response to your comments which were
submitted during the formal comment period.
1, 3, 5, 6
9
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
Dominion
John K Loftis, Michael F Gildea, Mike Garton, Louis S Slade
VSL R3. How do you measure a percentage of countable events over a period of time? How are you
to determine what the total population to be considered? An entity should not be penalized if they
are following their program, correcting issues, and documenting all actions, even if there is a high
failure rate in an instance.
Thank you for your comments. Attachment A, to which Requirement R3 refers, specifies that
countable events are assessed on the basis of “for the greater of either the last 30
components maintained or all components maintained in the previous year.”
1, 3, 4, 5, 6
FirstEnergy Energy Delivery, FirstEnergy Solutions, Ohio Edison Company
Robert Martinko, Kevin Querry, Kenneth Dresner, Mark S Travaglianti
Please see FirstEnergy's comments submitted separately through the comment period posting.
Thank you for your comments. Please see our response to your comments which were
submitted during the formal comment period.
4, 5
Florida Municipal Power Agency
Frank Gaffney, David Schumann
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC008/011 as being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other
protection system components, e.g., communications (probably not applicable), voltage and
current sensing devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution system
protection, so, these activities would not be covered by other BES protection system
maintenance and testing. I'm sure we are testing batteries and the like, but, we are
probably not testing battery chargers and control circuity, and, in many cases distribution
circuits are such that it is very difficult, if not impossible, to test control circuitry to the trip
coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one or two backup systems, there are thousands and thousands of UFLS relays and if one fails to operate, it
will not be noticeable to the event. It does make sense to test the relays themselves in part
to ensure that the regio0nsl UFLS program is being met, but, to test the other protection
system components is not worthwhile. Note that DC Supplies and most of the control
10
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
circuitry of distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits, reducing the
value of testing to just about null. However, this version is better than prior versions
because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of
"transmission Protection System" and should state: "Protection Systems applied on, or
designed to provide protection for a BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the
definition of Protection System (recently approved) does not clearly exclude "non-electrical"
protection,the Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of transformers, etc.
should not be included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical the VRF of R1 should be Low since
the attached tables are essentially the PSMP.
Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and
control circuitry are somewhat constrained relative to similar activities for
Protection Systems in general. Regardless, without proper functioning of these
component types, UFLS and UVLS will not respond as expected, and will therefore
degrade BES system reliability, particularly during the stressed system conditions
for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5
specifically excludes UFLS and UVLS from maintenance activities relate to the
interrupting device trip coil.
2. This interpretation is not yet approved. When this interpretation is approved, the
SDT will incorporate it within PRC-005-2. However, the SDT has made changes to
Applicability 4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been
approved by the NERC Board of Trustees and will soon be filed with FERC for
approval, clearly includes only protective relays that respond to electrical quantities.
As for auxiliary relays, the interpretation to which you refer states that they are not
explicitly included, but are included to the degree that an entity’s Protection System
control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
Segment
6
11
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
Response
Florida Municipal Power Pool
Thomas E Washburn
the VRF of R1 should be Low since the attached tables are essentially the PSMP.
Thank you for your comments. The SDT disagrees; the Tables establish the intervals and
activities, and Requirement R1 addresses the establishment of an entity’s individual PSMP.
4
Fort Pierce Utilities Authority
Thomas W. Richards
The VRF of R1 should be Low since the attached tables are essentially the PSMP.
Thank you for your comments. The SDT disagrees; the Tables establish the intervals and
activities, and Requirement R1 addresses the establishment of an entity’s individual PSMP.
1, 3
Hydro One Networks, Inc.
Ajay Garg, Michael D. Penstone
Hydro One is casting a negative vote with the following comments:
1. R1 Lower - Include a second part as follows: “Failed to identify calibration tolerances or other
equivalent parameters for one Protection System component type that establish acceptable
parameters for the conclusion of maintenance activities. “
2. R1 Moderate - Similar wording as for the Lower VSL but catering for two Protection System
component types. R1 High - Change the wording of the 3rd part to be similar to the Lower VSL to
match the requirement and to cater for more than two Protection System component types.
Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5
and the associated changes are addressed within the PSMP definition, and that
Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted
within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
2. Requirement R1 ‘Moderate’ appears to be similar to Requirement R1 ‘Lower’ as you
suggest. The SDT believes that, if more than two Protection System component types
are not addressed, the ‘Severe’ VSL is appropriate.
Segment
Organization
5
Indeck Energy Services, Inc.
12
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Member
Comment
Response
Segment
Organization
Member
Comment
Response
Rex A Roehl
The Violation Risk Factors should not be the same for all registered entities because the risk in a
violation by a 20 MW wind farm connected at 115 kV is de minimis compared to that same violation
at a 2,000 MW transmission substation or generator. The basic structure of this revision to PRC-005
is totally defective. Combining 4 standards that each have something to do with relays into one
omnibus standard was wrongheaded. The Violation Severity Levels need to match the violation and
four arbitrary categories cannot do so for the myriad of components, systems and varying numbers
of them for one registered entity that are covered by this draft standard.
Thank you for your comments. The VRFs are not dependent on size, and must be assigned
on a requirement-by-requirement basis.
2
Independent Electricity System Operator
Kim Warren
1. R1 Lower - We suggest including a second part as follows: “Failed to identify calibration
tolerances or other equivalent parameters for one Protection System component type that
establish acceptable parameters for the conclusion of maintenance activities. “
2. R1 Moderate - We suggest similar to the Lower VSL but catering for two Protection System
component types. R1 High - We suggest changing the wording of the 3rd part to match the
requirement and to cater for more than two Protection System component types.
3. Editorial Comment to Severe VSL for R3: In part 3, replace “less” with “fewer”.
Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5
and the associated changes are addressed within the PSMP definition, and that
Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted
within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
2. Requirement R1 ‘Moderate’ appears to be similar to Requirement R1 ‘Lower’ as you
suggest. The SDT believes that, if more than two Protection System component types
are not addressed, the ‘Severe’ VSL is appropriate.
3. The SDT has elected not to change the VSL for Requirement R3 as suggested.
Segment
Organization
Member
1
Lake Worth Utilities
Walt Gill
13
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC008/011 as being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other
protection system components, e.g., communications (probably not applicable), voltage and
current sensing devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution system
protection, so, these activities would not be covered by other BES protection system
maintenance and testing. I'm sure we are testing batteries and the like, but, we are
probably not testing battery chargers and control circuity, and, in many cases distribution
circuits are such that it is very difficult, if not impossible, to test control circuitry to the trip
coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one or two backup systems, there are thousands and thousands of UFLS relays and if one fails to operate, it
will not be noticeable to the event. It does make sense to test the relays themselves in part
to ensure that the regio0nsl UFLS program is being met, but, to test the other protection
system components is not worthwhile. Note that DC Supplies and most of the control
circuitry of distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits, reducing the
value of testing to just about null. However, this version is better than prior versions
because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of
"transmission Protection System" and should state: "Protection Systems applied on, or
designed to provide protection for a BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the
definition of Protection System (recently approved) does not clearly exclude "non-electrical"
protection,the Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of transformers, etc.
should not be included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical
4. the VRF of R1 should be Low since the attached tables are essentially the PSMP.
5. Table 1-4 requires a comparison of measured battery internal ohmic value to battery
baseline. Since battery manufacturers do not provide this value, it is unclear what the
“baseline” values ought to be if an entity recently began performing this test (assuming it’s
several years after the commissioning of the battery.) Would it be acceptable for an entity
to establish baseline values based on statistical analysis of multiple test results specific to a
14
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
given battery manufacturer and design?
6. Small entities with only one or two BES substations may not have enough components to
take advantage of the expanded maintenance intervals afforded by a performance-based
maintenance program. Aggregating these components across different entities doesn’t seem
too logical considering the variations at the sub-component level (wire gauge, installation
conditions, etc.)
7. Trip circuits are interconnected to perform various functions. Testing a trip path may involve
disabling other features (i.e. breaker failure or reclosing) not directly a part of the test being
performed. Temporary modifications made for testing introduce a chance to unknowingly
leave functions disabled, contacts shorted, jumpers lifted, etc. after testing has been
completed. Trip coils and cable runs from panels to breaker can be made to meet the
requirements for monitored components. The only portions of the circuitry where this may
not be the case is in the inter and intra-panel wiring. Because such portions of the circuitry
have no moving parts and are located inside a control house, the exposure is negligible and
should not be covered by the requirements. Entities will be at increased compliance risk as
they struggle to properly document the testing of all parallel tripping paths.
Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control
circuitry are somewhat constrained relative to similar activities for Protection Systems in
general. Regardless, without proper functioning of these component types, UFLS and
UVLS will not respond as expected, and will therefore degrade BES system reliability,
particularly during the stressed system conditions for which UFLS and UVLS are
installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and UVLS
from maintenance activities relate to the interrupting device trip coil.
2. This interpretation is not yet approved. When this interpretation is approved, the SDT will
incorporate it within PRC-005-2. However, the SDT has made changes to Applicability
4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been
approved by the NERC Board of Trustees and will soon be filed with FERC for approval,
clearly includes only protective relays that respond to electrical quantities. As for auxiliary
relays, the interpretation to which you refer states that they are not explicitly included, but
are included to the degree that an entity’s Protection System control circuitry addresses
them(which has been identified as a reliability gap), and are being added to PRC-005-2 to
resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities and Requirement R1
addresses the establishment of an entity’s individual PSMP.
15
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
5. Typical baseline values for various types of lead-acid batteries can be obtained from the
test equipment manufacturer, the battery vendor, and perhaps other sources for
batteries that are already in service. For new batteries, the initial battery baseline ohmic
values should be measured upon installation and used for trending.
6. Entities are not required to use performance-based maintenance programs. Requirement
R3 and Attachment A are provided for the use of entities that can (and desire to) avail
themselves of this approach.
7. The requirement relative to control circuitry does not explicitly require trip or functional
testing of the entire path; it requires that entities verify all paths without specifying the
method of doing so. Please see Section 15.5 of the Supplementary Reference Document
for a detailed discussion.
Segment
Organization
Member
Comment
1
Lakeland Electric
Larry E Watt
The major reasons are that:
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC008/011 as being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other
protection system components, e.g., communications (probably not applicable), voltage and
current sensing devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution system
protection, so, these activities would not be covered by other BES protection system
maintenance and testing. I'm sure we are testing batteries and the like, but, we are
probably not testing battery chargers and control circuity, and, in many cases distribution
circuits are such that it is very difficult, if not impossible, to test control circuitry to the trip
coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one or two backup systems, there are thousands and thousands of UFLS relays and if one fails to operate, it
will not be noticeable to the event. It does make sense to test the relays themselves in part
to ensure that the regio0nsl UFLS program is being met, but, to test the other protection
system components is not worthwhile. Note that DC Supplies and most of the control
circuitry of distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits, reducing the
value of testing to just about null. However, this version is better than prior versions
because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry.
16
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of
"transmission Protection System" and should state: "Protection Systems applied on, or
designed to provide protection for a BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the
definition of Protection System (recently approved) does not clearly exclude "non-electrical"
protection,the Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of transformers, etc.
should not be included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical
4. the VRF of R1 should be Low since the attached tables are essentially the PSMP.
Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control
circuitry are somewhat constrained relative to similar activities for Protection Systems in
general. Regardless, without proper functioning of these component types, UFLS and
UVLS will not respond as expected, and will therefore degrade BES system reliability,
particularly during the stressed system conditions for which UFLS and UVLS are
installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and UVLS from
maintenance activities relate to the interrupting device trip coil.
2. This interpretation is not yet approved. When this interpretation is approved, the SDT will
incorporate it within PRC-005-2. However, the SDT has made changes to Applicability
4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been
approved by the NERC Board of Trustees and will soon be filed with FERC for approval,
clearly includes only protective relays that respond to electrical quantities. As for auxiliary
relays, the interpretation to which you refer states that they are not explicitly included, but
are included to the degree that an entity’s Protection System control circuitry addresses
them(which has been identified as a reliability gap), and are being added to PRC-005-2 to
resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities and Requirement R1
addresses the establishment of an entity’s individual PSMP.
Segment
Organization
Member
6
Lakeland Electric
Paul Shipps
17
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
Response
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
Small entities with only one or two BES substations may not have enough components to take
advantage of the expanded maintenance intervals afforded by a performance-based maintenance
program. Aggregating these components across different entities doesn’t seem too logical
considering the variations at the sub-component level (wire gauge, installation conditions, etc.)
Thank you for your comments. Entities are not required to use performance-based
maintenance programs. Requirement R3 and Attachment A are provided for the use of
entities that can (and desire to) avail themselves of this approach.
5,6
Luminant Energy, Luminant Generation Company LLC
Brad Jones, Mike Laney
Luminant commends the PRC-005-2 Standard Drafting Team for its quality efforts in producing this
version of the Standard however; Luminant must cast a negative ballot vote for the present version
of the VRFs and VSLs for this Standard. The negative vote against is solely based on the addition of
the VSL associated with Requirement R1 Part 1.5.
Thank you for your comments. The SDT has determined that the fundamental concerns of
Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been
removed. Requirement R4 has also been re-drafted to address various related concerns
noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
1,3,6
Manitoba Hydro
Joe D Petaski, Greg C. Parent, Daniel Prowse
-The high VSL for R1 “Failed to include all maintenance activities relevant for the identified
monitoring attributes specified in Tables 1-1 through 1-5” may be interpreted in different ways and
should be further clarified.
Thank you for your comments. The SDT modified the VSL for clarity.
2
Midwest ISO, Inc.
Jason L Marshall
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Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
Response
Segment
Organization
Member
Comment
1. We disagree with the VRFs for R3, R4, and R5. R3, R4, and R5 are administrative
requirements and duplicate to requirements in FAC-008 and FAC-009 that already require
communication of facility ratings including those limited by relays. Thus, it should be Lower.
2. We disagree with the High VRF for Requirement R6 because the criteria in attachment will
identify circuits that are not critical. If the criteria is modified per our comments on the
standard and in the ballot, then we would agree with a High VRF.
3. Requirement R7 should be deleted as it represents double jeopardy. Thus, we do not agree
with any VRF for it.
Thank you for your comments.
1. It appears that this comment was intended to be offered on some other project, and
does not appear relevant to PRC-005-2.
2. It appears that this comment was intended to be offered on some other project, and
does not appear relevant to PRC-005-2.
3. It appears that this comment was intended to be offered on some other project, and
does not appear relevant to PRC-005-2.
1
Nebraska Public Power District
Richard L. Koch
VRF’s:
The definition of a Medium Risk Requirement included on page 8 of the SAR states: "A requirement
that, if violated, could directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system."
1. The PSMP does not "directly" affect the electrical state or the capability of the bulk electric
system. A failure of a Protection System component is required to "directly" affect the BES.
Therefore, the PSMP has only an "indirect" affect on the electrical state or the capability of
the BES. Requirements R1 through R3 and their subparts are administrative in nature in
that they are comprised entirely of documentation. Therefore, I recommend changing the
Violation Risk Factor of Requirements R1, R2, and R3 to Lower to be consistent with the
Violation Risk Factors defined in the SAR.
VSL’s:
2. R2: Tables 1-1 through 1-5 refers to time-based maintenance programs. I recommend
changing "condition-based" to "time-based" in all four severity levels.
3. SAR Attachment B - Reliability Standard Review Guidelines states that violation severity
levels should be based on the following equivalent scores: Lower: More than 95% but less
than 100% compliant Moderate: More than 85% but less than or equal to 95% compliant
High: More than 70% but less than equal to 85% compliant Severe: 70% or less compliant
I recommend revising the percentages of the violation severity levels to be consistent with
19
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
the SAR.
4. R3: The performance-based maintenance program identified in PRC-005 Attachment A
provides the requirements to establish the technical justification for the initial use of a
performance-based PSMP and the requirements to maintain the technical justification for
the ongoing use of a performance-based PSMP. However, it appears the VSLs for
Requirement R3 only addresses the ongoing use of the technical justification. I recommend
revising the VSLs for R3 to include the initial use of the technical justification.
a. Item 2) of R3 Severe VSL is a duplicate of Item 2) of R3 Lower VSL. This item is
administrative in nature therefore I recommend deleting Item 2) from R3 Severe VSL.
b. The first and third bullets of item 4) of R3 Severe VSL are administrative in nature and
should be moved to the Lower VSL
c. R4: SAR Attachment B - Reliability Standard Review Guidelines states that violation
severity levels should be based on the following equivalent scores: Lower: More than
95% but less than 100% compliant Moderate: More than 85% but less than or equal to
95% compliant High: More than 70% but less than equal to 85% compliant Severe:
70% or less compliant I recommend revising the percentages of the violation severity
levels to be consistent with the SAR.
Thank you for your comments.
1. Requirements R1, R2, and R3 are not administrative; they are foundational. Without
the fundamental development of a PSMP, an entity is unlikely to actually implement a
PSMP that satisfies the reliability needs of the BES.
2. The SDT concluded that Requirement R2 is redundant with Requirement R1, Part 1.4,
and has deleted Requirement R2 (together with the associated Measure and VSL).
3. The guidelines within the SAR have been superseded by subsequent revisions to the
VSL Guidelines. The VSLs in the draft standard adhere to the latest VSL Guidelines
and to the June 19, 2008 FERC order on VSLs in Docket No RR08-04-000.
4. Part a – The VSL for Requirement R3 has been modified in consideration of your
comments.
Part b – These requirements are not administrative; they are foundational. Without
compliance with these requirements, an entity does not have an effective
performance-based PSMP, and may be detrimentally affecting reliability.
Part c – The latest VSL Guidelines also provide examples of VSLs similar to those in the
draft standard.
Segment
1
20
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
Oncor Electric Delivery
Michael T. Quinn
Oncor cast a negative ballot vote for the present version of the VRFs and VSLs for this Standard.
The negative vote against is solely based on the addition of the VSL associated with Requirement
R1 Part 1.5.
Thank you for your comments. The SDT has determined that the fundamental concerns of
Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been
removed. Requirement R4 has also been re-drafted to address various related concerns
noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
6
Seattle City Light
Dennis Sismaet
The proposed Standard PRC-005-2 is an improvement over the previous draft in that it provides
more consistency in maintenance and testing duration internals. Notwithstanding, two issues are of
concern to Seattle City Light such that it is compelled to vote no:
1) the establishment of bookends for standard verification and
2) the implementation timelines for entities with systems where electro-mechanical relays still
compose a significant number of components in their protection systems.
1. Bookends: Proposed Standard PRC-005-2 specifies long inspection and maintenance intervals, up
to 12 years, which correspondingly exacerbates the so-called “bookend” issue. To demonstrate that
interval-based requirements have been met, two dates are needed - bookends. Evidencing an initial
date can be problematic for cases where the initial date would occur prior to the effective date of a
standard. NERC has provided no guidance on this issue, and the Regions approach it differently.
Some, such as Texas Regional Entity, require initial dates beginning on or after the effective date of
a Standard. Compliance with intervals is assessed only once two dates are available that occur on or
after a standard took effect. Other regions, such as Western Electricity Coordinating Council
(WECC), require that entities evidence an initial date prior to the effective date of a standard. For
WECC, compliance with intervals is assessed as soon as a standard takes effect. Such variation
makes application of standards involving bookends uncertain, arbitrary, capricious, and in the case
of WECC, possibly illegal. Proposed Standard PRC-005-2 will be another such standard. Indeed this
Standard will involve by far the largest number of bookends of any NERC standard - many
thousands for a typical entity. Furthermore, the long inspection and maintenance intervals
21
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
introduced in the draft will require entities in WECC, for instance, to evidence initial bookend dates
prior to the date original PRC-005-1 took effect. For the 12-year intervals for CTs and VTs in
proposed Standard PRC-005-2, many initial dates will occur prior to the 2005 Federal Power Act that
authorized Mandatory Reliability Standards and even reach back before the 2003 blackout that
catalyzed the effort to pass the Federal Power Act. As a result, many entities in WECC maybe at risk
of being found in violation of proposed Standard PRC-005-2 immediately upon its implementation.
Seattle City Light requests that NERC address the bookends issue, either within proposed Standard
PRC-005-2 or in a separate, concurrent document.
Response
Segment
Organization
Member
2. Legacy Systems: Many entities still have legacy protection systems that rely upon electromechanical relays. Effective testing approaches differ between electro-mechanical and digital relay
systems. Thus, although the proposed standard rightly looks to the future of digital relays by
specifying testing and maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with legacy systems. In
example, auxiliary relay and trip coil testing may be essential to prove the correct operation of
complex, multi-function digital protection systems. However, for legacy systems with single-function
electro-mechanical components, the considerable documentation and operational testing needed to
implement and track such testing is not necessarily proportional to the relative risk posed by the
equipment to the bulk electric system. Performance testing of electro-mechanical systems,
particularly regarding control circuits, will require extensive disconnection and reconnection of
portions of the circuits. Such activities will likely cause far more problems on restoration-to-service
than they will locate and correct. As such, to assist entities in their implementation efforts, we
believe provision of alternatives are necessary, such as additional implementation time through
phasing and/or through technical feasibility exceptions.
Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008
“PRC-005 R2 Pre-June 18 Evidence”.
2. Please see Sections 8 and 15.3 of the Supplementary Reference Document for a
discussion on this topic. FERC Order 693 directs that NERC establish requirements for
the maintenance of the Protection System and control circuitry is a portion thereof.
Therefore, requirements for the maintenance of the control circuitry are necessary and
the SDT has developed those requirements in a fashion that affords entities with the
opportunity to best meet those requirements.
1,3, 3, 3
Southern Company Services, Inc., Alabama Power, Georgia Power, Mississippi Power
Horace Stephen Williamson, Richard J. Mandes, Anthony L Wilson, Don Horsley
22
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
Response
Segment
Organization
Member
Comment
Response
We disagree with the inclusion of the VSLs, VRFs, and time Horizons associated with the new
Requirements 1.5 and 4.2
Thank you for your comments. The SDT has determined that the fundamental concerns of
Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been
removed. Requirement R4 has also been re-drafted to address various related concerns
noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
5
U.S. Bureau of Reclamation
Martin Bauer P.E.
The VSL levels are not consistent with the true impact on reliability. Severe levels are assigned for
failing to document rather than failing to maintain components. Documentation requirements that
are not met should not be assigned a Severe level. The concept of penalizing an entity for failed
components without regard to why they failed is unreasonable. The severely levels should be based
on avoidable failures or failures that could have been detected if the entity had performed
maintenance.
Thank you for your comments.
VSLs depict the level to which an entity has failed to comply with the standard; VRFs reflect
the risk to the BES. Escalations within the VSLs specifically address more egregious
(severe) violations of the standard in accordance with the NERC VSL Guidelines.
23
Consideration of Comments on Initial Ballot — Protection System Maintenance and Testing (Project 2007-17)
Date of Initial Ballot: December 10 – 20, 2010
Summary Consideration: Many commenters opposed R1 part 1.5 and the associated text, and the SDT responded by removing this text.
Most of these comments were duplicates of those submitted in response to the formal comment period; the SDT responses are
duplicated as well. Please see the Summary Consideration for each of the posted questions within the Consideration of Comments.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Gerry
1
Adamski, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
Voter
Rodney
Phillips
Entity
Segment
1
Vote
Comment
Allegheny Power applauds the hard work that the Standards Draft Team has
exhibited in producing a clear and enforceable standard that will increase the
reliability of the Bulk Electric System. However, the addition of requirement 1.5 is
such a significant change in scope from the last draft that a further review of the
potential impact and any implementation concerns is required by AP and the
industry in general before we can consider voting in-favor of this standard.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Kirit S. Shah
Ameren
1
Negative
(1)We believe that R1.5 and R4.2 “Calibration tolerances or other equivalent
Services
parameters” requirements should be removed. Neither the Supplement nor the
FAQ address the expectation for them. While we agree that tolerances are needed
and used, they need not be specified as part of this standard. (2)
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Paul B.
American
1
Negative
Restructured Tables:
Johnson
Electric Power
1) Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12 years
for unmonitored control circuitry, yet other portions of control circuitry have a
maximum interval of 6 years. AEP does not understand the rationale for the
difference in intervals, when in most cases, one verifies the other. Also,
unmonitored control circuitry is capitalized in row 4 such that it infers a
defined term.
2) In the first row of table 1-4 on page 16, it is difficult to determine if it is a cell
that wraps from the previous page or is a unique row. This is important
1
Allegheny
Power
Negative
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Voter
Entity
Segment
Vote
Comment
because the Maximum Maintenance Intervals are different (i.e. 18 months vs
6 years). It is difficult to determine to which elements the 6 year Maximum
Maintenance Interval applies. AEP suggests repeating the heading “Monitored
Station dc supply (excluding UFLS and UVLS) with: Monitor and alarm for
variations from defined levels (See Table 2):” for the bullet points on this
page.
VSLs, VRFs and Time Horizons:
3) The VSL table should be revised to remove the reference to the Standard
Requirement 1.5 in the R1 “High” VSL.
4) All four levels of the VSL for R2 make reference to a “condition-based PSMP.”
However, nowhere in the standard is the term “condition-based” used in
reference to defining ones PSMP. The VSL for R2 should be revised to remove
reference to a condition-based PSMP; alternatively the Standard could be
revised to include the term “condition-based” within the Standard
Requirements and Table 1.
5) In multiple instances, Table 1 uses the phrase “No periodic maintenance
specified” for the Maximum Maintenance Interval. Is this intended to imply
that a component with the designated attributes is not required to have any
periodic maintenance? If so, the wording should more clearly state “No
periodic maintenance required” or perhaps “Maintain per manufacturers
recommendations.” Failure to clearly state the maintenance requirement for
these components leaves room for interpretation on whether a Registered
Entity has a maintenance and testing program for devices where the Standard
has not specified a periodic maintenance interval and the manufacturer states
that no maintenance is required.
FAQ and Supplementary Reference:
6) With such a complex standard as this, the FAQ and Supplementary Reference
documents do aid the Protection System owner in demystifying the
requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a) Section 5 of the Supplementary Reference, refers to “condition-based”
maintenance programs. However, nowhere in the standard is the term
“condition-based” used in reference to defining ones PSMP. The
Supplementary Reference should be revised to remove reference to a
condition-based PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard Requirements and
Table 1.
2
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Comment
b) Section 15.7, page 26, appears to have a typographical error “...can all be
used as the primary action is the maintenance activity...”
c) Figure 2 is difficult to read. The figure is grainy and the colors representing
the groups are similar enough that it is hard to distinguish between
groups.
7) “Frequently-Asked Questions”: With such a complex standard as this, the FAQ
and Supplementary Reference documents do aid the Protection System owner
in demystifying the requirements. But AEP holds strong doubt on how much
weight the documents carry during audits. It would be better to include them
as an appendix in the actual standard, but in a more compact version with the
following modifications:
a) The section “Terms Used in PRC-005-2” is blank and should be removed as
it adds no value.
b) Section I.1 and Section IV.3.G reference “condition-based” maintenance
programs. However, nowhere in the standard is the term “conditionbased” used in reference to defining ones PSMP. The FAQ should be
revised to remove reference to a condition-based PSMP; alternatively the
Standard could be revised to include the term “condition-based” within the
Standard Requirements and Table 1.
c) The second sentence to the response in Section I.1 appears to have a
typographical error “... an entity needs to and perform ONLY timebased...”.
8) General:
a) Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2
should be removed. Specifying calibration tolerances for every protection
system component type, while a seemingly good idea, represents a
substantial change in the direction of the standard. It would be very
onerous for companies to maintain a list of calibration tolerances for every
protection system component type and show evidence of such at an audit.
AEP believes entities need the flexibility to determine what acceptance
criteria is warranted and need discretion to apply real-time
engineering/technician judgment where appropriate.
b) Three different types of maintenance programs (time-based, performancebased and condition-based) are referenced in the standard or VSLs, yet
the time-based and condition-based programs are neither defined nor
described. Certain terms defined within the definition section (such as
Countable Event or Segment) only make sense knowing what those three
programs entail. These programs should be described within the standard
itself and not assume a knowledge of material in the Supplementary
3
Voter
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Response: Thank you for your comments.
Comment
Reference or FAQ.
c) “Protective relay” should be a defined term that lists relay function for
applicability. There are numerous ‘relays’ used in protection and control
schemes that could be lumped in and be erroneously included as part of a
Protection System. For example, reclosing or synchronizing relays respond
to voltage and hence could be viewed by an auditor as protective relays,
but they in fact perform traditional control functions versus traditional
protective functions.
1. The 6-year activities are all related to components with “moving parts”, and the 12-year activities are related to the other
portions of the control circuitry. The capitalized term has been corrected.
2. Table 1-4 has been modified in consideration of your comments.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised.
4. The SDT concluded that Requirement R2 is redundant with R1, Part 1.4, and has deleted R2 (together with the associated
Measure and VSL).
5. If the indicated monitoring attributes are present, no “hands-on” periodic maintenance is required, as the monitoring of the
component is providing a continuing indication of its functionality.
6. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part
of the standard.
A. The Supplemental Reference Document discusses condition-based maintenance in a conceptual manner, as a
generally-recognized term. The SDT did make some changes within the Supplemental Reference document to
clarify the manner in which condition-based maintenance is discussed.
B. This clause has been corrected.
C. A higher-quality version of Figure 2 has been substituted.
7. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part
of the standard.
a) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
b) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
c) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
4
Voter
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Comment
Document as appropriate. The SDT considered your comments during this activity.
8. A) The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated
VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
B) The term, “condition-based” has been removed from the draft standard. The other terms are used, but are clear in the
context in which they are used.
C) “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition
with PRC-005. Further, the applicability of generically-described protective relays is defined by the Applicability clause of
PRC-005-2.
Jason Shaver
American
Transmission
Company, LLC
1
Negative
ATC recognizes the substantial efforts that the SDT has made on PRC-005 and
appreciate the SDT’s modifications to this Standard based on previous comments
made. ATC looks forward to continuing to have a positive influence on this process
via the comment process, ballots and interaction with the SDT. ATC was very
close to an affirmative vote on this Standard prior to the unanticipated changes
that appeared in this most recent posting. These changes introduce a significant
negative impact from ATC’s perspective. Therefore, ATC is recommending a
negative ballot in the hope that our concerns regarding R 1.5 and R 4.2 and other
clarifications will be included with the standard.
1. Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part
1.5 and the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not
necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address various related concerns
noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document,
Section 8 for a discussion of this.
John
Bussman
Associated
Electric
Cooperative,
Inc.
1
Negative
AECI want to thanks the team for the efforts being put forth by the drafting team.
The table is much easier to follow and less confusing. AECI is voting negative
because of the battery inspection intervals.
1. We have commented before about the 3 months being excessive and
think it should be annually. However, with that being stated if you are
going to use three months as the interval then that means inspections will
have to be scheduled every 2 months to ensure the inspections happen
every 3 months. Therefore AECI request that the battery inspection
schedule be extended to every 4 months and then entities can schedule
inspections to be performed every 3 months to ensure that the inspections
are completed every 4 months.
5
Voter
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Comment
2. The same comment applies the the unmonitored communication circuits.
Change the time interval to 4 months. Then scheduling can be every 3
months instead of every 2 months.
3. When you go to Table 1-4 there is confusion with the the DC for a UFLS
or UVLS system. For the interval it states "When control circuits are
verified" Then I go to Table 1-5 the second line that discusses trip coils for
UFLS and UVLS the interval states "No periodic maintenance specified" Is
this what was intended?
Response: Thank you for your comments.
1. The SDT believes that the 3-month interval is proper.
2. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
3. The SDT intends that tripping of the interrupting device for UFLS/UVLS is not required, but that the other portions of the dc
control circuitry still shall be maintained. See Section 15.3 of the Supplementary Reference Document
Joseph S.
Beaches
1
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
Stonecipher
Energy
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new PRCServices
005 sweeps in other protection system components, e.g., communications
(probably not applicable), voltage and current sensing devices (e.g., instrument
transformers), Station DC supply, control circuitry. What we see as a problem is
that these components are all part of distribution system protection, so, these
activities would not be covered by other BES protection system maintenance and
testing. I'm sure we are testing batteries and the like, but, in many cases
distribution circuits are such that it is very difficult, if not impossible, to test
control circuitry to the trip coil of the breaker without causing an outage of the
customers on that distribution circuit. There is no real reliability need for this
either. Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will not be
noticeable to the event. It does make sense to test the relays themselves, in part,
to ensure that the regionsl UFLS program is being met; but, to test the other
protection system components is not worthwhile. Note that DC Supplies and most
of the control circuitry of distribution line breakers are "tested" frequently by
distribution circuits clearing faults such as animals, vegetation blow-ins, lightning,
etc., on distribution circuits, reducing the value of testing to just about nill.
However, this version is better than prior versions because it essentially requires
the entity to determine it's own period of maintenance and testing for UFLS/UVLS
for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project
2009-17) of "transmission Protection System" and should state: "Protection
Systems applied on, or designed to provide protection for a BES Facility and that
6
Voter
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Comment
trips a BES Facility."
3. Applicability, 4.2. - does not reflect the interpretation of Project 2009-10 that
excludes non-electrical protection (e.g., sudden pressure relays) and auxiliary
relays. Because the definition of Protection System (recently approved) does not
clearly exclude "non-electrical" protection,the Applicability section should. For
instance,, a vibration monitor, steam pressure, etc. protection of generators,
sudden pressure protection of transformers, etc. should not be included in the
standard. An alternative is to change the definition of Protection System to make
sure it only includes electrical.
Response: Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat
constrained relative to similar activities for Protection Systems in general. Regardless, without proper functioning of
these component types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability,
particularly during the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry,
Table 1-5 specifically excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within
PRC-005-2. However, the SDT has made changes to Applicability 4.2.1. in consideration of your comment.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
Donald S.
Watkins
Bonneville
1
Negative
Please see BPA's formal comments submitted on 12/16/10. Our concerns have not
Power
been adequately addressed.
Administration
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
Paul Rocha
CenterPoint
Energy
1
Negative
1) CenterPoint Energy cannot support this proposed Standard. Any standard that
requires a 35 page Supplementary Reference document and a 37 page FAQ Practical Compliance and Implementation document is much too prescriptive
and complex.
2) CenterPoint Energy is very concerned that a large increase in the amount of
documentation will be required in order to demonstrate compliance - with no
resulting reliability benefit. CenterPoint Energy believes this Standard could
actually result in decreasing system reliability, as the Standard proposes
excessive maintenance requirements. The following is included in the
7
Voter
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Comment
Supplementary Reference document (page 8): “Excessive maintenance can
actually decrease the reliability of the component or system. It is not unusual
to cause failure of a component by removing it from service and restoring it.”
System reliability can be even further reduced by the number of transmission
line and autotransformer outages required to perform maintenance.
3) In addition, the following is included in the FAQ - Practical Compliance and
Implementation document: “PRC-005-2 assumes that thorough commission
testing was performed prior to a protection system being placed in service.
PRC-005-2 requires performance of maintenance activities that are deemed
necessary to detect and correct plausible age and service related degradation
of components such that a properly built and commission tested Protection
System will continue to function as designed over its service life.” CenterPoint
Energy believes some proposed requirements, such as wire checking a relay
panel, do not conform to this statement. CenterPoint Energy’s experience has
been that panel wiring does not degrade with age and service and that
problems with panel wiring, after thorough commissioning, is not a systemic
issue.
Response: Thank you for your comments.
1. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate.
2. FERC Order 693 directed that NERC establish maximum maintenance intervals. The documentation required should not
expand dramatically from the documentation currently required to demonstrate compliance. An entity may minimize hands-on
maintenance by utilizing monitoring to extend the intervals.
3. The standard does not require “wire-checking,” but instead generically specifies “verification” – however an entity chooses to
do so.
Jack Stamper
Clark Public
Utilities
1
Negative
My no vote reflects my concern regarding the testing of Station DC Supply (Table
1-4) and Alarming Paths (Table 2). The SDT has provided much clarity to this
standard in the testing requirements for relays, communication systems, voltage
and current sensing devices, and control circuitry.
1. Table 1-4 is still confusing. There are five separate categories of unmonitored
Station DC Supply testing requirements. It is unclear whether these categories
are to be combined or if they are mutually exclusive. The first category applies
to “Any unmonitored station dc supply not having the monitoring attributes of
a category below” and appears to be a set of inspection and verification
8
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requirements that are generally applicable to all unmonitored Station DC
Supplies. The next four categories are applicable to Station DC Supply with
specified types of batteries. If a station has unmonitored vented lead-acid
batteries, are the batteries ONLY subject to the testing requirements for VLA
batteries? OR would these batteries ALSO be subject to the requirements of
the first category?
It appears that the intent is for all Station DC Supply not having any
monitoring attributes to be tested and maintained in accordance with the first
category as well as the second through fifth category that is applicable. If this
is the case, the SDT should consider revising the Component Attributes in
Table 1-4 for the first category of Unmonitored Station DC Supplies to the
following: Any unmonitored station dc supply not having the monitoring
attributes of a category below. (excluding UFLS and UVLS). Station DC Supply
devices applicable under these Table 1-4 general requirements will have
additional testing requirements as described below for non-battery systems,
VRLA battery systems, VLA battery systems, and Ni-Cad battery systems.
2. Do monitored batteries need to have all of the monitoring attributes listed or
does having some of the monitoring attributes qualify a device as "Monitored?"
The frequently asked questions examples on pages 30 - 32 seem to indicate
that if only some of the items are monitored, the Station DC Supply is
considered “Monitored” as long as other items are tested or verified.
If this is the case, the SDT should consider revising the Component Attributes
in Table 1-4 for the first category of Monitored Station DC Supplies to the
following: Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2): o Station
dc supply voltage (voltage of battery charger) o State of charge of the
individual battery cell/units o Battery continuity of station battery o Cell-tocell (if available) and battery terminal resistance. Monitored Station dc supply
will have one or more of the above listed conditions monitored or alarmed with
the remainder of the conditions subject to inspection and verification activities.
3. In Table 2, the first Component Attribute for Alarm Paths contains the
requirement that “Alarms are automatically reported within 24 hours of
DETECTION to a location where corrective action can be taken.” I believe the
term “automatically” should be removed. This term implies an automated
process without human intervention. However, many facilities (i.e. generator
9
Voter
Entity
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Comment
protection devices or manned substations) have protective devices that while
not being subject to continuous monitoring, are visually inspected in daily or
twice daily inspections. If protection devices have internal self-diagnostics that
provide an alarm (i.e. failure indication on faceplate, relay interrogation, or
LED failure indicator) and these devices are inspected one or more times per
day, failures or malfunctions would be reported within the 24 hour DETECTION
time. This appears to be within the intent of the standard which is to make
sure that failed protective devices do not remain in failure longer than 24
hours without notification to a location where corrective action can be taken.
Response: Thank you for your comments.
1. Table 1-4 has been modified in consideration of your comments.
2. Table 1-4 has been modified in consideration of your comments, and has been revised to remove “state of charge”.
3. “Automatically” has been removed from Table 2 in consideration of your comment.
Danny
Cleco Power
1
Negative
Cleco applies its’ UFLS on the distribution grid with each UF relay individually
McDaniel
LLC
tripping a relatively low value of load thru breakers and reclosers. Since our
program is implemented via a large number of individual components, breakers,
reclosers, and individual batteries, the failure of any one component will have a
minimal impact on the effectiveness of the overall UFLS program within our
region. Therefore, the verification of sensing devices, dc supply voltages, and the
paths of the control circuit and trip circuits on the UFLS systems implemented on
the distribution grid is unnecessary.
Response: Thank you for your comments. The SDT disagrees; the sensing devices, control circuitry and dc supply related to UFLS
has an effect on the performance of the UFLS. The SDT has, however, respected the overall impact on the control circuitry of
individual UFLS on BES reliability by requiring that UFLS be subjected to a subset of the overall sensing devices, control circuitry
and dc supply maintenance activities.
Paul Morland Colorado
1
Negative
CSU offers the following comments:
Springs
1. The document refers to the "BES" or "Bulk Electrical System" yet we have been
Utilities
unable to get a clear definition as to what that is.
2. 1.5 Because some calibration tolerances, such as communications schemes,
change with the weather conditions, establishing tolerances could be difficult if
the weather conditions are not factored into the tables.
3. 4.2.5.4 There needs to be a clear definition for “Station Service Transformers”.
4. The reference to testing tolerances implies that test equipment must be
calibrated to some standard, which this document does not discuss, and leaves
a very wide interpretation for what this standard is, or the required calibration
is required.
5. Table 1-3 Voltage and current devices may be connected to a meter and
compared to a reference source to verify proper operation of the CT or PT.
This seems to be at error in thinking that only microprocessor relays can be
10
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Comment
used to verify CT or PT’s. Also in many PT’s there is more than one winding
and tap, or which this standard seems to imply that only one needs to be
monitored to verify the correct function of all of the windings and taps. If I
were to follow this logic, I only need to monitor one winding of a dual core CT.
Response: Thank you for your comments.
1. Bulk Electric System is defined by NERC, and further defined by the Regional Entities. Please refer to these definitions.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. Station Service transformer provide power to the auxiliary busses of generating plants. Some alternative names for these
devices are “unit auxiliary transformers”, “station auxiliary transformers”, The SDT believes that these devices are
commonly understood throughout industry and therefore require no definition.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
5. Table 1-3 does not prescribe how the voltage and current sensing device inputs to the protective relays shall be verified, just
that they be verified according to the established intervals. Please see Section 15.2 of the Supplementary Reference
Document for a discussion on this topic.
Christopher L
de
Graffenried
Consolidated
Edison Co. of
New York
1
Negative
PRC-005 Initial Ballot Comments:
1. The Tables - The wording “Component Type” is not necessary in each
title. Just the equipment category should be listed--what is now shown as
“Component Type - Protective Relay”, should be Protective Relay.
However, Protective Relay is too general a category. Electromechanical
relays, solid state relays, and microprocessor based relays should have
their own separate tables. So instead of reading Protective Relay in the
title, it should read Electromechanical Relays, etc. This will lengthen the
standard, but will simplify reading and referring to the tables, and
eliminate confusion when looking for information. The “Note” included in
the heading is also not necessary. “Attributes” is also not necessary in the
column heading, “Component” suffices.
2. Other Comments - In general, the standard is overly prescriptive and
complex. It should not be necessary for a standard at this level to be as
detailed and complex as this standard is. Entities working with
manufacturers, and knowledge gained from experience can develop
adequate maintenance and testing programs.
3. Why are “Relays that respond to non-electrical inputs or impulses (such
11
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4.
5.
6.
7.
8.
9.
as, but not limited to, vibration, pressure, seismic, thermal or gas
accumulation)...” not included? The output contacts from these devices
are oftentimes connected in tripping or control circuits to isolate problem
equipment.
Due to the critical nature of the trip coil, it must be maintained more
frequently if it is not monitored. Trip coils are also considered in the
standard as being part of the control circuitry. Table 1-5 has a row labeled
“Unmonitored Control circuitry associated with protective functions”,
which would include trip coils, has a “Maximum Maintenance Interval” of
“12 Calendar Years”. Any control circuit could fail at any time, but an
unmonitored control circuit could fail, and remain undetected for years
with the times specified in the Table (it might only be 6 years if I
understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure,
then the system must be operated in real time assuming that that breaker
will not trip for a fault or an event, and backup facilities would be called
upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker
unable to trip), instead of one line tripping, you might have many more
lines deloaded or tripped because of a bus having to be cleared because
of a breaker failure initiation. The bulk electric system would have to be
operated to handle this contingency.
In reference to the FAQ document, Section 5 on Station dc Supply,
Question K, clarification is needed with respect to dc supplies for
communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation,
would the standard apply to these batteries or not?
To define terms only as they are used in PRC-005-2 is inviting confusion.
Although they may be unique to PRC-005-2, some or all of them may be
used in future standards, some already may be used in existing standards,
and may or may not be deliberately defined. Consistency must be
maintained, not only for administrative purposes, but for effective
technical communications as well.
What is the definition of “Maintenance” as used in the table column
“Maximum Maintenance Interval”? Maintenance can range from cleaning a
relay cover to a full calibration of a relay.
A control circuit is not a component, it is made up of components.
Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify
calibration tolerances or other equivalent parameters...” means, and may
be subject to different interpretations by entities and compliance
12
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enforcement personnel.
10. In the Implementation plan for Requirement R1, recommend changing
“six” to fifteen. This change would restore the 3-month time difference
that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require
regulatory approval. It will ensure equity for those entities located in
jurisdictions that do not require regulatory approval, as is the case in
Ontario.
11. The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It
seems to continue to the next page to a new box. There are multiple
activities without clear delineation.
12. Regarding station service transformers, Item 4.2.5.5 under Applicability
should be deleted. The purpose of this standard is to protect the BES by
clearing generator, generator bus faults (or other electrical anomalies
associated with the generator) from the BES. Having this standard apply
to generator station service transformers, that have no direct connection
to the BES, does meet this criteria. The FAQs (III.2.A) discuss how the
loss of a station service transformer could cause the loss of a generating
unit, but this is not the purpose of PRC-005. Using this logic than any
system or device in the power plant that could cause a loss of generation
should also be included. This is beyond the scope of the NERC standards.
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that
minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent maintenance, a
performance-based program in accordance with Requirement R3 and Attachment A is an option.
3. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection
System definition. Also, there is currently no technical basis for the maintenance of the devices which respond to non-electrical
quantities on which to base mandatory standards related either to activities or intervals. Absent such a technical basis, we are
currently unable to establish mandatory requirements, but may do so in the future if such a technical basis becomes available.
4. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year interval.
You can maintain these devices more frequently if you desire.
5. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the communications
system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The specific station dc
supply requirements (Table 1-4) do not apply to the dc supply associated only with communications systems. The SDT decided to
13
Voter
Entity
Segment
Vote
Comment
eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate.
The SDT considered your comments during this activity.
6. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms,
either now or in the future, may not be consistent with the terms used here. They are defined only for clarify within this standard.
The SDT will confirm with NERC staff that this approach is acceptable.
7. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are specified in
the Activities column. The term is capitalized in the column title in conformance with normal editorial practice as a title, rather
than as a definition.
8. For purposes of this standard, the control circuit IS defined as one component type..
9. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed
within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4
has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Please see Supplementary Reference Document, Section 8 for a discussion of this.
10. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making it
consistent with the remainder of the Implementation Plan.
11. Table 1-4 has been further modified for clarity.
12. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
Robert W.
Roddy
Dairyland
Power Coop.
1
Negative
In Table 1-5 it is unclear which devices the Maximum Maintenance Intervals would
be held to, such as trip coils of circuit breakers and coils of electromechanical trip
or auxiliary relays whose continuity and energization are monitored and alarmed.
Response: Thank you for your comments. Trip coils of circuit breakers have a 6-year interval for physical operation. Coils of
lockout and auxiliary relays also have a 6-year interval for physical operation. Control circuitry whose continuity and energization or
ability to operate are monitored and alarmed require no hands-on maintenance.
John K Loftis
Dominion
Virginia Power
1
Negative
Dominion is opposed to this version because Requirement R1.5 is overly
prescriptive, requiring an extraordinary level of documentation, with little
anticipated improvement in reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
14
Voter
Entity
George R.
Bartlett
Entergy
Corporation
Segment
1
Vote
Negative
Comment
The restructured tables are generally much clearer and the SDT is to be
commended on their efforts.
1. However, we believe the Alarming Point Table needs additional
clarification with regard to the Maximum Maintenance Interval. If an
“alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there
isn’t necessarily a maximum interval established as there is for Protection
System components. Also, if an entity’s alarm producing device
maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum
intervals for the alarm producing device of that entity. On that basis, we
suggest the interval verbiage be revised to “When alarm producing device
or system is verified, or by sections as per the monitored
component/protection system specified maximum interval as applicable”.
Alternately, if the intention is to establish maximum intervals as simply
being no longer than the individual component maintenance intervals as
we suggest for inclusion above, then the verbiage should be revised to
“When alarm producing component/protection system segment is
verified”. In either case, are we to interpret monitored components with
attributes which allow for no periodic maintenance specified as not
requiring periodic alarm verification?
2. R1.5 calls for “identification of calibration tolerances or equivalent
parameters...” whereas the associated VSL references “failure to establish
calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply
“identify” or document such calibration tolerances would be analogous to
the severity level(s) of a “failure to specify one" or the severity level
should be consistent with the other elements of R1. Both cases appear to
be more of a documentation issue as opposed to a failure to implement.
Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4? R1.5 calls for “identification of calibration tolerances
or equivalent parameters for each Protection System Component Type....”.
We believe the Supplementary Reference document should provide
additional information and examples of calibration tolerances or equivalent
parameters which would be expected for the various component types.
Especially for any “equivalent” parameters which would be required for
compliance for a component type besides protective relays. Adding
Requirement 1.5 is a significant revision and raises questions as to how
broadly an accuracy or equivalent parameter requirement and associated
15
Voter
Entity
Segment
Vote
Comment
documentation would need to be addressed by entities and/or will be
measured for compliance. Discussion on this new requirement does not
seem to be addressed anywhere in the FAQ or Supplementary Reference
documents. Additionally, to the best of our knowledge, the need for such
a requirement was not brought up as a concern or comment on the prior
draft version of this standard, and in the context of a requirement need,
we don’t believe it has been attributed to or actually poses any significant
reliability risk. We do not believe this requirement is justified.
Response: Thank you for your comments.
1. The Maximum Maintenance Interval column entry in Table 2 has been revised to state, “When alarm producing Protection
System component is verified” to clarify this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Robert
FirstEnergy
1
Negative
Please see FirstEnergy's comments submitted separately through the comment
Martinko
Energy
period posting.
Delivery
Response: Thank you for your comments.
Please see our responses to your comments from the formal comment period.
Gordon
Pietsch
Great River
Energy
1
Negative
1. We believe that requiring an entity to identify calibration tolerances in
their PSMP does not add a material benefit and does not contribute to
increased reliability. In addition we believe that R1.5 should be rewritten
to state that a Relay test report should show when a Relay fell out of
tolerance. R4.2 should be rewritten to state that if a test report does show
that a Relay was out of tolerance it should be required to show that
resolution was initiated.
2. The Activities section of Table 1.3 should be revised to include that the
signals do not have to come from energized voltage or current sensing
devices. The current or voltage signals can come from a test set. Note: It
may be difficult to energize CTs or VTs for large capacitor banks, reactors,
or generating units.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
16
Voter
Entity
Segment
Vote
Comment
2. Table 1-3 has been modified in consideration of your comments.
Ajay Garg
Hydro One
Networks,
Inc.
1
Negative
Hydro One is casting a negative vote with the following comments:
1. The added requirement R1, Part 1.5 is vague and needs clarification. It is not
clear what “Identify calibration tolerances or other equivalent parameters”
means and as written will be subject to different interpretations by entities and
compliance enforcement personnel. The addition of this new part of
Requirement R1 that requires the Owners to “identify calibration tolerances or
other equivalent parameters for each Protection System component type” is
onerous and contributes little to the reliability of the BES.
2. Changes introduced to the Implementation Plan since the last posting are not
consistent with respect to jurisdictions where no regulatory approval is
required. The previously posted implementation for Requirement R1 required
entities to be 100% compliant on the first day of the first calendar quarter
three months following applicable regulatory approvals, or in those
jurisdictions where no regulatory approval is required, on the first day of the
first calendar quarter six months following Board of Trustees adoption. The
amended implementation plan changed the three-month time to twelve
months in jurisdictions with regulatory approval required but left the same sixmonth time for the others. For consistency, the six months timeframe should
be changed to fifteen months.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making
it consistent with the remainder of the Implementation Plan.
Michael
Moltane
International
Transmission
Company
Holdings Corp
1
Negative
1. ITC votes "Negative" for the following reasons: Our negative ballot is
based on our objection to the 6 year test interval for auxiliary relays. We
believe our present maintenance period for auxiliary relays of 10 years is
adequate.
2. We also object to the requirement to verify acceptable levels of current
values are received by the protective relays. We believe our present
current transformer testing practice adequately insures acceptable levels
of current are received by the relays and have requested that this
procedure be approved. Detailed comments are included with our
17
Voter
Entity
Segment
Vote
Comment
responses to the 5 questions in the Comment Form associated with this
proposed Standard revision.
Response: Thank you for your comments.
1. The SDT believes that the appropriate interval for devices such as aux or lockout relays remains at 6 years, as these devices
contain “moving parts” which must be periodically exercised to remain reliable.
2.
Please see our response in the Comment Form.
Stan T. Rzad
Keys Energy
Services
1
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuity, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
that distribution circuit. There is no real reliability need for this either.
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regio0nsl UFLS program is being
met, but, to test the other protection system components is not
worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing
faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this
version is better than prior versions because it essentially requires the
entity to determine it's own period of maintenance and testing for
UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
18
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical
4. The VRF of R1 should be Low since the attached tables are essentially the
PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to 4.2.1 in consideration of your comment.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the establishment of an
entity’s individual PSMP.
Walt Gill
Lake Worth
1
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
Utilities
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuity, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
19
Voter
Entity
Segment
Vote
Comment
2.
3.
4.
5.
that distribution circuit. There is no real reliability need for this either.
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regionsl UFLS program is being met,
but, to test the other protection system components is not worthwhile.
Note that DC Supplies and most of the control circuitry of distribution lines
are "tested" frequently by distribution circuits clearing faults such as
animals, vegetation blow-ins, lightning, etc., on distribution circuits,
reducing the value of testing to just about null. However, this version is
better than prior versions because it essentially requires the entity to
determine it's own period of maintenance and testing for UFLS/UVLS for
DC Supply and control circuitry.
Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical
The VRF of R1 should be Low since the attached tables are essentially the
PSMP.
Table 1-4 requires a comparison of measured battery internal ohmic value
to battery baseline. Since battery manufacturers do not provide this value,
it is unclear what the “baseline” values ought to be if an entity recently
began performing this test (assuming it’s several years after the
commissioning of the battery.) Would it be acceptable for an entity to
establish baseline values based on statistical analysis of multiple test
results specific to a given battery manufacturer and design? o Small
entities with only one or two BES substations may not have enough
components to take advantage of the expanded maintenance intervals
afforded by a performance-based maintenance program. Aggregating
20
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
these components across different entities doesn’t seem too logical
considering the variations at the sub-component level (wire gauge,
installation conditions, etc.)
6. Trip circuits are interconnected to perform various functions. Testing a trip
path may involve disabling other features (i.e. breaker failure or reclosing)
not directly a part of the test being performed. Temporary modifications
made for testing introduce a chance to unknowingly leave functions
disabled, contacts shorted, jumpers lifted, etc. after testing has been
completed. Trip coils and cable runs from panels to breaker can be made
to meet the requirements for monitored components. The only portions of
the circuitry where this may not be the case is in the inter and intra-panel
wiring. Because such portions of the circuitry have no moving parts and
are located inside a control house, the exposure is negligible and should
not be covered by the requirements. Entities will be at increased
compliance risk as they struggle to properly document the testing of all
parallel tripping paths.
1.For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component types,
UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during the stressed
system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and
UVLS from maintenance activities related to the interrupting device trip coil.
2.This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration to your comment.
3.The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As for
auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the degree
that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and are being
added to PRC-005-2 to resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the establishment of an
entity’s individual PSMP.
5. Typical baseline values for various types of lead-acid batteries can be obtained from the test equipment manufacturer, perhaps
the battery vendor, and perhaps other sources for batteries that are already in service. For new batteries, the initial battery
baseline ohmic values should be measured upon installation and used for trending.
6. The requirement relative to control circuitry does not explicitly require trip or functional testing of the entire path; it requires that
entities verify all paths without specifying the method of doing so. Please see Section 15.5 of the Supplementary Reference
Document for detailed discussion.
21
Voter
Larry E Watt
Entity
Lakeland
Electric
Segment
1
Vote
Negative
Comment
The major reasons are that:
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuity, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
that distribution circuit. There is no real reliability need for this either.
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regio0nsl UFLS program is being
met, but, to test the other protection system components is not
worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing
faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this
version is better than prior versions because it essentially requires the
entity to determine it's own period of maintenance and testing for
UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
22
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
electrical
4. the VRF of R1 should be Low since the attached tables are essentially the
PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comment.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the establishment of an
entity’s individual PSMP.
Joe D Petaski Manitoba
1
Negative
1. Implementation Plan (Timeline) for R1: In areas not requiring regulatory
Hydro
approval, the 6 month time frame proposed for R1 is not achievable and is
not consistent with areas requiring regulatory approval. To be consistent,
the effective date for R1 in jurisdictions where no regulatory approval is
required should be the first day of the first calendar quarter 12 months
after BOT approval.
2. VSLs: The high VSL for R1 “Failed to include all maintenance activities
relevant for the identified monitoring attributes specified in Tables 1-1
through 1-5” may be interpreted in different ways and should be further
clarified.
3. Table 1-4: The requirements for batteries listed in Table 1-4 do not
appear to be consistent with the comments in the FAQ Section (V 1A
Example 1). Please see comments submitted during formal comment
period for further detail.
4. Table 1-4: The requirement for a 3 month check on electrolyte level
seems too frequent based on our experience. We would like to point out
that although IEEE std 450 (which seems to be the basis for table 1-4)
does recommend intervals it also states that users should evaluate these
recommendations against their own operating experience.
23
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments.
1. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making
it consistent with the remainder of the Implementation Plan.
2. The SDT does not understand your concern; further details are needed.
3. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
4. The SDT believes that the 3-month interval specified in the Standard is appropriate.
Terry
MidAmerican
1
Negative
MidAmerican remains concerned that including requirements for testing of
Harbour
Energy Co.
electromechanical trip or auxiliary devices (Table 1-5 Row 3) will in some cases
require entire bus outages that will compromise the BES reliability due to the need
for entities across the US to take multiple BES elements out of service during the
testing. If this requirement is retained additional time should be included in the
implementation plan to allow for system modifications, such as the installation of
relay test switches, to potentially allow for this testing while minimizing testing
outages.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Saurabh
National Grid
1
Negative
National Grid believes that this new Requirement as written subjects the
Saksena
Transmission Owner, Generation Owner or Distribution Provider to vague
interpretations of what the requirement means by compliance officials. The
addition of the new part of Requirement R1 that requires the Owners to “identify
calibration tolerances or other equivalent parameters for each Protection System
component type” is too intrusive and divisive for what it brings to the reliability of
the BES.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Richard L.
Nebraska
1
Negative
1. The PSMP definition inappropriately extends the maintenance program to
Koch
Public Power
include corrective maintenance. The first bullet of the Detailed Description
District
section of the SAR specifically states: "Analysis of correct operations or
misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard." The
comment in the SAR was directed toward the Purpose of PRC-017 since it
is the only one of the applicable PRC standards that included corrective
measures in its Purpose. However, the concept of not including corrective
maintenance in a maintenance standard should apply to all of the
24
Voter
Entity
Segment
Vote
Comment
2.
3.
4.
5.
applicable PRC standards. The same statement from the SAR identified
above was also included in the NERC SPCTF Assessment of Standards
referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment
of the Standards identified the need to expand the maintenance and
testing program to include corrective maintenance. I recommend deleting
the words "and proper operation of malfunctioning components is
restored." from the first sentence of the PSMP definition. I believe that
failure to do so exceeds the scope of the SAR.
Applicability Part 4.2.2: The ERO does not establish underfrequency loadshedding requirements. Those requirements will be established by
Reliability Standard PRC-006-1 when it is approved by FERC. I recommend
changing Accountability Part 4.2.2. to "...installed to provide last resort
system preservation measures." (Note this wording is consistent with the
Purpose of PRC-006-0.)
Applicability Part 4.2.5.4 and 4.2.5.5: Station Service transformers provide
energy to plant loads and not the BES. If these plant transformers are
included, why not include the rest of the plant systems? I recommend
deleting Applicability Part 4.2.5.4 and 4.2.5.5.
Requirement R4: The PSMP definition inappropriately extends the
maintenance program to include corrective maintenance. The first bullet
of the Detailed Description section of the SAR specifically states: "Analysis
of correct operations or misoperations may be an integral part of
condition-based maintenance processes, but need not be mandated in a
maintenance standard." The comment in the SAR was directed toward the
Purpose of PRC-017 since it is the only one of the applicable PRC
standards that included corrective measures in its Purpose. However, the
concept of not including corrective maintenance in a maintenance
standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC
SPCTF Assessment of Standards referenced in the SAR. Neither the SAR
nor the NERC SPCTF Assessment of the Standards identified the need to
expand the maintenance and testing program to include corrective
maintenance. I recommend deleting the words "including identification of
the resolution of all maintenance correctable issues" from the first
sentence of the Requirement. I believe that failure to do so exceeds the
scope of the SAR.
Requirement R4 Part 4.2: The PSMP definition inappropriately extends the
maintenance program to include corrective maintenance. The first bullet
of the Detailed Description section of the SAR specifically states: "Analysis
25
Voter
Entity
Segment
Vote
Comment
of correct operations or misoperations may be an integral part of
condition-based maintenance processes, but need not be mandated in a
maintenance standard." The comment in the SAR was directed toward the
Purpose of PRC-017 since it is the only one of the applicable PRC
standards that included corrective measures in its Purpose. However, the
concept of not including corrective maintenance in a maintenance
standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC
SPCTF Assessment of Standards referenced in the SAR. Neither the SAR
nor the NERC SPCTF Assessment of the Standards identified the need to
expand the maintenance and testing program to include corrective
maintenance. I recommend re-wording Requirement 4, Part 4.2 to state:
"Verify that the components are within the acceptable parameters
established in accordance with Requirement R1, Part 1.5 at the conclusion
of the maintenance activities." I believe that failure to do so exceeds the
scope of the SAR.
6. Measurement M4: The PSMP definition inappropriately extends the
maintenance program to include corrective maintenance. The first bullet
of the Detailed Description section of the SAR specifically states: "Analysis
of correct operations or misoperations may be an integral part of
condition-based maintenance processes, but need not be mandated in a
maintenance standard." The comment in the SAR was directed toward the
Purpose of PRC-017 since it is the only one of the applicable PRC
standards that included corrective measures in its Purpose. However, the
concept of not including corrective maintenance in a maintenance
standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC
SPCTF Assessment of Standards referenced in the SAR. Neither the SAR
nor the NERC SPCTF Assessment of the Standards identified the need to
expand the maintenance and testing program to include corrective
maintenance. I recommend deleting the words: "and initiated resolution of
identified maintenance correctable issues" from the last sentence of
Measurement M4. I believe that failure to do so exceeds the scope of the
SAR.
Response: Thank you for your comments.
1. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues
(discovered during maintenance activities) is included. The SDT considers this inclusion to be appropriate and necessary as
part of the maintenance program.
26
Voter
Entity
Segment
Vote
Comment
2. Under frequency load shedding requirements, whether established by regional Entities (current practice) or by EC, are ERO
requirements.
3. Clause 4.2.5.5 has been removed. Generator-connected station service transformers are essential to the continuing operation
of the generation plant; therefore, protection on these system components is included within PRC-005-2 if the generation
plant is a BES facility.
4. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues
(discovered during maintenance activities) in included. The SDT considers the inclusion to be appropriate and necessary as
part of the maintenance program.
5. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
6. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues
(discovered during maintenance activities) in included. The SDT considers the inclusion to be appropriate and necessary as
part of the maintenance program.
David H.
Northeast
1
Negative
1) Requirement 1.5 states “Identify calibration tolerances or other equivalent
Boguslawski
Utilities
parameters for each Protection System component type that establish acceptable
parameters for the conclusion of maintenance activities”. This requirement is too
vague and requires that the owner develop his own acceptable calibration
tolerances for “each” protection system component type. The Owners internally
generated calibration tolerances would then be subjected to the personal
interpretation of what this requirement means by compliance officials and
auditors. The confusion and divisiveness that this requirement will create far
outweigh its potential benefits.
2) Due to the critical nature of the trip coil, it should be maintained more
frequently if it is not monitored. Hence, it would be prudent to increase the test
frequency of unmonitored trip coil so that it is more frequent than monitored trip
coil.
3) In reference to the FAQ document, Section 5 on Station dc Supply, Question K,
clarification is needed with respect to dc supplies for communication within the
substation. For example, if the communication systems were run off a separate
battery in separate area in a substation, would the standard apply to these
batteries or not?
4) In section D.1.3., the statement regarding data retention for R2 needs to be
reworded. The words “performance based maintenance program” should be
changed to “time based maintenance program”, since R2 refers to a time based
maintenance program.
27
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year
interval. You can maintain these devices more frequently if you desire.
3. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the
communications system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The
specific station dc supply requirements (Table 1-4) do not apply to the dc supply associated only with communications
systems. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the
Supplementary Reference Document. Your comments have been considered within that activity.
4. The SDT concluded that R2 is redundant with R1, Part 1.4, and has deleted R2 (together with the associated Measure and VSL),
and data retention that reflects the previous R2.
Douglas G
Omaha Public 1
Negative
The three newly added requirements not approved by the drafting team are
Peterchuck
Power District
confusing.
1. OPPD believes that Article 1.4 needs to be deleted from the standard. It is
redundant and serves no purpose.
2. OPPD believes that Article 1.5 needs to be deleted from the standard.
There is a major concern on what an “acceptable parameter” is and how it
would be interpreted by the Regional Entities.
3. OPPD believes that Article 4.2 needs to be deleted from the standard.
There is no need for this article if Article 1.5 is deleted.
Response: Thank you for your comments.
1. The SDT disagrees; Requirement R1, Part 1.4 supports Requirement R1, Part 1.2, and seems necessary to assure that entities
have appropriately applied the longer intervals associated with monitored components. However, in consideration to your
comment the SDT has revised R1.4 and has also removed R2 because of redundancy to Requirement R1, Part 1.4.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
3. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this..
Chifong L.
Pacific Gas
1
Negative
1. PG&E submits a Negative vote on Draft 3 of PRC-005-2 due to the
Thomas
and Electric
addition of Requirement R1, Part 1.5. We do not agree with the addition
Company
of Requirement R1, Part 1.5 to the standard, which requires the Owners
to "identify calibration tolerances or other equivalent parameters for each
Protection System component type". We feel this is too prescriptive and
does not belong in the PSMP which should remain at a higher level of
detail. This new requirement, as written, can subject the Transmission
Owner, Generation Owner or Distribution Provider to vague interpretations
28
Voter
Entity
Segment
Vote
Comment
of what the requirement means by compliance officials. Additionally, the
new requirement could require documenting thousands of calibration
tolerances or other equivalent parameters for companies such as PG&E
that use many different types of relays. This level of detail does not
belong in the PSMP and would make it nearly impossible to manage.
Rather, the calibration tolerances used to test the protection system
components should reside in the Transmission Owner, Generation Owner
and Distribution Provider's test procedure documents, test macros, or
relay instruction manuals. PG&E also has comments on the
Implementation Plan document.
2. PG&E does not agree with the time frames listed for implementation of
Requirements R1, R2, R3 and R4, as explained below:
a. Implementation plan for Requirement R1: Time was extended
from three months to twelve months following regulatory approval
which we agree with. For those jurisdictions where no regulatory
approval is required it would seem that the time frame should also
be extended to at least twelve months following NERC Board
approval. However, it is still listed as six months following NERC
Board approval.
b. Implementation plan for Requirements R2, R3 and R4: For
Protection System Components with maximum allowable intervals
less than 1 year, it does not make sense to require 100%
compliance after twelve months following regulatory approval,
when this is the same time frame for compliance with
Requirement R1 for establishment of the new PSMP. The
implementation time window for Requirements R2, R3 and R4
should follow the implementation of Requirement R1 which
establishes the new PSMP. So the dates listed for 100%
compliance with Requirements R2, R3 and R4 should all be
pushed out by 12 months each.
c. Following is a summary time line for suggested implementation
requirements. o Months 1-12 Establish PSMP per R1
i. Month 12+ Begin performing maintenance under new
PSMP
ii. Month 24 100% compliance date for R2, R3, R4, for
components with max allowable intervals less than 1 year.
iii. 3 Calendar Years 100% compliance date for R2, R3, R4,
for components with max allowable intervals 1 year or
more, but 2 years or less.
29
Voter
Entity
Segment
Vote
Comment
iv. 3 Calendar Years 30% compliance date for R2, R3, R4, for
components with max allowable intervals of 6 years.
v. 5 Calendar Years 60% compliance date for R2, R3, R4,
for components with max allowable intervals of 6 years.
vi. 7 Calendar Years 100% compliance date for R2, R3, R4,
for components with max allowable intervals of 6 years.
3. Overall the updated standard is a huge improvement over Draft 2 in terms
of structure of the tables and presentation, which simplifies the standard
quite a bit. PG&E would have been in support of Draft 3 if the requirement
R1.5 had not been added.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed
within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4
has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. The Implementation Plan for R1 has been changed from six months to twelve months, and the Implementation Plan for Protection
System Components with maximum allowable intervals less than 1 year has been changed from 12 months to 15 months in
consideration of your comment. The Implementation Plan for R4 has been revised to add one year to all established dates.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed
within the PSMP definition and that Requirement R1, Part 1.5 is not necessary. Therefore, it has been removed. The associated
VSL has also been revised.
Brenda L
PPL Electric
1
Negative
PPL Electric Utilities (“PPL EU”) appreciate the hard work and efforts of the
Truhe
Utilities Corp.
Standards Drafting Team in reaching this point in the standards development
process. The basis for the negative vote is the addition of Requirement R1.5
(calibration tolerances) and R4.2 to the standard. This requirement will provide
the opportunity for auditors to decide if the testing criteria for whether a relay
passes a test or not is acceptable. PPL EU recommends that Requirement R1.5 be
deleted from the standard.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Kenneth D.
Public Service 1
Negative
The PSEG Companies do not agree with the Facilities as currently described in
Brown
Electric and
section 4.2.5.5. Please refer to detailed comments provided in the formal
Gas Co.
Comment Form.
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
30
Voter
Pawel Krupa
Entity
Seattle City
Light
Segment
1
Vote
Negative
Comment
Comment: The proposed Standard PRC-005-2 is an improvement over the
previous draft in that it provides more consistency in maintenance and testing
duration internals.
Notwithstanding, two issues are of concern to Seattle City Light such that it is
compelled to vote no:
1) the establishment of bookends for standard verification and
2) the implementation timelines for entities with systems where electromechanical relays still compose a significant number of components in their
protection systems.
1. Bookends: Proposed Standard PRC-005-2 specifies long inspection and
maintenance intervals, up to 12 years, which correspondingly exacerbates the socalled “bookend” issue. To demonstrate that interval-based requirements have
been met, two dates are needed - bookends. Evidencing an initial date can be
problematic for cases where the initial date would occur prior to the effective date
of a standard. NERC has provided no guidance on this issue, and the Regions
approach it differently. Some, such as Texas Regional Entity, require initial dates
beginning on or after the effective date of a Standard. Compliance with intervals is
assessed only once two dates are available that occur on or after a standard took
effect. Other regions, such as Western Electricity Coordinating Council (WECC),
require that entities evidence an initial date prior to the effective date of a
standard. For WECC, compliance with intervals is assessed as soon as a standard
takes effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal. Proposed
Standard PRC-005-2 will be another such standard. Indeed this Standard will
involve by far the largest number of bookends of any NERC standard - many
thousands for a typical entity. Furthermore, the long inspection and maintenance
intervals introduced in the draft will require entities in WECC, for instance, to
evidence initial bookend dates prior to the date original PRC-005-1 took effect. For
the 12-year intervals for CTs and VTs in proposed Standard PRC-005-2, many
initial dates will occur prior to the 2005 Federal Power Act that authorized
Mandatory Reliability Standards and even reach back before the 2003 blackout
that catalyzed the effort to pass the Federal Power Act. As a result, many entities
in WECC maybe at risk of being found in violation of proposed Standard PRC-0052 immediately upon its implementation. Seattle City Light requests that NERC
address the bookends issue, either within proposed Standard PRC-005-2 or in a
31
Voter
Entity
Segment
Vote
Comment
separate, concurrent document.
2. Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with legacy
systems. In example, auxiliary relay and trip coil testing may be essential to prove
the correct operation of complex, multi-function digital protection systems.
However, for legacy systems with single-function electro-mechanical components,
the considerable documentation and operational testing needed to implement and
track such testing is not necessarily proportional to the relative risk posed by the
equipment to the bulk electric system. Performance testing of electro-mechanical
systems, particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause far
more problems on restoration-to-service than they will locate and correct. As such,
to assist entities in their implementation efforts, we believe provision of
alternatives are necessary, such as additional implementation time through
phasing and/or through technical feasability exceptions.
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18 Evidence”.
2. Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic. FERC Order 693
directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is a portion
thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has developed those
requirements in a fashion that affords entities with the opportunity to best meet those requirements.
Horace
Southern
1
Negative
Reference the new Requirements R.1.5 and R.4.2 which are new to this posting:
Stephen
Company
R.1.5 requires the Owners to “identify calibration tolerances or other equivalent
Williamson
Services, Inc.
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES. The entire SDT needs to
thoroughly discuss these new requirements and modify or delete them. Note: We
have also made various requests for clarification to the FAQ and Supplemental
Reference document in our Response to Comments which we are not including
here.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
32
Voter
Entity
Segment
Vote
Larry Akens
Tennessee
Valley
Authority
1
Negative
Brandy A
Dunn
Western Area
Power
Administration
1
Negative
Comment
NERC is making significant changes to this sizeable standard and only allowing
minimum comment period. While this is a good standard that has clearly taken
many hours to develop, we are primarily voting “NO” because of the hurried
fashion it is being commented, voted, and reviewed.
Response: Thank you for your comments. Because of the urgent priority placed on this Standard by NERC, this Standard was
posted for a 30-day formal comment period with a concurrent 10-day ballot period at the conclusion of that comment period, even
though the Standard Development Process allows for a maximum 45-day formal comment period.
1) Western disagrees with the requirement R1, Part 1.5 that requires identifying
"calibration tolerances or equivalent parameters for each Protection System
component~" This requirement will add a burdensome, manual documentation of
thousands of tolerances and parameters that are now part of multiple automated
software programs and routines. These programs were purchased and developed
over numerous years of testing experience by Western and testing equipment
manufacturers. The fact that these tolerance and parameters are automated to
Pass/Fail program notifications, gives our Maintenance Divisions repeatable testing
programs that are not dependent on personnel interpretations. Extracting all these
tolerances and parameters from these programs provides no benefit for our PSMP.
2) Western disagrees with the wording of the R4.2 requirement referencing the
Part 1.5 of R1. The requirements of R4 are that you are to perform the
appropriate maintenance activity and the associated testing. The fact that the
testing was done and the equipment passed the testing meets the compliance for
R4. If the equipment fails the testing, it then becomes a maintenance correctable
issue, that requires adjustment or replacing, with further testing until the
equipment passes the required testing. Documenting thousands of tolerances and
parameters, for possibly thousands of components, serves no useful purpose for
our PSMP or compliance documentation.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Gregory L
Xcel Energy,
1
Negative
“We feel that several improvements were made since the last draft. However, we
Pieper
Inc.
feel that some gaps exist that should be addressed before moving this project
forward. We have detailed our issues in our formal comments.”
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
33
Voter
Kim Warren
Entity
Independent
Electricity
System
Operator
Segment
2
Vote
Negative
Comment
1. Requirement R1, Part 1.5 is vague and needs clarification. It is not clear
what “Identify calibration tolerances or other equivalent parameters”
means and this may be subject to different interpretations by entities and
compliance enforcement personnel.
2. Additionally, in the Implementation plan for Requirement R1, we
recommend changing “six” to “fifteen” to restore the 3-month time
difference between the durations of the implementation periods for
jurisdictions that do and don’t require regulatory approval, which existed
in the previous draft. This change will ensure equity for those entities
located in jurisdictions that do not require regulatory approval as is the
case here in Ontario. More importantly it supports the IESO’s strong belief
in the principle that reliability standards should be implemented in an
orderly and coordinated fashion across regions to ensure system reliability
is not compromised.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making
it consistent with the remainder of the Implementation Plan
Richard J.
Alabama
3
Negative
Reference the new Requirements R.1.5 and R.4.2 which are new to this posting:
Mandes
Power
R.1.5 requires the Owners to “identify calibration tolerances or other equivalent
Company
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES. The entire SDT needs to
thoroughly discuss these new requirements and modify or delete them. Note: We
have also made various requests for clarification to the FAQ and Supplemental
Reference document in our Response to Comments which we are not including
here.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Bob Reeping Allegheny
3
Negative
Allegheny Power applauds the hard work that the Standards Draft Team has
Power
exhibited in producing a clear and enforceable standard that will increase the
reliability of the Bulk Electric System. However, the addition of requirement 1.5 is
such a significant change in scope from the last draft that a further review of the
potential impact and any implementation concerns is required by AP and the
industry in general before we can consider voting in-favor of this standard.
34
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Raj Rana
American
3
Negative
Restructured Tables:
Electric Power
1. Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12
years for unmonitored control circuitry, yet other portions of control
circuitry have a maximum interval of 6 years. AEP does not understand
the rationale for the difference in intervals, when in most cases, one
verifies the other. Also, unmonitored control circuitry is capitalized in row
4 such that it infers a defined term.
2. In the first row of table 1-4 on page 16, it is difficult to determine if it is a
cell that wraps from the previous page or is a unique row. This is
important because the Maximum Maintenance Intervals are different (i.e.
18 months vs 6 years). It is difficult to determine to which elements the 6
year Maximum Maintenance Interval applies. AEP suggests repeating the
heading “Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2):” for
the bullet points on this page.
VSLs, VRFs and Time Horizons:
3. The VSL table should be revised to remove the reference to the Standard
Requirement 1.5 in the R1 “High” VSL.
4. All four levels of the VSL for R2 make reference to a “condition-based
PSMP.” However, nowhere in the standard is the term “condition-based”
used in reference to defining ones PSMP. The VSL for R2 should be
revised to remove reference to a condition-based PSMP; alternatively the
Standard could be revised to include the term “condition-based” within the
Standard Requirements and Table 1.
5. In multiple instances, Table 1 uses the phrase “No periodic maintenance
specified” for the Maximum Maintenance Interval. Is this intended to imply
that a component with the designated attributes is not required to have
any periodic maintenance? If so, the wording should more clearly state
“No periodic maintenance required” or perhaps “Maintain per
manufacturers recommendations.” Failure to clearly state the maintenance
requirement for these components leaves room for interpretation on
whether a Registered Entity has a maintenance and testing program for
devices where the Standard has not specified a periodic maintenance
interval and the manufacturer states that no maintenance is required.
FAQ and Supplementary Reference:
35
Voter
Entity
Segment
Vote
Comment
6. With such a complex standard as this, the FAQ and Supplementary
Reference documents do aid the Protection System owner in demystifying
the requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a. Section 5 of the Supplementary Reference, refers to “conditionbased” maintenance programs. However, nowhere in the standard
is the term “condition-based” used in reference to defining ones
PSMP. The Supplementary Reference should be revised to remove
reference to a condition-based PSMP; alternatively the Standard
could be revised to include the term “condition-based” within the
Standard Requirements and Table 1.
b. Section 15.7, page 26, appears to have a typographical error
“...can all be used as the primary action is the maintenance
activity...”
c. Figure 2 is difficult to read. The figure is grainy and the colors
representing the groups are similar enough that it is hard to
distinguish between groups.
“Frequently-Asked Questions”:
7. With such a complex standard as this, the FAQ and Supplementary
Reference documents do aid the Protection System owner in demystifying
the requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a. The section “Terms Used in PRC-005-2” is blank and should be
removed as it adds no value.
b. Section I.1 and Section IV.3.G reference “condition-based”
maintenance programs. However, nowhere in the standard is the
term “condition-based” used in reference to defining ones PSMP.
The FAQ should be revised to remove reference to a conditionbased PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard
Requirements and Table 1.
c. The second sentence to the response in Section I.1 appears to
have a typographical error “... an entity needs to and perform
ONLY time-based...”.
General:
36
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
8. Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2
should be removed. Specifying calibration tolerances for every protection
system component type, while a seemingly good idea, represents a
substantial change in the direction of the standard. It would be very
onerous for companies to maintain a list of calibration tolerances for every
protection system component type and show evidence of such at an audit.
AEP believes entities need the flexibility to determine what acceptance
criteria is warranted and need discretion to apply real-time
engineering/technician judgment where appropriate.
9. Three different types of maintenance programs (time-based,
performance-based and condition-based) are referenced in the standard
or VSLs, yet the time-based and condition-based programs are neither
defined nor described. Certain terms defined within the definition section
(such as Countable Event or Segment) only make sense knowing what
those three programs entail. These programs should be described within
the standard itself and not assume a knowledge of material in the
Supplementary Reference or FAQ.
10. “Protective relay” should be a defined term that lists relay function for
applicability. There are numerous ‘relays’ used in protection and control
schemes that could be lumped in and be erroneously included as part of a
Protection System. For example, reclosing or synchronizing relays respond
to voltage and hence could be viewed by an auditor as protective relays,
but they in fact perform traditional control functions versus traditional
protective functions.
11. The Data Retention requirement of keeping maintenance records for the
two most recent maintenance performances is a significant hurdle for any
owners to abide by during the initial implementation period. The
implementation plan needs to account for this such that Registered
Entities do not have to provide retroactive testing information that was
not explicitly required in the past.
1. The 6-year activities are all related to components with “moving parts”, and the 12-year activities are related to the other
portions of the control circuitry. The capitalized term has been corrected and additional changes have been made.
2. Table 1-4 has been modified in consideration of your comments.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
The associated VSL has also been revised.
37
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Comment
4. The SDT concluded that Requirement R2 is redundant to Requirement R1, Part 1.4 and has deleted Requirement R2 (together
with the Measures and & VSL).
5. If the indicated monitoring attributes are present, no “hands-on” periodic maintenance is required, as the monitoring of the
component is providing a continuing indication of its functionality.
6. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part
of the standard.
D. The Supplementary Reference Document discusses condition-based maintenance in a conceptual manner, as a
generally-recognized term. The SDT did make some changes within the Supplementary Reference document to
clarify the manner in which condition-based maintenance is discussed. The SDT decided to eliminate the FAQ
document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The
SDT considered your comments during this activity.
E. This clause has been corrected.
7. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part
of the standard.
b) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
c) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
d) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
8. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
9. The term, “condition-based” has been removed from the draft standard. The other terms are used, but are clear in the context
in which they are used.
10. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition with
PRC-005. Further, the applicability of generically-described protective relays is defined by the Applicability clause of PRC005-2.
11. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need
the data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that entities
have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has
specified the data retention in the posted standard to establish this level of documentation. This seems to be consistent with
the current practices of several Regional Entities.
38
Voter
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Comment
Rebecca
Berdahl
Bonneville
3
Negative
Please refer to BPA's submitted comments on 12/16/10.
Power
Administration
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
Steve
Alexanderson
Central
Lincoln PUD
3
Affirmative
WECC does not use the definition of the BES that NERC supplied to FERC via
http://www.nerc.com/docs/docs/ferc/RM06-16-6-1407CompFilingPar77ofOrder693FINAL.pdf, so the answer to FAQ III.1.3 (page 1920) is not accurate.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into
the Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Gregg R
Griffin
City of Green
Cove Springs
3
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuitry, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
that distribution circuit. There is no real reliability need for this either.
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regio0nsl UFLS program is being
met, but, to test the other protection system components is not
worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing
faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this
version is better than prior versions because it essentially requires the
entity to determine it's own period of maintenance and testing for
UFLS/UVLS for DC Supply and control circuitry.
39
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Response: Thank you for your comments.
Vote
Comment
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical
4. the VRF of R1 should be Low since the attached tables are essentially the
PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comments.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the establishment of an
entity’s individual PSMP.
Bruce
ComEd
3
Negative
The addition of the requirement R1.5 and associated wording has resulted in
Krawczyk
Exelon to vote No on the standard. While Exelon does specify Protection System
tolerances and parameters in many maintenance documents; attempting to
establish documented requirements for each component type is not practical.
Additionally, this can leave much to the discretion of an auditor as to how in-depth
tolerances need to be. There are many equipment and applications variations,
many of which can utilize generic values while others require very specific value
40
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Comment
ranges. There are many instances where a very specific component tolerance is
required for one application, but the same component doesn’t require a tolerance
in a different application. This could lead to entities having to justify why one
application with a common component requires a narrow range versus the same
component in another application can use a generic value or no tolerance. The
last part of the requirement is also not clear. If a parameter is established, the
R1.5 requirement is inferring component must meet an acceptable parameter to
conclude the maintenance activity. There are many instances when a component
is found out of a tolerance, but the level does not require immediate action and
can even be scheduled for remediation at the next maintenance cycle. The
wording in R1.5 appears to conflict with the R4.2 which indicates maintenance
activities can be conclude as long as corrective maintenance is initiated as a result
of identifying the condition.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Peter T Yost
Consolidated
3
Negative
The Tables Edison Co. of
1. The wording “Component Type” is not necessary in each title. Just the
New York
equipment category should be listed--what is now shown as “Component
Type - Protective Relay”, should be Protective Relay. However, Protective
Relay is too general a category. Electromechanical relays, solid state
relays, and microprocessor based relays should have their own separate
tables. So instead of reading Protective Relay in the title, it should read
Electromechanical Relays, etc. This will lengthen the standard, but will
simplify reading and referring to the tables, and eliminate confusion when
looking for information.
2. The “Note” included in the heading is also not necessary.
“Attributes” is also not necessary in the column heading, “Component”
suffices.
Other Comments –
3. In general, the standard is overly prescriptive and complex. It should not
be necessary for a standard at this level to be as detailed and complex as
this standard is. Entities working with manufacturers, and knowledge
gained from experience can develop adequate maintenance and testing
programs.
4. Why are “Relays that respond to non-electrical inputs or impulses (such
as, but not limited to, vibration, pressure, seismic, thermal or gas
accumulation)...” not included? The output contacts from these devices
41
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5.
6.
7.
8.
9.
10.
11.
are oftentimes connected in tripping or control circuits to isolate problem
equipment.
Due to the critical nature of the trip coil, it must be maintained more
frequently if it is not monitored. Trip coils are also considered in the
standard as being part of the control circuitry. Table 1-5 has a row labeled
“Unmonitored Control circuitry associated with protective functions”,
which would include trip coils, has a “Maximum Maintenance Interval” of
“12 Calendar Years”. Any control circuit could fail at any time, but an
unmonitored control circuit could fail, and remain undetected for years
with the times specified in the Table (it might only be 6 years if I
understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure,
then the system must be operated in real time assuming that that breaker
will not trip for a fault or an event, and backup facilities would be called
upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker
unable to trip), instead of one line tripping, you might have many more
lines deloaded or tripped because of a bus having to be cleared because
of a breaker failure initiation. The bulk electric system would have to be
operated to handle this contingency.
In reference to the FAQ document, Section 5 on Station dc Supply,
Question K, clarification is needed with respect to dc supplies for
communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation,
would the standard apply to these batteries or not?
To define terms only as they are used in PRC-005-2 is inviting confusion.
Although they may be unique to PRC-005-2, some or all of them may be
used in future standards, some already may be used in existing standards,
and may or may not be deliberately defined. Consistency must be
maintained, not only for administrative purposes, but for effective
technical communications as well.
What is the definition of “Maintenance” as used in the table column
“Maximum Maintenance Interval”? Maintenance can range from cleaning a
relay cover to a full calibration of a relay.
A control circuit is not a component, it is made up of components.
Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify
calibration tolerances or other equivalent parameters...” means, and may
be subject to different interpretations by entities and compliance
enforcement personnel.
In the Implementation plan for Requirement R1, recommend changing
42
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Comment
“six” to fifteen. This change would restore the 3-month time difference
that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require
regulatory approval. It will ensure equity for those entities located in
jurisdictions that do not require regulatory approval, as is the case in
Ontario.
12. The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It
seems to continue to the next page to a new box. There are multiple
activities without clear delineation.
13. Regarding station service transformers, Item 4.2.5.5 under Applicability
should be deleted. The purpose of this standard is to protect the BES by
clearing generator, generator bus faults (or other electrical anomalies
associated with the generator) from the BES. Having this standard apply
to generator station service transformers, that have no direct connection
to the BES, does meet this criteria. The FAQs (III.2.A) discuss how the
loss of a station service transformer could cause the loss of a generating
unit, but this is not the purpose of PRC-005. Using this logic than any
system or device in the power plant that could cause a loss of generation
should also be included. This is beyond the scope of the NERC standards.
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. The SDT believes that the table headings are appropriate as reflected in the draft standard.
3. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies
that minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent
maintenance, a performance-based program in accordance with R3 and Attachment A is an option.
4. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection
System definition. Also, there is currently no technical basis for the maintenance of the devices which respond to nonelectrical quantities on which to base mandatory standards related either to activities or intervals. Absent such a technical
basis, we are currently unable to establish mandatory requirements, but may do so in the future if such a technical basis
becomes available.
5. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year
interval. You can maintain these devices more frequently if you desire
6. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the
communications system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The
43
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Comment
specific station dc supply requirements (Table 1-4) do not apply to the dc supply associated only with communications
systems. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
7. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms,
either now or in the future, may not be consistent with the terms used here. They are defined only for clarify within this
standard.
8. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are
specified in the Activities column. The term is capitalized in the column title in conformance with normal editorial practice as
a title, rather than as a definition.
9. For purposes of this standard, the control circuit IS defined as one component type.
10. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
11. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for R1, making it consistent
with the remainder of the Implementation Plan.
12. Table 1-4 has been further modified for clarity.
13. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
David A.
Consumers
3
Negative
We have the following comment on the revisions, specifically sub-requirement
Lapinski
Energy
R1.12a, which states, "Set the maximum torque angle (MTA) to 90 degrees or the
highest supported by the manufacturer.". We have no issue with this requirement
on transmission lines that are 200 kV or greater. However, we do have a concern
with applying requirement R1.12a on lower voltage lines now that the
Transmission Relay Loadability Standard is being revised to included selected
equipment 200 kV and below. The positive-sequence line angle on lower voltage
lines, such as 69 kV or 46 kV, is significantly lower than 90 degrees. The positivesequence line angle for 3/0 ACSR, for example, is only 55 degrees. Setting a 90
degree MTA on these lines would require a much larger reach setting to provide
adequate line protection. In some cases, especially for lines with long spurs and
poor line conductor, the increased reach setting may actually provide less
loadability than a reach setting based on an MTA set at the positive-sequence line
angle. A 90 degree MTA also dramatically reduces the resistive fault coverage for
these lines. For these reasons, we would propose a modification to sub-
44
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requirement R1.12a as follows: Set the maximum torque angle (MTA) to 90
degrees or the highest supported by the manufacturer on 200 kV or greater
transmission lines. Set the maximum torque angle (MTA) to the positive-sequence
line angle on transmission lines less than 200 kV.
Response: Thank you for your comments. This comment appears to apply to PRC-023-2 (Project 2010-17), which is a separate
activity, and is not apparently relevant to PRC-005-2.
Michael F
Dominion
3
Negative
Dominion is opposed to this version because Requirement R1.5 is overly
Gildea
Resources
prescriptive, requiring an extraordinary level of documentation, with little
Services
anticipated improvement in reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Henry Ernst- Duke Energy
3
Negative
1. R1.4 and R1.5 need more information to provide clarity for compliance. It’s
Jr
Carolina
unclear to us what the expectation is for compliance documentation for
“monitoring attributes and related maintenance activities” in R1.4 and
“calibration tolerances or other equivalent parameters” in R1.5. This is fairly
straightforward for relays, but not for other component types. Either provide
clarity or delete these requirements.
2. R4.2 - it is critical that more clarity be provided for R1.5 so that we can also
understand what the compliance expectation is for R4.2
3. M4 - Need to clarify that these pieces of evidence are all “or”, not “and” (i.e.
any of the listed examples are sufficient for compliance). We reiterate the
need for additional clarity on R1.5 and R4.2 such that compliance can be
demonstrated for all component types.
4. Table 2 - We are fairly clear on the expectation for relays, but need more
clarity on the expectation for other component types. Also, need to change
the phrase “corrective action can be taken” to “corrective action can be
initiated”, consistent with the Supplementary Reference document.
5. VSL for R1 - Sub-requirement R1.3 appears to be missing.
6. Also, it’s unclear to us what the expectation is for compliance documentation
for “monitoring attributes and related maintenance activities” in R1.4 and
“calibration tolerances or other equivalent parameters” in R1.5. This is fairly
straightforward for relays, but not for other component types.
7. VSL for R4 - More clarity must be provided on the expectation for compliance
documentation. This is a High VRF requirement, and there may only be a
small number of maintenance-correctable items, hence a significant exposure
to an extreme penalty.
8. There are typographical errors on the FAQ Requirements Flowchart (should
45
Voter
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Comment
be R4.1.1 and R4.1.2 instead of R4.4.1 and R4.4.2).
9. We have previously commented that the FAQ and Supplementary Reference
documents should be made part of this standard. If that cannot be done,
then more of the information in those documents needs to be included in the
requirements in the standard to provide clarity. Compliance will only be
measured against what is in the standard, and we need more clarity.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. The SDT has provided examples of the sort of evidence that may serve to demonstrate compliance. The degree to which any
single evidence type is sufficient is dependent on the completeness of the evidence itself. The Measure has been modified to
clarify this point.
4. Table 2 has been modified to be clearer. “Taken” has been replaced with “Initiation” in consideration of your comment.
5. The High VSL for Requirement R1 has been revised in consideration of your comment.
6. The issues of “monitoring attributes” are discussed within Section 15.7 of the Supplementary Reference Document. As for
Requirement R1, Part 1.5, the SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the
associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore,
it has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within
comments. The associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a
discussion of this.
7. Examples of compliance documentation are included within Measure M4 and discussed within various clauses of the FAQ and
within Section 15.7 of the Supplementary Reference Document.
8. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
9. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT believes the entities should be able to implement the standard without the Supplementary
Reference. However, the SDT is also convinced that many entities may find the supporting discussion rationale etc useful
particularly to assist them in implementing the standard in an efficient manner.
46
Voter
Joel T
Plessinger
Entity
Entergy
Segment
3
Vote
Negative
Comment
The restructured tables are generally much clearer and the SDT is to be
commended on their efforts.
1. However, we believe the Alarming Point Table needs additional
clarification with regard to the Maximum Maintenance Interval. If an
“alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there
isn’t necessarily a maximum interval established as there is for Protection
System components. Also, if an entity’s alarm producing device
maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum
intervals for the alarm producing device of that entity. On that basis, we
suggest the interval verbiage be revised to “When alarm producing device
or system is verified, or by sections as per the monitored
component/protection system specified maximum interval as applicable”.
Alternately, if the intention is to establish maximum intervals as simply
being no longer than the individual component maintenance intervals as
we suggest for inclusion above, then the verbiage should be revised to
“When alarm producing component/protection system segment is
verified”. In either case are we to interpret monitored components with
attributes which allow for no periodic maintenance specified as not
requiring periodic alarm verification?
2. R1.5 calls for “identification of calibration tolerances or equivalent
parameters...” whereas the associated VSL references “failure to establish
calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply
“identify” or document such calibration tolerances would be analogous to
the severity level(s) of a “failure to specify one (or the severity level
should be consistent with the other elements of R1. Both cases appear to
be more of a documentation issue as opposed to a failure to implement.
Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4? R1.5 calls for “identification of calibration tolerances
or equivalent parameters for each Protection System Component Type....”.
3. We believe the Supplementary Reference document should provide
additional information and examples of calibration tolerances or equivalent
parameters which would be expected for the various component types.
Especially for any “equivalent” parameters which would be required for
compliance for a component type besides protective relays. Adding
Requirement 1.5 is a significant revision and raises questions as to how
broadly an accuracy or equivalent parameter requirement and associated
47
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documentation would need to be addressed by entities and/or will be
measured for compliance. Discussion on this new requirement does not
seem to be addressed anywhere in the FAQ or Supplementary Reference
documents. Additionally, to the best of our knowledge, the need for such
a requirement was not brought up as a concern or comment on the prior
draft version of this standard, and in the context of a requirement need,
we don’t believe it has been attributed to or actually poses any significant
reliability risk. We do not believe this requirement is justified.
Response: Thank you for your comments.
1. The Maximum Maintenance Interval column entry in Table 2 has been revised to state, “When alarm producing Protection
System component is verified” to clarify this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Kevin Querry FirstEnergy
3
Negative
Please see FirstEnergy's comments submitted separately through the comment
Solutions
period posting.
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
Lee Schuster
Florida Power
Corporation
3
Negative
Implementation Plan for PRC-005-2
1. Since R2, R3, and R4 requirements would be performed after
establishment of the program documentation, an additional year should
be added to all implementation dates for Requirements R2, R3, and R4 as
shown below:
• Maintenance on components with intervals less than one year must be
completed within two years after applicable regulatory approval
(within one year of completion of R1 Program Documentation).
• Maintenance on components with intervals between one year and two
years must be completed within three years after applicable
regulatory approval (within two years of completion of R1 Program
Documentation).
• Maintenance on components with intervals of six years must be
completed within three-, five-, and seven-year milestones after
48
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
applicable regulatory approval (within two, four, and six years of
completion of R1 Program Documentation).
• Maintenance on components with intervals of twelve years must be
completed within five-, nine-, and thirteen-year milestones after
applicable regulatory approval (within four, eight, and twelve years of
completion of R1 Program Documentation).
Standard PRC-005-02 1.
2. Table 1-2: Rows 1 and 2 require different intervals for the activity “Verify
essential signals to and from Protection System components.” Unless
these inputs and outputs are monitored for Row 2, it would seem that
they should be performed at the same interval for both Rows 1 and 2.
Therefore, EITHER:
• Row 1 should be broken into the following three activities:
• 3 months - Verify communications system is functional
• 6 years - Verify channel meets performance criteria
• 12 years - Verify essential signals to and from other Protection
System components OR:
• Row 2 should be broken into the following two activities:
• 12 years - Verify channel meets performance criteria
•
6 years - Verify essential signals to and from other Protection
System components
3. Table 1-4: Only Row 1 addresses dc supplies associated with UFLS or
UVLS systems. All other rows state that UFLS or UVLS systems are
excluded. What is required to “Verify dc supply voltage” for the
UFLS/UVLS systems? Does it require that the overall station battery
voltage be checked or just the dc voltage available to the UFLS/UVLS
circuit of interest? If a voltage measurement is taken at the UFLS/UVLS
circuit (e.g., in distribution breaker cabinet), can the batteries/chargers at
these facilities be excluded from the PRC-005-2 scope as long as they do
not also supply transmission-related protection?
4. PRC-005-2 FAQ’s Document Section V.1.A, Example #2: The instrument
transformer should be classified as “unmonitored” not “monitored.”
1. The Implementation Plan for Requirement R1 has been changed from 12 months to 15 months in consideration of your
comment. The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
2. The first and second rows differ in that the first row is for unmonitored communications systems, and the second row is
for monitored communications systems. The activities in both rows are appropriate and correct.
3. Table 1-4 has been completely re-structured. For station dc supply for only UFLS/UVLS, the only activity is to verify the dc
49
Voter
Entity
Segment
Vote
Comment
voltage.
4. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
Anthony L
Wilson
Georgia
Power
Company
3
Negative
Reference the new Requirements R.1.5 and R.4.2 which are new to this posting:
R.1.5 requires the Owners to “identify calibration tolerances or other equivalent
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES. The entire SDT needs to
thoroughly discuss these new requirements and modify or delete them.
Note: We have also made various requests for clarification to the FAQ and
Supplemental Reference document in our Response to Comments which we are
not including here.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Michael D.
Hydro One
3
Negative
1. The added requirement R1, Part 1.5 is vague and needs clarification. It is not
Penstone
Networks,
clear what “Identify calibration tolerances or other equivalent parameters” means
Inc.
and as written will be subject to different interpretations by entities and
compliance enforcement personnel. The addition of this new part of Requirement
R1 that requires the Owners to “identify calibration tolerances or other equivalent
parameters for each Protection System component type” is onerous and
contributes little to the reliability of the BES.
2. Changes introduced to the Implementation Plan since the last posting are not
consistent with respect to jurisdictions where no regulatory approval is required.
The previously posted implementation for Requirement R1 required entities to be
100% compliant on the first day of the first calendar quarter three months
following applicable regulatory approvals, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter six
months following Board of Trustees adoption. The amended implementation plan
changed the three-month time to twelve months in jurisdictions with regulatory
approval required but left the same six-month time for the others. For consistency,
the six months timeframe should be changed to fifteen months.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated
VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
50
Voter
Entity
Segment
Vote
Comment
2. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1,
making it consistent with the remainder of the Implementation Plan.
Garry Baker
JEA
3
Negative
JEA will be voting no on PRC-005-2 because of the following:
1. In Table 1-1 for electromechanical trip or auxiliary devices requires verification
of operation as opposed to verify ability to operate that was specified on trip coils.
I believe it should be ability to operate in each case.
2. Between Table 1-1 and Tables 1-5 essentially would require full functional test
of each station every 12 years.
Response: Thank you for your comments.
1. The distinction in Table 1-5 is correct and as intended by the SDT.
2. A full functional test is one means of completing the required activities, but other methods are also acceptable. See Sections 8
and 15.3 of the Supplementary Reference Document for additional discussion.
Mace Hunter Lakeland
3
Negative
1. Table 1-4 requires a comparison of measured battery internal ohmic
Electric
value to battery baseline. Since battery manufacturers do not provide
this value, it is unclear what the “baseline” values ought to be if an entity
recently began performing this test (assuming it’s several years after the
commissioning of the battery.) Would it be acceptable for an entity to
establish baseline values based on statistical analysis of multiple test
results specific to a given battery manufacturer and design?
2. Lakeland feels that the SDT should have taken into consideration
numerous comments previously made regarding general concerns with
testing Control Circuitry in energized substations. We agree that this can
negatively impact reliability and would like to emphasize the following:
• Small entities with only one or two BES substations may not have enough
components to take advantage of the expanded maintenance intervals
afforded by a performance-based maintenance program. Aggregating
these components across different entities doesn’t seem too logical
considering the variations at the sub-component level (wire gauge,
installation conditions, etc.)
• Trip circuits are interconnected to perform various functions. Testing a trip
path may involve disabling other features (i.e. breaker failure or reclosing)
not directly a part of the test being performed. Temporary modifications
made for testing introduce a chance to unknowingly leave functions
disabled, contacts shorted, jumpers lifted, etc. after testing has been
completed. Trip coils and cable runs from panels to breaker can be made
to meet the requirements for monitored components. The only portions of
the circuitry where this may not be the case is in the inter and intra-panel
51
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
wiring. Because such portions of the circuitry have no moving parts and
are located inside a control house, the exposure is negligible and should
not be covered by the requirements. Entities will be at increased
compliance risk as they struggle to properly document the testing of all
parallel tripping paths.
3. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
4. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative
is to change the definition of Protection System to make sure it only
includes electrical
5. the VRF of R1 should be Low since the attached tables are essentially the
PSMP.
1. Typical baseline values for various types of lead-acid batteries can be obtained from the test equipment manufacturer,
perhaps the battery vendor, and perhaps other sources for batteries that are already in service. For new batteries, the
initial battery baseline ohmic values should be measured upon installation and used for trending.
2. A) Entities are not required to use performance-based maintenance programs. Requirement R3 and Attachment A are
provided for the use of entities that can (and desire to) avail themselves of this approach.
B) The requirement relative to control circuitry does not explicitly require trip or functional testing of the entire path; it
requires that entities verify all paths without specifying the method of doing so. Please see Section 15.5 of the
Supplementary Reference Document for detailed discussion.
3. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within
PRC-005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comments.
4. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
52
Voter
Entity
Segment
Vote
Comment
5. The SDT disagrees; the Tables establish the intervals and activities, and R1 addresses the establishment of an entities’
individual PSMP.
Bruce Merrill
Lincoln
Electric
System
3
Affirmative
While the proposed draft of the standard is acceptable as currently written, LES
would like the drafting team to consider the following comments.
(1) Table 1-1 should state “Test and calibrate (if necessary)” in the first section
under activities. If a relay passes the test, there is no need to calibrate it.
Therefore, not all relays will require calibration.
(2) Please explain the drafting team’s reason for not checking the trip coils of
breakers in the UFLS/UVLS schemes but ensuring that all others are operated
every six years. It would appear that they can all be lumped into the same group
one way or another.
(3) In regards to Specific Gravity Testing, many people do not perform the
specific gravity test routinely if they perform the individual cell internal ohmic test
routinely. LES asks the drafting team to consider allowing the internal cell ohmic
test as a substitute for the specific gravity test.
Response: Thank you for your comments.
1. Table 1-1 has been modified as you suggest.
2. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the
Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system
elements.
3. Table 1-4 does not specify specific gravity testing.
Charles A.
Louisville Gas 3
Negative
LG&E and KU Energy LLC appreciate the hard work and efforts of the Standards
Freibert
and Electric
Drafting Team in reaching this point in the standards development process. The
Co.
basis for the negative vote is the addition of Requirement R1.5 (calibration
tolerances) and R4.2 to the standard. This requirement will provide the
opportunity for auditors to decide if the testing criteria for whether a relay passes
a test or not is acceptable. LG&E and KU Energy recommend that Requirement
R1.5 be deleted from the standard.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Greg C.
Manitoba
3
Negative
1. -Implementation Plan (Timeline) for R1: In areas not requiring regulatory
Parent
Hydro
approval, the 6 month time frame proposed for R1 is not achievable and is not
consistent with areas requiring regulatory approval. To be consistent, the
effective date for R1 in jurisdictions where no regulatory approval is required
should be the first day of the first calendar quarter 12 months after BOT
approval.
53
Voter
Entity
Segment
Vote
Comment
2. - VSLs: The high VSL for R1 “Failed to include all maintenance activities
relevant for the identified monitoring attributes specified in Tables 1-1 through
1-5” may be interpreted in different ways and should be further clarified.
3. -Table 1-4: The requirements for batteries listed in Table 1-4 do not appear to
be consistent with the comments in the FAQ Section (V 1A Example 1). Please
see comments submitted during the formal comment period for further detail.
4. -Table 1-4: The requirement for a 3 month check on electrolyte level seems
too frequent based on our experience. We would like to point out that
although IEEE std 450 (which seems to be the basis for table 1-4) does
recommend intervals it also states that users should evaluate these
recommendations against their own operating experience.
Response: Thank you for your comments.
1. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making
it consistent with the remainder of the Implementation Plan.
2. The SDT does not understand your concern; further details are needed.
3. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
4. The SDT believes that the 3-month interval specified in the Standard is appropriate.
Don Horsley
Mississippi
3
Negative
Reference the new Requirements R.1.5 and R.4.2 which are new to this posting:
Power
R.1.5 requires the Owners to “identify calibration tolerances or other equivalent
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES. The entire SDT needs to
thoroughly discuss these new requirements and modify or delete them.
Note: We have also made various requests for clarification to the FAQ and
Supplemental Reference document in our Response to Comments which we are
not including here.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Michael
Niagara
3
Negative
This new Requirement as written subjects the Transmission Owner, Generation
Schiavone
Mohawk
Owner or Distribution Provider to vague interpretations of what the requirement
(National Grid
means by compliance officials. The addition of the new part of Requirement R1
Company)
that requires the Owners to “identify calibration tolerances or other equivalent
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES.
54
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Sam Waters
Progress
3
Negative
4.
Implementation Plan for PRC-005-2 Since R2, R3, and R4 requirements
Energy
would be performed after establishment of the program documentation, an
Carolinas
additional year should be added to all implementation dates for
Requirements R2, R3, and R4 as shown below:
• Maintenance on components with intervals less than one year must be
completed within two years after applicable regulatory approval (within
one year of completion of R1 Program Documentation).
• Maintenance on components with intervals between one year and two
years must be completed within three years after applicable regulatory
approval (within two years of completion of R1 Program Documentation).
•
Maintenance on components with intervals of six years must be
completed within three-, five-, and seven-year milestones after applicable
regulatory approval (within two, four, and six years of completion of R1
Program Documentation). o Maintenance on components with intervals
of twelve years must be completed within five-, nine-, and thirteen-year
milestones after applicable regulatory approval (within four, eight, and
twelve years of completion of R1 Program Documentation). Standard PRC005-02 1.
5.
Table 1-2:
1. Rows 1 and 2 require different intervals for the activity “Verify essential
signals to and from Protection System components.” Unless these inputs
and outputs are monitored for Row 2, it would seem that they should be
performed at the same interval for both Rows 1 and 2. Therefore,
EITHER:
• Row 1 should be broken into the following three activities:
• 3 months - Verify communications system is functional
•
6 years - Verify channel meets performance criteria
• 12 years - Verify essential signals to and from other
Protection System components OR:
•
Row 2 should be broken into the following two activities:
• 12 years - Verify channel meets performance criteria
•
6 years - Verify essential signals to and from other
Protection System components.
6.
Table 1-4: Only Row 1 addresses dc supplies associated with UFLS or UVLS
systems. All other rows state that UFLS or UVLS systems are excluded. What
55
Voter
Entity
Segment
Vote
Comment
7.
is required to “Verify dc supply voltage” for the UFLS/UVLS systems? Does it
require that the overall station battery voltage be checked or just the dc
voltage available to the UFLS/UVLS circuit of interest? If a voltage
measurement is taken at the UFLS/UVLS circuit (e.g., in distribution breaker
cabinet), can the batteries/chargers at these facilities be excluded from the
PRC-005-2 scope as long as they do not also supply transmission-related
protection?
PRC-005-2 FAQ’s Document Section V.1.A, Example #2: The instrument
transformer should be classified as “unmonitored” not “monitored.”
Response: Thank you for your comments.
4. The Implementation Plan for Requirement R1 has been changed from 12 months to 15 months in consideration of your
comment. The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
5. The first and second rows differ in that the first row is for unmonitored communications systems, and the second row is for
monitored communications systems. The activities in both rows are appropriate and correct.
6. Table 1-4 has been completely re-structured. For station dc supply for only UFLS/UVLS, the only activity is to verify the dc
voltage.
7. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
Jeffrey
Public Service 3
Negative
The PSEG Companies do not agree with the Facilities as currently described in
Mueller
Electric and
section 4.2.5.5. Please refer to detailed comments provided in our formal
Gas Co.
Comment Form.
Response: Thank you for your comments. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the
Applicability of the standard.
Anthony
Schacher
Salem Electric
3
Negative
Battery testing methodologies are too specific and don't allow for different
substation battery configurations.
Response: Thank you for your comments. The SDT disagrees; the requirements within Table 1-4 establish the minimum
maintenance activities required to assure that station dc supply of various technologies and configurations will perform as intended
without unnecessarily prescribing specific methodologies.
Dana
Wheelock
Seattle City
Light
3
Negative
Comment: The proposed Standard PRC-005-2 is an improvement over the
previous draft in that it provides more consistency in maintenance and testing
duration internals.
Notwithstanding, two issues are of concern to Seattle City Light such that it is
compelled to vote no:
1)
the establishment of bookends for standard verification and 2) the
implementation timelines for entities with systems where electro-mechanical
56
Voter
Entity
Segment
Vote
Comment
2)
relays still compose a significant number of components in their protection
systems. Bookends: Proposed Standard PRC-005-2 specifies long inspection
and maintenance intervals, up to 12 years, which correspondingly
exacerbates the so-called “bookend” issue. To demonstrate that intervalbased requirements have been met, two dates are needed - bookends.
Evidencing an initial date can be problematic for cases where the initial date
would occur prior to the effective date of a standard. NERC has provided no
guidance on this issue, and the Regions approach it differently. Some, such
as Texas Regional Entity, require initial dates beginning on or after the
effective date of a Standard. Compliance with intervals is assessed only once
two dates are available that occur on or after a standard took effect. Other
regions, such as Western Electricity Coordinating Council (WECC), require
that entities evidence an initial date prior to the effective date of a standard.
For WECC, compliance with intervals is assessed as soon as a standard takes
effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal.
Proposed Standard PRC-005-2 will be another such standard. Indeed this
Standard will involve by far the largest number of bookends of any NERC
standard - many thousands for a typical entity. Furthermore, the long
inspection and maintenance intervals introduced in the draft will require
entities in WECC, for instance, to evidence initial bookend dates prior to the
date original PRC-005-1 took effect. For the 12-year intervals for CTs and
VTs in proposed Standard PRC-005-2, many initial dates will occur prior to
the 2005 Federal Power Act that authorized Mandatory Reliability Standards
and even reach back before the 2003 blackout that catalyzed the effort to
pass the Federal Power Act. As a result, many entities in WECC maybe at
risk of being found in violation of proposed Standard PRC-005-2 immediately
upon its implementation. Seattle City Light requests that NERC address the
bookends issue, either within proposed Standard PRC-005-2 or in a separate,
concurrent document.
Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with
legacy systems. In example, auxiliary relay and trip coil testing may be
essential to prove the correct operation of complex, multi-function digital
protection systems. However, for legacy systems with single-function
57
Voter
Entity
Segment
Vote
Comment
electro-mechanical components, the considerable documentation and
operational testing needed to implement and track such testing is not
necessarily proportional to the relative risk posed by the equipment to the
bulk electric system. Performance testing of electro-mechanical systems,
particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause
far more problems on restoration-to-service than they will locate and correct.
As such, to assist entities in their implementation efforts, we believe
provision of alternatives are necessary, such as additional implementation
time through phasing and/or through technical feasibility exceptions.
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18 Evidence”.
Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic.
2. FERC Order 693 directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is a
portion thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has developed
those requirements in a fashion that affords entities with the opportunity to best meet those requirements.
James R.
Wisconsin
3
Negative
Q4: Table 1-4 requires an activity to verify the state of charge of battery cells.
Keller
Electric Power
There are no possible options for meeting this requirement listed in the FAQ
Marketing
document. Unlike other terms used in the standard, this term is not mentioned or
defined in the FAQ. To comply with this standard, the SDT needs to provide more
guidance. For example, for VLA batteries the measured specific gravity could
indicate state of charge. For VRLA batteries, it is not as clear how to determine
state of charge, but possibly this can be determined by monitoring the float
current.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into
the Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has
been revised to remove “state of charge” from the activities.
Michael Ibold
Xcel Energy,
Inc.
3
Negative
See comments under the Transmission segment.
Response: Thank you for your comments. Please see our responses to your comments from the Transmission segment.
Kenneth
Goldsmith
Alliant Energy
Corp.
Services, Inc.
4
Negative
We are concerned with this paragraph being interpreted differently by the various
regions and thereby causing a large increase in scope for Distribution Provider
protection systems beyond the reach of UFLS or UVLS.
i. Protection Systems applied on, or designed to provide protection for, the BES.
The description is vague and open for different interpretations for what is “applied
58
Voter
Entity
Segment
Vote
Comment
on” or “designed to provide protection”.
According to the November 17, 2010 Draft Supplementary Reference page 4, the
Standard will not apply to sub-transmission and distribution circuits, but will apply
to any Protection System that is designed to detect a fault on the BES and take
action in response to the fault. The Standard Drafting Team does not feel that
Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the
Regional Entity interpretations of ‘protecting” the BES. Most distribution protection
systems will not react to a fault on the BES, but are caught up in the
interpretation due to tripping a breaker(s) on the BES.
Response: Thank you for your comments. Applicability 4.2.1 has been revised to remove “applied on”. The SDT believes that this
addresses your concern. Applicability 4.2.2 and 4.2.3, respectively, address UFLS and UVLS specifically, and are not related to 4.2.1.
The Supplementary Reference Documentation has been revised to clarify.
David Frank
Ronk
Consumers
Energy
4
Negative
1. Table 1-3 states, “are received by the protective relays”. Does this require that
the inputs to each individual relay must be checked, or is it sufficient to verify that
acceptable signals are received at the relay panel, etc?
2. Relative to Table 1-5, the activities will likely require that system components
be removed from service to complete those activities. If the changes to the BES
definition (per the FERC Order) causes system elements such as 138 kV connected
distribution transformers to be considered as BES, these components can not be
removed from service for maintenance without outaging customers. The standard
must exempt these components from the activities of Table 1-5 if the activity
would result in deenergizing customers.
3. For the component types addressed in Tables 1-3 and 1-5, the requirements
may cause entities to identify components very differently than they are currently
doing, and doing so may take several years to complete. The Implementation
Plan for R1 and R4 is too aggressive in that it may not permit entities to complete
the identification of discrete components and the associated maintenance and
implement their program as currently proposed. We propose that the
Implementation Plan specifically address the components in Table 1-3 and 1-5
with a minimum of 3 calendar years for R1 and 12 calendar years after that for
R4.
4. As for the interval in Table 1-4 regarding the battery terminal connection
resistance, we believe that an 18-month interval is excessively frequent for this
59
Voter
Entity
Segment
Vote
Comment
activity, and suggest that it be moved to the 6-calendar-year interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections
every 4-years, rather than measuring the terminal connection resistance to
determine if the connections are sound. Disregarding the interval, would this
activity satisfy the “verify the battery terminal connection resistance” activity?
Response: Thank you for your comments.
1. The SDT intends that the voltage and current signals properly reach each individual relay, but there may be several methods of
accomplishing this activity.
2. This concern seems more properly to be one to be addressed during the activities to develop the new BES definition, rather than
within PRC-005-2.
3. The Implementation Plan for Requirement R1 has been modified from “six” months to “twelve” months. The standard has also
been modified (Requirement R1, Part 1.1) to not specifically require identification of all Individual Protection System components.
The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
4. IEEE 450, 1188, and 1106 all recommend this activity at a 12-month interval. Please see Clause 15.4.1 of the Supplementary
Reference Document for a discussion of this activity.
5. Re-torqueing the battery terminals would not meeting this requirement.
Frank
Gaffney
Florida
Municipal
Power Agency
4
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new
PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution
system protection, so, these activities would not be covered by other BES
protection system maintenance and testing. I'm sure we are testing
batteries and the like, but, we are probably not testing battery chargers and
control circuity, and, in many cases distribution circuits are such that it is
very difficult, if not impossible, to test control circuitry to the trip coil of the
breaker without causing an outage of the customers on that distribution
circuit. There is no real reliability need for this either. Unlike Transmission
and Generation Protection Systems which are needed to clear a fault and
may only have one or two back-up systems, there are thousands and
thousands of UFLS relays and if one fails to operate, it will not be noticeable
to the event. It does make sense to test the relays themselves in part to
60
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
ensure that the regionsl UFLS program is being met, but, to test the other
protection system components is not worthwhile. Note that DC Supplies and
most of the control circuitry of distribution lines are "tested" frequently by
distribution circuits clearing faults such as animals, vegetation blow-ins,
lightning, etc., on distribution circuits, reducing the value of testing to just
about null. However, this version is better than prior versions because it
essentially requires the entity to determine it's own period of maintenance
and testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a BES
Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical the VRF of R1 should be Low since the attached tables are
essentially the PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during the
stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comments.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
61
Voter
Thomas W.
Richards
Entity
Fort Pierce
Utilities
Authority
Segment
4
Vote
Negative
Comment
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new
PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution
system protection, so, these activities would not be covered by other BES
protection system maintenance and testing. I'm sure we are testing batteries
and the like, but, we are probably not testing battery chargers and control
circuitry, and, in many cases distribution circuits are such that it is very
difficult, if not impossible, to test control circuitry to the trip coil of the
breaker without causing an outage of the customers on that distribution
circuit. There is no real reliability need for this either. Unlike Transmission
and Generation Protection Systems which are needed to clear a fault and
may only have one or two back-up systems, there are thousands and
thousands of UFLS relays and if one fails to operate, it will not be noticeable
to the event. It does make sense to test the relays themselves in part to
ensure that the regio0nsl UFLS program is being met, but, to test the other
protection system components is not worthwhile. Note that DC Supplies and
most of the control circuitry of distribution lines are "tested" frequently by
distribution circuits clearing faults such as animals, vegetation blow-ins,
lightning, etc., on distribution circuits, reducing the value of testing to just
about null. However, this version is better than prior versions because it
essentially requires the entity to determine it's own period of maintenance
and testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a BES
Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 2009-10 that
excludes non-electrical protection (e.g., sudden pressure relays) and auxiliary
relays. Because the definition of Protection System (recently approved) does
not clearly exclude "non-electrical" protection, the Applicability section
should. For instance, a vibration monitor, steam pressure, etc. protection of
generators, sudden pressure protection of transformers, etc. should not be
included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical
4. Table 1-4 requires a comparison of measured battery internal ohmic value to
battery baseline. Battery manufacturers typically do not provide this value
62
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
and one manufacturer states that the baseline test are to be performed after
the battery has been in regular float service for 90 days. It is unclear how to
comply with the requirement for the initial 90 days. Additionally, we would
recommend that this requirement be modified to permit an entity to establish
a “baseline” value based on statistical analysis of multiple test results specific
to a given battery manufacturer/model. Several commenters previously
expressed their concerns with performing capacity tests. While this may just
be an entity’s preference, allowing an entity to establish a baseline at some
point beyond the initial installation period would give entities the option of
using the internal resistance test in lieu of a capacity test.
5. Small entities with only one or two BES substations may not have enough
components to take advantage of the expanded maintenance intervals
afforded by a performance-based maintenance program. Aggregating these
components across different entities doesn’t seem too logical considering the
variations at the sub-component level (wire gauge, installation conditions,
etc.)
6. Trip circuits are interconnected to perform various functions. Testing a trip
path may involve disabling other features (i.e. breaker failure or reclosing)
not directly a part of the test being performed. Temporary modifications
made for testing introduce a chance to accidentally leave functions disabled,
contacts shorted, jumpers lifted, etc. after testing has been completed. Trip
coils and cable runs from panels to breaker can be made to meet the
requirements for monitored components. The only portions of the circuitry
where this may not be the case is in the inter- and intra-panel wiring.
Because such portions of the circuitry have no moving parts and are located
inside a control house, the exposure is negligible and should not be covered
by the requirements. Entities will be at increased compliance risk as they
struggle to properly document the testing of all parallel tripping paths. The
interconnected nature of tripping circuits will make it difficult to count the
number of circuits consistently for the purpose of calculating a VSL.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during the
stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comments.
63
Voter
Entity
Segment
Vote
Comment
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
4. Typical baseline values for various types of lead-acid batteries can be obtained from the test equipment manufacturer, perhaps
the battery vendor, and perhaps other sources for batteries that are already in service. For new batteries, the initial battery
baseline ohmic values should be measured upon installation and used for trending.
5. Entities are not required to use performance-based maintenance programs. Requirement R3 and Attachment A are provided
for the use of entities that can (and desire to) avail themselves of this approach.
6. The requirement relative to control circuitry does not explicitly require trip or functional testing of the entire path; it requires that
entities verify all paths without specifying the method of doing so. Please see Section 15.5 of the Supplementary Reference
Document for detailed discussion.
Bob C.
Illinois
4
Negative
It is IMEA's understanding from interaction with other entities that Draft 3
provides significant improvement, but that key concerns raised by many entities
Thomas
Municipal
Electric
on Draft 2 were not addressed. IMEA supports comments submitted by Florida
Agency
Municipal Power Agency.
Response: Thank you for your comments. Please see our responses to your comments submitted during the Formal Comment
period..
Christopher
Plante
Integrys
Energy
Group, Inc.
4
Negative
Reason for No Vote:
1. Implementation plan is too aggressive given the drastic changes from
PRC-005-1 to PRC-005-2
2. The drastic changes don’t appear to provide an incremental increase in
the reliability of the BES
3. We support the MRO NSRS comments
Response: Thank you for your comments.
1. The SDT has carefully considered the changes that entities will be expected to make to their program in response to PRC-005-2
and provided an Implementation Plan that should be sufficient and provided a phase-in approach to permit entities to
systemically implement the revised standard. The Implementation Plan for Requirement R4 has been revised to add one year to
all established dates.
2. FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
maintenance activities. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion
that benefits reliability and that may be consistently monitored for compliance.
3. Please see our responses to MRO’s NSRS comments on the Standard Comments.
Joseph G.
Madison Gas
4
Negative
The SDT has made great improvements with this Standard but please consider the
DePoorter
and Electric
following items.
Co.
1. Replace "affecting" with "protecting" in the purpose statement.
64
Voter
Entity
Segment
Vote
Comment
2. 4.2.1 under Facilities, The description is vague and open for different
interpretations for what is “applied on” or “designed to provide protection”.
According to the November 17, 2010 Draft Supplementary Reference page 4, the
Standard will not apply to sub-transmission and distribution circuits, but will apply
to any Protection System that is designed to detect a fault on the BES and take
action in response to the fault. The Standard Drafting Team does not feel that
Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the
Regional Entity interpretations of ‘protecting” the BES. Most distribution protection
systems will not react to a fault on the BES, but are caught up in the
interpretation due to tripping a breaker(s) on the BES. Clarification is needed by
the SDT that this does not include distribution assets (notwithstanding UFLS and
UVLS).
3. Upon review, R1.4, R1.5, and R4.2 were added since the last posting. These
are not needed and must of been added to the Standard from an outside sorce.
The SDT was on the proper track to finalize this Standard. These requirements
need to be left to the individual entities to determine the depth and breath of thier
PMSP.
Response: Thank you for your comments.
1. The “Purpose” is defined by the SAR.
2. Applicability 4.2.1 has been revised to remove “applied on”. The SDT believes that this addresses your concern. Applicability
4.2.2 and 4.2.3, respectively, address UFLS and UVLS specifically, and are not related to Applicability 4.2.1. The
Supplementary Reference Documentation has been revised to clarify.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Douglas
Ohio Edison
4
Negative
Please see FirstEnergy's comments submitted separately through the comment
Hohlbaugh
Company
period posting.
Response: Thank you for your comments. Please see our responses to your comments submitted during the Formal Comment
period.
John D.
Martinsen
Public Utility
District No. 1
of Snohomish
4
Affirmative
The overly prescriptive nature of the PRC-005-2 provides greater implementation
clarity. However it may be too onerous for Local Network that have demonstrated
through studies that delayed clearing (that could be attributed to protection
65
Voter
Entity
Segment
Vote
County
Comment
system maintenance and testing) events do not create reliability or cascading
concerns.
Response: Thank you for your comments. PRC-005-2 is applicable to Protection Systems that are designed to provide protection for
BES elements, and uses the Compliance Registry to determine applicable entities. Contributions of BES elements to cascading, etc,
are immaterial in this Applicability.
Hao Li
Seattle City
Light
4
Negative
Comment: The proposed Standard PRC-005-2 is an improvement over the
previous draft in that it provides more consistency in maintenance and testing
duration internals. Notwithstanding, two issues are of concern to Seattle City Light
such that it is compelled to vote no:
1) the establishment of bookends for standard verification and 2) the
implementation timelines for entities with systems where electro-mechanical
relays still compose a significant number of components in their protection
systems. Bookends: Proposed Standard PRC-005-2 specifies long inspection
and maintenance intervals, up to 12 years, which correspondingly
exacerbates the so-called “bookend” issue. To demonstrate that intervalbased requirements have been met, two dates are needed - bookends.
Evidencing an initial date can be problematic for cases where the initial date
would occur prior to the effective date of a standard. NERC has provided no
guidance on this issue, and the Regions approach it differently. Some, such
as Texas Regional Entity, require initial dates beginning on or after the
effective date of a Standard. Compliance with intervals is assessed only once
two dates are available that occur on or after a standard took effect. Other
regions, such as Western Electricity Coordinating Council (WECC), require
that entities evidence an initial date prior to the effective date of a standard.
For WECC, compliance with intervals is assessed as soon as a standard takes
effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal.
Proposed Standard PRC-005-2 will be another such standard. Indeed this
Standard will involve by far the largest number of bookends of any NERC
standard - many thousands for a typical entity. Furthermore, the long
inspection and maintenance intervals introduced in the draft will require
entities in WECC, for instance, to evidence initial bookend dates prior to the
date original PRC-005-1 took effect. For the 12-year intervals for CTs and
VTs in proposed Standard PRC-005-2, many initial dates will occur prior to
the 2005 Federal Power Act that authorized Mandatory Reliability Standards
and even reach back before the 2003 blackout that catalyzed the effort to
pass the Federal Power Act. As a result, many entities in WECC maybe at
66
Voter
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Segment
Vote
Comment
risk of being found in violation of proposed Standard PRC-005-2 immediately
upon its implementation. Seattle City Light requests that NERC address the
bookends issue, either within proposed Standard PRC-005-2 or in a separate,
concurrent document.
2) Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with
legacy systems. In example, auxiliary relay and trip coil testing may be
essential to prove the correct operation of complex, multi-function digital
protection systems. However, for legacy systems with single-function
electro-mechanical components, the considerable documentation and
operational testing needed to implement and track such testing is not
necessarily proportional to the relative risk posed by the equipment to the
bulk electric system. Performance testing of electro-mechanical systems,
particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause
far more problems on restoration-to-service than they will locate and correct.
As such, to assist entities in their implementation efforts, we believe
provision of alternatives are necessary, such as additional implementation
time through phasing and/or through technical feasibility exceptions.
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18 Evidence”.
Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic.
2. FERC Order 693 directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is
a portion thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has developed
those requirements in a fashion that affords entities with the opportunity to best meet those requirements.
James A
Y-W Electric
4
Negative
Y-WEA appreciates the significant amount of work that the SDT has put into this
Ziebarth
Association,
revision of the standard. It is clear that the SDT is making a sincere effort to
Inc.
address comments and concerns from previous revisions of this standard, and that
is a good thing.
While Y-WEA thanks the SDT for the straightforward honesty of disagreeing with
our previous comments on the battery testing interval of 3 months for VRLA
batteries, we still feel that this mandatory maximum testing interval is
unreasonably short, based on IEEE 1188-2005.
67
Voter
Entity
Segment
Vote
Comment
The recommended testing intervals contained in that IEEE standard should be
targeted as reasonable testing intervals, with some degree of leeway allowed
before any mandatory maximum interval is defined. A mandatory maximum
interval of four calendar months would be much more appropriate here. This
would allow a reasonable testing and maintenance program to define a standard
testing interval of three months (in line with the IEEE standard) and still be able to
allow a one month buffer or grace period to account for unexpected delays in
testing due to extreme storms or other unanticipated heavy workloads. With the
draft standard as written, a company must use an unreasonably short preferred
maintenance interval if any grace period is to be built in and still remain under the
mandatory maximum interval of the NERC standard. In particular, this could have
a substantial impact on small companies that are distributed over a large area but
have limited resources to deal with such stringent testing requirements. Because
this standard will ultimately have to comply with the Regulatory Flexibility Act, it
would be worthwhile for the SDT to consider the potential impacts of essentially
forcing entities into much more stringent testing programs than recommended by
current technically-derived and peer reviewed and approved standards such as
IEEE 1188-2005.
Other than that, Y-WEA sincerely appreciates the clarity that has been added to
this standard over that contained in previous versions of the testing and
maintenance standards. This will give registered entities much more guidance as
to what NERC's and the regional entities' expectations are when it comes to
protection system testing and maintenance programs.
Response: Thank you for your comments. The SDT has revised the 3-month interval specified for VRLA batteries for some activities
to 6 months.
Francis J.
Halpin
Bonneville
5
Negative
Please see BPA's comments submitted seperately
Power
Administration
Response: Thank you for your comments. Please see our responses to your comments submitted during the Formal Comment
period.
Wilket (Jack) Consolidated
5
Negative
The Tables –
Ng
Edison Co. of
1. The wording “Component Type” is not necessary in each title. Just the
New York
equipment category should be listed--what is now shown as “Component
Type - Protective Relay”, should be Protective Relay. However, Protective
Relay is too general a category. Electromechanical relays, solid state
relays, and microprocessor based relays should have their own separate
tables. So instead of reading Protective Relay in the title, it should read
68
Voter
Entity
Segment
Vote
Comment
2.
3.
4.
5.
6.
Electromechanical Relays, etc. This will lengthen the standard, but will
simplify reading and referring to the tables, and eliminate confusion when
looking for information.
The “Note” included in the heading is also not necessary. “Attributes” is
also not necessary in the column heading, “Component” suffices. Other
Comments - In general, the standard is overly prescriptive and complex. It
should not be necessary for a standard at this level to be as detailed and
complex as this standard is. Entities working with manufacturers, and
knowledge gained from experience can develop adequate maintenance
and testing programs.
Why are “Relays that respond to non-electrical inputs or impulses (such
as, but not limited to, vibration, pressure, seismic, thermal or gas
accumulation)...” not included? The output contacts from these devices
are oftentimes connected in tripping or control circuits to isolate problem
equipment.
Due to the critical nature of the trip coil, it must be maintained more
frequently if it is not monitored. Trip coils are also considered in the
standard as being part of the control circuitry. Table 1-5 has a row labeled
“Unmonitored Control circuitry associated with protective functions”,
which would include trip coils, has a “Maximum Maintenance Interval” of
“12 Calendar Years”. Any control circuit could fail at any time, but an
unmonitored control circuit could fail, and remain undetected for years
with the times specified in the Table (it might only be 6 years if I
understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure,
then the system must be operated in real time assuming that that breaker
will not trip for a fault or an event, and backup facilities would be called
upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker
unable to trip), instead of one line tripping, you might have many more
lines deloaded or tripped because of a bus having to be cleared because
of a breaker failure initiation. The bulk electric system would have to be
operated to handle this contingency.
In reference to the FAQ document, Section 5 on Station dc Supply,
Question K, clarification is needed with respect to dc supplies for
communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation,
would the standard apply to these batteries or not?
To define terms only as they are used in PRC-005-2 is inviting confusion.
Although they may be unique to PRC-005-2, some or all of them may be
69
Voter
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Comment
7.
8.
9.
10.
11.
12.
used in future standards, some already may be used in existing standards,
and may or may not be deliberately defined. Consistency must be
maintained, not only for administrative purposes, but for effective
technical communications as well.
What is the definition of “Maintenance” as used in the table column
“Maximum Maintenance Interval”? Maintenance can range from cleaning a
relay cover to a full calibration of a relay.
A control circuit is not a component, it is made up of components.
Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify
calibration tolerances or other equivalent parameters...” means, and may
be subject to different interpretations by entities and compliance
enforcement personnel.
In the Implementation plan for Requirement R1, recommend changing
“six” to fifteen. This change would restore the 3-month time difference
that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require
regulatory approval. It will ensure equity for those entities located in
jurisdictions that do not require regulatory approval, as is the case in
Ontario.
The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It
seems to continue to the next page to a new box. There are multiple
activities without clear delineation.
Regarding station service transformers, Item 4.2.5.5 under Applicability
should be deleted. The purpose of this standard is to protect the BES by
clearing generator, generator bus faults (or other electrical anomalies
associated with the generator) from the BES. Having this standard apply
to generator station service transformers, that have no direct connection
to the BES, does meet this criteria. The FAQs (III.2.A) discuss how the
loss of a station service transformer could cause the loss of a generating
unit, but this is not the purpose of PRC-005. Using this logic than any
system or device in the power plant that could cause a loss of generation
should also be included. This is beyond the scope of the NERC standards.
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that
minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent maintenance,
a performance-based program in accordance with R3 and Attachment A is an option.
70
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Comment
3. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection
System definition. Also, there is currently no technical basis for the maintenance of the devices which respond to non-electrical
quantities on which to base mandatory standards related either to activities or intervals. Absent such a technical basis, we are
currently unable to establish mandatory requirements, but may do so in the future if such a technical basis becomes available.
4. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year interval.
You can maintain these devices more frequently if you desire.
5. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the communications
system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The specific station dc
supply requirements (Table 1-4) do not apply to the dc supply associated only with communications systems. The SDT has
decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference
document. Your comments have been considered within that activity.
6. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms,
either now or in the future, may not be consistent with the terms used here. They are defined only for clarify within this standard.
7. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are specified
in the Activities column. The term is capitalized in the column title in conformance with normal editorial practice as a title, rather
than as a definition.
8. For purposes of this standard, the control circuit is defined as one component type.
9. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed
within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4
has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been
revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
10. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1,making it
consistent with the remainder of the Implementation Plan.
11. Table 1-4 has been further modified for clarity.
12. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
Amir Y
Constellation
5
Negative
Constellation Power Generation is voting against this standard for the following
Hammad
Power Source
reasons:
Generation,
1. The applicability has included more generation protective components.
Inc.
The current PRC-005 guidance states that only Station Service
transformers for plants 75 MVA and up should be included. The proposed
71
Voter
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Comment
2.
3.
4.
5.
standard includes all station service transformers, regardless of plant size
or connection (via generator or system). Constellation Power Generation
does not see the reliability benefits of this increased scope.
R1.4 states that all monitoring attributes of all components must be listed
and identified. For most generation facilities, it is more efficient to
calibrate/check the entire protective system while the plant is in an
outage, regardless of a component’s monitoring capabilities. This
requirement would require those facilities to maintain a list of attributes
that won’t ever be used, and would not alter their testing frequency. What
if an entity were found non-compliant in the situation that was just
described? It does not affect the reliability of the BES and therefore R1.4
should be removed.
M1 doesn’t include a measure for R1.4. It just implies that a facility must
maintain a list.
The battery listing in the attached table is still too prescriptive. If
unmonitored, there should be a quarterly and yearly check, which is
implied, but it is then broken out by battery type to be more prescriptive.
PTs and CTs are mentioned, but it seems as though the drafting team
wants a facility to only test the outputs to ensure they are working
properly. To clarify this, Constellation Power Generation suggests
rewording the testing verbiage for PTs and CTs.
Response:
1. Section 4.2.5 of “Applicability” specifies that only Generation Facilities that are part of the BES are included.
2. The SDT disagrees; Requirement R1, Part 1.4 supports Requirement R1, Part 1.2, and seems necessary to assure that entities have
appropriately applied the longer intervals associated with monitored components. However, in consideration to your comment the
SDT has revised Requirement R1, Part 1.4 and has also removed Requirement R2 because of redundancy to Requirement R1, Part
1.4.
3. Measure M1 has been revised in consideration of your comment.
4. The activities for different battery types are addressed separately because the relevant activities differ.
5. The SDT intends that the instrument transformer and associated circuitry be verified to be functional, but believes that customary
apparatus maintenance (dielectric, infrared, etc) are not relevant to PRC-005-2.
James B
Consumers
5
Negative
1. Table 1-3 states, “are received by the protective relays”. Does this require that
Lewis
Energy
the inputs to each individual relay must be checked, or is it sufficient to verify that
acceptable signals are received at the relay panel, etc?
2. Relative to Table 1-5, the activities will likely require that system components
be removed from service to complete those activities. If the changes to the BES
definition (per the FERC Order) causes system elements such as 138 kV connected
distribution transformers to be considered as BES, these components can not be
removed from service for maintenance without tripping customers. The standard
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Response: Thank you for your comments.
Vote
Comment
must exempt these components from the activities of Table 1-5 if the activity
would result in deenergizing customers.
3. For the component types addressed in Tables 1-3 and 1-5, the requirements
may cause entities to identify components very differently than they are currently
doing, and doing so may take several years to complete. The Implementation Plan
for R1 and R4 is too aggressive in that it may not permit entities to complete the
identification of discrete components and the associated maintenance and
implement their program as currently proposed. We propose that the
Implementation Plan specifically address the components in Table 1-3 and 1-5
with a minimum of 3 calendar years for R1 and 12 calendar years after that for
R4.
4. As for the interval in Table 1-4 regarding the battery terminal connection
resistance, we believe that an 18-month interval is excessively frequent for this
activity, and suggest that it be moved to the 6-calendar-year interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections
every 4-years, rather than measuring the terminal connection resistance to
determine if the connections are sound. Disregarding the interval, would this
activity satisfy the “verify the battery terminal connection resistance” activity?
1. The SDT intends that the voltage and current signals properly reach each individual relay, but there may be several methods
of accomplishing this activity.
2. This concern seems more properly to be one to be addressed during the activities to develop the new BES definition, rather
than within PRC-005-2.
3. The Implementation Plan for Requirement R1 has been modified from 6 months to 12 months. The Standard has also been
modified (Requirement R1, Part 1.1) to not specifically require identification of all individual Protection System components.
The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
4. IEEE 450, 1188, 1106 all recommend this activity at a 12-month interval. Please see Clause 15.4.1 of the Supplementary
Reference Document for a discussion of this activity.
5. Re-torqueing the battery terminals would not meet this requirement.
Mike Garton
Dominion
5
Negative
Dominion is opposed to this version because Requirement R1.5 is overly
Resources,
prescriptive, requiring an extraordinary level of documentation, with little
Inc.
anticipated improvement in reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
73
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Stanley M
Jaskot
Entergy
Corporation
Segment
5
Vote
Negative
Comment
The restructured tables are generally much clearer and the SDT is to be
commended on their efforts.
1. However, we believe the Alarming Point Table needs additional
clarification with regard to the Maximum Maintenance Interval. If an
“alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there
isn’t necessarily a maximum interval established as there is for Protection
System components. Also, if an entity’s alarm producing device
maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum
intervals for the alarm producing device of that entity. On that basis, we
suggest the interval verbiage be revised to “When alarm producing device
or system is verified, or by sections as per the monitored
component/protection system specified maximum interval as applicable”.
Alternately, if the intention is to establish maximum intervals as simply
being no longer than the individual component maintenance intervals as
we suggest for inclusion above, then the verbiage should be revised to
“When alarm producing component/protection system segment is
verified”. In either case are we to interpret monitored components with
attributes which allow for no periodic maintenance specified as not
requiring periodic alarm verification?
2. R1.5 calls for “identification of calibration tolerances or equivalent
parameters...” whereas the associated VSL references “failure to establish
calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply
“identify” or document such calibration tolerances would be analogous to
the severity level(s) of a “failure to specify one (or the severity level
should be consistent with the other elements of R1. Both cases appear to
be more of a documentation issue as opposed to a failure to implement.
Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4?
3. R1.5 calls for “identification of calibration tolerances or equivalent
parameters for each Protection System Component Type....”. We believe
the Supplementary Reference document should provide additional
information and examples of calibration tolerances or equivalent
parameters which would be expected for the various component types.
Especially for any “equivalent” parameters which would be required for
compliance for a component type besides protective relays. Adding
Requirement 1.5 is a significant revision and raises questions as to how
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Comment
broadly an accuracy or equivalent parameter requirement and associated
documentation would need to be addressed by entities and/or will be
measured for compliance. Discussion on this new requirement does not
seem to be addressed anywhere in the FAQ or Supplementary Reference
documents. Additionally, to the best of our knowledge, the need for such
a requirement was not brought up as a concern or comment on the prior
draft version of this standard, and in the context of a requirement need,
we don’t believe it has been attributed to or actually poses any significant
reliability risk. We do not believe this requirement is justified.
Response: Thank you for your comments.
1. The Maximum Maintenance Interval column entry in Table 2 has been revised to state, “When alarm producing Protection
System component is verified” to clarify this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Kenneth
FirstEnergy
5
Negative
Please see FirstEnergy's comments submitted separately through the comment
Dresner
Solutions
period posting
Response: Thank you for your comments. Please see our responses to your comments submitted during the formal comment
period.
David
Schumann
Florida
Municipal
Power Agency
5
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuity, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
that distribution circuit. There is no real reliability need for this either.
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Response: Thank you for your comments.
Vote
Comment
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regio0nsl UFLS program is being
met, but, to test the other protection system components is not
worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing
faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this
version is better than prior versions because it essentially requires the
entity to determine it's own period of maintenance and testing for
UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical the VRF of R1 should be Low since the attached tables are
essentially the PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made modifications to Applicability 4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
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Comment
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
Rex A Roehl
Indeck Energy
Services, Inc.
5
Negative
The level of detail for every conceivable component of every conceivable
protective system does not relate to improving reliability. For some protective
systems on some equipment, following these requirements, which is undoubtedly
already done, will result in good reliability, but probably not improve reliability.
Applying those same requirements to the thousands, if not millions, of other
protective systems with generate significant costs, generate significant numbers of
violations and not have any significant impact on reliability. The costs of this type
of program cannot be justified unless there is an NRC mandate or a pass through
to ratepayers. Most of the industry will take the cost of this program directly from
the bottom line. For minimal reliability improvement, that is not appropriate under
the FPA Section 215.
Response: Thank you for your comments. FERC Order 693 and the approved SAR assign the SDT to develop a standard with
maximum allowable intervals and minimum maintenance activities. The intervals and activities specified are believed by the SDT to
be technically effective, in a fashion that benefits reliability and that may be consistently monitored for compliance.
Dennis
Florom
Lincoln
Electric
System
5
Affirmative
While the proposed draft of the standard is acceptable as currently written, LES
would like the drafting team to consider the following comments.
(1) Table 1-1 should state “Test and calibrate (if necessary)” in the first section
under activities. If a relay passes the test, there is no need to calibrate it.
Therefore, not all relays will require calibration.
(2) Please explain the drafting team’s reason for not checking the trip coils of
breakers in the UFLS/UVLS schemes but ensuring that all others are operated
every six years. It would appear that they can all be lumped into the same group
one way or another.
(3) In regards to Specific Gravity Testing, many people do not perform the specific
gravity test routinely if they perform the individual cell internal ohmic test
routinely. LES asks the drafting team to consider allowing the internal cell ohmic
test as a substitute for the specific gravity test.
Response: Thank you for your comments.
1. Table 1-1 has been modified as you suggest.
2. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the
Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system
elements.
3. Table 1-4 does not specify specific gravity testing.
Mike Laney
Luminant
5
Negative
Luminant commends the PRC-005-2 Standard Drafting Team for its quality efforts
Generation
in producing this version of the Standard however; Luminant must cast a negative
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Comment
ballot vote for this present version of the Standard. The negative vote against the
present version of PRC-005-2 is solely based on the addition of Requirement R1
Part 1.5 with its associated reference to it in Requirement R4 Part 4.2 and the VSL
table.
It is Luminant’s opinion that this new Requirement as written subjects all
Transmission Owners, Generation Owners and Distribution Providers to vague
interpretations of a requirement that cannot be complied with because it is
impossible for any of them to draft the necessary documentation to be compliant
with the Standard. As stated in the High VSL associated with Part 1.5 of
Requirement R1 all owners will fail “to establish calibration tolerance or equivalent
parameters to determine if every individual discrete piece of equipment in a
Protection System is within acceptable parameters.”
It is Luminant’s opinion that the measurement of acceptable performance during
maintenance and testing activities can be accomplished with a Pass/Fail type of
documentation on a test form. No company can effectively establish calibration
tolerance parameters for an entire “component type” of the Protection System.
Doing so could be detrimental to the reliability of the grid. Parameters are
dependent on the location, application and situation specific to each Protection
System device.
The inclusion of Part 1.5 of Requirement R1 is a significant addition to the
standard, and by NERC Rules of Procedure requires the input and consideration of
the full Standard Drafting Team.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Wayne Lewis Progress
5
Negative
1. Implementation Plan for PRC-005-2 Since R2, R3, and R4 requirements
Energy
would be performed after establishment of the program documentation,
Carolinas
an additional year should be added to all implementation dates for
Requirements R2, R3, and R4 as shown below:
• Maintenance on components with intervals less than one year must be
completed within two years after applicable regulatory approval
(within one year of completion of R1 Program Documentation).
•
Maintenance on components with intervals between one year and
two years must be completed within three years after applicable
regulatory approval (within two years of completion of R1 Program
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Comment
Documentation).
• Maintenance on components with intervals of six years must be
completed within three-, five-, and seven-year milestones after
applicable regulatory approval (within two, four, and six years of
completion of R1 Program Documentation).
•
Maintenance on components with intervals of twelve years must be
completed within five-, nine-, and thirteen-year milestones after
applicable regulatory approval (within four, eight, and twelve years of
completion of R1 Program Documentation).
2. Standard PRC-005-02 1. Table 1-2: Rows 1 and 2 require different
intervals for the activity “Verify essential signals to and from Protection
System components.” Unless these inputs and outputs are monitored for
Row 2, it would seem that they should be performed at the same interval
for both Rows 1 and 2. Therefore, EITHER:
1. Row 1 should be broken into the following three activities:
• 3 months - Verify communications system is functional
• 6 years - Verify channel meets performance criteria
• 12 years - Verify essential signals to and from other Protection
System components OR:
2. Row 2 should be broken into the following two activities:
1. 12 years - Verify channel meets performance criteria
2. 6 years - Verify essential signals to and from other Protection System
components 2.
3. Table 1-4: Only Row 1 addresses dc supplies associated with UFLS or
UVLS systems. All other rows state that UFLS or UVLS systems are
excluded. What is required to “Verify dc supply voltage” for the
UFLS/UVLS systems? Does it require that the overall station battery
voltage be checked or just the dc voltage available to the UFLS/UVLS
circuit of interest? If a voltage measurement is taken at the UFLS/UVLS
circuit (e.g., in distribution breaker cabinet), can the batteries/chargers at
these facilities be excluded from the PRC-005-2 scope as long as they do
not also supply transmission-related protection?
4. PRC-005-2 FAQ’s Document Section V.1.A, Example #2: The instrument
transformer should be classified as “unmonitored” not “monitored.”
Response: Thank you for your comments.
1. The Implementation Plan for Requirement R1 has been changed from 12 months to 15 months in consideration of your
comment. The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
2. The first and second rows differ in that the first row is for unmonitored communications systems, and the second row is for
monitored communications systems. The activities in both rows are appropriate and correct.
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Comment
3. Table 1-4 has been completely re-structured. For station dc supply for only UFLS/UVLS, the only activity is to verify the dc
voltage.
4. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
Jerzy A
PSEG Power
5
Negative
The PSEG Companies do not agree with the Facilities as currently described in
Slusarz
LLC
section 4.2.5.5. Please refer to detailed comments provided in the formal
Comment Form.
Response: Thank you for your comments. Please see our response to your detailed comments from the formal comment period.
Steven
Grega
Public Utility
District No. 1
of Lewis
County
5
Negative
Do not like the word "all" in the proposed standard. Does all components mean
each piece of wire is included? Engineers are conservative in their protection
system designs and have redundant relays and protection paths. Even with half
the relays out of service, protection is normally retained. Would want to have 80%
a compliance level with a year to test & maintenance any component testing
founded to be non-compliant. This proposed standard will ensure many more
violations.
Response: Thank you for your comments. The approved PRC-005-1 already requires that entities have a program to maintain their
Protection System and implement that program. This already implies, “all”, therefore PRC-005-2 should not have the impact
suggested by your comment.
Michael J.
Haynes
Seattle City
Light
5
Negative
The proposed Standard PRC-005-2 is an improvement over the previous draft in
that it provides more consistency in maintenance and testing duration internals.
Notwithstanding, two issues are of concern to Seattle City Light such that it is
compelled to vote no:
1.
the establishment of bookends for standard verification and 2) the
implementation timelines for entities with systems where electro-mechanical
relays still compose a significant number of components in their protection
systems. Bookends: Proposed Standard PRC-005-2 specifies long inspection
and maintenance intervals, up to 12 years, which correspondingly
exacerbates the so-called “bookend” issue. To demonstrate that intervalbased requirements have been met, two dates are needed - bookends.
Evidencing an initial date can be problematic for cases where the initial date
would occur prior to the effective date of a standard. NERC has provided no
guidance on this issue, and the Regions approach it differently. Some, such
as Texas Regional Entity, require initial dates beginning on or after the
effective date of a Standard. Compliance with intervals is assessed only once
two dates are available that occur on or after a standard took effect. Other
regions, such as Western Electricity Coordinating Council (WECC), require
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2.
that entities evidence an initial date prior to the effective date of a standard.
For WECC, compliance with intervals is assessed as soon as a standard takes
effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal.
Proposed Standard PRC-005-2 will be another such standard. Indeed this
Standard will involve by far the largest number of bookends of any NERC
standard - many thousands for a typical entity. Furthermore, the long
inspection and maintenance intervals introduced in the draft will require
entities in WECC, for instance, to evidence initial bookend dates prior to the
date original PRC-005-1 took effect. For the 12-year intervals for CTs and
VTs in proposed Standard PRC-005-2, many initial dates will occur prior to
the 2005 Federal Power Act that authorized Mandatory Reliability Standards
and even reach back before the 2003 blackout that catalyzed the effort to
pass the Federal Power Act. As a result, many entities in WECC maybe at
risk of being found in violation of proposed Standard PRC-005-2 immediately
upon its implementation. Seattle City Light requests that NERC address the
bookends issue, either within proposed Standard PRC-005-2 or in a separate,
concurrent document.
Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with
legacy systems. In example, auxilary relay and trip coil testing may be
essential to prove the correct operation of complex, multi-function digital
protection systems. However, for legacy systems with single-function
electro-mechnical compenents, the considerable documentation and
operational testing needed to implement and track such testing is not
necessarily proporational to the relative risk posed by the equipment to the
bulk electric system. Performance testing of electro-mechanical systems,
particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause
far more problems on restoration-to-service than they will locate and correct.
As such, to assist entities in their implementation efforts, we believe
provision of alternatives are necessary, such as additional implementation
time through phasing and/or through technical feasability exceptions.
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Comment
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18
Evidence”.
2. Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic. FERC Order
693 directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is a
portion thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has
developed those requirements in a fashion that affords entities with the opportunity to best meet those requirements.
William D
Southern
5
Negative
Please see comments submitted via the electronic comment form.
Shultz
Company
Generation
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
George T.
Ballew
Tennessee
Valley
Authority
5
Negative
Project 2007-17 Protection System Maintenance for Standard PRC-005-2 Draft NERC is recommending significant changes to this sizeable standard and only
allowing minimum comment period. While this is a good standard that has clearly
taken many hours to develop, we are primarily voting NO because of the hurried
fashion it is being commented, voted, and reviewed. Official comments to the
document were entered on the NERC Portal.
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
Melissa Kurtz
U.S. Army
Corps of
Engineers
5
Negative
Paragraph 4.2.5.4 - The standard should be changed to require station service
transformers only if they will cause a loss of the generator tied to the BES. Also
recommend a definition of station service - we have station service that if lost
would not negatively effect the BES.
Response: Thank you for your comments. Clause 4.2.5.5 has been removed. Generator-connected station service transformers are
essential to the continuing operation of the generation plant; therefore, protection on these system components is included within
PRC-005-2 if the generation plant is a BES facility.
Martin Bauer
P.E.
U.S. Bureau
of
Reclamation
5
Negative
1. The tables rely on a reference document which is not a part of the standard
and as such may be altered without due process. Either the relevant text from
the reference needs to be inserted into the standard or the reference itself
incorporated into the standard.
2. The supplemental reference provides significant clarity to the intent of
standard; however, in doing so, it reveals conflicts and ambiguity in the text of
the standard. It is suggested that some of the clarifying language be inserted
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into the text of the standard.
3. The concept of including definitions in this standard that are not a part of the
Glossary of Terms will create a conflict with other standards that choose to use
the term with a different meaning. This practice should be disallowed. If a
definition is be introduced it should be added to the Glossary of Terms. This
concept was not provided to industry for comment when the modifications to
the Definition of Protection System was introduced. Additional related to this
practice are included later on.
4. The Term "Protective Relays" is overly broad as it is not limited to those
devices which are used to protect the BES. In the reference provided to the
standard, the SDT defined "Protective Relays" as "These relays are defined as
the devices that receive the input signal from the current and voltage sensing
devices and are used to isolate a faulted portion of the BES. " The Definition
for "Protective Relays' as well as the components associated with the them
should be associated with the protection of the BES in the definition.
5. The Section 2.4 of the attached reference and the recent FERC NOPR are in
conflict with the definition of "Protective Relays" which include lockout relays
and transfer trip relays "The relays to which this standard applies are those
relays that use measurements of voltage, current, frequency and/or phase
angle and provide a trip output to trip coils, dc control circuitry or associated
communications equipment.
6. This Draft 2: April3: November 17, 2010 Page 5 definition extends to IEEE
device # 86 (lockout relay) and IEEE device # 94 (tripping or trip-free relay) as
these devices are tripping relays that respond to the trip signal of the
protective relay that processed the signals from the current and voltage
sensing devices." The definition should be revised to reflect that is really
intended. The SDT as created an implied definition by specifically defining DC
circuits associated with the trip function of a "Protective Relay" but failing to
specifically define voltage and current sensing circuits providing inputs to
"Protective Relays". The team clearly intended the circuits to be included but
the definition does not since it only refers the the "voltage and current sensing
devices".
7. Starting with the Definitions and continuing through the end of the document,
terms that have been defined are not capitalized. This leaves it ambiguous as
to whether the defined term is to be applied or it is a generic reference. Only
defined terms "Protection System Maintenance Program" and "Protection
System" are consistently capitalized.
8. Protection System Maintenance Program (PSMP) definition: The Restore bullet
should be revised to read as follows: "Return malfunctioning components to
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proper operation by repair or calibration during performance of the initial onsite activity." Add the following at the end of the PSMP definition: “NOTE:
Repair or replacement of malfunctioning Components that require follow-up
action fall outside of the PSMP, and are considered Maintenance Correctable
Issues.”
9. Protection System (modification) definition: The term "protective functions"
that is used herein should be changed to "protective relay functions" or what is
meant by the phrase should become a defined term, as it is being used as if it
is a well known well defined, and agreed upon term.
a. The first bullet text should be revised to read as follows: "Protective relays
that monitor BES electrical quantities and respond when those quantities
exceed established parameters," the last two bullets should be reversed in
order and modified to read as follows: o control circuitry associated with
protective relay functions through the trip coil(s) of the circuit breakers or
other interrupting devices, and o station dc supply (including station
batteries, battery chargers, and non-battery-based dc supply) associated
with the preceding four bullets.
10. Statement between the Protection System (modification) definition and the
Maintenance Correctable Issue definition; Is this a NERC accepted practice?
There does not appear to be a location in the standard for defining terms.
Having terms that are not contained in the "Glossary of Terms used in NERC
Reliability Standards," and are outside of the terms of the standards, and yet
are necessary to understand the terms of the Requirements is not acceptable.
They would become similar to the reference documents, and could be changed
without notice.
11. Maintenance Correctable Issue definition: The last sentence should be
modified to read as follows: "Therefore this issue requires follow-up corrective
action which is outside the scope of the Protection System Maintenance
Program and the Standard PRC-005-2 defined Maximum Maintenance
Intervals." The definition could also be easily clarified to read "Maintenance
Correctable Issue - Failure of a component to operate within design
parameters such that it cannot be restored to functional order by repair or
calibration; therefore requires replacement." This ensures that any action to
restore the equipment, short of replacement, is still considered maintenance.
Otherwise ambiguity is introduced as what "maintenance" is.
12. Countable Event definition: An explanation should be made that this is a part
of the technical justification for the ongoing use of a performance-based
Protection System Maintenance Program for PRC-005.
13. Insert the phrase "Standard PRC-005-2" before the term "Tables 1-1..."
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14. Applicability: 4.2. Facilities: 4.2.5.4 and 4.2.5.5: Delete these two parts of
the applicability. Station service transformer protection systems are not
designed to provide protection for the BES. Per PRC-005-2 Protection System
Maintenance Draft Supplementary Reference, Nov. 17 2010, Section 2.3 Applicability of New Protection System Maintenance Standards: “The BES
purpose is to transfer bulk power. The applicability language has been changed
from the original PRC-005: “...affecting the reliability of the Bulk Electric
System (BES)...” To the present language: “... and that are applied on, or are
designed to provide protection for the BES.” The drafting team intends that
this Standard will not apply to “merely possible” parallel paths, (subtransmission and distribution circuits), but rather the standard applies to any
Protection System that is designed to detect a fault on the BES and take action
in response to that fault.” Station Service transformer protection is designed to
detect a fault on equipment internal to a powerplant and not directly related to
the BES. In addition, many Station Service protection ensures fail over to a
second source in case of a problem. Thus station service transformer
protection system is a powerplant reliability issue and not a BES reliability
issue. As such station service transformer protection should not be included in
PRC 005 2. In addition, the SDT appears to have targeted generation station
service without regard to transmission systems. If generating station service
transformers are that important, then why are substation/switchyard station
service transformers not also important?
15. Requirements Should the sub requirements have the "R" prefix?
16. R4. Change the phrase "... PSMP, including identification of the resolution of
all ..." to read "...PSMP including identification, but not the resolution, of all
...".
17. General comment PRC005-2 is very specific in listing the
Response: Thank you for your comments.
1. The Tables do not provide a reference to either the Supplementary Reference Document or the FAQ. An entity must comply with
the standard when approved. The reference documents provide additional explanation, discussion, and rationale, but are not
part of the mandatory standard. Since the reference documents are developed in accordance with the standard and will be
posted with the standard, the NERC Standard Development Procedure does require that they undergo industry review before
being initially posted, and upon any revision.
2. The clarifying language is exactly that – clarifying language, and is not essential to application of the Standard. He NERC
Standards Development Procedure establishes that the standard shall not include explanatory text.
3. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms,
may change them in a fashion inconsistent with the intended usage within PRC-005-2.
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4. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition with
PRC-005. Further, the applicability of generically-described protective relays is defined by the Applicability clause of PRC-0052.
5. The issues raised by the FERC NOPR will be addressed as part of the response to the NOPR (and, ultimately, the Order). The
extension of auxiliary and lockout relays is not part of the protective relay (addressed within Table 1-1), but instead as part of the
control circuitry (Table 1-5).
6. The extension of auxiliary and lockout relays is not part of the protective relay (addressed within Table 1-1), but instead as part of
the control circuitry (Table 1-5).
7. Definition from the NERC Glossary of Terms (or those intended for the Glossary) are consistently capitalized (Protection System
and Protection System Maintenance Program fall within this category). As for terms defined only for use within this standard,
these terms are NOT capitalized, since they are not in the Glossary of Terms.
8. The “restore” portion of PSMP specifically addresses returning malfunctioning components to your proper operation. The
requirements regarding maintenance correctable issues are further addressed within that definition (for use only within PRC-0052).
9. The SDT is currently not planning on further modifying the most recent NERC BOT-approved definition of Protection System.
10. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms,
may change them in a fashion inconsistent with the intended usage within PRC-005-2.
11. Identifying problems, but not fixing them, does not constitute an effective program. In deference to the time that may be
necessary to repair / replace defective components, the SDT has decided to require only initiation of resolution of maintenance
correctable issues, not to demonstration completion of them.
12. Since this term is used only in Attachment A, it seems unnecessary to provide the explanation requested.
13. The SDT has elected not to change the reference to the Tables throughout the Standard.
14. Thank you for your comments. Clause 4.2.5.5 has been removed. Generator-connected station service transformers are essential
to the continuing operation of the generation plant; therefore, protection on these system components is included within PRC005-2 if the generation plant is a BES facility.
15. The current style guide for NERC Standards does not preface the Parts with an “R”.
16. Identifying problems, but not fixing them, does not constitute an effective program. In deference to the time that may be
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necessary to repair / replace defective components, the SDT has decided to require only initiation of resolution of maintenance
correctable issues, not to demonstration completion of them.
17. It appears the remainder of your comment was truncated and cannot be ascertained.
Linda Horn
Wisconsin
Electric Power
Co.
5
Negative
Q4: Table 1-4 requires an activity to verify the state of charge of battery cells.
There are no possible options for meeting this requirement listed in the FAQ
document. Unlike other terms used in the standard, this term is not mentioned or
defined in the FAQ. To comply with this standard, the SDT needs to provide more
guidance. For example, for VLA batteries the measured specific gravity could
indicate state of charge. For VRLA batteries, it is not as clear how to determine
state of charge, but possibly this can be determined by monitoring the float
current.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into
the Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been
revised to remove “state of charge” from the activities.
Leonard
Rentmeester
Wisconsin
Public Service
Corp.
5
Negative
1. Implementation plan is too aggressive given the drastic changes from PRC005-1 to PRC-005-2
2. The drastic changes don’t appear to provide an incremental increase in the
reliability of the BES
3. We support the MRO NSRS comments
Response: Thank you for your comments.
1. The SDT has carefully considered the changes that entities will be expected to make to their program in response to PRC-005-2
and provided an Implementation Plan that should be sufficient and provided a phase-in approach to permit entities to
systemically implement the revised standard. The Implementation Plan for Requirement R4 has been revised to add one year to
all established dates.
2. FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
maintenance activities. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that
benefits reliability and that may be consistently monitored for compliance.
3. Please see our responses to MRO’s NSRS formal comments in the Consideration of Comments document.
Liam Noailles Xcel Energy,
5
Negative
We feel that several improvements were made since the last draft. However, we
Inc.
feel that some gaps exist that should be addressed before moving this project
forward. We have detailed our issues in our formal comments
Response: Thank you for your comments. Please see our response to your formal comments.
Edward P.
Cox
AEP
Marketing
6
Negative
Restructured Tables:
1. Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12 years
for unmonitored control circuitry, yet other portions of control circuitry have a
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maximum interval of 6 years. AEP does not understand the rationale for the
difference in intervals, when in most cases, one verifies the other. Also,
unmonitored control circuitry is capitalized in row 4 such that it infers a
defined term.
2. In the first row of table 1-4 on page 16, it is difficult to determine if it is a cell
that wraps from the previous page or is a unique row. This is important
because the Maximum Maintenance Intervals are different (i.e. 18 months vs
6 years). It is difficult to determine to which elements the 6 year Maximum
Maintenance Interval applies. AEP suggests repeating the heading “Monitored
Station dc supply (excluding UFLS and UVLS) with: Monitor and alarm for
variations from defined levels (See Table 2):” for the bullet points on this
page.
VSLs, VRFs and Time Horizons:
3. The VSL table should be revised to remove the reference to the Standard
Requirement 1.5 in the R1 “High” VSL.
4. All four levels of the VSL for R2 make reference to a “condition-based PSMP.”
However, nowhere in the standard is the term “condition-based” used in
reference to defining ones PSMP. The VSL for R2 should be revised to remove
reference to a condition-based PSMP; alternatively the Standard could be
revised to include the term “condition-based” within the Standard
Requirements and Table 1.
5. In multiple instances, Table 1 uses the phrase “No periodic maintenance
specified” for the Maximum Maintenance Interval. Is this intended to imply
that a component with the designated attributes is not required to have any
periodic maintenance? If so, the wording should more clearly state “No
periodic maintenance required” or perhaps “Maintain per manufacturers
recommendations.” Failure to clearly state the maintenance requirement for
these components leaves room for interpretation on whether a Registered
Entity has a maintenance and testing program for devices where the Standard
has not specified a periodic maintenance interval and the manufacturer states
that no maintenance is required.
FAQ and Supplementary Reference:
6. With such a complex standard as this, the FAQ and Supplementary Reference
documents do aid the Protection System owner in demystifying the
requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a. Section 5 of the Supplementary Reference, refers to “condition-based”
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maintenance programs. However, nowhere in the standard is the term
“condition-based” used in reference to defining ones PSMP. The
Supplementary Reference should be revised to remove reference to a
condition-based PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard Requirements
and Table 1.
b. Section 15.7, page 26, appears to have a typographical error “...can
all be used as the primary action is the maintenance activity...”
c. Figure 2 is difficult to read. The figure is grainy and the colors
representing the groups are similar enough that it is hard to
distinguish between groups.
“Frequently-Asked Questions”:
7. With such a complex standard as this, the FAQ and Supplementary Reference
documents do aid the Protection System owner in demystifying the
requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a. The section “Terms Used in PRC-005-2” is blank and should be
removed as it adds no value. Section I.1 and Section IV.3.G reference
“condition-based” maintenance programs. However, nowhere in the
standard is the term “condition-based” used in reference to defining
ones PSMP.
b. The FAQ should be revised to remove reference to a condition-based
PSMP; alternatively the Standard could be revised to include the term
“condition-based” within the Standard Requirements and Table 1.
c. The second sentence to the response in Section I.1 appears to have a
typographical error “... an entity needs to and perform ONLY timebased...”.
General:
8. Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2
should be removed. Specifying calibration tolerances for every protection
system component type, while a seemingly good idea, represents a substantial
change in the direction of the standard. It would be very onerous for
companies to maintain a list of calibration tolerances for every protection
system component type and show evidence of such at an audit. AEP believes
entities need the flexibility to determine what acceptance criteria is warranted
and need discretion to apply real-time engineering/technician judgment where
appropriate.
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Response: Thank you for your comments.
Vote
Comment
9. Three different types of maintenance programs (time-based, performancebased and condition-based) are referenced in the standard or VSLs, yet the
time-based and condition-based programs are neither defined nor described.
Certain terms defined within the definition section (such as Countable Event or
Segment) only make sense knowing what those three programs entail. These
programs should be described within the standard itself and not assume a
knowledge of material in the Supplementary Reference or FAQ.
10. “Protective relay” should be a defined term that lists relay function for
applicability. There are numerous ‘relays’ used in protection and control
schemes that could be lumped in and be erroneously included as part of a
Protection System. For example, reclosing or synchronizing relays respond to
voltage and hence could be viewed by an auditor as protective relays, but
they in fact perform traditional control functions versus traditional protective
functions.
11. The Data Retention requirement of keeping maintenance records for the two
most recent maintenance performances is a significant hurdle for any owners
to abide by during the initial implementation period. The implementation plan
needs to account for this such that Registered Entities do not have to provide
retroactive testing information that was not explicitly required in the past.
1. The 6-year activities are all related to components with “moving parts”, and the 12-year activities are related to the other
portions of the control circuitry. The capitalized term has been corrected.
2. Table 1-4 has been modified in consideration of your comments.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
The associated VSL has also been revised.
4. The SDT concluded that Requirement R2 is redundant to Requirement R1, Part 1.4 and has deleted Requirement R2 (together
with the Measures and & VSL).
5. If the indicated monitoring attributes are present, no “hands-on” periodic maintenance is required, as the monitoring of the
component is providing a continuing indication of its functionality.
6. The discussion within the Supplementary Reference Document and FAQ are informative, not normative, and thus do not
belong as part of the standard.
a) The Supplementary Reference Document discusses condition-based maintenance in a conceptual manner, as a
generally-recognized term. The SDT did make some changes within the Supplementary Reference document to
clarify the manner in which condition-based maintenance is discussed.
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b) This clause has been corrected.
c) A higher-quality version of Figure 2 has been substituted.
7. The discussion within the Supplementary Reference Document and FAQ are informative, not normative, and thus do not
belong as part of the standard.
a) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
b) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
c) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
8. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
9. The term, “condition-based” has been removed from the draft standard. The other terms are used, but are clear in the context
in which they are used.
10. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition with
PRC-005. Further, the applicability of generically-described protective relays is defined by the Applicability clause of PRC005-2.
11. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the
data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that entities have
been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified
the data retention in the posted standard to establish this level of documentation. This seems to be consistent with the current
practices of several Regional Entities.
Brenda S.
Bonneville
6
Negative
Refer to BPA comments
Anderson
Power
Administration
Response: Thank you for your comments. Please see our response to the BPA comments.
Matthew D
Cripps
Cleco Power
LLC
6
Negative
Cleco applies its’ UFLS on the distribution grid with each UF relay individually
tripping a relatively low value of load thru breakers and reclosers. Since our
program is implemented via a large number of individual components, breakers,
reclosers, and individual batteries, the failure of any one component will have a
minimal impact on the effectiveness of the overall UFLS program within our
region. Therefore, the verification of sensing devices, dc supply voltages, and the
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paths of the control circuit and trip circuits on the UFLS systems implemented on
the distribution grid is unnecessary.
Response: Thank you for your comments. The SDT disagrees; the sensing devices, control circuitry and dc supply related to UFLS
has an effect on the performance of the UFLS. The SDT has, however, respected the overall impact on the control circuitry of
individual UFLS on BES reliability by requiring that UFLS be subjected to a subset of the overall sensing devices, control circuitry
and dc supply maintenance activities.
Nickesha P
Consolidated
6
Negative
The Tables
Carrol
Edison Co. of
1. The wording “Component Type” is not necessary in each title. Just the
New York
equipment category should be listed--what is now shown as “Component Type
- Protective Relay”, should be Protective Relay. However, Protective Relay is
too general a category. Electromechanical relays, solid state relays, and
microprocessor based relays should have their own separate tables. So
instead of reading Protective Relay in the title, it should read
Electromechanical Relays, etc. This will lengthen the standard, but will simplify
reading and referring to the tables, and eliminate confusion when looking for
information. The “Note” included in the heading is also not necessary.
2. “Attributes” is also not necessary in the column heading, “Component”
suffices.
Other Comments –
3. In general, the standard is overly prescriptive and complex. It should not be
necessary for a standard at this level to be as detailed and complex as this
standard is. Entities working with manufacturers, and knowledge gained from
experience can develop adequate maintenance and testing programs.
4. Why are “Relays that respond to non-electrical inputs or impulses (such as,
but not limited to, vibration, pressure, seismic, thermal or gas
accumulation)...” not included? The output contacts from these devices are
oftentimes connected in tripping or control circuits to isolate problem
equipment.
5. Due to the critical nature of the trip coil, it must be maintained more
frequently if it is not monitored. Trip coils are also considered in the standard
as being part of the control circuitry. Table 1-5 has a row labeled
“Unmonitored Control circuitry associated with protective functions”, which
would include trip coils, has a “Maximum Maintenance Interval” of “12
Calendar Years”. Any control circuit could fail at any time, but an unmonitored
control circuit could fail, and remain undetected for years with the times
specified in the Table (it might only be 6 years if I understand that as being
the trip test interval specified in the table). Regardless, if a breaker is unable
to trip because of control circuit failure, then the system must be operated in
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6.
7.
8.
9.
10.
11.
12.
13.
real time assuming that that breaker will not trip for a fault or an event, and
backup facilities would be called upon to operate. Thus, for a line fault with a
“stuck” breaker (a breaker unable to trip), instead of one line tripping, you
might have many more lines deloaded or tripped because of a bus having to
be cleared because of a breaker failure initiation. The bulk electric system
would have to be operated to handle this contingency.
In reference to the FAQ document, Section 5 on Station dc Supply, Question
K, clarification is needed with respect to dc supplies for communication within
the substation. For example, if the communication systems were run off a
separate battery in separate area in a substation, would the standard apply to
these batteries or not?
To define terms only as they are used in PRC-005-2 is inviting confusion.
Although they may be unique to PRC-005-2, some or all of them may be used
in future standards, some already may be used in existing standards, and may
or may not be deliberately defined. Consistency must be maintained, not only
for administrative purposes, but for effective technical communications as
well.
What is the definition of “Maintenance” as used in the table column “Maximum
Maintenance Interval”? Maintenance can range from cleaning a relay cover to
a full calibration of a relay.
A control circuit is not a component, it is made up of components.
Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify
calibration tolerances or other equivalent parameters...” means, and may be
subject to different interpretations by entities and compliance enforcement
personnel.
In the Implementation plan for Requirement R1, recommend changing “six” to
fifteen. This change would restore the 3-month time difference that existed in
the previous draft, between the durations of the implementation periods for
jurisdictions that do and do not require regulatory approval. It will ensure
equity for those entities located in jurisdictions that do not require regulatory
approval, as is the case in Ontario.
The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It
seems to continue to the next page to a new box. There are multiple activities
without clear delineation. Regarding station service transformers,
Item 4.2.5.5 under Applicability should be deleted. The purpose of this
standard is to protect the BES by clearing generator, generator bus faults (or
other electrical anomalies associated with the generator) from the BES.
Having this standard apply to generator station service transformers, that
have no direct connection to the BES, does meet this criteria. The FAQs
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(III.2.A) discuss how the loss of a station service transformer could cause the
loss of a generating unit, but this is not the purpose of PRC-005. Using this
logic than any system or device in the power plant that could cause a loss of
generation should also be included. This is beyond the scope of the NERC
standards.
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. Please see the SDT’s response to ISO New England Inc. in the formal Standard Comments
3. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies
that minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent
maintenance, a performance-based program in accordance with R3 and Attachment A is an option.
4. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection
System definition. Also, there is currently no technical basis for the maintenance of the devices which respond to nonelectrical quantities on which to base mandatory standards related either to activities or intervals. Absent such a technical
basis, we are currently unable to establish mandatory requirements, but may do so in the future if such a technical basis
becomes available.
5. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year
interval. You can maintain these devices more frequently if you desire
6. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the
communications system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The
specific station dc supply requirements (Table 1-4) do not apply to the dc supply associated only with communications
systems. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
7. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms,
either now or in the future, may not be consistent with the terms used here. They are defined only for clarify within this
standard. The SDT will confirm with NERC staff that this approach is acceptable.
8. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are
specified in the Activities column. The term is capitalized in the column title in conformance with normal editorial practice as
a title, rather than as a definition.
9. For purposes of this standard, the control circuit is defined as one component type.
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10. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
11. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1,
making it consistent with the remainder of the Implementation Plan Please see the SDT’s response to NPPC in the formal
Standard Comments.
12. Table 1-4 has been further modified for clarity.
13. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
Brenda
Constellation
6
Negative
1. The applicability has included more generation protective components. The
Powell
Energy
current PRC-005 guidance states that only Station Service transformers for
Commodities
plants 75 MVA and up should be included. The proposed standard includes all
Group
station service transformers, regardless of plant size or connection (via
generator or system). Constellation Energy Commodities Group does not see
the reliability benefits of this increased scope.
2. R1.4 states that all monitoring attributes of all components must be listed and
identified. For most generation facilities, it is more efficient to calibrate/check
the entire protective system while the plant is in an outage, regardless of a
component’s monitoring capabilities. This requirement would require those
facilities to maintain a list of attributes that won’t ever be used, and would not
alter their testing frequency. What if an entity were found non-compliant in
the situation that was just described? It does not affect the reliability of the
BES and therefore R1.4 should be removed.
3. M1 doesn’t include a measure for R1.4. It just implies that a facility must
maintain a list.
4. The battery listing in the attached table is still too prescriptive. If
unmonitored, there should be a quarterly and yearly check, which is implied,
but it is then broken out by battery type to be more prescriptive.
5. PTs and CTs are mentioned, but it seems as though the drafting team wants a
facility to only test the outputs to ensure they are working properly. To clarify
this, Constellation Energy Commodities Group suggests rewording the testing
verbiage for PTs and CTs.
Response: Thank you for your comments.
1. Section 4.2.5 of “Applicability” specifies that only Generation Facilities that are part of the BES are included.
2. The SDT disagrees; Requirement R1, Part 1.4 supports Requirement R1, Part 1.2, and seems necessary to assure that entities have
appropriately applied the longer intervals associated with monitored components. However, in consideration to your comment the
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SDT has revised Requirement R1, Part 1.4 and has also removed Requirement R2 because of redundancy to Requirement R1, Part
1.4.
3. Measure M1 has been revised in consideration of your comment.
4. The activities for different battery types are addressed separately because the relevant activities differ.
5. The SDT intends that the instrument transformer and associated circuitry be verified to be functional, but believes that customary
apparatus maintenance (dielectric, infrared, etc) are not relevant to PRC-005-2.
Louis S Slade Dominion
6
Negative
Dominion is opposed to this version because Requirement R1.5 is overly
Resources,
prescriptive, requiring an extraordinary level of documentation, with little
Inc.
anticipated improvement in reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Terri F
Entergy
6
Negative
The restructured tables are generally much clearer and the SDT is to be
Benoit
Services, Inc.
commended on their efforts.
1. However, we believe the Alarming Point Table needs additional
clarification with regard to the Maximum Maintenance Interval. If an
“alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there
isn’t necessarily a maximum interval established as there is for Protection
System components. Also, if an entity’s alarm producing device
maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum
intervals for the alarm producing device of that entity. On that basis, we
suggest the interval verbiage be revised to “When alarm producing device
or system is verified, or by sections as per the monitored
component/protection system specified maximum interval as applicable”.
Alternately, if the intention is to establish maximum intervals as simply
being no longer than the individual component maintenance intervals as
we suggest for inclusion above, then the verbiage should be revised to
“When alarm producing component/protection system segment is
verified”. In either case are we to interpret monitored components with
attributes which allow for no periodic maintenance specified as not
requiring periodic alarm verification?
2. R1.5 calls for “identification of calibration tolerances or equivalent
parameters...” whereas the associated VSL references “failure to establish
calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply
“identify” or document such calibration tolerances would be analogous to
96
Voter
Entity
Segment
Vote
Comment
the severity level(s) of a “failure to specify one (or Cthe severity level
should be consistent with the other elements of R1. Both cases appear to
be more of a documentation issue as opposed to a failure to implement.
Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4? R1.5 calls for “identification of calibration tolerances
or equivalent parameters for each Protection System Component Type....”.
We believe the Supplementary Reference document should provide
additional information and examples of calibration tolerances or equivalent
parameters which would be expected for the various component types.
Especially for any “equivalent” parameters which would be required for
compliance for a component type besides protective relays. Adding
Requirement 1.5 is a significant revision and raises questions as to how
broadly an accuracy or equivalent parameter requirement and associated
documentation would need to be addressed by entities and/or will be
measured for compliance. Discussion on this new requirement does not
seem to be addressed anywhere in the FAQ or Supplementary Reference
documents. Additionally, to the best of our knowledge, the need for such
a requirement was not brought up as a concern or comment on the prior
draft version of this standard, and in the context of a requirement need,
we don’t believe it has been attributed to or actually poses any significant
reliability risk. We do not believe this requirement is justified.
Response: Thank you for your comments.
1. The Maximum Maintenance Interval column entry in Table 2 has been revised to state, “When alarm producing Protection
System component is verified” to clarify this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Mark S
FirstEnergy
6
Negative
Please see FirstEnergy's comments submitted separately through the comment
Travaglianti
Solutions
period posting.
Response: Thank you for your comments. Please see our response to your comments submitted separately through the formal
comment period.
Richard L.
Montgomery
Florida
Municipal
Power Agency
6
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new
PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control circuitry.
97
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
What's key about this is that these components are all part of distribution
system protection, so, these activities would not be covered by other BES
protection system maintenance and testing. I'm sure we are testing batteries
and the like, but, we are probably not testing battery chargers and control
circuity, and, in many cases distribution circuits are such that it is very
difficult, if not impossible, to test control circuitry to the trip coil of the breaker
without causing an outage of the customers on that distribution circuit. There
is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one
or two back-up systems, there are thousands and thousands of UFLS relays
and if one fails to operate, it will not be noticeable to the event. It does make
sense to test the relays themselves in part to ensure that the regio0nsl UFLS
program is being met, but, to test the other protection system components is
not worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits,
reducing the value of testing to just about null. However, this version is better
than prior versions because it essentially requires the entity to determine it's
own period of maintenance and testing for UFLS/UVLS for DC Supply and
control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a BES
Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that
excludes non-electrical protection (e.g., sudden pressure relays) and auxiliary
relays. Because the definition of Protection System (recently approved) does
not clearly exclude "non-electrical" protection, the Applicability section should.
For instance,, a vibration monitor, steam pressure, etc. protection of
generators, sudden pressure protection of transformers, etc. should not be
included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical the VRF of R1 should
be Low since the attached tables are essentially the PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
98
Voter
Entity
Segment
Vote
Comment
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
Thomas E
Washburn
Florida
Municipal
Power Pool
6
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new
PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution
system protection, so, these activities would not be covered by other BES
protection system maintenance and testing. I'm sure we are testing batteries
and the like, but, we are probably not testing battery chargers and control
circuity, and, in many cases distribution circuits are such that it is very
difficult, if not impossible, to test control circuitry to the trip coil of the breaker
without causing an outage of the customers on that distribution circuit. There
is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one
or two back-up systems, there are thousands and thousands of UFLS relays
and if one fails to operate, it will not be noticeable to the event. It does make
sense to test the relays themselves in part to ensure that the regio0nsl UFLS
program is being met, but, to test the other protection system components is
not worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits,
reducing the value of testing to just about null. However, this version is better
than prior versions because it essentially requires the entity to determine it's
own period of maintenance and testing for UFLS/UVLS for DC Supply and
control circuitry.
2. Applicability, should reflect the Y&W and Tri-State interpretation (Project
2009-17) of "transmission Protection System" and should state: "Protection
Systems applied on, or designed to provide protection for a BES Facility and
that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that
99
Voter
Entity
Segment
Vote
Comment
excludes non-electrical protection (e.g., sudden pressure relays) and auxiliary
relays. Because the definition of Protection System (recently approved) does
not clearly exclude "non-electrical" protection,the Applicability section should.
For instance,, a vibration monitor, steam pressure, etc. protection of
generators, sudden pressure protection of transformers, etc. should not be
included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical the VRF of R1 should
be Low since the attached tables are essentially the PSMP.
Response: Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
Silvia P
Mitchell
Florida Power
& Light Co.
6
Negative
This draft standard is too perscriptive.
1. Requirement R1, Part 1.5 would be overwhelming if approved. Requirement
R1, Part 1.5 should be deleted.
2. Requirement R4, Part 4.2 phrase "established in accordance with Requirement
R1, Part 1.5" should be deleted. The standard without these additional
requirements would be sufficient to establish that the Protection System is
maintained and protects the BES.
3. Table 1-2 Component Type Communications Systems Maximum Maintenance
Interval of 3 Calendar Months to verify that the communications system is
functional for any unmonitored communications system is unyielding. Most
communication failures are caused by power supply failures which Next Era
does monitor. Based on experience and monitoring of communication power
supplies, 12 calendar months would be adequate. The maximum maintenance
interval should be changed from 3 calendar months to 12 calendar months.
4. Table 1-4, Component Type Station dc Supply Maximum Maintenance Interval
of 3 Calendar Months to inspect electrolyte levels on “Any unmonitored station
100
Voter
Entity
Segment
Vote
Comment
dc supply not having the monitoring attributes of a category below. (Excluding
UFLS and UVLS)” is too stringent. Verifying battery charger float voltage every
18 calendar months is sufficient to prevent excessive gassing and water loss
of battery cells. The maximum maintenance interval should be changed from
3 calendar months to 6 calendar months.
5. Table 1-4, Component Type Station dc Supply Maximum Maintenance Interval
of 3 Calendar Months to measure the internal ohmic values on “Unmonitored
Station dc supply with Valve Regulated Lead-Acid (VRLA) batteries that does
not have the monitoring attributes of a category below. (excluding UFLS and
UVLS)” is too stringent. With the standard’s requirement to verify the float
voltage every 18 calendar months, measuring the internal ohmic values every
6 calendar months would be adequate. The maximum maintenance interval
should be changed from 3 calendar months to 6 calendar months.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
2. Requirement R4 has also been re-drafted to address various related concerns noted within comments. Please see
Supplementary Reference Document, Section 8 for a discussion of this. The associated VSL has also been revised.
3. The activity to which you refer is an inspection-based activity based on overall functionality, and addresses functionality of
various communications technologies. If an entity monitors the power supply (as suggested), doing so addresses one
portion of the functionality, but does not address channel integrity, etc.
4. The SDT disagrees, and believes that the specified activities, at the specified intervals, are appropriate.
5. The standard has been revised as you suggested.
Paul Shipps
Lakeland
6
Negative
Small entities with only one or two BES substations may not have enough
Electric
components to take advantage of the expanded maintenance intervals afforded by
a performance-based maintenance program. Aggregating these components
across different entities doesn’t seem too logical considering the variations at the
sub-component level (wire gauge, installation conditions, etc.)
Response: Thank you for your comments. Entities are not required to use performance-based maintenance programs. Requirement
R3 and Attachment A are provided for the use of entities that can (and desire to) avail themselves of this approach.
Eric
Ruskamp
Lincoln
Electric
System
6
Affirmative
While the proposed draft of the standard is acceptable as currently written, LES
would like the drafting team to consider the following comments.
(1) Table 1-1 should state “Test and calibrate (if necessary)” in the first section
under activities. If a relay passes the test, there is no need to calibrate it.
101
Voter
Entity
Segment
Vote
Comment
Therefore, not all relays will require calibration.
(2) Please explain the drafting team’s reason for not checking the trip coils of
breakers in the UFLS/UVLS schemes but ensuring that all others are operated
every six years. It would appear that they can all be lumped into the same group
one way or another.
(3) In regards to Specific Gravity Testing, many people do not perform the specific
gravity test routinely if they perform the individual cell internal ohmic test
routinely. LES asks the drafting team to consider allowing the internal cell ohmic
test as a substitute for the specific gravity test.
Response: Thank you for your comments.
1. Table 1-1 has been modified as you suggest.
2. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the
Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system
elements.
3. Table 1-4 does not specify specific gravity testing.
Brad Jones
Luminant
Energy
6
Negative
Luminant commends the PRC-005-2 Standard Drafting Team for its quality efforts
in producing this version of the Standard however; Luminant must cast a negative
ballot vote for this present version of the Standard. The negative vote against the
present version of PRC-005-2 is solely based on the addition of Requirement R1
Part 1.5 with its associated reference to it in Requirement R4 Part 4.2 and the VSL
table.
It is Luminant’s opinion that this new Requirement as written subjects all
Transmission Owners, Generation Owners and Distribution Providers to vague
interpretations of a requirement that cannot be complied with because it is
impossible for any of them to draft the necessary documentation to be compliant
with the Standard. As stated in the High VSL associated with Part 1.5 of
Requirement R1 all owners will fail “to establish calibration tolerance or equivalent
parameters to determine if every individual discrete piece of equipment in a
Protection System is within acceptable parameters.”
It is Luminant’s opinion that the measurement of acceptable performance during
maintenance and testing activities can be accomplished with a Pass/Fail type of
documentation on a test form. No company can effectively establish calibration
tolerance parameters for an entire “component type” of the Protection System.
Doing so could be detrimental to the reliability of the grid. Parameters are
dependent on the location, application and situation specific to each Protection
System device.
102
Voter
Entity
Segment
Vote
Comment
The inclusion of Part 1.5 of Requirement R1 is a significant addition to the
standard, and by NERC Rules of Procedure requires the input and consideration of
the full Standard Drafting Team.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Daniel
Prowse
Manitoba
Hydro
6
Negative
1. Implementation Plan (Timeline) for R1: In areas not requiring regulatory
approval, the 6 month time frame proposed for R1 is not achievable and is not
consistent with areas requiring regulatory approval. To be consistent, the
effective date for R1 in jurisdictions where no regulatory approval is required
should be the first day of the first calendar quarter 12 months after BOT
approval.
2. VSLs: The high VSL for R1 “Failed to include all maintenance activities relevant
for the identified monitoring attributes specified in Tables 1-1 through 1-5”
may be interpreted in different ways and should be further clarified.
3. Table 1-4: The requirements for batteries listed in Table 1-4 do not appear to
be consistent with the comments in the FAQ Section (V 1A Example 1). Please
see comments submitted during the formal comment period for further detail.
4. Table 1-4: The requirement for a 3 month check on electrolyte level seems
too frequent based on our experience. We would like to point out that
although IEEE std 450 (which seems to be the basis for table 1-4) does
recommend intervals it also states that users should evaluate these
recommendations against their own operating experience.
Response: Thank you for your comments.
1. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for R1, making it consistent
with the remainder of the Implementation Plan.
2. The SDT does not understand your concern; further details are needed.
3. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
4. The SDT believes that the 3-month interval specified in the Standard is appropriate.
Joseph
Northern
6
Negative
We disagree with the practice of performing calibration checks on non
O'Brien
Indiana Public
microprocessor relays every 6 years.
Service Co.
Response: Thank you for your comments. The SDT considers it important that calibration checks be performed on non
microprocessor relays no less frequently than every 6 years.
103
Voter
Entity
Segment
Vote
Comment
James D.
Hebson
PSEG Energy
6
Negative
The PSEG Companies do not agree with the Facilities as currently described in
Resources &
section 4.2.5.5. Please refer to detailed comments provided in the formal
Trade LLC
Comment Form.
Response: Thank you for your comments. Please see our response to your comments from the formal comment period.
Dennis
Sismaet
Seattle City
Light
6
Negative
The proposed Standard PRC-005-2 is an improvement over the previous draft in
that it provides more consistency in maintenance and testing duration internals.
Notwithstanding, two issues are of concern to Seattle City Light such that it is
compelled to vote no:
1) the establishment of bookends for standard verification and
2) the implementation timelines for entities with systems where electromechanical relays still compose a significant number of components in their
protection systems.
1. Bookends: Proposed Standard PRC-005-2 specifies long inspection and
maintenance intervals, up to 12 years, which correspondingly exacerbates the socalled “bookend” issue. To demonstrate that interval-based requirements have
been met, two dates are needed - bookends. Evidencing an initial date can be
problematic for cases where the initial date would occur prior to the effective date
of a standard. NERC has provided no guidance on this issue, and the Regions
approach it differently. Some, such as Texas Regional Entity, require initial dates
beginning on or after the effective date of a Standard. Compliance with intervals is
assessed only once two dates are available that occur on or after a standard took
effect. Other regions, such as Western Electricity Coordinating Council (WECC),
require that entities evidence an initial date prior to the effective date of a
standard. For WECC, compliance with intervals is assessed as soon as a standard
takes effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal. Proposed
Standard PRC-005-2 will be another such standard. Indeed this Standard will
involve by far the largest number of bookends of any NERC standard - many
thousands for a typical entity. Furthermore, the long inspection and maintenance
intervals introduced in the draft will require entities in WECC, for instance, to
evidence initial bookend dates prior to the date original PRC-005-1 took effect. For
the 12-year intervals for CTs and VTs in proposed Standard PRC-005-2, many
initial dates will occur prior to the 2005 Federal Power Act that authorized
Mandatory Reliability Standards and even reach back before the 2003 blackout
that catalyzed the effort to pass the Federal Power Act. As a result, many entities
104
Voter
Entity
Segment
Vote
Comment
in WECC maybe at risk of being found in violation of proposed Standard PRC-0052 immediately upon its implementation. Seattle City Light requests that NERC
address the bookends issue, either within proposed Standard PRC-005-2 or in a
separate, concurrent document.
2. Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with legacy
systems. In example, auxilary relay and trip coil testing may be essential to prove
the correct operation of complex, multi-function digital protection systems.
However, for legacy systems with single-function electro-mechanical components,
the considerable documentation and operational testing needed to implement and
track such testing is not necessarily proportional to the relative risk posed by the
equipment to the bulk electric system. Performance testing of electro-mechanical
systems, particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause far
more problems on restoration-to-service than they will locate and correct. As such,
to assist entities in their implementation efforts, we believe provision of
alternatives are necessary, such as additional implementation time through
phasing and/or through technical feasibility exceptions.
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18 Evidence”.
2. Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic. FERC Order 693
directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is a portion
thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has developed those
requirements in a fashion that affords entities with the opportunity to best meet those requirements.
David F.
Xcel Energy,
6
Negative
We feel that several improvements were made since the last draft. However, we
Lemmons
Inc.
feel that some gaps exist that should be addressed before moving this project
forward. We have detailed our issues in our formal comments.
Response: Thank you for your comments. Please see our responses to your formal comments.
Jim R
Stanton
SPS
Consulting
Group Inc.
8
Negative
1. The standard as written is wildly prescriptive and violates the concept of "what
and not how." The standard and its Tables seek to prescribe in detail
maintenance and testing processes which should be left up to the owners and
operators of the protection systems.
105
Voter
Entity
Segment
Vote
Comment
2. References to Tables 1-5 should be deleted from the standard itself and
moved to a reference section.
Response: Thank you for your comments.
1. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that
minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent maintenance, a
performance-based program in accordance with Requirement R3 and Attachment A is an option.
2. Tables 1-1 through 1-5 are considered by the SDT to be an integral part of the requirements of the standard and thus belong
within the Standard.
Louise
Western
10
Affirmative Our affirmative vote reflects our belief that the proposed PRC-005-2 is an overall
McCarren
Electricity
improvement to the four standards that it would replace. We also believe that it is
appropriate to address maintenance and testing of all protection systems in one
Coordinating
standard rather than in four individual standards.
Council
Response: Thank you for your comments and support.
END OF REPORT
106
Consideration of Comments on the 4th draft of the standard for Protection System
Maintenance and Testing — Project 2007-17
Consideration of Comments on the 4th Draft of Protection System Maintenance and
Testing — Project 2007-17
The Protection System Maintenance and Testing Drafting Team thanks all commenters who
submitted comments on the 4th draft of the Protection System Maintenance standard, its
implementation plan, and the associated reference document. The standard and associated
documents were posted for a 30-day public comment period from April 13, 2011 through
May 13, 2011. Stakeholders were asked to provide feedback on the standard and
associated documents through a special electronic comment form. There were 55 sets of
comments, including comments from more than 176 people from approximately 103
companies representing 10 of the 10 Industry Segments as shown in the table on the
following pages.
All comments submitted may be reviewed in their original format on the standard’s project
page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
In addition, a successive ballot of the standard was conducted from May 3-13, 2011, and a
non-binding poll of the Violation Risk Factors and Violation Severity Levels was conducted
from May 3-16, 2011 and comments from the ballot and poll have been included in this
report.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is
a NERC Reliability Standards Appeals Process. 1
Summary Consideration of all Comments Received:
Purpose:
The SDT modified the Purpose to state, “To document and implement programs for the
maintenance of all Protection Systems affecting the reliability of the Bulk Electric System
(BES) so that these Protection Systems are kept in working order” in response to previous
Quality Review comments.
Applicability:
Several comments were offered, suggesting that PRC-005-2 needs to be consistent with the
interpretation in Project 2009-17, now implemented as PRC-005-1a, and the SDT modified
Applicability 4.2.1 for better consistency with the interpretation 4.2.1 as shown below:
4.2.1. Protection Systems that are installed for the purpose of detecting faults on BES Elements
(lines, buses, transformers, etc.).
Requirement R1:
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
1
Consideration of Comments on the 4th draft of the standard for Protection System
Maintenance and Testing — Project 2007-17
Requirement R1 was modified as shown below for improved specificity, based on
stakeholder comments:
R1.
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems identified in
Section 4.2.
Tables
Most commenters seemed to agree in general that the restructured tables added clarity, and
some commenters offered assorted suggestions for further improvement. Minor clarifying
changes were made to the Tables themselves, and additional discussion was added to the
“Supplementary Reference and FAQ” to address various comments.
Implementation Plan
Some commenters noted that for entities not subject to regulatory approvals, the
implementation plan should be longer so that all entities have sufficient time for
implementation. The team did modify the Implementation Plan to provide for a lengthened
implementation period for R1 and the less-than-1-calendar-year activities in R2 and R3 to
allow entities not subject to regulatory approvals of 9 additional months following BOT
approvals, and, for the remaining activities, of 12 additional months following BOT
approvals, to be more consistent with the expected Regulatory Approval timelines.
Additionally, all “calendar year” implementation periods were revised to “months” for
additional clarity.
VLSs:
VSLs for Requirement R1
•
Phased VSLs were added to address R1 Part 1.1, which was previously addressed only
as a “Severe” VSL.
•
A reference was added within the R1 VSL to Part 1.3.
•
R1 High VSL was revised to add a reference to Table 2.
VSLs for Requirement R2
•
One element of the R2 VSL was made binary (Severe), rather than “phased” (in two
steps), in response to several comments.
•
Many commenters pointed out an error (which was corrected by the SDT) within the VSL
for R2, where the Lower and High VSLs contained identical text.
VSLs for Requirement R3
•
The R3 VSLs were revised to replace “complete” with “implement and follow” for
consistency with the Requirement.
•
Other minor editorial changes were made throughout the VSLs in response to
comments.
Supplementary Reference and FAQ
•
The commenters were generally supportive of the reference document.
2
Consideration of Comments on the 4th draft of the standard for Protection System
Maintenance and Testing — Project 2007-17
•
Several questions regarding the enforceability of this document were posed, and the
SDT explained that the document is a supporting reference and not enforceable – only
standard requirements are enforceable.
•
A variety of suggestions were offered regarding additional information for the document,
which largely resulted in modifications to the Supplementary Reference document. One
specific suggestion of note (resulting in additional discussion within the document)
requested a FAQ regarding “Calendar Year”.
•
Several commenters posed questions regarding “grace periods” and “PSMPs established
by entities that are more stringent than the requirements within the standard”. No
additional changes were made due to these questions. If an entity develops a PSMP that
includes time intervals that are more stringent than those in the standard, the entity will
be audited against the intervals in its PSMP.
Definitions:
•
Several comments were offered regarding Maintenance Correctable Issues, and resulted
in modifying this definition to be “…such that the deficiency cannot be corrected during
the performance of the maintenance activity …”
Unresolved Minority Views:
•
Many comments were offered objecting to the 3-calendar-month intervals for station dc
supply and communications systems, and suggesting that a 3-calendar-month interval
requires entities to schedule these activities for 2-calendar-months in order to assure
compliance. The SDT did not modify the standard in response to these comments, and
responded that the intervals were appropriate, and that entities should be able to assure
compliance on a 3-calendar-month schedule by using program oversight. The
“Supplementary Reference and FAQ” document was augmented with additional
explanatory text.
•
Several commenters were concerned that an entity has to be “perfect” in order to be
compliant; the SDT responded that NERC Standards currently allow no provision for any
degree of non-performance relative to the requirements.
•
Several commenters continued to insist that “grace periods” should be allowed. The
SDT continued to respond that grace periods would not be measurable.
•
Several comments were offered questioning various aspects of Applicability 4.2.5.4
(generation auxiliary transformers). No changes were made in response to these
comments, and responses were offered illustrating why these transformers are included.
•
Many comments were offered, questioning the propriety of including distribution system
Protection Systems, almost all related to UFLS/UVLS. The SDT explained that these
Protection Systems are appropriate to be included for consistency with legacy standards
PRC-008, PRC-011, and PRC-017, and noted that their inclusion is consistent with
Section 202 of the NERC Rules of Procedure.
•
Several comments were offered, objecting to the 6-calendar-year interval for lockout
and auxiliary relays. The SDT declined to adopt the requested changes, and noted that
these “electromechanical” devices with “moving parts” share failure mechanisms with
electromechanical protective relays and that the intervals should be identical.
3
Consideration of Comments on the 4th draft of the standard for Protection System
Maintenance and Testing — Project 2007-17
Index to Questions, Comments, and Responses
1.
The SDT has restructured the Table for Station DC Supply, separating it into six subtables individually addressing the various different technologies. Do you agree that the
restructured tables provide more clarity? If not, please provide specific suggestions for
improvement. ................................................................................................... 18
2.
The SDT has modified the Implementation Periods within the Implementation Plan. Do
you agree with the changes? If not, please provide specific suggestions for
improvement. ................................................................................................... 39
3.
The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do you
agree with the changes? If not, please provide specific suggestions for improvement. 47
4.
The SDT has incorporated the FAQ document into the “Supplementary Reference”
document and has provided the combined document as support for the Requirements
within the standard. Do you have any specific suggestions for further improvements? 53
5.
If you have any other comments on this Standard that you have not already provided
in response to the prior questions, please provide them here. ................................. 64
4
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Guy Zito
Additional Member
Northeast Power Coordinating Council
Additional Organization
2
3
4
5
6
7
8
9
10
X
Region Segment Selection
1. Alan Adamson
New York State Reliablity Council, LLC
NPCC 10
2. Gregory Campoli
New York Independent System Operator
NPCC 2
3. Kurtis Chong
Independent Electricity System Operator
NPCC 2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7. Brian Evans-Mongeon Utility Services
NPCC 8
8. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
9. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
10. Kathleen Goodman
ISO - New England
NPCC 2
11. Chantel Haswell
FPL Group, Inc.
NPCC 5
12. David Kiguel
Hydro One Networks Inc.
NPCC 1
13. Michael R. Lombardi
Northeast Utilities
NPCC 1
14. Randy MacDonald
New Brunswick Power Transmission
NPCC 1
5
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
15. Bruce Metruck
New York Power Authority
NPCC 6
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
19. Saurabh Saksena
National Grid
NPCC 1
20. Michael Schiavone
National Grid
NPCC 1
21. Wayne Sipperly
New York Power Authority
NPCC 5
22. Donald Weaver
New Brunswick System Operator
NPCC 1
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Group
Marie Knox
Additional Member
MISO Standards Collaborators
Additional Organization
NIPSCO
RFC
6
2. Gary Carlson
Michigan Public Power Agency RFC
3
3.
Additional Member
Mike Garton
Electric Market Policy
Additional Organization
Dominion Resources Services, Inc. SERC
3
2. Michael Crowley
Dominion Virginia Power
1
3. Louis Slade
Group
SERC
Dominion Resources Services, Inc. RFC
Terry L. Blackwell
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
Region Segment Selection
1. Michael Gildea
4.
3
Region Segment Selection
1. Joe O'Brien
Group
2
6
Santee Cooper
Additional Member Additional Organization Region Segment Selection
1. S. T. Abrams
Santee Cooper
SERC
1
2. Glenn Stephens
Santee Cooper
SERC
1
3. Rene Free
Santee Cooper
SERC
1
4. Kevin Bevins
Santee Cooper
SERC
1
5. Bridgett Coffman
Santee Cooper
SERC
1
6
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
BPA, Transmission, SPC Technical Svcs
WECC 1
2. Jason Burt
BPA, Transmission, RAS and Data Systems
WECC 1
3. Robert France
BPA, Transmission, PSC Technical Svcs
WECC 1
4. Mason Bibles
BPA, Transmission, Sub Maint and HV Engineering WECC 1
5. Deanna Phillips
BPA, Transmission, FERC Compliance
Group
Jonathan Hayes
Additional Member
SPP reliability standard development Team
Additional Organization
Oklahoma Gas and Electric
SPP
1, 3, 5
Grand Rvier Dam Authority
SPP
1, 3, 5
3. James Hutchinson
Oklahoma Gas and Electric
SPP
1, 3, 5
4. Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5
5. Rick Bartlett
Independence Power & Light
SPP
1, 3, 5
6. Sean Simpson
Board of Public Utilities, City of McPherson SPP
1, 3, 5
7. Mark Wurm
Board of Public Utilities, City of McPherson SPP
1, 3, 5
8. Joe Border
Board of Public Utilities, City of McPherson SPP
1, 3, 5
9. Michelle Corley
CLECO
1, 3, 5, 6
David Thorne
5
X
6
7
8
9
10
X
X
Region Segment Selection
2. Edwin Averill
Group
X
4
WECC 1
1. David Reilly
7.
X
3
Region Segment Selection
1. Dean Bender
6.
2
SPP
Pepco Holdings Inc
X
X
Additional Member Additional Organization Region Segment Selection
1. Carlton Bradshaw
8.
Group
Additional Member
Atlantic Electric
Dave Davidson
Additional Organization
1
Tennessee Valley Authority
X
X
Region Segment Selection
1. David Thompson
River Operations Engineering SERC
NA
2. Frank Cuzzort
Nuclear Power Engineering
NA
SERC
7
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Robert Brown
Nuclear Power Engineering
SERC
NA
4. Robert Mares
Fossil Power Engineering
SERC
NA
5. Paul Barlett
Transmission O&M Support
SERC
NA
6. Pat Caldwell
Transmission O&M Support
SERC
NA
7. Rusty Hardison
Transmission O&M Support
SERC
NA
8. Jerry Findley
Communications/SCADA
SERC
NA
Jose Landeros
Imperial Irrigation District
9.
Group
2
3
X
X
X
X
4
X
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Epifanio Martinez
WECC
2. Fernando Gutierrez
WECC
3. Gerardo Landeros
WECC
4. Tony Allegranza
10.
Group
Additional Member
WECC
Ron Sporseen
PNGC Comment Group
Additional Organization
X
Region Segment Selection
1. Bud Tracy
Blachly-Lane Electric Cooperative
WECC 3
2. Dave Markham
Central Electric Cooperative
WECC 3
3. Roman Gillen
Consumer's Power Inc.
WECC 3
4. Roger Meader
Coos-Curry Electric Cooperative
WECC 3
5. Dave Hagen
Clearwater Electric Cooperative
WECC 3
6. Dave Sabala
Douglas Electric Cooperative
WECC 3
7. Bryan Case
Fall River Electric Cooperative
WECC 3
8. Rick Crinklaw
Lane Electric Cooperative
WECC 3
9. Michael Henry
Lincoln Electric Cooperative
WECC 3
10. Richard Reynolds
Lost River Electric Cooperative
WECC 3
11. Jon Shelby
Northern Lights Electric Cooperative WECC 3
12. Ray Ellis
Okanogan Electric Cooperative
WECC 3
13. Aleka Scott
PNGC Power
WECC 4
8
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
14. Heber Carpenter
Raft River Electric Cooperative
WECC 3
15. Ken Dizes
Salmon River Electric Cooperative
WECC 3
16. Steve Eldrige
Umatilla Electric Cooperative
WECC 3
17. Marc Farmer
West Oregon Electric Cooperative
WECC 3
18. Margaret Ryan
PNGC Power
WECC 8
19. Stuart Sloan
Consumer's Power Inc.
WECC 1
20. Rick Paschal
PNGC Power
WECC 3
11.
Group
Additional Member
Additional Organization
Omaha Public Utility District
MRO
1, 3, 5, 6
American Transmission Company
MRO
1
3. Tom Webb
Wisconsin Public Service Corporation MRO
3, 4, 5, 6
4. Jodi Jenson
Western Area Power Administration
MRO
1, 6
5. Ken Goldsmith
Alliant Energy
MRO
4
6. Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
7. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
8. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
9. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
10. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
11. Scott Nickels
Rochester Public Utilties
MRO
4
12. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
13. Richard Burt
Minnkota Power Cooperative, Inc.
MRO
1, 3, 5, 6
Daniel Herring
4
5
6
7
8
9
10
X
Region Segment Selection
2. Chuck Lawrence
Group
3
MRO's NERC Standards Review
Subcommittee
Carol Gerou
1. Mahmood Safi
12.
2
The Detroit Edison Company
X
X
X
Additional Member Additional Organization Region Segment Selection
1. David A Szulczewski Engineering
RFC
3, 4, 5
2. Steven P Kerkmaz
RFC
3, 4, 5
Engineering
9
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Nicole M Syc
13.
Group
Engineering
Albert DiCaprio
RFC
2
3
4
5
6
7
8
9
10
3, 4, 5
ISO/RTO Standards Review Committee
X
Additional Member Additional Organization Region Segment Selection
1. Terry Bilke
MISO
RFC
2
2. Patrick Brown
PJM
RFC
2
3. Greg Campoli
ISO-NY
NPCC
2
4. Mike Falvo
IESO
NPCC
2
5. Matt Goldberg
ISO-NE
NPCC
2
6. Kathleen Goodman ISO-NE
NPCC
2
7. Ben Li
IESO
NPCC
2
8. Steve Myers
ERCOT
ERCOT 2
9. Bill Phillips
MISO
RFC
10. Mark Thompson
AESO
WECC 2
11. Don Weaver
NBSO
NPCC
2
12. Mark Westendorf
MISO
RFC
2
SPP
SPP
2
13. Charles Yeung
14.
Group
Sam Ciccone
2
FirstEnergy
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
2. Jim Kinney
FE
RFC
1
3. Brian Orians
FE
RFC
5
4. Ken Dresner
FE
RFC
5
5. Bill Duge
FE
RFC
5
6. Craig Boyle
FE
RFC
1
7. Mark Pavlick
FE
RFC
1, 3, 4, 5, 6
8. Lenny Lee
FE
RFC
1
9. J. Chmura
FE
RFC
1
10
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10. Rusty Loy
FE
RFC
5
11. Hugh Conley
FE
RFC
1
FE
RFC
1
12. Frank Hartley
15.
Individual
Cynthia S. Bogorad
Transmission Access Policy Study Group
X
16.
Individual
Brandy A. Dunn
Western Area Power Administration
X
17.
Individual
David Youngblood
Luminant
18.
Individual
Silvia Parada Mitchell
NextEra Energy
19.
Individual
David Youngblood
Luminant
20.
Individual
Jim Eckelkamp
Progress Energy
21.
Individual
Steve Rueckert
Western Electricity Coordinating Council
Individual
Janet Smith, Regulatory
Affairs Supervisor
Arizona Public Service Company
23.
Individual
Robert W. Kenyon
NERC - EA & I
24.
Individual
Daniel Duff
Liberty Electric Power LLC
25.
Individual
Russ Schneider
FHEC
26.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
27.
Individual
Beth Young
Tampa Electric Company
22.
2
3
X
4
X
5
X
6
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
28.
Individual
Joe O'Brien
NIPSCO
X
29.
Individual
Linda Jacobson
Farmington Electric Utility System
30.
Individual
Greg Rowland
Duke Energy
31.
Individual
Steve Alexanderson
Central Lincoln
32.
Individual
Bob Thomas
Illinois Municipal Electric Agency
33.
Individual
Joe Petaski
Manitoba Hydro
34.
Individual
Mike Hancock
Shermco Industries
35.
Individual
Michael Crowley
Dominion Virginia Power
X
36.
Individual
Edward J Davis
Entergy Services
37.
Individual
Thad Ness
38.
Individual
39.
2
3
4
X
5
6
X
X
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
American Electric Power
X
X
X
X
Jose H Escamilla
CPS Energy
X
Individual
Melissa Kurtz
US Army Corps of Engineers
X
40.
Individual
Kenneth A. Goldsmith
Alliant Energy
41.
Individual
Kirit Shah
Ameren
42.
Individual
Rex Roehl
Indeck Energy Services
43.
Individual
Kevin Luke
Georgia Transmission Corporation
X
X
X
X
X
X
X
X
12
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
44.
Individual
Andrew Z Pusztai
American Transmission Company, LLC
X
45.
Individual
John Bee
Exelon
X
46.
Individual
Glen Sutton
AtCO Electric ltd
X
47.
Individual
Claudiu Cadar
GDS Associates
X
48.
Individual
Gerry Schmitt
BGE
X
49.
Individual
Michael Moltane
ITC
X
50.
Individual
Bill Middaugh
Tri-State G&T
X
51.
Individual
Don Schmit
Nebraska Public Power District
X
52.
Individual
Michael Falvo
Independent Electricity System Operator
53.
Individual
Martin Kaufman
ExxonMobil Research and Engineering
X
54.
Individual
Gary Kruempel
MidAmerican Energy Company
X
X
X
55.
Individual
Alice Ireland
Xcel Energy
X
X
X
X
X
X
X
6
7
8
9
10
X
X
X
X
13
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
The following balloters submitted comments either with a comment form or with their ballot:
Balloter
Edward P. Cox
Brock Ondayko
Kenneth Goldsmith
Kirit S. Shah
Paul B. Johnson
Company
AEP Marketing
AEP Service Corp.
Alliant Energy Corp. Services, Inc.
Ameren Services
American Electric Power
6
7
8
9
10
11
Jason Shaver
Robert D Smith
John Bussman
Joseph S. Stonecipher
Donald S. Watkins
Francis J. Halpin
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Beaches Energy Services
Bonneville Power Administration
Bonneville Power Administration
1
1
1
1
1
5
12
13
14
15
16
17
William Mitchell Chamberlain
Steve Alexanderson
Matt Culverhouse
Linda R. Jacobson
Gregg R Griffin
Paul Morland
California Energy Commission
Central Lincoln PUD
City of Bartow, Florida
City of Farmington
City of Green Cove Springs
Colorado Springs Utilities
9
3
3
3
3
1
18
19
20
21
22
23
Christopher L de Graffenried
Peter T Yost
Wilket (Jack) Ng
Nickesha P Carrol
Brenda Powell
Amir Y Hammad
Consolidated Edison Co. of New York
Consolidated Edison Co. of New York
Consolidated Edison Co. of New York
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Constellation Power Source Generation, Inc.
1
3
5
6
6
5
24
25
26
David A. Lapinski
David Frank Ronk
James B Lewis
Consumers Energy
Consumers Energy
Consumers Energy
3
4
5
1
2
3
4
5
Segment
6
5
4
1
1
14
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
27
28
29
Kenneth Parker
Joel T Plessinger
Terri F Benoit
Entegra Power Group, LLC
Entergy
Entergy Services, Inc.
5
3
6
30
31
32
33
34
35
Robert Martinko
Kevin Querry
Kenneth Dresner
Mark S Travaglianti
Dennis Minton
Frank Gaffney
FirstEnergy Energy Delivery
FirstEnergy Solutions
FirstEnergy Solutions
FirstEnergy Solutions
Florida Keys Electric Cooperative Assoc.
Florida Municipal Power Agency
1
3
5
6
1
4
36
37
38
39
40
41
David Schumann
Richard L. Montgomery
Thomas E Washburn
Luther E. Fair
Claudiu Cadar
Guy Andrews
Florida Municipal Power Agency
Florida Municipal Power Agency
Florida Municipal Power Pool
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia System Operations Corporation
5
6
6
1
1
4
42
43
44
45
46
47
Gordon Pietsch
Gwen Frazier
Ronald D. Schellberg
Bob C. Thomas
Rex A Roehl
Michael Moltane
1
3
1
4
5
1
48
49
50
51
52
Garry Baker
Stan T. Rzad
Larry E Watt
Mace Hunter
Paul Shipps
Great River Energy
Gulf Power
Idaho Power Company
Illinois Municipal Electric Agency
Indeck Energy Services, Inc.
International Transmission Company
Holdings Corp
JEA
Keys Energy Services
Lakeland Electric
Lakeland Electric
Lakeland Electric
53
54
55
56
Daniel Duff
Brad Jones
Mike Laney
Joseph G. DePoorter
Liberty Electric Power LLC
Luminant Energy
Luminant Generation Company LLC
Madison Gas and Electric Co.
5
6
5
4
3
1
1
3
6
15
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
57
58
59
Joe D Petaski
Greg C. Parent
Mark Aikens
Manitoba Hydro
Manitoba Hydro
Manitoba Hydro
1
3
5
60
61
62
63
64
65
Daniel Prowse
Jason L. Marshall
John S Bos
Saurabh Saksena
Arnold J. Schuff
Gerald Mannarino
Manitoba Hydro
Midwest ISO, Inc.
Muscatine Power & Water
National Grid
New York Power Authority
New York Power Authority
6
2
3
1
1
5
66
67
68
69
70
71
Guy V. Zito
William SeDoris
Joseph O'Brien
John Canavan
Douglas Hohlbaugh
Mark Ringhausen
Northeast Power Coordinating Council, Inc.
Northern Indiana Public Service Co.
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Edison Company
Old Dominion Electric Coop.
10
3
6
1
4
4
72
73
74
75
76
77
Margaret Ryan
Sandra L. Shaffer
Tom Bowe
John C. Collins
Terry L Baker
Carol Ballantine
Pacific Northwest Generating Cooperative
PacifiCorp
PJM Interconnection, L.L.C.
Platte River Power Authority
Platte River Power Authority
Platte River Power Authority
8
5
2
1
3
6
78
79
80
David Thorne
Jerzy A Slusarz
Henry E. LuBean
1
5
4
81
82
Steven Grega
Greg Lange
Potomac Electric Power Co.
PSEG Power LLC
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County
83
84
85
86
Terry L. Blackwell
Lewis P Pierce
Suzanne Ritter
Pawel Krupa
Santee
Santee
Santee
Seattle
1
5
6
1
Cooper
Cooper
Cooper
City Light
5
3
16
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
87
88
89
Dana Wheelock
Hao Li
Michael J. Haynes
Seattle City Light
Seattle City Light
Seattle City Light
3
4
5
90
91
92
93
94
95
Dennis Sismaet
Horace Williamson
William D Shultz
Scott M. Helyer
Larry Akens
George T. Ballew
Seattle City Light
Southern Company
Southern Company Generation
Tenaska, Inc.
Tennessee Valley Authority
Tennessee Valley Authority
6
1
5
5
1
5
96
97
98
99
100
101
Marjorie S. Parsons
Keith V Carman
Janelle Marriott
Barry Ingold
John Tolo
Melissa Kurtz
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tri-State G & T Association, Inc.
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
U.S. Army Corps of Engineers
6
1
3
5
1
5
102
103
104
105
106
107
Martin Bauer P.E.
Ric Campbell
Louise McCarren
Linda Horn
James R. Keller
Anthony Jankowski
U.S. Bureau of Reclamation
Utah Public Service Commission
Western Electricity Coordinating Council
Wisconsin Electric Power Co.
Wisconsin Electric Power Marketing
Wisconsin Energy Corp.
5
9
10
5
3
4
108
109
James A Ziebarth
Kristina M. Loudermilk
Y-W Electric Association, Inc.
4
8
17
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
1. The SDT has restructured the Table for Station DC Supply, separating it into six sub-tables individually
addressing the various different technologies. Do you agree that the restructured tables provide more clarity?
If not, please provide specific suggestions for improvement.
Summary Consideration: Most commenters seemed to agree in general that the restructured tables added clarity, and some
commenters offered assorted suggestions for further improvement. Minor clarifying changes were made to the Tables
themselves, and additional discussion was added to the “Supplementary Reference and FAQ” to address various comments.
A number of commenters continued to object to the “3 Calendar Month” maintenance intervals, and the SDT chose not to
modify the standard. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type
activities of unmonitored battery systems and suggestions to extend the maintenance intervals to 6 or 18 months were not
adopted.
Some comments suggested extending the interval to 4 months. Additional discussion (including an example) regarding this
item was added to Section 7.1 of the “Supplementary Reference and FAQ”. As explained in the reference, a calendar month
begins on the first day of a new month following the month in which the activity was performed. Thus every “3 Calendar
Months” means to add 3 months from the last time the activity was performed.
Specific changes made to the tables in response to comments:
Tables 1-1 and 1-3 – References to Table 2 were corrected.
Table 1-4(a) and Table 1-4(d) – Modified header to clarify, “Protection System Station dc supply”
Table 1-4(b) and Table 1-4(c) - Modified header and component attributes to clarify, “Protection System Station dc supply”
Table 1-4(e) - Modified header and component attributes to clarify, “Protection System Station dc supply” and replaced,
“distribution breakers” with “non-BES interrupting devices”.
Table 1-4(f) - Modified header to clarify, “Protection System Station dc supply”, modified the seventh table entry for clarity, and
added eighth table entry.
Table 1-5 – Added “Associated with Protective Functions” to header
Organization
Tri-State G & T Association, Inc.
Yes or No
Ballot
Question 1 Comment
On Table 1-2, page 11: The standard describes the following component attributes, “Any unmonitored
18
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
(3) (5)
Comment –
Affirmative
communications system necessary for correct operation of protective functions, and not having all the
monitoring attributes of a category below.” How does this apply to redundant communication systems? If the
primary communications channel fails the protective relay automatically fails over to the back-up channel and
continues to function properly. Are redundant communication channels excluded from this component
attribute and associated interval? Also, if a relay is set to operate in a manner typical when communication is
not used for protection (i.e. defaulting to step-distance functions with a loss of communication), is the
defaulted operation of the relay considered “correct operation” thereby excluding the communication as
necessary for its correct operation?
Please clarify the term correct operation and how it applies to redundant communication systems and/or the
performance of the relay in the absence of communication.
Response: Thank you for your comments. If communication-assisted protection is provided as described in the Applicability of PRC-005-2, it must be tested in
accordance with the intervals and activities described in the standard. Redundant equipment and/or channels do not relieve the entity of the responsibility to
maintain all equipment as required. An entity is entitled to use any monitoring present on the communications system to adjust its maintenance as established
within Table 1-2, and, if sufficient component populations are present and the entity wishes to address the additional included requirements, performance-based
maintenance is also available.
Correct operation of the protective function means that if the communications system is part of the protection system and loss of it causes the system to fail to
meet the schemes protection requirements it has failed. In the example you provide, loss of communications would result in time delay clearing depending on
location of the fault. If time delay clearing will be sufficient for your system clearing time requirements, then high speed clearing is not required and the Comm.
System would not need to be installed. If it is installed, you must meet the PRC-005 requirements. Redundant communications schemes are installed where high
speed clearing is required to meet planning criteria. The second scheme is in place to prevent the line from being removed from service if the primary scheme
must be maintained or fails. If redundant schemes are in place, both must meet the PRC-005 standard.
Tri-State G&T
On Table 1-2, page 11: The standard describes the following component attributes, “Any unmonitored
communications system necessary for correct operation of protective functions, and not having all the
monitoring attributes of a category below.” How does this apply to redundant communication systems? If the
primary communications channel fails the protective relay automatically fails over to the back-up channel and
continues to function properly. Are redundant communication channels excluded from this component
attribute and associated interval? Please clarify the term correct operation and how it applies to redundant
communication systems.
Response: Thank you for your comments. If communication-assisted protection is provided as described in the Applicability of PRC-005-2, it must be tested in
accordance with the intervals and activities described in the standard. Redundant equipment and/or channels do not relieve the entity of the responsibility to
maintain all equipment as required. An entity is entitled to use any monitoring present on the communications system to adjust its maintenance as established
19
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
within Table 1-2, and, if sufficient component populations are present and the entity wishes to address the additional included requirements, performance-based
maintenance is also available.
Correct operation of the protective function means that if the communications system is part of the protection system and loss of it causes the system to fail to
meet the schemes protection requirements it has failed. In the example you provide, loss of communications would result in time delay clearing depending on
location of the fault. If time delay clearing will be sufficient for your system clearing time requirements, then high speed clearing is not required and the Comm.
System would not need to be installed. If it is installed, you must meet the PRC-005 requirements. Redundant communications schemes are installed where high
speed clearing is required to meet planning criteria. The second scheme is in place to prevent the line from being removed from service if the primary scheme
must be maintained or fails. If redundant schemes are in place, both must meet the PRC-005 standard.
Consumers Energy (4)
Ballot
Comment Negative
Relating to Table 1-3, The SDT has advised that the voltage and current inputs must be checked at each
individual relay. This may not be difficult if the relays are microprocessor relays (where internal metering may
be used), but for the predominant population of electromechanical relays (particularly for current signals), this
requirement will necessitate repeated operation of test switches and associated insertion of meters. Such
activities will not only be very difficult and time consuming, but will actually be dangerous because of the
dangers of accidentally opening current circuits during testing. It should be sufficient to verify the integrity of
the series string of protective relays, etc during maintenance activities, as all devices within the series string
will be receiving the same values.
Response: Thank you for your comments. Entities can choose how to best manage their risk. If online testing is deemed too risky, offline tests such as, but not
limited to, secondary injection, CT excitation test and PT turns ratio tests can be compared to baseline data and be used in conjunction with CT and PT secondary
wiring insulation verification tests to adequately “verify the current and voltage circuit inputs from the voltage and current sensing devices to the protective relays”.
Tri-State G & T Association, Inc.
(3) (5)
Ballot
Comment Affirmative
The draft standard requires the PSMP to include maintenance and testing intervals for Station DC supply
associated with protective functions (including batteries, battery chargers, and non-battery-based dc supply).
Does this requirement include DC systems (batteries not included in station batteries) used by communication
systems necessary for the correct operation of protective functions?
Response: Thank you for your comments. No, an independent DC Supply related only to communication equipment is not considered to be “station dc supply”.
The periodic functional observation and testing of the communications equipment is included, but there are no requirements for the independent dc supply.
Wisconsin Electric Power Co. (5)
Wisconsin Electric Power
Ballot
Comment Negative
(1) The maximum maintenance intervals listed in various PRC-005-2 tables are described as “calendar years”
which is an undefined term. Since maintenance intervals are critical to this standard, this term should be
either clearly defined or explained in the standard. For example, if a component was last tested on
6/1/2005; does that component need to be tested by 6/1/2011 or 12/31/2011 to satisfy its 6 calendar year
20
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Marketing (3)
Wisconsin Energy Corp. (4)
Question 1 Comment
maximum maintenance interval?
2) Clarification and/or direction is desired on the testing of protection systems that contain components owned
by various entities. For example, in the instance of non-vertical integrated utilities where a distribution
provider has a Protection System that directly trips a transmission owner’s circuit breaker(s), how would
the distribution provider verify that the trip coil is able to operate the circuit breaker?
(3) Maximum testing intervals are defined. Does this imply that there are no minimum testing intervals? In
other words, is the maintenance cycle reset anytime maintenance is performed?
(4) Requirement R1.1.2 states that” “All batteries associated with the station dc supply component type of a
Protection System shall be included in a time-based program as described in Table 1-4.” Yet, in Table 1-4
under Component Attributes it refers to “…not having monitoring attributes of Table 1-4(f).” Suggest this
statement be made more clear by adding “All batteries associated with the station dc supply component
type of a Protection System shall be included in a time-based program as described in Table 1-4., unless
the dc supply has the monitoring attributes listed in Table 1-4(f).”
(5) Suggest the inspection Maximum Maintenance Interval for inspection of batteries be 4 months instead of 3
months to allow for workforce constraints that may preclude an inspection being performed within a 3
month window. Every 3 months has been found to be more than adequate to observe changing
conditions that affect batteries, therefore we feel 4 months would still be sufficient.
(6) In Tables 1-4 (a), (b), (c) – What is your interpretation of battery continuity? In other words, what
measurements or indications would be acceptable to affirm an acceptable condition? Table 1-4(b) VRLA
batteries, Maximum Maintenance Interval 18 Calendar Months, Maintenance Activities, Verify: Battery
terminal connection resistance, Verify: Battery intercell or unit-to-unit connection resistance - comment:
Add the following qualifier to these resistance checks: "If battery posts are not readily accessible or too
small to allow a good connection, follow the manufacturer's recommendation(s)."
Response: Thank you for your comments.
1. A “calendar year” refers to the years on the Julian calendar commonly used, and should be regarded as referring to a numbered year, comprising the months of
January through December. For example, 2010 is one calendar year; 2011 is another. A component, with a 6-year interval, which was last tested in 2005, would
next have to be tested by the end of 2011.
2. The standard does not prescribe “how” an entity must meet the requirements, only that the requirements must be met. However, all entities listed in the
Applicability are “owner entities”, and the SDT believes that the owner of the component should be responsible for its maintenance. However, it may be necessary
to have records relating to specific activities from the associated entity in order to demonstrate compliance to an auditor.
3. No minimum intervals are provided. To the degree that any maintenance includes all required activities, that maintenance can be recorded as addressing the
21
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
standard and re-setting the interval.
4. A “time-based” program includes extended intervals for those activities that can be effectively performed by condition monitoring. However, this requirement
excludes an entity from utilizing performance-based maintenance per R3 and Attachment A.
5. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities. The SDT believes that an entity may schedule
activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the intervals should be extended.
The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. See Section 7.1 of the
“PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about “calendar month”
6. In Section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT gives its interpretation of battery continuity and lists
several examples of measurements or indications that would be acceptable to affirm an acceptable condition and contains a discussion of connection resistance.
Your comment concerning the inaccessibility of posts or being too small would fit more appropriately as a qualifier there than in the in the standard itself.
Tennessee Valley Authority (1)
(5) (6)
Ballot
Comment Negative
In Table 1-4(a), the requirement to perform battery cell internal ohmic measurements every 18 months for
vented lead-acid batteries is excessive, and no technical justification is provided for an 18-month interval. A 3year internal ohmic test frequency is adequate to prove battery integrity. IEEE 450 does not provide a
recommended interval for internal ohmic measurements. For standard capacity testing, the recommended
interval is no greater than 25% of expected battery life. Our normal battery life is 20+ years, so the
recommended capacity test interval would be about 5 years. EPRI also recommends capacity testing at 5
year intervals. There is no justification for performing internal ohmic measurements every 18 months (which
equals every 7.5% interval of the expected battery life). We feel the standard should set the interval for
battery internal cell ohmic testing at 3 years.
Response: Thank you for your comments. The Maintenance Activity of evaluating the measured cell/unit internal ohmic values to station battery baseline is an
optional activity to verify that the station battery can perform as designed. An owner who desires not to take internal ohmic measurements on a Vented Lead-Acid
(VLA) battery can elect to verify that the station battery can perform as designed by conducting a performance, service, or modified performance capacity test of
the entire battery bank without ever having to perform any internal ohmic measurement on the battery. The maximum maintenance interval for performing this
capacity test on a VLA battery bank is 6 Calendar Years. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” - that
was posted for review with PRC-005-2 - the SDT answered several Frequently Asked Questions which explain why the 18 month Maximum Maintenance Interval
is justified rather than the 3 year frequency that is assumed by some to be adequate.
Great River Energy (1)
Ballot
Comment Affirmative
1. Table 1-4(b) VRLA Batteries---both” 6 Calendar Months” in the table should be changed to 12 months. This
would avoid being in violation if we miss a bank during a “6 month maintenance cycle”
2. Table 1-4(c) Nickel-Cadmium Batteries under the Maintenance Activities column for the 6 Calendar Years-- This maintenance activity should be optional if 18 Calendar Month Activities are completed. Or increase
load test to 10 years.
22
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments.
1. In the IEEE recommended Practice for Maintenance, Testing and Replacement of VRLA batteries (IEEE SDT 1188) a quarterly inspection should include
“Cell/unit internal ohmic values.” Based on this recommendation the SDT believes that extending the Maximum Maintenance Interval of 6 Calendar Months in
Table 1-4(b) to 12 months as suggested would be too excessive. The 6 Calendar Months for this maintenance activity will allow an entity to avoid being in
violation if they miss a bank by a few days during the quarterly maintenance cycle.
2. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT answered a Frequently Asked Question explaining
why the 6 Calendar Year maintenance activity cannot be optional if the 18 Calendar Month Activity of Table 1-4(c) is performed. The SDT also in the
Supplemental Reference & FAQ document justifies why the 6 Calendar Year Maximum Maintenance interval for performing the Maintenance Activity in Table 14(c) can not be extended to 10 years as suggested.
AtCO Electric ltd
Table 1-4: ATCO Electric has a number of remote substations that are difficult to access.
1. The requirement for a 3 calendar month inspection for electrolyte level is too frequent. The requirement
would become achievable if electrolyte level inspections were moved to the 18 calendar months category,
or if the 3 calendar months frequency were increased to 8 calendar months.
2. Table 1-4(b): for the same reasons, the requirement of a 6 calendar month inspection of individual battery
cell/unit internal ohmic values is too frequent. The requirement would become achievable if battery cell/unit
internal ohmic value inspections were moved to the 18 calendar months category, or if the 6 calendar
months frequency were increased to 14 calendar months.
3. Table 1-4(c): the requirement of a 6 calendar year performance service or modified performance capacity
test should be removed. From our experience, there is no benefit in doing battery load tests. Instead, we
apply verification of battery intercell resistance as a more efficient method of monitoring battery condition,
which provides an 8 to 14 month lead time to replace a battery unit/cell before it goes dead.
Response: Thank you for your comments.
1. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval. If adequate program oversight is exercised, and disagrees that the intervals should be
extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about “calendar month”.
2. In the IEEE recommended Practice for Maintenance, Testing and Replacement of VRLA batteries (IEEE SDT 1188) a quarterly inspection should include
“Cell/unit internal ohmic values.” Based on this recommendation the SDT believes that extending the Maximum Maintenance Interval of 6 Calendar Months in
Table 1-4(b) to the 18 calendar months category as suggested would be excessive and the SDT notes that this verification may be possible via monitoring
methods.”(See Table 1-4(f), component attribute row “Any lead acid battery based …”). The 6 Calendar Months for this maintenance activity will allow an entity to
avoid being in violation if they miss a bank by a few days during the quarterly maintenance cycle.
23
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
3. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT answered a Frequently Asked Question explaining
why the 6 Calendar Year maintenance activity cannot be optional if the 18 Calendar Month Activity of Table 1-4(c) is performed. The SDT also in the
Supplemental Reference & FAQ document justifies why the 6 Calendar Year Maximum Maintenance interval for performing the Maintenance Activity in Table 14(c) can not be removed as suggested.
Kristina M. Loudermilk (8)
Ballot
Comment Affirmative
1) In Table 1-4(b) under the Component Attributes, the sentence begins with Station dc supply; while the
other 1-4 tables begin with Protection System Station dc. I propose to make it consistent with the other
tables.
2) Table 1-4(e) mentions Maximum intervals and references another table. Is there an easier way in the
Standard to send the same information without having them flip pages? As another example in every
Component Attribute in Table 1-4(f) we mention (See Table 2). Could it be possible to make that a note,
instead of placing it under each attribute? It seems overwhelming when looking at these and for each one
that is read, flip over to Table 2. I feel like some of these references give the feel of a scavenger hunt. I am
not sure if anything can be done, but thought I would mention it.
Response: Thank you for your comments.
1.The Tables have been modified to use “Protection System Station dc supply”
2. In this regard, the SDT has tried several methods of presentation for this information. Of all methods reviewed, including the one you suggest, the SDT has
determined that the method currently represented in the Tables represents the best compromise.
Consumers Energy (4)
Ballot
Comment Negative
Relative to the 18-month activity to measure battery terminal connection resistance in Table 1-4, measuring
the battery terminal connection resistance for all terminals of the battery is an involved process that may force
the battery (and thus the system) out-of-service, or alternatively the use of a temporary battery, for the
duration of the activity. We suggest that a 6-year interval for this involved and invasive activity is appropriate
and adequate. We also suggest that it should alternatively be sufficient to instead re-torque all battery
terminal connections at the same interval.
Response: Thank you for your comments. In IEEE Standards 450, 1188, and 1106 for vented lead-acid (VLA), valve-regulated lead-acid (VRLA) and nickelcadmium (NiCd) batteries respectively state that a “yearly inspection” should include “Cell-to-cell and terminal connection resistance”, “Cell-to-cell and detail
resistance of entire battery”, and “Condition and resistance of cable connections.” Based on these IEEE recommendations the SDT believes that the Maximum
Maintenance Interval of 18 Calendar Months for this Maintenance activity will allow an entity to avoid being in violation if they miss a bank by a few weeks during
the yearly maintenance cycle.
In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” - that was posted for review with PRC-005-2 - the SDT explains
what hazards can result from high connection resistance. Also in the Supplementary Reference the SDT references where in the IEEE Standards entities can find
excellent information and examples of performing this non-intrusive Maintenance Activity. The SDT respectively disagrees with the premise that the activity to
24
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
measure battery terminal connection resistance in Table 1-4 is “an involved process that may force the battery (and thus the system) out-of-service, or
alternatively the use of a temporary battery, for the duration of the activity.” Members of the SDT are familiar with numerous Transmission Owners, Generator
Owners and Distribution Providers in NERC who yearly perform this benign maintenance activity on their battery systems while the Protection Systems that the
station batteries support are in service.
Ameren Services (1)
Ballot
Comment Affirmative
Clarify p17 Table 1-4(e) interval meaning. We think this means we need to verify the Station dc supply voltage
on 12 calendar year interval if unmonitored, or no periodic maintenance if monitored as stated.
Response: Thank you for your comments. You are correct in your interpretation for Protection System dc supply used only for distribution breakers that are
associated with UFLS, UVLS, or SPS, as stated in Table 1-4(e).
Old Dominion Electric Coop. (4)
Ballot
Comment Affirmative
ODEC believes the standard is very close to being ready for approval.
1. In the Attachment A for the battery testing, you exempt the UFLS and UVLS equipment in tables and then
include SPS batteries in the table with UFLS and UVLS. Either SPS should be associated with UFLS and
UVLS and you need to add it to the previous tables or fix table 1(f).
2. Also, consider going to 4 calendar months instead of 3 calendar months for the battery maintenance
requirements.
Response: Thank you for your comments.
1. Special Protection Systems are often a far more complex system which may comprise a combination of “transmission”, distribution, and generation
components, and are often installed to prevent serious system problems. Therefore, the requirements for SPS equipment maintenance align with that for other
generic Protection Systems. It is also notable that the legacy PRC-017-1 includes batteries within the list of components to be addressed. However, if the breaker
is a distribution breaker that is associated with SPS but is not otherwise associated with generic Protection Systems, the extended interval in Table 1.4(e) applies.
2. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month.”
Associated Electric Cooperative,
Inc. (1)
Ballot
Comment Negative
AECI appreciates the effort by the drafting team. However, the 90 day inspections for batteries and
communications circuits should be extended to 120 days to allow for a 30 grace period. Schedules would be
set for every 90 days as what is required in this revision.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
25
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
unmonitored components. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program
oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary
Reference & FAQ” for a discussion about “calendar month”
Manitoba Hydro (1) (3) (5) (6)
Ballot
Comment Negative
1. Battery Check Interval Manitoba Hydro maintains our position that the 3 month battery check interval
should be extended to 6 months. The 3 month interval is too frequent based on our experience and while
IEEE SDT 450 (which seems to be the basis for table 1-4) does recommend intervals, it also states that
users should evaluate these recommendations against their own operating experience. With the 3 month
battery check frequency and no allowance for a grace period, there may be a negative impact on reliability
caused by diverting resources away from projects that are critical to reliability to meet this maintenance
interval.
2. Conductance Measurements Conductance measurement should be listed in Table 1-4 as an acceptable
measurement method.
Response: Thank you for your comments.
1. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval if adequate program oversight is exercised, and disagrees that the intervals should be
extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about “calendar month”.
2. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT answered a Frequently Asked Question explaining
what cell/unit internal ohmic measurements are. Conductance by definition is an ohmic measurement and although not spelled out in the standard is listed in
Table 1-4 because it is an ohmic measurement.
Georgia Transmission
Corporation
No
We need clarification on the UFLS or UVLS system Station DC Supply test. We trip the high side device (nonBES asset) for each of our distribution stations UFLS or UVLS schemes, not the individual distribution
breakers. It is hard to distinguish what maintenance interval and maintenance activities we should engage for
Station DC Supply test. Since the device is not a distribution breaker as mentioned in the Table 1-4 (a-f) we
would be conservative and choose to perform maintenance at all our distribution stations with UFLS or UVLS
schemes as per Table 1-4(a). Reading the statements in the Supplementary Reference and FAQ, we notice
our devices perform similar functions as the distribution breakers. Reference pg 60 of Supp. Ref. and FAQ
paragraph 4. Since tripping the high side device of a distribution transformer still constitutes a distributed
system would our system meat the exclusion criteria although it is not a distribution breaker, would this meet
the same requirements and exempt the station from Table 1-4(a) and require only maintenance for DC
systems as per Table 1-4(e)? Please clarify. We recommend changing the term distribution breaker to
distribution asset interruption device or non-BES equipment interruption device.
26
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. Table 1-4 (e) has been modified in consideration of your comment to improve clarity (“non-BES interrupting devices “).
If the cited distribution transformer is not a BES element, the Protection Systems for that distribution transformer are not included per the Applicability (4.2.1) as
modified.
PNGC Comment Group
No
We agree the changes to the tables have added clarity, but disagree with the maintenance intervals for DC
supply. Comments:
PNGC’s comment group views the Maximum Maintenance Interval for station DC Power Supply (Table 14a/b/c/d) to be unnecessarily onerous and restrictive to many smaller-rural entities, in the west and probably
throughout the US, and this prevents us from being able to support PRC-005-2 as written. We make these
comments with the understanding that others have made similar comments in the past but we feel strongly
that this is an important issue worthy of further review by the SDT. We believe a quarterly inspection
schedule can be met while at the same time allowing entities the flexibility they need. IEEE 1188-2005
suggests a quarterly inspection schedule for lead acid batteries and we believe the standard interval for
verifying and inspecting dc supply should be 3 months with a maximum interval of 6 months. This meets the
quarterly threshold and gives some flexibility to account for unusual conditions. There are substations in
Pacific Northwest rural areas that can be inaccessible during long periods of time during the winter, potentially
exposing an entity to sanction if weather conditions prevent access to equipment for an extended period of
time. Additionally, due to a smaller workforces and greater distances between equipment subject to PRC005, small-rural entities face obstacles that large entities may not have. The three month maximum interval
assumes ideal conditions and resource access and is not realistic. We thank the SDT for considering our
comments.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended.
Arizona Public Service Company
No
Although considerable clarity was achieved in the structuring of the table for the different types of
technologies associated with the DC supply, there is issue on the maximum allowable intervals. The standard
remains too prescriptive in the intervals and maintenance activities. As an example it is believed the intent of
the interval for verifying voltages and inspecting electrolyte levels and unintentional grounds level would be
every 3 months. However, for the entity to ensure compliance and not incur a violation it would have to have
a shorter interval, probably every 2 months just to ensure compliance and not incur a violation. The 3 month
interval is in question based on programs that have been in service for many years where four months have
been proven as reliable for operation, an even shorter period than 3 or 4 months is not only a burden but an
unnecessary expense without a benefit of increase reliability of the Bulk Electric System.
27
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”.
Southern Company Generation
(5)
Ballot
Comment Affirmative
The restructured Table for Station DC supply does clarify what is being required for each type of dc system,
yet the Station DC Supply requirements, however, are excessively prescriptive in comparison to the other
Protection System component types.
Response: Thank you for your comments. The SDT recognizes that Table 1-4 with its tables a through f is considerably larger than any of the tables for the other
four Protection System components. However the SDT does not agree that the maintenance activities of Tables 1-4 (a –f) for the station dc supply are
“excessively prescriptive.” As pointed out in Section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the station battery
which is part of the station dc supply is unique from any other Protection System component in that it is a perishable product which requires several prescribed
maintenance activities to monitor and maintain its ability to perform as designed for its life cycle.
Indeck Energy Services
No
The tables are limited to a few battery technologies and will be out of date in short order with the many types
of advanced batteries already on the market. The testing requirements should be performance based as
opposed to prescriptive.
Response: Thank you for your comments. While the SDT agrees that there are a few advanced batteries and new station dc supplies which have non battery
based energy storage devices in them on the market, the SDT disagrees that the testing requirements for batteries used in station dc supplies should be
performance based as opposed to prescriptive. FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals
and minimum maintenance activities. Please note that the Standard specifically addresses requirements for non-battery based energy storage devices within
Table 1-4(d). According to the NERC Reliability Standard Development Process, NERC Reliability Standards must be reviewed at least once every five years,
and any changes related to new technologies can be addressed within that process.
Tampa Electric Company
No
If during a UF operation there were ever any breakers that did not trip properly, there may be enough that do
trip to return things to balance. There is more room for error with UFLS than with BES. The standard does
make some allowance for differences between UFLS equipment and BES equipment. For example the DC
source testing requirement for UFLS is to just test the battery voltage when the control circuit is tested. It is
not necessary that the breaker be tripped for UFLS testing every six years as is the case for BES. However,
every 12 years all unmonitored control circuitry must be tested, which may include tripping the breaker.
Response: Thank you for your comments. Table 1-5 does not require tripping of the breaker for UFLS/UVLS.
Tri-State G & T Association, Inc.
Ballot
On Page 19, Table 1-5, the standard requires that electromechanical lockout control circuits be maintained
28
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
(3) (5)
Comment Affirmative
every 6 years and protective function unmonitored control circuits be maintained every 12 years. Why is there
inconsistency in the interval between the electromechanical lockout and protective function control circuits?
Response: Thank you for your comments. The circuit itself is 12-years, but the interval for electromechanical devices such as auxiliary or lockout relays remains at
6 years, as these devices contain “moving parts” which must be periodically exercised to remain reliable.
Constellation Energy
Commodities Group (6)
Ballot
Comment Negative
As with previous revisions of this standard, the maintenance intervals and activities described in Table 1-1
through Table 1-5 are too prescriptive.
Constellation Power Source
Generation, Inc. (5)
Ballot
Comment Negative
CPG believes, as with previous revisions of this standard, that the maintenance intervals and activities
described in Table 1-1 through Table 1-5 are too prescriptive.
Response: Thank you for your comments. The SDT is not prescribing or suggesting what methods an entity employs within their program. The intervals remain as
prescribed within the standard and are designed to be clear and effective to support reliability of the BES.
Alliant Energy Corp. Services,
Inc. (4)
Ballot
Comment Negative
Table 1-5 (Component Type – Control Circuitry) Item 4 – “Unmonitored control circuitry associated with
protective functions” require a 12 calendar year maximum maintenance interval. We believe UFLS and UVLS
control circuitry should be exempted from this requirement. It would take multiple failures to have any impact,
and the impact on the BES would be minimal.
Response: Thank you for your comments. The SDT disagrees; however, the requirements related to interrupting devices used only for UFLS/UVLS are less
detailed than those for other Protection Systems because of the reason cited in your comment.
Consumers Energy (4)
Ballot
Comment Negative
Relative to Table 1-5, the activities will likely require that system components be removed from service to
complete those activities. In the case of system elements that do not have redundant protection systems
(such as those related to lower-voltage systems within the BES), it may not be possible to do so with outaging
customers for the duration of the maintenance activity. The standard must exempt these components from the
activities of Table 1-5 if the activity would result in deenergizing customers.
Response: Thank you for your comments. The intervals and activities specified are believed by the SDT to be technically effective. It is left to the entity to
determine how to align these requirements with requirements of other regulations and with operational concerns. Entities should be able to complete the activities
within the shorter intervals without outages.
American Transmission
Ballot
1. ATC recognizes the substantial efforts and improvements to PRC-005-2 that have been made and
29
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
Company, LLC (1)
Comment Negative
appreciate the dedicated work of the SDT. ATC appreciates the removal of Requirement R1.5 and R4 and
other clarifications from draft 3.
2. ATC’s remaining concerns to PRC-005-2 are with the definition and timelines established in Table 1-5. ATC
is recommending a negative ballot since, as written, the testing of “each” trip coil and the proposed
maintenance interval for lockout testing will result in the increased amount of time that the BES is in a less
intact system configuration. Note: Additional Comments to overall Standard also submitted.
Response: Thank you for your comments.
1. Thank you for your support.
2. The lockout relays and trip coils contain “moving parts” which must be periodically exercised to remain reliable. Operational results, if desired by an entity,
MAY be used to meet maintenance requirements to the degree that they verify, etc, the relevant performance. Whether their use is effective for a specific entity is
left to the entity to determine.
Wisconsin Electric Power Co. (5)
Ballot
Comment Negative
Wisconsin Electric Power
Marketing (3)
Clarification is required in Table 1-5 as to what trip and control paths should be tested. Specifically, should
non-protection paths, such as local control switches, that are not part of the Protection System, but operate
Protection System Component, be tested?
In Table 1-5, the maintenance activity for unmonitored control circuitry associated with protective functions is
to “verify all paths of the control and trip circuits”. We recommend that only the protection system paths of the
control and trip circuits require verification by PRC-005-2.
Wisconsin Energy Corp. (4)
Response: Thank you for your comments. The SDT believes that Protection Systems that protect BES elements should be included. This position is consistent
with the currently-approved PRC-005-1 and consistent with the SAR for Project 2007-17. The header section of Table 1-5 has been modified to clarify that only
the control circuitry associated with protective functions is being addressed.
Kristina M. Loudermilk (8)
Ballot
Comment Affirmative
In table 1-5 is it necessary to mention the second and last item in the table. If there is nothing to do, then why
have it as an attribute making it mandatory to keep track of, well, nothing. If those items do need to stay, then
could we reorganize the table so where it is in ascending order from Maximum maintenance intervals, like the
other tables?
Response: Thank you for your comments. The SDT believes that inclusion of these two items add clarity. The Table entry for trip coils associated only with
UVLS/UVLS has been left in the original position to relate it directly to the companion activities for other applications.
30
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Nebraska Public Power District
Yes or No
No
Question 1 Comment
The restructured tables are indeed an improvement; however the tables still need some work for clarity:
1. Table 1-5:
Unmonitored control circuitry has a maintenance activity of “Verify all paths of the control and
trip circuits.”
The wording of “control and trip circuits” leads to circuit verification of more than just trip circuits. In fact
multiple circuits would have to verified, such as station house load transfer schemes. Providing
documentation to an auditor to prove all paths have been tested will be difficult and is considered
excessive. The paperwork required to prove compliance is extremely excessive for this requirement and
doesn’t provide a benefit to reliability.
2. Table 1-5: Table 1-5 requires trip checking every six calendar years for trip coils and electromechanical
lockout and/or tripping auxiliary devices. Every six years is excessive, when suitable monitoring is used.
We recommend verification of these components be completed at the same frequency as the associated
relay testing when monitoring is used. For electromechanical, no more than every 6 calendar years, for
microprocessor, no more than 12 calendar years.
Response: Thank you for your comments.
1. The header section of Table 1-5 has been revised to clarify that it applies to “Control Circuitry Associated with Protective Functions”, and the SDT believes that
this revision addresses your concerns.
2. The electromechanical devices such as auxiliary or lockout relays remains at 6 years, as these devices contain “moving parts” which must be periodically
exercised to remain reliable.
Consolidated Edison Co. of New
York (1) (3) (5)
Ballot
Comment Affirmative
1. We recommend increasing the Table 2 reporting window from 24-hours to 72-hours for facilities not
continuously manned in order to accommodate discovery and reporting of failed alarms at these facilities
which may occur over a long (3-day) holiday weekend.
Consolidated Edison Co. of New
York (6)
Ballot
Comment Affirmative
1. We recommend increasing the Table 2 reporting window from 24-hours to 72-hours for facilities not
continuously manned in order to accommodate discovery and reporting of failed alarms at these facilities
which may occur over a long (3-day) holiday weekend.
2. We recommend that the drafting team recognize that a “fail safe” or “self-reporting” alarm design serves as
an acceptable alternative to periodic testing. This “fail safe” or “self-reporting” alarm design is equivalent to
continuous testing the alarm. When the alarm circuit fails the alarm is set to “alarm on” and automatically
notifies the control center, initiating a corrective action.
Response: Thank you for your comments.
31
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
1. The SDT believes that the monitoring and reporting will be generally done by automatic reporting methods such as SCADA and previously removed a reference
to “automatic reporting” specifically to address those cases where the facility is manned.
2. The application discussed seems to the SDT to be an effective method of “monitoring the monitoring circuit”. (See Table 2, last row with heading “Alarm Path
with monitoring.”)
Nebraska Public Power District
No
1. Table 2: The interrelationship between Tables 1-1 through 1-5 and Table 2 is ambiguous. Tables 1-1
through 1-5 “component attributes” columns references Table 2 in many cases as the criteria for maximum
interval. However, each table entry has a maximum maintenance interval listed as well. There are a few
instances where the “trump” interval is not clear. Table 1-5 is a good example.
2. Table 2 states that monitored devices (1-1 through 1-5) not having monitored alarm paths shall be tested
every 12 years. However, Table 1-5 states that DC circuits with monitored continuity shall have no periodic
maintenance. We suspect that Table 2 attributes needs further clarification to eliminate the confusion, both
Table 2 attributes at first glance appear to say the same thing. However, after study it appears to address
“detection” monitoring versus continuous (control center type) monitoring. We believe further distinguishing
clarifications are needed to make it evident and clear.
Response: Thank you for your comments.
1. The SDT believes that the activities and intervals, as they relate to whatever monitoring attributes are present, are clear. Table 2 is specifically labeled to
address whatever maintenance is necessary to the monitoring and alarming equipment itself. The references to Table 2 have been corrected where necessary.
2. Table 1 is related to the component itself, and Table 2 relates to maintenance of the monitoring and alarming if relevant. If the monitoring specified is present,
no periodic maintenance of the control circuitry itself is needed. However, as indicated in Table 2, maintenance (or monitoring) is required to assure that the
monitoring on the control circuitry is operational.
ExxonMobil Research and
Engineering
No
Ameren
Yes
Please carry the grid across in Table 1-4(f) to show the Maintenance Activities that go with the Component
Attribute.
Response: Thank you for your comments. The grid in Table 1-4(f) is drawn as the SDT intended, to show “No periodic maintenance specified” for all table entries.
The activity listed is the activity that is being accomplished by the monitoring mechanism.
Tennessee Valley Authority
Yes
However, The requirement to perform battery cell internal ohmic measurements every 18 months for vented
lead-acid batteries is excessive, and no technical justification is provided for an 18-month interval. A 3-year
32
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
internal ohmic test frequency is adequate to prove battery integrity. EEE 450 does not provide a
recommended interval for internal ohmic measurements. For standard capacity testing, the recommended
interval is no greater than 25% of expected battery life. Our normal battery life is 20+ years, so the
recommended capacity test interval would be about 5 years. EPRI also recommends capacity testing at 5
year intervals. There is no justification for performing internal ohmic measurements every 18 months (which
equals every 7.5% interval of the expected battery life). Recommendation: Set the interval for battery internal
cell ohmic testing at 3 years.
Response: Thank you for your comments. The Maintenance Activity of evaluating the measured cell/unit internal ohmic values to station battery baseline is an
optional activity to verify that the station battery can perform as designed. An owner who desires not to take internal ohmic measurements on a Vented Lead-Acid
(VLA) battery can elect to verify that the station battery can perform as designed by conducting a performance, service, or modified performance capacity test of
the entire battery bank without ever having to perform any internal ohmic measurement on the battery. The maximum maintenance interval for performing this
capacity test on a VLA battery bank is 6 Calendar Years. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” - that
was posted for review with PRC-005-2 - the SDT answered several Frequently Asked Questions which explain why the 18 month Maximum Maintenance Interval
is justified rather than the 3 year frequency that is assumed by some to be adequate.
Exelon
Yes
What kind of component we are talking about in table 1.4(d) “Station DC Supply using Non Battery Based
Energy Storage” for switchyard in nuclear plants?
Response: Thank you for your comments. An example of a “station dc supply” component of this nature would be fuel cells. The SDT is aware that some entities
are beginning to apply non-battery-based dc supplies, but we are unaware whether anyone is using these in switchyards for nuclear plants.
Xcel Energy
Yes
Regarding the last row of Table 1-4(f): it seems very inconsistent to require a formal trending program for a
manual 6 month (VRLA)/18 month (VLA) internal ohmic reading but to require no gathering and analysis of
data as an alarm for a ohmic value for each cell/unit is available. If just a raw ohmic value is an adequate
predictor of cell life, than why require a trending program for the manual reading if all that is needed to
determine adequacy of remaining cell life is just a simple acceptance criteria (i.e. - alarm set point) against
which you need to compare your measured data? In theory these are very gradual and predictable changes
in ohmic readings over the entire life of the battery, such that the benefit of real time knowledge of exactly
when a threshold is reached via alarm is minimal rather than having to wait until the next manual reading to
ascertain that the threshold limit has been reached.
Response: Thank you for your comments. Your comment concerning the last row of Table 1-4(f) being inconsistent with the two distinct maintenance activities for
internal ohmic value measurement found in the unmonitored station dc supply tables 1-4(a) and 1-4(b) was very incisive. As pointed out in section 15.4 of “PRC005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT recognized that there are two maintenance activities in Table 1-4(b) which
appear to be the same, but require a different method of interpretation to complete the required maintenance activity. The Drafting Team has considered your
comment in light of its own discussion in the Supplementary Reference & FAQ document and has divided the last row of Table 1-4(f) into two rows to reflect the
33
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
two distinct maintenance activities required in the unmonitored tables (inspection of the condition of individual VRLA cell/units, and evaluating internal ohmic
measurements to a baseline to verify the station battery can perform as designed).
Duke Energy
Yes
We believe the table could be improved further to aid compliance by adding a footnote to the term “baseline”
in the sub-tables 1-4(a), 1-4(b) and 1-4(f). The following proposed footnote text is taken from page 65 of the
Supplementary and FAQ Reference Document: “Often for older VLRA batteries the owners of the station
batteries have not established a baseline at installation. Also for owners of VLA batteries who want to
establish a maintenance activity which requires trending of measured ohmic values to a baseline, there was
typically no baseline established at installation of the station battery to trend to. To resolve the problem of the
unavailability of baseline internal ohmic measurements for the individual cell/unit of a station battery, all
manufacturers of internal ohmic measurement devices have established libraries of baseline values for VRLA
and VLA batteries using their testing device. Also several of the battery manufacturers have libraries of
baselines for their products that can be used to trend to.”
Response: Thank you for your comments. The addition that you suggest is properly considered application guidance; the SDT has been advised that such
information is not to be included within the standard, and that it is appropriately included in separate reference materials.
Ingleside Cogeneration LP
Yes
1. Ingleside Cogeneration, LP, continues to believe that the six year requirement to verify channel
performance on associated communications equipment will prove to be more detrimental than beneficial on
older relays. Clearly newer technology relays which provide read-outs of signal level or data-error rates will
easily verified, but the tools which measure power levels and error rates on non-monitored communication
links are far more intrusive. After the technician uncouples and re-attaches a fiber optic connection, the
communications channel may be left in worse shape after verification than it was prior to the start of the
test.
2. However, we have found that the remainder of the items in the Tables are logically organized and
correspond effectively with the five components of a Protection System. The maintenance activities and
intervals are technically solid and reasonable. In our opinion, the benefits to proceed outweigh our one
concern with the validation of communications channel performance.
Response: Thank you for your comments.
1. We agree that it is not good practice to disturb fiber connections as you indicate. Draft 4 does not require that. The Entity must perform the activities in the
“Maintenance Activities” column. The SDT does not interpret this as taking anything apart.
2. Thank you.
Manitoba Hydro
Yes
The restructured tables are an improvement, but we suggest that conductance (siemens) should be listed as
34
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
an acceptable measurement in addition to the resistance measurements already included in the tables.
Response: Thank you for your comments. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT answered a
Frequently Asked Question explaining what cell/unit internal ohmic measurements are. Conductance is an ohmic measurement and although not spelled out in
the standard is listed in Table 1-4 because it is an ohmic measurement.
NIPSCO
Yes
Sub-tables are good. A related question: Some devices such as reclosers and circuit breakers may include
batteries within the device itself. Does Table 1-4 apply to such batteries and DC supply? Recloser batteries
do not provide access to intercell connections.
Response: Thank you for your comments. In most instances Table 1-4 does not apply to recloser batteries or batteries within the device because they are not
generally used to provide dc power to Protection Systems designed to provide protection for BES elements. However, these types of devices with self contained
batteries may be used at the distribution level to provide Protection Systems used for underfrequency and undervoltage load-shedding. Maintenance activities
and maximum maintenance intervals for such batteries are found in Table 1-4(e) of the Standard.
MISO Standards Collaborators
Yes
American Transmission
Company, LLC
1. Yes, however, in the “Supplemental reference and FAQ” document on page 65 there are two areas of
concern. Page 65, paragraph 4:” the type of test equipment used to establish the baseline must be used for
any future trending of the cells internal ohmic measurements because of variances in test equipment and
the type of ohmic measurement used by different manufacturer’s equipment.”
While we understand the importance of creating a baseline, it is not feasible to expect the test equipment
be the same as the manufacturer’s test equipment or even the same test equipment over the life of the
battery. The expected life of a battery may be in excess of 20 years and it is not feasible to expect that the
type of equipment will not change during this period.
2. On Page 65, paragraph 6, it states:”all manufacturers of internal ohmic measurement devices have
established libraries of baseline values.” We question the availability of baseline libraries for all
manufacturers considering the variety and longevity of installations.
Response: Thank you for your comments.
1. The “Supplementary Reference and FAQ” concerning types of equipment have been changed per your suggestion to reflect consistent test data as opposed to
exactly the same piece of test equipment.
2. Many manufacturers of “Ohmic” test equipment have established libraries of baseline data. You are correct that test equipment manufacturers may not have
data on every battery in service today. Several manufacturers of batteries (not all) have libraries for some (but perhaps not all) of their products. To achieve
significant results from a trending program one needs to have good baseline data. The “Supplementary Reference and FAQ” document has been revised to reflect
your concern – the word, “all” was changed to “many”.
35
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
Yes
Question 1 Comment
Yes, however, in the “Supplemental reference and FAQ” document on page 65 this is one area of concern.
Page 65, paragraph 4 ”the type of test equipment used to establish the baseline must be used for any future
trending of the cells internal ohmic measurements because of variances in test equipment and the type of
ohmic measurement used by different manufacturer’s equipment”
While we understand the importance of creating a baseline, it’s not feasible to expect the test equipment to be
the same as the manufacturer’s test equipment or even the same test equipment over the life of the battery.
The expected life of a battery may be in excess of 15 years and it is not feasible to expect that the type of test
equipment will not change during this period.
We suggest changing the wording to read that consistent test equipment should be used to provide
consistent/comparable results.
Response: Thank you for your comments. The statements concerning types of equipment have been changed per your suggestion to reflect consistent test data
as opposed to exactly the same piece of test equipment.
The Detroit Edison Company
Yes
Yes, the tables do provide more clarity. It is much easier to understand the requirements now that they are
broken down by technology, and the exclusion of intervals on certain activities based on the individual
monitoring attributes is helpful. I appreciate the thought that went into revising this.
Response: Thank you for your comments.
New York Power Authority (1)
Yes
No comments.
ITC
Yes
The re-structured tables are easier to use.
Response: Thank you for your comments.
Luminant
Yes
No comments.
BGE
Yes
No comments.
Luminant
Yes
No comments
Northeast Power Coordinating
Council
Yes
36
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Electric Market Policy
Yes
Santee Cooper
Yes
Bonneville Power Administration
Yes
SPP reliability standard
development Team
Yes
Pepco Holdings Inc
Yes
Imperial Irrigation District
Yes
FirstEnergy
Yes
Western Area Power
Administration
Yes
NextEra Energy
Yes
Liberty Electric Power LLC
Yes
FHEC
Yes
Farmington Electric Utility System
Yes
Central Lincoln
Yes
Illinois Municipal Electric Agency
Yes
Shermco Industries
Yes
Dominion Virginia Power
Yes
Question 1 Comment
37
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
American Electric Power
Yes
CPS Energy
Yes
US Army Corps of Engineers
Yes
Alliant Energy
Yes
GDS Associates
Yes
Independent Electricity System
Operator
Yes
MidAmerican Energy Company
Yes
Question 1 Comment
38
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
2. The SDT has modified the Implementation Periods within the Implementation Plan. Do you agree with the
changes? If not, please provide specific suggestions for improvement.
Summary Consideration: Most commenters who responded to this question agreed with the proposed Implementation Plan.
There was no predominant theme in the comments. A few commenters focused on the perceived short time period allowed for
the initial conversion and development of their maintenance program while and other commenters suggested specifying Jan. 1
as an interval marker to ease in calendar year interval determination.
The SDT believes that the time frames in the proposed Implementation Plan are adequate for conversion when considering the
complete time frame that is likely to occur between industry approval vote and regulatory approvals.
The Implementation Plan was modified to provide for a lengthened implementation period for R1 and the less-than-1-calendaryear activities in R2 and R3 to allow entities not subject to regulatory approvals of 9 additional months following BOT approvals,
and, for the remaining activities, of 12 additional months following BOT approvals, to be more consistent with the expected
Regulatory Approval timelines. Additionally, all “calendar year” implementation periods were revised to “months” for additional
clarity.
The team also clarified that during the phase-in of the requirements in PRC-005-2, entities must be prepared to identify
whether each component is being maintained according to PRC-005-2, or according to PRC-005-1, PRC-008-0, PRC-011-0, and
PRC-017-0.
Under Item 4a, the team corrected the reference to generating plant outages to change “two years” to “three years” to align
with the time allocated for becoming 30% compliant (3 years) with maintenance of components subject to a 6 year interval.
Organization
Yes or No
Tri-State G&T
Question 2 Comment
The draft standard requires the PSMP to include maintenance and testing intervals for Station DC supply
associated with protective functions (including batteries, battery chargers, and non-battery-based dc supply).
Does this requirement include DC systems (batteries not included in station batteries) used by communication
systems necessary for the correct operation of protective functions?
Response: Thank you for your comments. This comment does not apply to the Implementation Plan.
Consumers Energy (4)
Ballot
Comment Negative
The implementation period for R1 and R3 for the component types addressed in Tables 1-3 and 1-5 is not
adequate. The requirements may cause entities to identify components very differently than they are currently
doing, and doing so may take several years to complete. The Implementation Plan for R1 and R3 is too
aggressive in that it may not permit entities to complete the identification of discrete components and the
associated maintenance and implement their program as currently proposed. We propose that the
Implementation Plan specifically address the components in Table 1-3 and 1-5 with a minimum of 3 calendar
39
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 2 Comment
years for R1 and 12 calendar years after that for R4.
Response: Thank you for your comments. The SDT believes that the degree of flexibility written in the standard for categorizing (and subcategorizing) is sufficient
for accomplishing the requirements within the time frames given in the Implementation Plan. For example, the voltage and current sensing devices may be
individually identified or identified by group (associated with a relay). Examples of different ways to group the dc control circuitry discrete components include
individual circuits, individual lockout devices, component protected, by control panel, or by station. The method chosen for the representation will impact the
amount of time required to transform a maintenance program.
Ameren Services (1)
Ballot
Comment Affirmative
PSMP Implement Date should commence at the beginning of a Calendar year (i.e., January 1st ). This is the
most practical way to transition assets from our existing PRC-005-1 plans
Response: Thank you for your comments. The SDT believes that the proposed Implementation Plan intervals are long enough to provide an entity the amount of
time it will take to transition to the new intervals. Considering the additional time between an approved ballot by the industry through the NERC BOT approval and
regulatory agency approval, it is very likely that an entity may have an additional 6-9 months to transition to the new program. The guidance provided to drafting
teams by NERC suggests that standards should be effective at the beginning of a calendar quarter, rather than a calendar year.
Independent Electricity System
Operator
No
We commented on this before and we will comment again. The time periods for FERC-jurisdictional entities
and non-jurisdictional entities should have at least a 3-month difference to allow some time for FERC
approval after BoT adoption in an attempt to more or less put the effective dates of the two groups of entities
in the same general time frame. The implementation plan as presented will always result in an effective date
for the non-jurisdictional entities to be at least some months (the time between BoT adoption and FERC
approval) earlier than their jurisdictional counterparts.
Response: Thank you for your comments. The Implementation Plan was modified to provide for a lengthened implementation period for R1 and the less-than-1calendar-year activities in R2 and R3 to allow entities not subject to regulatory approvals of 9 additional months following BOT approvals, and, for the remaining
activities, of 12 additional months following BOT approvals, to be more consistent with the expected Regulatory Approval timelines.
NIPSCO
No
This new standard’s calibration intervals outlined here will require additional staff at our organization. In order
to get people hired and trained the implementation plan should allow more time for the phase-in period. From
experience, calibration should have been de-emphasized since more concerns are discovered during full
tests.
Response: Thank you for your comments. The SDT believes that the proposed Implementation Plan intervals are long enough to provide an entity the amount of
time it will take to transition to the new intervals. Considering the additional time between an approved ballot by the industry through the NERC BOT approval and
regulatory agency approval, it is very likely that an entity may have an additional 6-9 months to transition to the new program.
40
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Tampa Electric Company
Yes or No
No
Question 2 Comment
The new maintenance plan has to be completed in 1 year.
1. Would that mean it is required to identify and list every element that requires testing in a database within
the first year? This will be a time intensive effort that probably that would be difficult to complete in a year
with current personnel.
2. After 1 year, would entities be required to start implementing the plan depending on the maintenance
intervals of the equipment? Qualified people would have to be in place to start the work, again this would
be difficult to accomplish with current personnel.
Response: Thank you for your comments.
1. No. Please read R1 carefully to determine what’s necessary to be implemented. There is no requirement to have a database – just to have a PSMP that
identifies the component “types” and for each component type, the associated type of maintenance program, associated maintenance activities, maintenance
intervals, and, for component types that use monitoring to extend the intervals, the appropriate monitoring attributes. There is no requirement to identify and
list every element.
2. Yes. The implementation of the plan must proceed as indicated.
Indeck Energy Services
No
The last part of the implementation plan is vague, if not undefined. The implementation should “follow the
previous maintenance intervals until all maintenance is transitioned to the new intervals.”
Response: Thank you for your comments. The SDT presumes that your comment is related to the last paragraph of the General Consideration section of the
proposed Implementation Plan. The entity should follow the previous maintenance intervals for any specific components until that component is addressed by
PRC-005-2. As the transition is occurring, the entity should adjust its maintenance and testing schedule so that it is able to demonstrate that the required % of
components meet the maintenance intervals given in the PRC-005-2 tables at each of the % compliant milestones given in this Implementation Plan.
American Electric Power
No
On page 2 of the implementation plan, it is indicated that PRC-005-1, PRC-008-0, PRC-011-0 and PRC-017-0
shall be retired and that entities will be required to identify which components will be addressed under PRC005-1 or PRC-005-2. There is no wording to cover those components that are still being addressed under
PRC-008-0, PRC-011-0 or PRC-017-0 during the implementation period.
Response: Thank you for your comments. As noted in the “General Considerations”, the entity should follow the previous maintenance intervals for any specific
components until that component is addressed by PRC-005-2. As the transition is occurring, the entity should adjust its maintenance and testing schedule so that
they are able to demonstrate that the required % of components meet the maintenance intervals given in the PRC-005-2 tables at each of the % compliant
milestones given in this Implementation Plan. The team also clarified that during the phase-in of the requirements in PRC-005-2, entities must be prepared to
identify whether each component is being maintained according to PRC-005-2 or according to PRC-005-1, PRC-008-0, PRC-011-0, or PRC-017-0.
41
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Bonneville Power Administration
Yes or No
Question 2 Comment
No
Many of the maintenance intervals in the standard are given in the terms calendar years or calendar months.
There is no description of these terms in the NERC Glossary. My Webster's dictionary defines calendar year
as the period that begins on January 1 and ends on December 31. There is no definition in my dictionary of
calendar month. Is the intent of the term calendar year in the standard that maintenance intervals start on
January 1 and end on December 31? This would make all maintenance due on December 31, and December
would be a very busy time. Does this mean that if I do maintenance on something with a maximum interval of
six calendar years in June of 2011 that it will be due again on January 1 of 2017 instead of June 1 of 2017?
We believe that the drafting team intends for maintenance to be due after a given number of years that begins
to elapse immediately after the previous maintenance is completed so that in the previous example the
maintenance would be due on June 1, 2017. Please remove the word calendar from the maximum
maintenance intervals to remove this confusion.
Response: Thank you for your comments. The intent of the term calendar year is to indicate that the maintenance is due sometime during a particular calendar
year (Jan-Dec). If you perform maintenance in June 2011 and have a 6 calendar year interval, then the same maintenance is again due sometime in 2017 (2011
+ 6). The NERC Compliance Application Notice CAN-0010, posted 19 Apr 2011, supports this compliance guideline. An interval of one calendar year means that
the activity or event must be conducted at least once within each calendar year.
FHEC
No
Can't locate the implementation plan in the posted materials.
Response: Thank you for your comments. The implementation plan was provided as a separate document within the posting and is available in the Standards
Under Development section of the NERC website under Project 2007-17:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
FirstEnergy
No
Although we agree with the timeframes being afforded to achieve compliance, we suggest the following
changes:
1. During the last comment period, we suggested changes to the wording regarding retirement of existing
standards on page 2. We do no see a response to these comments. Therefore, we would like to reiterate that
the four existing standards are to be retired upon the effective date of the new standard and not upon
regulatory approval.
2. In 4a of the plan, since the timeframe for 30% completion is 3 calendar years, we suggest a change to
three calendar years for the parenthetical phrase “(or, for generating plants with scheduled outage intervals
exceeding two calendar years, at the conclusion of the first succeeding maintenance outage)”. Change ”two”
to “three”
3. We suggest the implementation plan be included within the body of the standard. It is very burdensome for
42
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 2 Comment
entities to have to look for the implementation plan and we believe that a “one-stop shopping” approach would
alleviate this burden.
Response: Thank you for your comments.
1. The Effective Date within the Standard was stated as it is based on verbal advice of NERC Compliance – several drafts ago.
2. The Implementation Plan has been modified as you suggested.
3. The Implementation Plan is provided separately in accordance with instructions from the NERC Standards Department and Standards Committee. Further, at
the end of all transition periods, it is not needed in the standard.
ExxonMobil Research and
Engineering
No
Ameren
Yes
While we agree with the Implementation Periods, it would be best to alter R2 and R3 implementation such
that components with maximum allowable intervals of 1 year or longer align with a true calendar year (i.e.
begin with January 1).
Response: Thank you for your comments. The SDT believes that the proposed Implementation Plan intervals are long enough to provide an entity the amount of
time it will take to transition to the new intervals. Considering the additional time between an approved ballot by the industry through the NERC BOT approval and
regulatory agency approval, it is very likely that an entity may have an additional 6-9 months to transition to the new program. The guidance provided to drafting
teams by NERC suggests that standards should be effective at the beginning of a calendar quarter, rather than a calendar year.
MidAmerican Energy Company
Yes
1. In the background section of the implementation plan in item two it states “...it is unrealistic for those
entities to be immediately in compliance with the new intervals.” Recent compliance application notices
indicate that auditors are requiring entities to include proof of compliance to maintenance intervals by
providing the most recent and prior maintenance dates. The implementation document could be improved by
providing clarity to what is expected with regard to when an entity is expected to provide evidence of
maintenance interval compliance given the quoted item above. As an example in the section the
implementation plan for a 6 year interval item it states: “The entity shall be at least 30% compliant on the first
day of the first calendar quarter 3 years following applicable regulatory approval..”
In keeping with the previously quoted “reasonableness” criteria it would seem that 30% compliant would mean
only one test action would be needed to be completed by the indicated deadline and the next one would be
required no later than 6 years from that first test. It is recommended that the implementation plan document
be improved to clarify this issue.
2. In addition, it would seem appropriate to allow entities that decide to implement PRC-005-2 requirements
43
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 2 Comment
before the standard becomes effective to count the maintenance they do before the effective date in the
implementation plan schedule and in the testing interval compliance.
Response: Thank you for your comments.
1. The Implementation Plan establishes that an entity must follow its current plan until the new standard is implemented for any specific component. Therefore,
an entity should have documentation that it has maintained any given component according to its current program until it is addressed in the revised program
(including all relevant activities addressed in PRC-005-2). An entity should adjust it‘s maintenance and testing schedule so that it is able to demonstrate that the
required % of components meet the maintenance intervals given in the PRC-005-2 tables at each of the % compliant milestones given in the Implementation
Plan. The team also clarified that during the phase-in of the requirements in PRC-005-2, entities must be prepared to identify whether each component is being
maintained according to PRC-005-2 or according to PRC-005-1, PRC-008-0, PRC-011-0, or PRC-017-0.
2. If entities begin to implement the PRC-005-2 activities before the effective date, it seems to the SDT that this entity will find that they it has fully implemented
PRC-005-2 sooner, and will thus have attained a stable sustainable program that much sooner.
New York Power Authority (1)
Ballot
Comment Affirmative
2. The SDT has modified the Implementation Periods within the Implementation Plan.. Do you agree with the
changes? If not, please provide specific suggestions for improvement.
X0 Yes 0 No Comments:
Luminant
Yes
No comments.
BGE
Yes
No comments.
Luminant
Yes
No comments
Northeast Power Coordinating
Council
Yes
MISO Standards Collaborators
Yes
Electric Market Policy
Yes
Santee Cooper
Yes
44
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
SPP reliability standard
development Team
Yes
Pepco Holdings Inc
Yes
Tennessee Valley Authority
Yes
Imperial Irrigation District
Yes
PNGC Comment Group
Yes
MRO's NERC Standards Review
Subcommittee
Yes
The Detroit Edison Company
Yes
Western Area Power
Administration
Yes
NextEra Energy
Yes
Arizona Public Service Company
Yes
Liberty Electric Power LLC
Yes
Ingleside Cogeneration LP
Yes
Farmington Electric Utility System
Yes
Duke Energy
Yes
Central Lincoln
Yes
Illinois Municipal Electric Agency
Yes
Question 2 Comment
45
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Manitoba Hydro
Yes
Shermco Industries
Yes
Dominion Virginia Power
Yes
CPS Energy
Yes
US Army Corps of Engineers
Yes
Alliant Energy
Yes
Georgia Transmission
Corporation
Yes
American Transmission
Company, LLC
Yes
GDS Associates
Yes
ITC
Yes
Xcel Energy
Yes
Question 2 Comment
46
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
3. The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do you agree with the changes? If
not, please provide specific suggestions for improvement.
Summary Consideration: Many commenters pointed out an error (which was corrected by the SDT) within the VSL for R2,
where the Lower and High VSLs contained identical text.
Many comments were offered on the VRFs that demonstrated unfamiliarity with the relationship between VSLs and VRFs.
Violation Risk Factors identify the reliability-related risk associated with non-compliance; VSLs are applied after a finding of
non-compliance to identify the degree of non-compliance.
Many duplicate comments were offered on the content of the standard which were not relevant to the VRFs, VSLs, or Time
Horizons and these were answered elsewhere in this document
VSLs for R1:
•
Phased VSLs were added to address R1 Part 1.1, which was previously addressed only as a “Severe” VSL.
•
A reference was added within the R1 VSL to Part 1.3.
•
R1 High VSL was revised to add a reference to Table 2.
VSLs for R2:
•
One element of the R2 VSL was made binary (Severe), rather than “phased” (in two steps), in response to several
comments.
VSLs for R3:
•
The R3 VSLs were revised to replace “complete” with “implement and follow” for consistency with the Requirement.
Other minor editorial changes were made throughout the VSLs in response to comments.
Organization
Tri-State G&T
Yes or No
Question 3 Comment
On Page 19, Table 1-5, the standard requires that monitored electromechanical lockouts be
maintained every 6 years. Why is there inconsistency in the interval between the monitored lockouts
and monitored relays?
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to your comments on the standard provided elsewhere in this report.
47
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
SPP reliability standard
development Team
Yes or No
Question 3 Comment
No
1. If the maintenance is done prior to the maximum interval would it then reset the clock. Or should
it read that maintenance and testing should be done at least once per quarter etc.
2. We would like to see the plan split up into generation time horizons and transmission time
horizons, these can be significantly different.
Response: Thank you for your comments.
1. Provided that all required maintenance activities are done, the activity for that interval is taken care of, and the clock is reset.
2. The options for the Time Horizons are “Long-term Planning” (a planning horizon of one year or longer), “Operations Planning” (operating and
resource plans from day-ahead up to and including seasonal), “Same Day Operations” (actions required within the timeframe of a day, but not realtime), “Real-time Operations” (actions required within one hour or less to preserve the reliability of the bulk electric system), and “Operations
Assessment” (follow-up evaluations and reporting of real time operations). All of the requirements are properly assigned a Time Horizon of “Long
Term Planning”. There is no provision for different Time Horizon between entity types.
Indeck Energy Services
No
1. The VSL’s for R1 should combine the ones for Lower, Moderate and High VSL into Lower VSL.
The Severe VSL should be moved to the Moderate VSL. Because R1 is administrative, it
shouldn’t have High or Severe VSL’s.
2. The R2 High VSL (3 yrs) is more stringent than the Severe VSL (5 yrs).
3. The R3 VSL’s need to have combined numbers of components or percentages because small
generators may only have 25 relays or 1 battery and would be categorized as High or Severe VSL
with a few components affected. The percentage could apply to RE’s with more than 250
components included in the PSMP.
4. The Medium VRF for R1 should be Low VRF because R1 is administrative. Only the performance
of the maintenance has anything more than Low VRF.
5. The Medium VRF for R2 is OK.
6. Having a High VRF for R3 is without basis. R3 should have Medium VRF.
Response: Thank you for your comments.
1. R1 is not administrative – it is foundational to developing the program. The VSLs as established conform to the NERC Violation Severity Level
Guidelines.
2. The SDT disagrees. R2 “High” reflects a failure to return the “Countable Events” to an acceptable level in three years. R2 “Severe” reflects even
worse performance, in that the entity has failed to return the “Countable Events” to an acceptable level in an even longer period – five years.
48
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
3. The SDT disagrees. A smaller entity will have less to maintain in accordance with the standard, and thus the percentages are still appropriate.
4. R1 is not administrative – it is foundational to developing the program, and not having a program could “directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric system” as established in the criteria
for a Medium VRF, even if the devices are being maintained to some degree. Without having an established program, the remaining requirements are
far less meaningful.
5. Thank you.
6. The SDT believes that failure to maintain Protection Systems could “place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures” as established in the criteria for a High VRF. This concern is borne out by observations relating to several disturbances over the last
several years. Also, a High VRF for R3 is consistent with the PRC-005-1 VRF for the corresponding requirement (R2).
FRCC (10)
Non-binding
Poll
Comment
The VSL's need additional work. Here are some of the issues I see:
1. For R1, the High VSL has a condition that states "Failed to include all maintenance activities or
intervals relevant for the identified monitoring attributes specified in Tables 1-1 through 1-5. (Part
1.4)" This condition is really a combination of what is required in Part 1.3 AND Part 1.4. How would
the compliance enforcement determine an appropriate VSL if the registered entity only did not do
Part 1.3 (maintenance activities)? These should be separated.
2. Also the Severe VSL is also identified for failure to specify three or more component types. I
believe it is more appropriate to have three in High VSL and leave the Severe VSL for 4 or more.
3. For R2, the Lower VSL lists item 1) as "Failed to reduce countable events to less than 4% within
three years." This is also the same condition that is identified for the High VSL. It is also the same
condition that is listed as item 2) for the Severe VSL. In Lower and Severe, the items are
separated by OR so they are each distinct. So, which VSL should the compliance enforcement
authority use?
4. Also for R2, Lower VSL is indicated for failure to document for countable events for 5% or less of
components. Then you jump to Severe VSL for over 5%. That seems like a very huge jump. The
Moderate and High VSLs should be used to make a more gradual difference.
5. Finally, for R2, the Lower VSL is indicated if a segment has 54-59 components and a Severe is
more than 54 components. In reading Attachment A, it states that a segment MUST contain at
least sixty (60) individual components. This would appear to me to be all or nothing. I would
suggest that the only VSL for this would be a Severe if it did not have 60 or more.
Response: Thank you for your comments.
49
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
1. The SDT disagrees. For the assessment of compliance to R1, Part 1.3 and Part 1.4 work together in the fashion identified in the VSL.
2. The SDT disagrees, and believes that failure to address three or more component types (out of a total of five) indeed reflects a Severe violation of the
requirement.
3. Thank you for catching this. The High VSL has been modified from three years to four years. Where elements of the VSL are separated by “or”, the
compliance enforcement authority should use each of them as appropriate.
4. The SDT disagrees. The documentation of countable events is so fundamental to a performance-based maintenance program that the SDT has
assigned a Lower VSL to minor transgressions, with all other transgressions being regarded as a Severe VSL.
5. The SDT has modified the R2 VSL for the segment population to be binary as you suggested.
Tri-State G & T Association,
Inc. (3) (5)
Ballot
Comment
1. On Page 7, R2 Violation Severity Levels, “Entity has Protection System elements in a
performance-based PSMP but has failed to reduce countable events to less than 4% within three
years” is shown as both a Lower VSL and a High VSL. What differentiates the two VSLs?
2. R1 VSL - Second item in Severe VSL is not addressed in any lower VSL. Should there also be a
comparable violation in Lower and Moderate?
Response: Thank you for your comments.
1. Thank you for catching this. The High VSL has been modified from three years to four years.
2. VSLs have been added to Moderate and High to address lesser violations.
Tri-State G & T Association
Inc. (3)
Non-binding
Poll
Comment
1. Comment 1: On Page 7, R2 Violation Severity Levels, “Entity has Protection System elements in a
performance-based PSMP but has failed to reduce countable events to less than 4% within three
years” is shown as both a Lower VSL and a High VSL. What differentiates the two VSLs?
2. Comment 2: R1 VSL - Second item in Severe VSL is not addressed in any lower VSL. Should
there also be a comparable violation in Lower and Moderate?
Response: Thank you for your comments.
1. Thank you for catching this. The High VSL has been modified from three years to four years.
2. VSLs have been added to Moderate and High to address lesser violations.
Tri-State G & T Association
Inc. (5)
Non-binding
Poll
1: On Table 1-2, page 11: The standard describes the following component attributes, “Any
unmonitored communications system necessary for correct operation of protective functions, and
50
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Comment
Question 3 Comment
not having all the monitoring attributes of a category below.” How does this apply to redundant
communication systems? If the primary communications channel fails the protective relay
automatically fails over to the back-up channel and continues to function properly. Are redundant
communication channels excluded from this component attribute and associated interval? Also, if
a relay is set to operate in a manner typical when communication is not used for protection (i.e.
defaulting to step-distance functions with a loss of communication), is the defaulted operation of
the relay considered “correct operation” thereby excluding the communication as necessary for its
correct operation? Please clarify the term correct operation and how it applies to redundant
communication systems and/or the performance of the relay in the absence of communication.
2: The draft standard requires the PSMP to include maintenance and testing intervals for Station DC
supply associated with protective functions (including batteries, battery chargers, and non-batterybased dc supply). Does this requirement include DC systems (batteries not included in station
batteries) used by communication systems necessary for the correct operation of protective
functions?
3: On Page 19, Table 1-5, the standard requires that electromechanical lockout control circuits be
maintained every 6 years and protective function unmonitored control circuits be maintained every
12 years. Why is there inconsistency in the interval between the electromechanical lockout and
protective function control circuits?
4: On Page 7, R2 Violation Severity Levels, “Entity has Protection System elements in a
performance-based PSMP but has failed to reduce countable events to less than 4% within three
years” is shown as both a Lower VSL and a High VSL. What differentiates the two VSLs?
Response: Thank you for your comments.
1. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
2. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
3. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
4. Thank you for catching this. The High VSL has been modified from three years to four years.
Farmington Electric Utility
System
No
VSL on R2: Lower criteria item 1; the wording is identical High VSL. FEUS recommends keeping the
criteria in the Lower VSL.
51
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
City of Farmington (3)
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
Alliant Energy Corp. Services,
Inc. (4)
Non-binding
Poll
Comment
The Lower and High VSL for Requirement 2 have the same description. The Lower VSL has other
possible items, but there is a conflict where an entity could argue for both a Lower and High VSL.
That needs to be clarified.
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
GDS Associates
No
1. Suggest clarification of the VSL for R2. It appears that R2 Lower VSL is also contained in the R2
High VSL.
2. If the maintenance is completed prior to the maximum interval, would it then reset the clock? Or
should it read that maintenance should be done at least once per quarter?
3. The plan should split into generation time horizons and transmission time horizons since these
can be significantly different
Response: Thank you for your comments.
1. Thank you for catching this. The High VSL has been modified from three years to four years.
2. Yes – it would reset the clock, provided that all required activities are completed during the performance of the maintenance.
3. The SDT disagrees. The options for the Time Horizons are “Long-term Planning” (a planning horizon of one year or longer), “Operations Planning”
(operating and resource plans from day-ahead up to and including seasonal), “Same Day Operations” (actions required within the timeframe of a
day, but not real-time), “Real-time Operations” (actions required within one hour or less to preserve the reliability of the bulk electric system), and
“Operations Assessment” (follow-up evaluations and reporting of real time operations). All of the requirements are properly assigned a Time Horizon
of “Long Term Planning”. There is no provision for different Time Horizon between entity types.
Alabama Power Company (3)
Georgia Power Company (3)
Non-binding
Poll
Comment
But only if the clean version on Page 7 under Violation Severity Levels R2/High VSL match the
redline dated 4/12/2011. Entity has Protection System elements in a performance-based PSMP but
has failed to reduce countable events to less than 4% within four years.
Gulf Power (3)
Mississippi Power (3)
Response: Thank you for your comments. The clean version represents the content desired for the Standard. The red-line is affected by peculiarities of
52
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
the red-lining tool within Microsoft Word.
Tampa Electric Company
No
VSL is severe for more than 4% Countable Events on R2. It does not seem feasible.
Response: Thank you for your comments. R2, by reference to Attachment A, requires that entities using performance-based maintenance reduce
Countable Events to less than 4% within three years. The R2 Severe VSL reflects failure to do so within five years.
Manitoba Hydro
No
1. VSL for Requirement 2:-Needs to use consistent terminology. The standard requirements refer to
components and component types, not elements.
2. The violation “Entity has Protection System elements in a performance-based PSMP but has failed
to reduce countable events to less than 4% within three years” appears in both the Lower VSL
column and the High VSL column. The violation cannot be both Lower and High. VSL for
Requirement R3: -Suggested wording “completed its scheduled program”.
Manitoba Hydro (1) (3) (5) (6)
Non-binding
Poll
Comment
Manitoba Hydro is voting negative for the following reasons:
1. VSL for Requirement 2: -Needs to use consistent terminology. The standard requirements refer to
components and component types, not elements.
2. The violation “Entity has Protection System elements in a performance-based PSMP but has failed
to reduce countable events to less than 4% within three years” appears in both the Lower VSL
column and the High VSL column. The violation cannot be both Lower and High.
3. VSL for Requirement R3: -Suggested wording “completed its scheduled program”.
Response: Thank you for your comments.
The term, “element” is not used in any of the VSLs.
2. Thank you for catching this. The High VSL has been modified from three years to four years.
3. The SDT disagrees; the VSL address failure to complete the scheduled program. The suggested change does not reflect this.
Duke Energy
No
Duke Energy
Non-binding
Poll
Typographical error - the High VSL for R2 has been incorrectly changed to “within three years” from
“within four years”. This is now the same as the Lower VSL.
There is a typographical error on the High VSL for R2. It has been incorrectly changed to “within three
years” from “within four years”. This is now the same as the Lower VSL.
53
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
Comment
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
Kristina M. Loudermilk
Non-binding
Poll
Comment
1. In VSL R2 I find it confusing for the Lower VSL and High VSL. In the Lower VSL for R2 #1 is
mentioned, but again mentioned in High VSL. IS there an easier way to make that flow?
2. Also I found that I have forgotten a comment for the Standard itself.... In Attachment A, #5 is
mentioned twice. I understand as to why, so I think, but in the "To Maintain" #5 says that one has to
use the prior year's data. It matches the exact form of "how to establish the performance based
PSMP". I find this confusing. So does this mean that testing will be once a year for parts of the
segment. I did not get that same understanding from the support documents. Is there way to reword
one of the #5's to show case a difference. Or is this on purpose? I just found it confusing.
Response: Thank you for your comments.
1. The High VSL has been modified from three years to four years.
2. The “first” #5 applies to establishing the performance-based program; the “second” one – now modified to be #4 in the second section, applies to
maintaining the performance-based program on a continuing basis.
Alliant Energy
No
The LOW and HIGH VSL for R2 are the same. There are additional possibilities for the LOW, but it is
possible to be in both the LOW and HIGH VSL at the same time. We recommend removing #1 in the
LOW VSL category to resolve the issue.
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
The Detroit Edison Company
No
R2 - It appears that the Lower VSL point 1) and High VSL are identical.
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
Consolidated Edison Co. of
New York (1) (3) (5) (6)
Ballot
Comment Affirmative
Clarification is needed to assure that the industry more fully understands how the percentage of
“maintenance correctable issues” will be computed in the R3 VSL.
Consolidated Edison Co. of
New York (1) (5) (6)
Non-binding
Poll
1: Clarification is needed to assure that the industry more fully understands how the percentage of
“maintenance correctable issues” will be computed in the R3 VSL.
54
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
Comment
2: We recommend increasing the Table 2 reporting window from 24-hours to 72-hours for facilities not
continuously manned in order to accommodate discovery and reporting of failed alarms at these
facilities which may occur over a long (3-day) holiday weekend.
3: We recommend that the drafting team recognize that a “fail safe” or “self-reporting” alarm design
serves as an acceptable alternative to periodic testing. This “fail safe” or “self-reporting” alarm
design is equivalent to continuous testing the alarm. When the alarm circuit fails the alarm is set to
“alarm on” and automatically notifies the control center, initiating a corrective action.
Response: Thank you for your comments.
1. The SDT believes that this is clear; if an entity has 20 maintenance-correctable issues and has failed to initiate resolution of one, it has failed to initiate
resolution of 5% of the maintenance-correctable issues.
2. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
3. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
Independent Electricity System
Operator
Independent Electricity System
Operator (2)
No
Non-binding
Poll
Comment
(1) We do not agree with the High VRF for R3 which asks for implementing the maintenance plan
(and initiate corrective measures) whose development and content requirements (R1 and R2)
themselves have a Medium VRF. Failure to develop a maintenance program with the attributes
specified in R1, and stipulation of the maintenance intervals or performance criteria as required in
R2, will render R3 not executable. Hence, we suggest that the VRF for R3 be changed to Medium.
(2) The Severe VSL for R2 is improper. First, the reference to R3 is incorrect. Second, the first
condition that says: “Failed to establish the entire technical justification described within R3 for the
initial use of the performance-based PSMP” introduces a requirement not stipulated in R2 itself.
We suggest to remove this condition. If the SDT feels strongly that the technical justification (we’re
not sure what exactly it is) needs to be established for the initial use of the performance-based
PSMP, then R2 should be revised to capture this requirement.
Response: Thank you for your comments.
1. The SDT believes that failure to maintain Protection Systems could “place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures” as established in the criteria for a High VRF. This concern is borne out by observations relating to several disturbances over the last
several years. However, even if the program is not fully documented per R1 and R2, devices may still be maintained; thus the reduced VRF for these
requirements. Also, the R3 “High” VRF is consistent with the VRF assigned to the similar PRC-005-1 requirement (R2).
55
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
2. The Severe VSL for R2 has been corrected to refer to R2. The remainder of the Severe VSL for R2 is correct, in that R2 itself specifies that the
procedure in Attachment A must be used, both to establish and maintain a performance-based maintenance program. The definition of maintenance
correctable issue has been revised to be clearer.
Tennessee Valley Authority
No
TVA has 590 Pilot Relay (Carrier Blocking) Terminals that are tested twice a year. After an extensive
study of carrier failures over a 5-year period, it was determined that we were not having any failures
that could have been prevented by a functional test. In January 2008, we reduced our frequency
from 4 times per year to 2 times per year. The failure rate has remained about the same since that
change.
As PRC 005-2 currently states, the PM frequency would be 3 months. Allowing for a one-month
grace period would actually require the interval to be set at 2 months. Therefore, the interval we used
prior to 2008 (4 times per year) still would not make TVA compliant with the stated 3 month
interval.TVA Power Control Systems is in the process of developing extensive PM tests for carrier
terminals to complement the existing PM program. This PM would record signal levels, reflected
power, line losses, and other pertinent data. It is my position that this PM will improve reliability more
than increasing the frequency of the functional test.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to your comments on the standard provided elsewhere in this report.
American Electric Power
No
This standard encompasses a very broad range of component types and functionality. It also
encompasses broad segments of the BES. The proposed VSLs and VRFs place the same level of
severity or priority on facilities that serve local load with that of an EHV facility. The percentages
indicated in the VSLs seem to be too strict based upon the vast quantity of elements in scope and
broad range of application.
Response: Thank you for your comments. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation. The NERC VRF Guidelines establish the criteria for assigning VRFs and do not provide for multiple VRFs for a single requirement,
and the percentages (where used) assigned within the VSLs conform to the criteria established within the NERC VSL guidelines.
FHEC
No
For Distribution Provider level equipment there should be no High or Severe VSLs
Response: Thank you for your comments. The SDT disagrees; the VSLs are intended to address the degree to which an entity fails to comply with each
requirement, and the nature of the entity has no bearing on this determination.
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Pepco Holdings Inc
Yes or No
No
Question 3 Comment
1. Are the bullet items listed for the R2 Severe Violation Severity Level , Item 5 an "and" or an "or"?
5) Failed to:
• Annually update the list of components,
• Perform maintenance on the greater of 5% of the segment population or 3 components,
• Annually analyze the program activities and results for each segment.
2. The wording of the R3 Lower Violation Severity Level seems to imply that an entity that fails to
complete 0% (i.e., completes 100%) of its maintenance correctable issues is non-compliant. Entity
has failed to complete scheduled program on 5% or less of total Protection System components.
OR Entity has failed to initiate resolution on 5% or less of identified maintenance correctable
issues.
The following re-phrasing is suggested: Entity has failed to complete scheduled program on
greater than 0%, but no more than 5% of total Protection System components. OR Entity has
failed to initiate resolution on greater than 0%, but less than or equal to 5% of identified
maintenance correctable issues.
Response: Thank you for your comments.
1. The VSL has been modified to separate these items with “or”.
2. The SDT disagrees; this description conforms to the guidance in the NERC VSL Guidelines, and VSLs only apply if there is a failure to comply with
the relevant requirement.
Liberty Electric Power LLC (5)
Non-binding
Poll
Comment
The use of percentages, without accounting for the size of the entity, unfairly burdens small IPPs.
Response: Thank you for your comments. The SDT disagrees. A smaller entity will have less to maintain in accordance with the standard, and thus the
percentages are still appropriate.
Liberty Electric Power LLC
No
See comments at end.
Response: Thank you for your comments. Please see our response to your other comments.
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
ExxonMobil Research and
Engineering
Consumers Energy (5)
Yes or No
Question 3 Comment
No
Non-binding
Poll
Comment
see comment on R3
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to your comments on the standard provided elsewhere in this report.
New York Power Authority (1)
Yes
No comments.
Luminant
Yes
No comments.
BGE
Yes
No comments.
Luminant
Yes
No comments
Northeast Power Coordinating
Council
Yes
MISO Standards Collaborators
Yes
Santee Cooper
Yes
Imperial Irrigation District
Yes
PNGC Comment Group
Yes
MRO's NERC Standards
Review Subcommittee
Yes
FirstEnergy
Yes
58
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Western Area Power
Administration
Yes
NextEra Energy
Yes
Ingleside Cogeneration LP
Yes
Central Lincoln
Yes
Shermco Industries
Yes
CPS Energy
Yes
US Army Corps of Engineers
Yes
Ameren
Yes
Georgia Transmission
Corporation
Yes
ITC
Yes
MidAmerican Energy
Company
Yes
Xcel Energy
Yes
NIPSCO
Northern Indiana Public
Service Co. (3)
Question 3 Comment
no comments at this time
Non-binding
Poll
Comment
One of our concerns is that, while the present standard is 2 pages and is the most highly violated and
fined standard, the new proposed standard is 22 pages, the implementation plan is 4 pages and the
Supplemental FAQ document is 87 pages.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
59
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
response to NIPSC’s comments on the standard provided elsewhere in this report.
Public Utility District No. 2 of
Grant County
Non-binding
Poll
Comment
GCPD has made it a practical practice of not voting affirmative for VRF and VSL until the standard is
edited to our satisfaction and can vote affirmative on the standard.
Response: Thank you for your comments. Please see the revisions made to the standard and the drafting team’s responses to the comments.
Florida Municipal Power
Agency (4) (5)
FMPP (6)
Non-binding
Poll
Comment
· Section 4.2.1 states that the Standard is applicable to “Protections Systems designed to provide
protection BES Elements.” Section 15.1 of the Supplementary Reference Document defines the
scope as those “devices that receive the input signal from the current and voltage sensing devices
and are used to isolate a faulted element of the BES.” These two statements are not exactly
equivalent, and in fact, are in conflict with the Interpretation of PRC-004-1 and PRC-005-1 for Y-W
Electric and Tri-State, Approved by the Board of Trustees on February 17, 2011. Section 4.2.1 should
be changed to “Any Protection System that is installed for the purpose of detecting faults on
transmission elements (lines, buses, transformers, etc.) identified as being included in the Bulk
Electric System (BES) and trips an interrupting device that interrupts current supplied directly from
the BES.”
· Examples #1, #2 and #3 in Section 7.1 of the Supplementary Reference all indicate that it is a
requirement to “verify all paths of control and trip circuits” every 12 years. As stated, there would be
circuits included in the testing requirement that the SDT did not mean to include in the scope of the
Standard (e.g., SCADA closing circuit.) The statements in the illustrative examples should be
changed to “verify all paths in the control circuitry associated with protective functions through the trip
coil(s) of the circuit breakers or other interrupting devices” to be in line with the definition of a
Protection System.
· Section 15.5 of the Supplementary Reference Document states: “It was the intent of this Standard to
require that a test be made of any communications-assisted trip scheme regardless of the vintage of
the technology. The essential element is that the tripping (or blocking) occurs locally when the remote
action has been asserted; or that the tripping (or blocking) occurs remotely when the local action is
asserted”. The SDT should reword this statement recognizing that tests performed on communication
systems may not be performed at the same time an entity chooses to perform trip tests on the
associated breaker(s). The notion of “overlapping” can be applied, for instance, by taking an outage
on one relay set in a fully redundant system, initiating a trip signal from the remote end and observing
60
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
the trip signal locally. All remaining portions in the local communication-assisted trip paths can then
be tested when the local line panel is taken out of service for maintenance.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to the same comments on the proposed standard provided elsewhere in this report.
Seattle City Light (5)
Non-binding
Poll
Comment
Pursuant to the negative ballot relating to the Standard. Both votes will be affirmed if the comments
are addressed.
Response: Thank you for your comments. Please see the drafting team’s responses to the comments offered by Seattle on the proposed standard.
Seattle City Light (6)
Non-binding
Poll
Comment
Seattle City Light (SCL) commends the Standard Drafting Team (SDT) for the many improvements in
the latest draft of proposed standard PRC-005-2. The proposed PRC-005-2 standard is an
improvement over the four standards that it will replace. Each draft has been better than that
preceding, and the supporting material is very helpful in understanding the impact and
implementation of the proposed Standard. However, SCL votes NO for this draft because of
1) the inclusion and treatment of electromechanical lockout relays within the scope of draft Standard
and
2) confusion about language between section 4.2 and Requirement 1.
Regarding electromechanical lockout relays, SCL is highly concerned about the reliability risks and
logistical difficulties associated with meeting the requirements proposed for these relays. Lockout
relays operate rarely and are known for reliable service. For many such relays, the proposed
maintenance would require clearance of entire bus sections or even multiple bus sections (such as
for a bus differential lockout relay). In SCL's opinion, the reliability risks posed by such switching and
outages to the Bulk Electric System outweigh the reliability benefits of including lockout relays in the
scope of PRC-005-2. If the SDT deems it necessary to include electromechnical lockout relays within
PRC-005-2, SCL recommends that a difference be made between the maintenance activities
specified for monitored and unmonitored types. The draft Standard describes the requirements for
"electromechanical lockout and/or tripping auxiliary devices" in Table 1-5 (p.19) and assigns a 6-year
maximum maintenance interval, the same as for other unmonitored relays. Modern electromechanical
lockout relays may be specified with a built-in self-monitoring trip-coil alarm. SCL believes the
maintenance requirements for electromechanical lockout relays with such an alarm should be similar
to those for other alarmed or monitored relays.
As such we recommend that a new entry be added to Table 1-5 for monitored electromechanical
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
lockout relays, as follows:
• Component Attributes: Electromechanical lockout and/or tripping auxiliary devices which are directly
in a trip path from the protective relay to the interrupting device trip coil AND include built-in selfmonitoring trip-coil alarm
• Maximum Maintenance Interval: 12 calendar years
• Maintenance Activities: Verify electrical operation of electromechanical trip and auxiliary devices.
Verify that the alarm path conveys alarm signals to a location where corrective action can be initiated.
Regarding confusion over language, section 4.2 section identifies five types of Facilities that the
standard is applicable to, whereas Requirement 1 indicates that applicable entities need to establish
a Protection System Maintenance Program (PSMP) for the Protection Systems designed to provide
protection for BES Element(s) (Part 4.2.1 of Section 4.2). As such, it is not clear if PRC-005-2 applies
to five Facilities or to certain Protection Systems. SCL believes the intent is to have a PSMP for all
Protection Systems identified in "Part A, Section 4.2 - Facilities" and that the language of
Requirement 1 may cause confusion or be misleading. We suggest changing the language of
Requirement 1 from:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for
BES Element(s). to: • Each Transmission Owner, Generator Owner, and Distribution Provider shall
establish a Protection System Maintenance Program (PSMP) for its Facilities identified in Part A,
Section 4.2.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to the same comments on the proposed standard provided elsewhere in this report.
Beaches Energy Services (1)
Non-binding
Poll
Comment
We believe that there is an unnecessary expansion of the scope of equipment covered by this
standard into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes
batteries, instrument transformers, DC control circuitry and communications in addition to the relays
for BES protection systems. PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether
non-relay components are included in those standards. The new PRC-005-2 includes these non-relay
components into UFLS and UVLS. The problem is, for UFLS and UVLS, these non-relay components
are mostly distribution class equipment; hence, the result of this version 2 standard will be inclusion
of most distribution class protection system components into PRC-005-2. This is a huge expansion of
the scope of equipment covered by the standard with negligible benefit to BES reliability. We agree
wholeheartedly with the inclusion of non-relay components for BES Protection Systems. It is critical
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
that BES Protection Systems work and clear the fault (e.g., on > 100 kV Facilities). However, UFLS
and UVLS are quite different. For an event requiring UFLS and UVLS operation, there are many, e.g.,
hundreds and possibly thousands of relays, that operate to shed load automatically and if a small
percentage of those do not operate as expected, the impact is minimal. So, it is not important for BES
reliability to include non-relay components of UFLS and UVLS in the PRC-005-2 standard. In
addition, testing of protection systems on distribution circuits is difficult for distribution circuits that are
radial in nature. For instance, testing trip coils of distribution breakers will likely result in service
interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault
current on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing
customer service quality for an infinitesimal increase in BES reliability. In addition, non-relay
protection components operate much more frequently on distribution circuits than on Transmission
Facilities due to more frequent failures due to trees, animals
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to the same comments on the proposed standard provided elsewhere in this report.
City of Green Cove Springs (3)
Non-binding
Poll
Comment
GCS believes that there is an unnecessary expansion of the scope of equipment covered by this
standard into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes
batteries, instrument transformers, DC control circuitry and communications in addition to the relays
for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are
included in those standards. The new PRC-005-2 includes these non-relay components into UFLS
and UVLS. The problem is, for UFLS and UVLS, these non-relay components are mostly distribution
class equipment; hence, the result of this version 2 standard will be inclusion of most distribution
class protection system components into PRC-005-2. This is a huge expansion of the scope of
equipment covered by the standard with negligible benefit to BES reliability. GCS agrees
wholeheartedly with the inclusion of non-relay components for BES Protection Systems. It is critical
that BES Protection Systems work and clear the fault (e.g., on > 100 kV Facilities). However, UFLS
and UVLS are quite different. For an event requiring UFLS and UVLS operation, there are many, e.g.,
hundreds and possibly thousands of relays, that operate to shed load automatically and if a small
percentage of those do not operate as expected, the impact is minimal. So, it is not important for BES
reliability to include non-relay components of UFLS and UVLS in the PRC-005-2 standard. In
addition, testing of protection systems on distribution circuits is difficult for distribution circuits that are
radial in nature. For instance, testing trip coils of a distribution breakers will likely results in service
interruption to customers on that distribution circuit in order to test the breaker or to perform break-
63
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
before-make switching on the distribution system often required to manage maximum available fault
current on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing
customer service quality for an infinitesimal increase in BES reliability. In addition, non-relay
protection components operate much more frequently on distribution circuits than on transmission
Facilities due to more frequent failures due to trees, animals, lightning, traffic accidents, etc., and
have much less of a need for testing since they are operationally tested.
As another comment, station service transformers are not BES Elements and should not be part of
the Applicability - they are radial serving only load.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to the same comments on the proposed standard provided elsewhere in this report.
ReliabilityFirst
Non-binding
Poll
Comment
ReliabilityFirst agrees with the VRFs but votes negative on the VSLs for the following reasons:
1.
2.
3.
VSL for R1
a. Part 1.3 is not mentioned in the VSLs
b. The VSLs should start off with the phrase “The responsible entities PSMP…”
c. For the VSLs dealing with Part 1.2, the term “or a combination” should be added as one of the
methods for maintenance.
d. The last VSL under the Severe category should reference Part 1.2
e. The VSLs for Part 1.1 should be gradated similar to Part 1.2 (e.g. what VSL does an entity
fall under if they failed to address two component types included in the definition of ‘Protection
System’?)
VSL for R2
a. To be consistent with Requirement 2, the VSLs should start off with the phrase “The
responsible entity uses performance-based maintenance intervals in its PSMP, but…”
b. The first VSL under the “Lower” category is a duplicate of the VSL under the “High” category
c. The third VSL under the “Lower” category has language stating “or containing different
manufacturers.” Neither R2 nor Attachment A mentions this language. This is a violation of the
FERC Guideline 3: “Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement”
d. Recommend that the VSL regarding entities that “maintained a segment with less than X
amount of components” should be a binary “Severe” VSL
VSL for R3
a. The VSLs should start off with the phrase “The responsible entity…”
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
b. R3 does not require an entity to “…complete scheduled program…” This is a violation of the
FERC Guideline 3: “Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement”
c. The “implement and follow its PSMP” language in R3 is not mentioned in the VSLs for R3.
Recommend including this language in the VSLs for R3
Response: Thank you for your comments.
1.
a. Part 1.3 has been added to the R1 High VSL.
b. The R1 Lower, Medium, and Higher VSLs have been modified as you suggest.
c. The R1 Lower, Medium, and Severe VSLs have been modified as you suggest.
d. The R1 Severe VSL has been modified as you suggest
e. The R1 Moderate and High VSLs have been modified to add graduated VSLs for part 1.1.
2.
a. The R2 VSLs have been modified as you suggest.
b. Thank you for catching this. The High VSL has been modified from three years to four years.
c. This portion of the R2 Lower VSL has been removed, making the VSL for this portion of R2 binary (with only a Severe VSL).
d. The VSL for R2 has been modified as you suggest.
3.
a. The R3 VSLs have been modified as you suggest.
b. The R3 VSLs have been modified by replacing “complete” with “implement and follow” in consideration of your comment.
c. The R3 VSLs have been modified by replacing “complete” with “implement and follow” in consideration of your comment.
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
4. The SDT has incorporated the FAQ document into the “Supplementary Reference” document and has provided
the combined document as support for the Requirements within the standard. Do you have any specific
suggestions for further improvements?
Summary Consideration: The commenters were generally supportive of the combination of documents.
Several comments were offered, repeating previous questions regarding the enforceability of this document, and the SDT
repeated previous responses explaining the status of this document as a supporting reference – reference documents have no
enforceability.
A variety of suggestions were offered regarding additional information for the document, which largely resulted in modifications
to the Supplementary Reference document. One specific suggestion of note (resulting in additional discussion within the
document) requested a FAQ regarding “Calendar Year”.
Several commenters posed questions regarding “grace periods” and “PSMPs established by entities that are more stringent than
the requirements within the standard”. No additional changes were made due to these questions, but the SDT further
explained previous guidance on these issues within the responses. Entities are always allowed to implement practices that are
more stringent than those identified in a standard.
Organization
Yes or No
Manitoba Hydro
Question 4 Comment
A red line was not provided making this document difficult to review. We suggest that a redline of this
document be posted.
Response: Thank you for your comments. A red-line was not provided because of overall extensive changes, resulting from merging of the previous
Supplementary Reference Document and FAQ; the entire document would have been red-line. The next posting will include a red-lined document, as well as the
“clean” document.
U.S. Bureau of Reclamation (5)
Ballot
Comment Affirmative
1. The reference material provides a significant insight into the intent of the proposed changes to the
standard. In some cases an interpretation is provided which is not supported by the explicit interpretation of
the standard text. The SDT is encouraged to either attach the reference material to the standard or add
relevant sections to standard as Background. The Background section could reference the Supplemental
Reference & FAQ.
2. The reference material provides more detail indicating that “Voltage & Current Sensing Device circuit input
66
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 4 Comment
connections to the protection system relays can be verified by (but not limited to) comparison of measured
values on live circuits or by using test currents and voltages on equipment out of service for maintenance. .
. . . . The values should be verified to be as expected, (phase value and phase relationships are both
equally important to verify).” This interpretation is not consistent with the text of the standard and would
suggest that it be incorporated into Table 1-3.
3. When protective equipment is replaced, the reference information indicates that the information associated
with the original equipment must be retained to show compliance with the standard until the performance
with the new equipment can be established. This is not stated in the Measurements and should be added if
the expectation exists.
Response: Thank you for your comments.
1. This standard is not being developed in a “results-based” format. Attaching the extra document as you suggest would make the supporting information within
the FAQ and Supplementary Reference part of the standard, and this would add extensive and unnecessary prescription to the standard. As you suggest the
reference material is listed within the Standard (Section F – Supplemental Reference Document). The next revision will likely resemble your suggestion.
2. Details within the Supplemental Reference Document are provided as examples and should not be construed as limitations or additional requirements. The
intent of the supplementary information is to spur insight into possible means of satisfying requirements and is not intended to promote a single technical method
of accomplishing tasks.
3. M1 states “Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence that it has implemented the Protection System
Maintenance Program and…” Documenting the implementation of the PSMP certainly requires evidence that maintenance was performed at the prescribed
intervals and the data retention requirements state that evidence of the two most recent performances of each distinct maintenance activity be retained. Also,
please see the NERC Compliance Process Bulletin #2011-001 (“Data Retention Requirements”) for similar guidance.
Ameren Services (1)
Ballot
1. Omit retention of maintenance records for replaced equipment. Supplement FAQ 12.1 on page 51 final
Comment –
sentence states that documentation for replaced equipment must be retained to prove the interval of its
Affirmative
maintenance. We oppose this because: the replaced equipment is gone and has no impact on BES reliability;
and such retention clutters the data base and could cause confusion. For example, it could result in saving
lead acid battery load test data beyond the life of its replacement. Since BES Element protection is the
objective, we suggest a compromise of keeping the evidences of last test for the removed equipment and
using that with the equivalent function replacement equipment commissioning or in-service date to prove
interval.
2. In Supplement examples on pp 22-23, replace “Instrumentation transformers” with “Verify that current and
voltage signal values are provided to the protective relays” to be consistent with Table 1-3.
3. Remove “Reverse power relays” from the sample list of generator devices in Supplement p31 because
reverse power relays are applied for mechanical protection of the prime mover, not electrical protection of the
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 4 Comment
generator.
4. Revise Supplement Figure 1 & 2 Legend p83 to align with Draft 4 (a) state “Protective relays designed to
provide protection for BES Element(s)” (b) state “Current and voltage signals provided to the protective
relays”.
5. Please add a Performance-Based maintenance example for control circuitry, and /or voltage and current
sensing.
Response: Thank you for your comments.
1. This cited reference in the Supplementary Reference Document is present to maintain consistent evidence that maintenance was performed within prescribed
intervals. Please see the NERC Compliance Process Bulletin #2011-001 (“Data Retention Requirements”) for similar guidance.
2. Thank you, the change has been made.
3. The commenter is correct that it is the prime mover that is protected by the Reverse Power relay; however the Standard considers relays (such as Reverse
Power relays) that sense voltage and current are within the scope. Furthermore, Part 4.2.5.1 (Applicability) of the Standard includes Protection Systems for
generator Facilities that are part of the BES including Protection Systems that act to trip the generator either directly or via generator lockout or auxiliary tripping
relays.
4. The column marked Component of Protection System closely aligns with the definition of Protection System as approved by the NERC Board of Trustees and is
included within the Standard itself. The next column (“Includes”) is more explanatory in nature and is intended to give insight on the SDT’s intent.
5. Thank you, the requested changes have been made. Additional Q&A (including one for control circuitry and one for voltage and current sensing devices) have
been added to Section 9.2.
National Grid (1)
Ballot
Comment Affirmative
National Grid suggests that FAQ be added:
1. Regarding Table 2 in the standard, Does a fail-safe “form b” contact that is alarmed to a 24/7 operation
center classify as an alarm path with monitoring?
2. Please add a clarification as part of the FAQ document that defines whether the control circuitry and trip
coil of a non-BES breaker, tripped via a BES protection component, must be tested per Table 1.5.
Response: Thank you for your comments.
1. Thank you, the change has been made. An additional Q&A has been added to Section 15.6.1.
2. Thank you, the change has been made. An additional Q&A has been added to Section 15.3.1.
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Organization
Yes or No
New York Power Authority (1)
Ballot
Comment Affirmative
Question 4 Comment
Comments: We suggest that FAQ be added:
1. Regarding Table 2 in the standard, Does a fail-safe “form b” contact that is alarmed to a 24/7 operation
center classify as an alarm path with monitoring?
2. Please add a clarification as part of the FAQ document that defines whether the control circuitry and trip
coil of a non-BES breaker, tripped via a BES protection component, must be tested per Table 1.5.
Response: Thank you for your comments.
1. Thank you, the change has been made. An additional Q&A has been added to Section 15.6.1.
2. Thank you, the change has been made. An additional Q&A has been added to Section 15.3.1.
Muscatine Power & Water (3)
Ballot
Comment Affirmative
In the “Supplemental Reference and FAQ” document on page 65 there is one area of concern.
In paragraph 4 “…the type of test equipment used to establish the baseline must be used for any future
trending of the cells internal ohmic measurements because of variances in test equipment and the type of
ohmic measurement used by different manufacturer’s equipment.”
While MP&W understands the importance of creating a valid baseline, it is disingenuous to expect the test
equipment to be the same as the manufacturer’s test equipment. For that matter, it would be highly unlikely
the same test equipment would be used over the life of the battery. The expected life of a battery may be in
excess of 15 years in most cases and it would not be probable to expect that the type of test equipment is not
going to change during this period. MP&W suggests changing the wording to read that CONSISTENT test
equipment should be used to provide consistent/comparable results.
Response: Thank you for your comments, the change has been made. The statements concerning types of equipment have been changed per your suggestion to
reflect consistent test data as opposed to exactly the same piece of test equipment.
Florida Municipal Power Agency
(4) (5) (6)
Florida Municipal Power Pool (6)
Ballot
Comment Negative
1. Examples #1, #2 and #3 in Section 7.1 of the Supplementary Reference all indicate that it is a requirement
to “verify all paths of control and trip circuits” every 12 years. As stated, there would be circuits included in
the testing requirement that the SDT did not mean to include in the scope of the Standard (e.g., SCADA
closing circuit.) The statements in the illustrative examples should be changed to “verify all paths in the
control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other
interrupting devices” to be in line with the definition of a Protection System.
2. Section 15.5 of the Supplementary Reference Document states: “It was the intent of this Standard to
require that a test be made of any communications-assisted trip scheme regardless of the vintage of the
technology. The essential element is that the tripping (or blocking) occurs locally when the remote action
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Organization
Yes or No
Question 4 Comment
has been asserted; or that the tripping (or blocking) occurs remotely when the local action is asserted”. The
SDT should reword this statement recognizing that tests performed on communication systems may not be
performed at the same time an entity chooses to perform trip tests on the associated breaker(s). The notion
of “overlapping” can be applied, for instance, by taking an outage on one relay set in a fully redundant
system, initiating a trip signal from the remote end and observing the trip signal locally. All remaining
portions in the local communication-assisted trip paths can then be tested when the local line panel is taken
out of service for maintenance.
Response: Thank you for your comments.
1. Thank you, the change has been made.
2. Thank you, the change has been made.
ITC
No
We agree with the combination of the two. One document with the FAQ’s grouped with the supplemental
topics makes it easier to review the whole topic.
Response: Thank you for your comments.
Central Lincoln
No
The first FAQ under 2.3.1 is incorrect, referencing a FERC informational filing. Included in the filing was a
WECC test that was never approved by the WECC board and is not being used. Using this document as
suggested will get WECC entities into trouble.
Response: Thank you for your comments. There are presently regional differences allowed that may cease to exist once the BES is redefined. The SDT for the
BES Definition (Project 2010-17) is charged with developing a continent-wide BES definition; however, this FERC informational filing is on the public record, and
was part of the basis for FERC Order 743.
Tampa Electric Company
No
Tampa Electric requests further differentiation between BES protection elements and UFLS equipment.
Response: Thank you for your comments. UFLS equipment is presently covered under PRC-008. PRC-005-2 will cover all Protection Systems components
including components used for UFLS. The Standard addresses UFLS and UVLS to the degree that they are installed per NERC Standards, even though entities
may choose to install them on distribution systems. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed
within the Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping non-BES system elements.
Electric Market Policy
No
Santee Cooper
No
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
SPP reliability standard
development Team
No
Tennessee Valley Authority
No
Imperial Irrigation District
No
MRO's NERC Standards Review
Subcommittee
No
The Detroit Edison Company
No
NextEra Energy
No
Western Electricity Coordinating
Council
No
Ingleside Cogeneration LP
No
Farmington Electric Utility System
No
Illinois Municipal Electric Agency
No
Shermco Industries
No
Dominion Virginia Power
No
American Electric Power
No
CPS Energy
No
Indeck Energy Services
No
MidAmerican Energy Company
No
Question 4 Comment
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Organization
NIPSCO
Yes or No
Yes
Question 4 Comment
We used the FAQ Supplemental Reference while reviewing this draft standard and found it useful.
Response: Thank you for your comments.
FirstEnergy
Yes
1. We do not agree with the following wording on page 37 of the reference document: (1) “If your PSMP (plan)
requires more activities then you must perform and document to this higher standard.” and (2) “If your
PSMP (plan) requires activities more often than the Tables maximum then you must perform and document
those activities to your more stringent standard.”
2. We continue to believe that the auditor is required to audit to the standard. If the standard requires
maintenance intervals every 6 years, this is what the auditor should verify. This was also verified in the
recent NERC Workshop at which it was confirmed that “auditors must audit to the standard”.
To this end, we also suggest changes to Requirement R3 as explained in our comments in Question 5.
Response: Thank you for your comments.
1. The SDT respectfully disagrees with the commenter. R1 of the Standard states that “… shall establish a Protection System Maintenance Program (PSMP)…,
and R3 states that “… shall implement and follow its (PSMP)…” Therefore, if an entity has a more stringent PSMP then they must follow their own PSMP. An
example of this might be a case that has an entity with Performance Based Maintenance; this entity could find time intervals between maintenance activities that
are more frequent than are laid out in the Tables. This entity must follow their PSMP. Another example might be an entity that requires CT Saturation tests every
10 years; this is a more stringent requirement than is contained within the minimum maintenance activities of the Standard. Neither the SDT nor any auditor has
any idea why an entity may require more stringent requirements of themselves than the Standard requirements. Even under the present PRC-005-1 an auditor
audits to the entity’s PSMP; a case in point is if an entity PSMP requires relay testing with simulated fault values of voltage and current every year then they are
audited to that requirement (even though PRC-005-1 specifically does not require any particular relay testing and certainly has no time intervals stated). Please
note that FERC Order 693 directs NERC to establish maximum allowable intervals not minimum intervals, and the entity’s program must, at a minimum, conform
to those intervals.
2. The SDT has set no requirements that an entity have a more stringent PSMP than the minimum requirements set out in the Standard, only that any PSMP meet
the minimums laid out within the Standard. But, should an entity have a PSMP that is more stringent then, according to R3, they must maintain to their own more
stringent PSMP.
BGE
Yes
1. The supplementary reference on page 30, under the question beginning “Our maintenance plan requires”
states that an entity is “out of compliance” if maintenance occurs at a time longer than that specified in the
entity’s plan, even if that maintenance occurred at less than the maximum interval in PRC-005-2. But then
on page 35, under the question, “How do I achieve a grace period without being out of compliance”
provides an example of scheduling maintenance at four year intervals in order to manage scheduling
complexities and assure completion in less in less than the maximum time of six calendar years. This is
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Yes or No
Question 4 Comment
conflicting advice. The FAQ /supplementary reference should be revised so that it does imply that an entity
is out-of-compliance by performing maintenance more frequently than required. Avoiding compliance risk is
one reason to do this, but there are other valid motives not directly related to reliable protection system
performance.
2. Testing of PT’s and CT’s (12 year max) is non invasive and convenient to schedule at the same time as
relays (6 year max) just to keep procedures consistent and reduce program administration. Testing of ties
to other TOs or GOs may have to be scheduled more frequently than preferred in order to synchronize
schedules.
Response: Thank you for your comments.
1. There is no conflict, the first commenter-cited PSMP example has language that has no grace-period built in, and the second commenter-cited PSMP example
has language with a built-in grace period. Both cited examples are measurable to a time limit between testing activities.
2. Your observations are correct; an entity may choose to perform activities more often than is specified in the Standard. For that matter, an entity may choose to
perform activities more often than their own PSMP; the entity simply cannot exceed their own PSMP intervals which in turn cannot exceed the intervals in the
Standard.
Pepco Holdings Inc
Yes
The Supplementary Reference and FAQ should be an attachment to the standard (Appendix A) and not just
referenced. If not attached it will not be readily accessible to those that will be using the standard.
Response: Thank you for your comments. The Supplementary Reference and FAQ is referenced in Section F of the standard (which was on Page 9 of the clean
version of the recent posting), in accordance with the Standards Development Process, and will be posted with the standard as “Reference Materials”.
GDS Associates
Yes
The standard should include a footnote indicating this document as reference
Response: Thank you for your comments. This document is addressed within the Standard as a reference document by listing it in Section F (which was on Page
9 of the clean version of the recent posting), in accordance with the Standards Development Process.
ExxonMobil Research and
Engineering
Yes
The SDT should provide notes that reference the sources used for developing the maximum maintenance
intervals utilized in the time-based program, and provide a technical explanation as to why they have not
provided a tolerance band for use with the time-based program. What is the increase in risk owned by an
entity when a protective device is tested at the 6 year and 30 day mark instead of the 6 year mark?
Response: Thank you for your comments. The SDT was tasked to create a standard with maximum time intervals between maintenance activities. Thus the task,
in and of itself, sets the limit as absolute. Where the intervals were set at six years (or any interval for that matter), there was no assessment of risk beyond the
time interval chosen as the absolute. The question always would arise as “Why not an additional thirty days after that?” The reference material cites methodology
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Organization
Yes or No
Question 4 Comment
to determine initial time intervals. The SDT took further care to try to align the initial maintenance intervals with common maintenance schedules like plant outages
and other published guidelines. Please note that the Tables refer to “Calendar Year” for the intervals referenced in the comment; the noted concern would only be
relevant if the entity actually completes the activity at the very end of the calendar year.
US Army Corps of Engineers
Yes
1. The reference material provides a significant insight into the intent of the proposed changes to the
standard. In some cases an interpretation is provided which is not supported by the explicit interpretation of
the standard text. The SDT is encouraged to either attach the reference material to the standard or add
relevant sections to standard as Background. The Background section could reference the Supplemental
Reference & FAQ.
2. The reference material provides more detail indicating that “Voltage & Current Sensing Device circuit input
connections to the protection system relays can be verified by (but not limited to) comparison of measured
values on live circuits or by using test currents and voltages on equipment out of service for maintenance. .
. . . . The values should be verified to be as expected, (phase value and phase relationships are both
equally important to verify).”
This interpretation is not consistent with the text of the standard and would suggest that it be
incorporated into Table 1-3.
Response: Thank you for your comments.
1. This standard is not being developed in a “results-based” format. As you suggest the reference material is listed within the Standard (Section F – Supplemental
Reference Document). The next revision will likely resemble your suggestion.
2. Details within the Supplemental Reference Document are provided as examples and should not be construed as limitations or additional requirements. The
intent of the supplementary information is to spur insight into possible means of satisfying requirements and is not intended to promote a single technical method
of accomplishing tasks.
Luminant
Yes
The document was valuable in understanding PRC-005-2 by providing clarification using practical protective
relay system examples. Below are two comments for further improvement.
1. It would be beneficial if the document could provide additional information for relaying in the high-voltage
switchyard (transmission owned) - power plant (generation owned) interface. While Figures 1 and 2 are
typical generation and transmission relay diagrams, it would be helpful if protective relays typically used in
the interface also be included. For example, a transmission bus differential would remove a generator from
service by tripping the generator lockout.
2. Figures 1 and 2 refer to a “Figure 1 and 2 Legend” table which provides additional information on
qualifications for relay components. Should a footnote be used to point toward Reference 1 (Protective
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Organization
Yes or No
Question 4 Comment
System Maintenance: A Technical Reference) located in Section 16?
Response: Thank you for your comments.
1. There are so many variations possible that it is impractical to try to capture all configurations on a single picture or in a single document. However, for the cited
example - a transmission bus Protection System would be included. All five of the Protection System component types would fall within the Standard including the
trip paths and the electrical test requirements of the generator lockout device.
2. Thank you, a link has been provided to the references.
MISO Standards Collaborators
Yes
The additional documentation seems to be quite large, and the additional content seems to go far beyond
what is necessary for the PRC-005-2 standard. We recommend the SDT lessen the amount of content
provided in the “Supplementary Reference” document.
Response: Thank you for your comments. Details within the Supplemental Reference Document are provided as examples and should not be construed as
limitations or additional requirements. The intent of the supplementary information is to spur insight into possible means of satisfying requirements and is not
intended to promote a single technical method of accomplishing tasks.
Northeast Power Coordinating
Council
Yes
Suggest that to FAQ be added:
1. Regarding Table 2 in the standard, does a fail-safe “form” contact that is alarmed to a 24/7 operation
center qualify as an alarm path with monitoring?
2. Add a clarification as part of the FAQ document that defines whether the control circuitry and trip coil of a
non-BES breaker, tripped via a BES protection component, must be tested as per Table 1.5.
Response: Thank you for your comments.
1. Thank you, the change has been made. An additional Q&A has been added to Section 15.6.1.
2. Thank you, the change has been made. An additional Q&A has been added to Section 15.3.1.
Georgia Transmission
Corporation
Yes
See comments for item 1 and continue clarification where we could include high side or distributed
interrupting devices, exchange nomenclature removing distribution breaker and adding distributed interrupting
device or non-BES equipment.
Response: Thank you for your comments. Circuit interrupting devices that only participate in a UFLS or UVLS scheme are excluded from the tripping requirement,
but not from the circuit test requirements. The “non-BES equipment interruption device” phrase has been inserted as suggested.
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PNGC Comment Group
Yes or No
Yes
Question 4 Comment
Section 9.2 (copied below) indicates that small entities can utilize Performance-Based PSMP if they
aggregate with other entities. Does this section indicate that only a parent entity with individually owned
components can aggregate, or can independent entities under a G&T aggregate? In other words, individual
DP/LSE/TOs with different audits. Can they aggregate under a common PSMP for performance based
maintenance?
9.2 Frequently Asked Questions: I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity? Multiple asset owning entities may aggregate their individually
owned populations of individual Protection System components to create a segment that crosses ownership
boundaries. All entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance intervals and
criteria), for which the multiple owners are individually responsible with respect to the requirements of the
Standard. The requirements established for performance-based maintenance must be met for the overall
aggregated program on an ongoing basis. The aggregated population should reflect all factors that affect
consistent performance across the population, including any relevant environmental factors such as
geography, power-plant vs. substation, and weather conditions.
Response: Thank you for your comments.
Two entities in such a shared program must have populations of components that can be aggregated and the PSMP for those components are the same between
the two entities. Thus the combined entities can show total populations, total numbers of components tested and total failures found. The combined entities would
thus be forced to follow the same intervals, test procedures and statistical analysis. There would have to be cooperation between entities but in the end the
outcome would be the same as if the PBM process were applied to a single entity. There is no inherent advantage or disadvantage to multiple entities cooperating
in such a manner. The SDT intends that small entities with small populations of equipment have the same access to PBM as the larger entities.
FHEC
Yes
It is unclear what compliance obligations may be created or clarified with the FAQ. It is a good explanatory
document and a helpful reference, but the Standard should speak for itself as it relates to what it takes to
achieve compliance.
Response: Thank you for your comments. The Standard is the only “mandatory and enforceable” document. Details within the Supplemental Reference
Document are provided as examples and should not be construed as limitations or additional requirements. The SDT intends that it be posted as a Reference
Document, accompanying the standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc, and is not to include
explanatory information like that included in the Supplementary Reference Document. The Supplementary Reference FAQ will be revised in the course of the
revision process of the standard.
Western Area Power
Yes
Can the SDT add a better definition or clarification of ”Calendar Year” as it pertains to PRC-005-2 and provide
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Yes or No
Administration
Question 4 Comment
examples or parameters of Compliance with the Standard requirements and tables? Calendar Year is
explained in various details within Pages 35-Pages 37 of the Supplementary Reference and FAQ. This
important attribute of a TBM or TBM/CBM combination program is not easily found in the Table of Contents or
section sub-headings.
Response: Thank you for your comments. Per your suggestion, a “What is a Calendar Year?” Q&A has been added to the front end of Section 7.1.
Duke Energy
Yes
Along the lines of what we have suggested in our comment to Question #1 above, we believe it would make
compliance more certain if selected language from the Supplementary reference could be incorporated into
the standard, either directly in requirements, or in footnotes.
Response: Thank you for your comments. The addition that you suggest is properly considered application guidance; the SDT has been advised that this
information is not to be included within the standard, and that it is appropriately included in separate reference materials.
Ameren
Yes
1. Comments: Supplement FAQ 12.1 on page 51 final sentence states that documentation for replaced
equipment must be retained to prove the interval of its maintenance. We oppose this because: the
replaced equipment is gone and has no impact on BES reliability; and such retention clutters the data base
and could cause confusion. For example, it could result in saving lead acid battery load test data beyond
the life of its replacement. Since BES Element protection is the objective, we suggest a compromise of
keeping the evidences of last test for the removed equipment and using that with the equivalent function
replacement equipment commissioning or in-service date to prove interval.
2. Clarify p17 Table 1-4(e) interval meaning. We think this means we need to verify the Station dc supply
voltage on 12 calendar year interval if unmonitored, or no periodic maintenance if monitored as stated.
3. In Supplement examples on pp 22-23, replace “Instrumentation transformers” with “Verify that current and
voltage signal values are provided to the protective relays” to be consistent with Table 1-3.
4. Remove “Reverse power relays” from the sample list of generator devices in Supplement p31 because
reverse power relays are applied for mechanical protection of the prime mover, not electrical protection of
the generator.
5. Revise Supplement Figure 1 & 2 Legend p83 to align with Draft 4 (a) state “Protective relays designed to
provide protection for BES Element(s)”. (b) state “Current and voltage signals provided to the protective
relays”
6. Please add a Performance-Based maintenance example for control circuitry, and /or voltage and current
sensing.
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Yes or No
Question 4 Comment
Response: Thank you for your comments.
1. This cited reference in the proposed Standard is present to maintain consistent evidence that maintenance was performed within prescribed intervals.
2. The SDT agrees.
3. Thank you, the change has been made
4. The commenter is correct that it is the prime mover that is protected by the Reverse Power relay, however the Standard considers relays (such as Reverse
Power relays) that sense voltage and current as within the scope. Furthermore, Part 4.2.5.1 of the Standard states that Protection Systems for generator Facilities
that are part of the BES including Protection Systems that act to trip the generator either directly or via generator lockout or auxiliary tripping relays
5. The column marked Component of Protection System closely aligns with the definition of Protection System as approved by the NERC Board of Trustees and is
included within the Standard itself. The next column (“Includes”) is more explanatory in nature and is intended to give insight on the SDT intent
6. Thank you, the changes have been made. Additional Q&A have been added to Section 9.2.
Xcel Energy
Yes
1) On page 65, paragraph 4, of the ”Supplemental reference and FAQ” document, it states:”the type of test
equipment used to establish the baseline must be used for any future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement used by
different manufacturer’s equipment.” While we understand the importance of creating a baseline, it is not
feasible to expect the test equipment be the same as the manufacturer’s test equipment or even the same
test equipment over the life of the battery. The expected life of a battery may be in excess of 20 years
and it is not feasible to expect that the type of test equipment will not change during this period.2) A FAQ
to clarify in scope protection systems for variable energy resource facilities (wind, solar, etc) would be
very helpful.
2) Does paragraph 4.2.5.3 “Facilities” imply that the only protection system associated with a wind farm that
is considered in scope for PRC-005-2 is that for the aggregating transformer? If other protection systems
associated with a wind farm are in scope, please clarify which systems would be in scope for PRC-005-2.
For example, a typical wind farm in our system might have 30-33, 1.5MVA windmills connected to one
34.5 KV collecting feeder circuit for a total of roughly 50 MVA per collecting feeder. 4 of these 50 MVA
collecting feeders are tied via circuit breakers to a low side 34.5 KV bus which in turn is connected via a
low side breaker to aggregating step up transformer which then connects to the BES transmission
system. Obviously per paragraph 4.2.5.3, the protection system for the aggregating step up transformer
is in scope. What about the protection system for the transformer low side 34.5 KV breaker - serving 200
MVA of aggregate generation? What about the protection system of each individual 34.5 KV aggregating
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Yes or No
Question 4 Comment
feeder - 50 MVA of aggregate generation? What about the”protection system” for each individual 1.5
MVA windmill? An FAQ on this topic would be very helpful.
Response: Thank you for your comments.
1. Thank you for your suggestion; the paragraph cited has been changed.
2. Clause 4.2.5.3 states specifically that the Protection Systems on the aggregating transformer are included. The SDT has not specifically included other
equipment, but, depending on what, specifically, is defined to be BES for these facilities, either within current Regional definitions or within the emerging NERC
definition, other equipment may be drawn in.
Alliant Energy
Yes
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
5. If you have any other comments on this Standard that you have not already provided in response to the prior
questions, please provide them here.
Summary Consideration: Several commenters were concerned that an entity has to be “perfect” in order to be compliant;
the SDT responded that NERC Standards currently allow no provision for any degree of non-performance relative to the
requirements.
Several commenters continued to insist that “grace periods” should be allowed. The SDT continued to respond that grace
periods would not be measurable.
Several comments were offered, suggesting that PRC-005-2 needs to be consistent with the interpretation in Project 2009-17,
now implemented as PRC-005-1a, and the SDT modified Applicability 4.2.1 for better consistency with the interpretation 4.2.1
(Protection Systems that are installed for the purpose of detecting faults on BES Elements (lines, buses, transformers, etc).
Many comments were offered objecting to the 3-calendar-month intervals for station dc supply and communications systems,
and suggesting that a 3-calendar-month interval requires entities to schedule these activities for 2-calendar-months in order to
assure compliance. The SDT did not modify the standard in response to these comments, and responded that the intervals
were appropriate, and that entities should be able to assure compliance on a 3-calendar-month schedule by using program
oversight. The “Supplementary Reference and FAQ” document was augmented with additional explanatory text.
Several comments were offered questioning various aspects of Applicability 4.2.5.4 (generation auxiliary transformers). No
changes were made in response to these comments, and responses were offered illustrating why these transformers are
included.
Many (essentially identical) comments were offered, questioning the propriety of including distribution system Protection
Systems, almost all related to UFLS/UVLS. The SDT explained that these Protection Systems are appropriate to be included for
consistency with legacy standards PRC-008, PRC-011, and PRC-017, and noted that their inclusion is consistent with Section
202 of the NERC Rules of Procedure.
Several comments were offered, objecting to the 6-calendar-year interval for lockout and auxiliary relays. The SDT declined to
adopt the requested changes, and noted that these “electromechanical” devices with “moving parts” share failure mechanisms
with electromechanical protective relays and that the intervals should be identical.
Several comments were offered regarding Maintenance Correctable Issues, and resulted in modifying this definition to be
“…such that the deficiency cannot be corrected during the performance of the maintenance activity …”
Assorted additional comments were offered by individual commenters (most of them similar to comments on previous
postings), which resulted in responses similar to those offered during previous posting periods.
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Yes or No
Question 5 Comment
Consolidated Edison Co. of New
York (1) (3) (5)
Ballot
Comment Affirmative
We recommend that the drafting team recognize that a “fail safe” or “self-reporting” alarm design serves as an
acceptable alternative to periodic testing. This “fail safe” or “self-reporting” alarm design is equivalent to
continuous testing the alarm. When the alarm circuit fails the alarm is set to “alarm on” and automatically
notifies the control center, initiating a corrective action.
Response: Thank you for your comments. The application discussed seems to the SDT to be an effective method of “monitoring the monitoring circuit”. (See Table
2, last row with heading “Alarm Path with monitoring.”)
Ameren Services (1)
Ballot
Comment Affirmative
(1) Need some tolerance – require 99% of components to meet R3. Measure M3 on page 5 should apply to
99% of the components. “Each … shall have evidence that it has implemented the Protection System
Maintenance Program for 99% of its components and initiated….” PRC-005-2 unrealistically mandates
perfection without providing technical justification. A basic premise of engineering is to allow for reasonable
tolerances, even Six Sigma allows for defects. Requiring perfection may well harm reliability in that valuable
resources will be distracted from other duties.
(2) Define BES perimeter in accordance with Project 2009-17 Interpretation. Facilities Section 4.2.1 “or
designed to provide protection for the BES” needs to be clarified so that it incorporates the latest Project
2009-17 interpretation. The industry has deliberated and reached a conclusion that provides a meaningful
and appropriate border for the transmission Protection System; this needs to be acknowledged in PRC005-2 and carried forward. The BOT adopted this 2/17/2011.
(3) Battery inspection every 4 months is sufficient. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for an
interval that might extend past three calendar months due to storms and outages must set a target interval
of two months thereby increasing the number of inspections each year by half again. This is unnecessarily
frequent. We suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar
months.
Response: Thank you for your comments.
1. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation.
2. The referenced interpretation relates to a quasi-definition of “transmission Protection System”, and in the context of the approved PRC-004-1 and PRC-005-1,
presents a consistent context for this term. However, the interpretation was constrained to not introducing any requirements or applicability not already included
within the approved standards. PRC-005-2 does not use this term, and expands upon the applicability in the interpretation to address what seems to the SDT to
be an appropriate applicability for PRC-005-2. The applicability of the interpretation to PRC-004-1 is not affected by PRC-005-2.
3. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
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that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the activity was performed.
Xcel Energy
1) Regarding “Facilities” paragraph 4.2.5, we are in agreement with the elimination from scope of system
connected station service transformers for those plants that are normally fed from a generator connected
station service transformers. However, in the cases where a plant does not have a generator connected
station service transformer such that it is normally fed from a system connected station service transformer,
is it still the drafting team’s intent to exclude the protection systems for these system connected auxiliary
transformers from scope even when the loss of the normal (system connected) station service transformer
will result in a trip of a BES generating facility? If the end result of the trip of the primary station service
transformer is a trip of a BES generating facility, it would be more consistent to include the protection
system for that transformer as in scope - whether it be connected to the system or to the generator.
2) We recommend the SDT consider an interval of 12 calendar years for the component in row 3, of Table 1-5
on page 19 of the standard. The maximum maintenance interval for “Electromechanical lockout and/or
tripping devices which are directly in a trip path from the protective relay to the interrupting device trip coil”
should be consistent with the “Unmonitored control circuit” interval which is 12 calendar years. In order to
test the lockout relays, it may be necessary to take a bus outage (due to lack of redundancy and associated
stability issues with delayed clearing). Increasing the frequency of bus outages (with associated lines or
transformers) will also increase the amount of time that the BES is in a less intact system configuration.
Increasing the time the BES is in a less intact system configuration also increases the probability of a low
frequency, high impact event occurring. Therefore, the Maximum Maintenance Interval should be 12 years
for lockout relays. We believe that, as written, the testing of “each” trip coil and the proposed maintenance
interval for lockout testing will result in the increased amount of time that the BES is in a less intact system
configuration. We hope that the SDT will consider these changes.
Response: Thank you for your comments.
1. The SDT does not intend that the system-connected station auxiliary transformers be included in the Applicability. The generator-connected station service
transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
2. The SDT believes that electromechanical devices share performance attributes (and failure modes) with electromechanical relays and need to be tested at
similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
Northeast Power Coordinating
Council, Inc. (10)
Ballot
Comment -
A concern exists that an entity with a very strict PSMP with intervals that are much shorter than neighboring
entities or the standard will rewrite their PSMP and loosen their requirements to allow postponed maintenance
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up the maximum specified in the standard. This standard, as written penalizes non-adherence to more
stringent and better PSMPs and may inadvertently driving entities to the least common denominator. I am
hopeful that Phase 2 will address this issue.
Response: Thank you for your comments. The Standard is defining maximum allowable intervals and minimum acceptable activities for a PSMP. Entities are
empowered to develop PSMPs that exceed these requirements if they determine such a PSMP to be necessary.
GDS Associates
Requirement R1
1.
Suggest changing the language in R1.2 to read “Identify which maintenance method such as the timebased, performance-based (detailed in PRC-005 Attachment A), or a combination of the two would be
appropriate to be used for each type of Protection System component. Based upon their own constructive
type, all batteries associated with the station DC supply shall be included in a time-based maintenance
program consistent with Table 1-4(a) through Table 1-4(f)”
2. Suggest changing the language for the first paragraph in R1.3 to read “Establish the occurrences
associated with the time-based maintenance programs up to but no less than the time intervals specified
in Table 1-1 through Table 1-5, and Table 2. Consequently, include all applicable monitoring attributes
and related maintenance activities characteristic to each type of Protection System component specified
in Table 1-1 through Table 1-5, and Table 2”
3. Suggest adding a sub-requirement such as R1.5 to read “Include documentation of maintenance, testing
interval and their basis and a summary of testing procedures”
Requirement R3
4. The redline version of the standard is misleading. Requirement R3 is crossed out and then replacing
requirement R7 which is also crossed out.
5. The wording “initiates resolution of any identified maintenance correctable issues” it is vague. What a
responsible entity should do to become compliant with this requirement? We also believe that is not
sufficient to just “initiate resolution”; the standard should call for corrective actions to be performed within
the maintenance time interval.
6.
The “identified maintenance correctable issues” may not be a proper choice. The name of the new term
suggests that is about issues that can be corrected during maintenance, while the definition from the
clean version explains otherwise?
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Additional requirement
7. Suggest adding a requirement to read “The Transmission Owner, Generator Owner, and Distribution
Provider shall provide documentation of its PSMP and implementation to the appropriate Regional
Reliability Organizations on request (within 45 calendar days).”
8. Add measure for the evidence on documenting the PSMP from the additional requirement
General comments and notes
9. If you own electro-mechanical relays and microprocessor based relays is there a need to keep two
different logs for these?
10. On table 1-4 the generator CTs should be tested earlier than the suggested 12 years due to exposure of
continuous mechanical stress
11. Clarify table 1-5 to address verification tests on different circuits. Suggest that the Table 1-5 to read
“Complete a terminal test of unmonitored circuitry” instead of the “Unmonitored control circuitry
associated with protective functions”
12. In what instances (what extent) would the standard allow using the real time breaker operation to be
considered maintenance as applicable to different types of relays involved in the real time event? This is
briefly emphasized under TBM at paragraph 5.1 from the supplementary reference document?
Response: Thank you for your comments.
1. It is not enough for an entity to determine if time-based, performance-based, or a combination of the two would be “appropriate”; the entity must specify which
method is being used, so that it is clear to both the entity and an auditor if R2 and Attachment A apply.
2. The SDT has considered your comment and has determined that the text currently within the requirement is appropriate.
3. The requirement that you suggest is identical to one of the most troublesome requirements from the approved PRC-005-1. By providing Tables 1-1 through 1-5,
as well as Table 2, the SDT is establishing maximum allowable intervals as well as minimum required activities, and thus replacing this PRC-005-1 requirement
with a more prescriptive one. If an entity chooses to extend the intervals and alter the activities by using monitoring, or to apply performance-based maintenance
per R2 and Attachment A, the additional requirements related to those choices effectively establish a requirement such as you suggest.
4. The red-lining tools in Microsoft Word can sometimes be misleading, but the red-line is provided in an effort to illustrate the changes made to the document. We
recommend that the entity use the “clean” version in order to see the final resulting text.
5. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even
several years) to complete effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with
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other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these
more extended activities to “correct the maintenance correctable issue”; therefore, the SDT has opted to require only that the entity initiate correction of
maintenance correctable issues within PRC-005-2 and rely on the operating focus on the degraded system to ensure that they are completed. The associated
measure provides examples of relevant documentation. The definition of maintenance correctable issue has been revised to be clearer.
6. The phrase from the entire sentence states “initiate resolution of any identified maintenance correctable issues”. This is to ensure follow-up for items which
cannot be corrected during maintenance. The definition of maintenance correctable issue has been revised to be clearer.
7. No direct BES reliability purpose is supported by “on request documentation of a program”; this has value only for monitoring compliance. Additionally,
Compliance Enforcement Authorities are empowered by the NERC Rules of Procedure to request information demonstrating compliance at any time.
8. No additional measure is necessary, as the suggested requirement is unnecessary.
9. The SDT is not specifying how the maintenance records are maintained relative to the Standard. It is up to the entity to determine how to best document the
detailed implementation of their program.
10. Instrument transformers are addressed in Table 1-3, not Table 1-4. Entities are allowed to maintain components more frequently than required within the
Standard if they feel it necessary.
11. The SDT does not believe that the suggested text adds clarity to the standard. Please see Section 15.3 of the Supplementary Reference Document for
additional discussion.
12. The SDT suggests that observed in-service performance may be usable for any activities that are clearly verified by the in-service performance.
Liberty Electric Power LLC
Apologies to the drafting team for submitting this with the ballot, repeated here to insure the comments are
captured and addressed. While the SDT has done a very good job at responding to the most objectionable
parts of the previous version, there are still a number of issues which makes the standard problematic.
1. The standard introduces the term "initiate resolution". This is an interpretable term, and has the potential for
an auditor and an entity to disagree on an action. Would issuing a work order be considered "initiating
resolution"? What if the WO had a completion date many years into the future? I would suggest adding the
term to the list of definitions which will remain with the standard, and defining it as "performing any task
associated with conducting maintenance activities, including but not limited to issuing purchase orders,
soliciting bids, scheduling tasks, issuing work requests, and performing studies".
2. Some clarity is needed to differentiate system connected and generator connected station service
transformers. A statement that a station service transformer connected radially to the generator bus is
considered a system connected transformer if the transformer cannot be used for service unless connected
to the BES.
3. The "bookends" issue, brought up in the prior round of comments, still exists. Although the SDT rightly
notes a CAN has been issued regarding bookends, the CAN covers the documentation for system
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components that entities were required to self-certify to on June 18, 2007. PRC-005-2 adds additional
components to the protection system scheme which were not part of that certification, and has the potential
to put entities into violation space due to a lack of records for those components. The SDT should add to
M3 a statement that entities may demonstrate compliance with the standard by demonstrating that required
activities took place twice within the maximum maintenance interval -starting from the effective date of the
standard - for all components not listed in PRC-005-1.
Response: Thank you for your comments.
1. The SDT believes that issuing a work order would satisfy this requirement. M3 presents several examples of relevant evidence. The SDT has considered that,
while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even several years) to complete
effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with other standards. The SDT
is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these more extended activities to
“correct the maintenance correctable issue”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues and
rely on the operating focus on the degraded system to ensure that they are completed. The definition of maintenance correctable issue has been revised to be
clearer.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
3. The Implementation Plan specifies that entities may implement PRC-005-2 incrementally throughout the intervals specified, and that they shall follow their
existing program for components not yet implemented. The SDT believes that the “bookends” issue to which you refer is therefore addressed. Also, please see
Compliance Process Bulletin 2011-001 for a discussion about data retention.
Central Lincoln
As we stated two ballots ago, we continue to believe that IEEE battery standard quarterly maintenance was
never intended to be performed at a maximum interval of three months. Instead, three months is a target
value that might be extended due to emergency. We continue to support a maximum interval of four months
for these activities.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the
activity was performed.
Tampa Electric Company
1. As written PRC-005-2 would have a very significant impact on Tampa Electric Company with very little
reliability benefit. For the testing of the DC control circuits Tampa Electric would need to remove from
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service each BES element (circuit, bus, transformer, breaker) and perform an R&C checkout somewhat
equivalent to what Tampa Electric does for new construction. That process would have to be repeated no
less often than every six years. The testing of DC control circuits to the level described / required in the
proposed standard in an energized station is a very risky proposition. Even though an element can be
taken out of service for testing, the DC control circuits are often interconnected for functions such as
breaker failure, bus and transformer lockouts etc. It is very easy to accidentally trip other in service
equipment while doing this testing. Another concern is getting outages on equipment to perform the
proposed testing.
2. Tampa Electric believes that there is an unnecessary expansion of the scope of equipment covered by the
proposed PRC-005-2 standard into the distribution system related to UVLS and UFLS. Currently, PRC-0051 includes batteries, instrument transformers, DC control circuitry and communications in addition to the
relays for BES protection systems. PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether
non-relay components are included in those standards. The proposed PRC-005-2 includes the non-relay
components into UFLS and UVLS. The problem is, for UFLS and UVLS, the non-relay components are
mostly distribution class equipment; hence, the result of this version 2 standard will be inclusion of most
distribution class protection system components into PRC-005-2. This is a huge expansion of the scope of
equipment covered by the proposed standard with negligible benefit to BES reliability.
3. In addition, testing of protection systems on distribution circuits is difficult for distribution circuits that are
radial in nature. In addition, non-relay protection components operate much more frequently on distribution
circuits than on transmission Facilities due to more frequent failures due to trees, animals, lightning, traffic
accidents, etc., and have much less of a need for testing since they are operationally tested.
4. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
5. Tampa Electric’s Energy Supply Department has the following comment / question regarding Data
Retention: For Requirement R3 R2 and Requirement R4R3, the Transmission Owner, Generator Owner,
and Distribution Provider shall each keep documentation of the two most recent performances of each
distinct maintenance activity for the Protection System components, or all performances of each distinct
maintenance activity for the Protection System component since or to the previous scheduled audit date,
whichever is longer. If all of the data which the proposed PRC-005-2 standard requires to be collected is
not be available or kept for the prescribed period of time, how does a registered entity comply with the
required data retention?
Response: Thank you for your comments.
1. Entities must employ processes and training on how to best manage risk . Not performing DC control circuit verification of protection functions is a risk to the
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reliability of the BES.
2. Section 202 of the NERC Rules of Procedure define “Reliability standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition. The SDT notes that several Table entries for
components that are used only for UFLS or UVLS involve fewer activities and/or longer intervals than for other similar components for generic Protection Systems.
3. The requirements related to UFLS and UVLS, which are commonly applied on non-BES equipment, are less involved than those for other Protection System
equipment in recognition of the observations by the commenter.
4. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
5. The stated data retention period is consistent with what auditors are expecting (per the SDT’s experience), and is also consistent with Compliance Process
Bulletins 2011-001 and 2009-05. The entity is urged to assure that data is retained as specified within the Standard.
American Transmission
Company, LLC
1. Change the text of Standard PRC-005-2 - Protection System Maintenance Table 1-5 on page 19, Row 1,
Column 3 to:
”Verify that a trip coil is able to operate the circuit breaker, interrupting device, or mitigating device.”
Or alternately, ”Electrically operate each interrupting device every 6 years”
Trip coils are designed to be energized no longer than the breaker opening time (3-5 cycles). They are
robust devices that will successfully operate the breaker for 5,000-10,000 electrical operations. The most
likely source of trip coil failure is the breaker operating mechanism binding, thereby preventing the breaker
auxiliary stack from opening and keeping the trip coil energized for too long of a time period. Therefore,
trip coil failure is a function of the breaker mechanism failure. Exercising the breakers and circuit switchers
is an excellent practice. We would encourage language that would suggest this task be done every 2
years, not to exceed 3 years. Exercising the interrupting devices would help eliminate mechanism binding,
reducing the chance that the trip coils are energized too long. The language as currently written in table 1-5
row 1 will also have the unintentional effect of changing an entities existing interrupting device maintenance
interval (essentially driving interrupting device testing to a less than 6 year cycle).
2. Change the text of Standard PRC-005-2 -Protection System Maintenance Table 1-5 on page 19, Row 3,
Column 2 to:
“12 calendar years”
The maximum maintenance interval for “Electromechanical lockout and/or tripping devices which are
directly in a trip path from the protective relay to the interrupting device trip coil” should be consistent with
the “Unmonitored control circuit” interval which is 12 calendar years. In order to test the lockout relays, it
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may be necessary to take a bus outage (due to lack of redundancy and associated stability issues with
delayed clearing). Increasing the frequency of bus outages (with associated lines or transformers) will also
increase the amount of time that the BES is in a less intact system configuration. Increasing the time the
BES is in a less intact system configuration also increases the probability of a low frequency, high impact
event occurring. Therefore, the Maximum Maintenance Interval should be 12 years for lockout relays.ATC
recognizes the substantial efforts and improvements to PRC-005-2 that have been made and appreciate
the dedicated work of the SDT. We appreciate the removal of Requirement R1.5 and R4 and other
clarifications from draft 3.
3. ATC’s remaining concern for PRC-005-2 is with definition and timelines established in Table 1-5. ATC
believes that, as written, the testing of “each” trip coil and the proposed maintenance interval for lockout
testing will result in the increased amount of time that the BES is in a less intact system configuration. ATC
hopes that the SDT will consider these changes.
Response: Thank you for your comments.
1. The SDT considers it important to verify that each breaker trip coil has indeed operated within the established intervals. While breakers may be operated much
more frequently at times (and allow the entity to document these operations to address this activity), other breakers may not be called on to operate for many
years.
2. The SDT believes that electromechanical devices share performance attributes (and failure modes) with electromechanical relays and need to be tested at
similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
3. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.
Tri-State G & T Association, Inc.
(3)
Ballot
Comment Affirmative
1: Section A.4.2. They are referencing Protection Systems as if they are Facilities in the Applicability section.
Facilities are BES Elements, but Protection Systems are not. That needs to be modified somehow. Perhaps
the drafting team needs to add another category under Applicability entitled “Protection Systems” and then
list which types are included.
2: Maintenance Correctable Issue - This definition seems to be more of a Maintenance Non-Correctable Issue
since it can only be resolved by follow-up corrective action. Suggest changing the term.
3: Change Definitions as indicated below:
Segment - Protection System components that are identical or share common elements. Consistent
performance is expected across the entire population of a Segment. A Segment must contain at least sixty
(60) individual components in order to be considered for inclusion in a performance-based PSMP
Component -An individual piece of equipment included in the definition of a Protection System., Entities are
allowed some latitude to designate their own definitions of a Component. An example of where the entity
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has some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three-phase set of such devices or
a single device as a single Component.
4: M1 - Why is the document necessary to be “current or updated?” Eliminate “or updated.”
5: The Applicability section needs to be changed, regardless of whether it has been discussed before.
Protection Systems are not Facilities.
Response: Thank you for your comments.
1. The standard template allows for two separate sections within Applicability, “Entities” and “Facilities”. The listing under Facilities is describing the applicable
facilities to which the Protection Systems are applied, clarified further to indicate that only the Protection Systems on those Facilities are relevant.
2. The definition of maintenance correctable issue has been revised to be clearer. Please see Section 4.1 of the Supplementary Reference Document for
additional discussion. The revised definition is:
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
3. The SDT does not believe that your suggested changes add clarity.
4. M1 has been modified as you suggest.
5. The standard template allows for two separate sections within Applicability, “Entities” and “Facilities”. The listing under Facilities is describing the applicable
Facilities to which the Protection Systems are applied, clarified further to indicate that only the Protection Systems on those Facilities are relevant.
Progress Energy
Comments on Draft Standard
1. Table 1-1, 2nd row, 2nd bullet: The comment “(see Table 2)” does not apply to this bullet, but applies to the
first bullet.
2. Table 1-3, 2nd row: Need to add “(See Table 2).”
Comments on Implementation Plan
1. Section 3a states that “The entity shall be at least 30% compliant on the first day of the first calendar
quarter 2 calendar years following applicable regulatory approval”
If regulatory approval occurs on January 31, 2012, does this mean that the entity has until December
31, 2014 to be 30% compliant? It might be beneficial to provide an example explaining “calendar year.”
Comments on Supplementary Reference
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1. Table of Contents does not list Section 15.4
2. Page 54, last paragraph, last sentence: “advances that are may be coming”
3. Page 65, 5th paragraph: VLRA should be VRLA
4. Page 67, 4th paragraph, 4th sentence: “typically looking for on the plates”
5. Page 69, 4th paragraph, last sentence: “Grounds because to of the possible”
6. Page 69, 5th paragraph, 2nd sentence: “For example, to do I need”
7. Page 70 5th paragraph, 5th sentence: “A manufacturer of”
8. Page 70 5th paragraph, 6th sentence: “by a third manufacturer’s equipment”
9. Page 71, first line: “(impedance, conductance, and resistance)”
Response: Thank you for your comments.
Draft Standard Comments
1. The Table has been modified as you suggest.
2. The Table has been modified as you suggest.
Implementation Plan Comments
1. The Implementation Plan has been modified for clarity. For the cited example with regulatory approval on January 31, 2012, the entity must be 30% compliant
on the first day of the first calendar quarter 24 months following regulatory approvals. Hence, the entity must be 30% compliant on April 1, 2014.
Supplemental Reference Document Comments
1. Changed per your suggestion.
2. Changed per your suggestion.
3. Changed per your suggestion.
4. Changed per your suggestion.
5. Changed per your suggestion.
6. Changed per your suggestion.
7. Changed per your suggestion.
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8. Changed per your suggestion.
9 Changed per your suggestion.
Dominion Virginia Power
Comments: IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not
maximums. An entity wishing to avoid non-compliance for an interval that might extend past three calendar
months must implement a policy of two months with one month of grace period thereby increasing the number
of inspections each year by half again. This is unnecessarily frequent. We suggest changing the maximum
interval for battery inspections to 4 calendar months. For consistency, Dominion suggests that all battery
maintenance intervals expressed as 3 calendar months be changed to 4 calendar months.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the
activity was performed.
Santee Cooper
Comments:
1. Santee Cooper does not agree with the expansion of the UFLS and UVLS requirements to include the dc
supply. We understand that, in the previous consideration of comments, it is stated that “For UFLS and
UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat
constrained relative to similar activities for Protection Systems in general.” In the table, the requirement for
dc supply for UFLS is to verify the station dc supply voltage when the control circuits are verified, which
could be 6 or 12 years. It seems like the restraint shown in the requirement, if an indication of the level of
need for the verification, is of a much longer timeframe than what would actually happen in the typical
operation of a distribution system. Therefore, proof of this verification seems to be of minimal value
compared to the extra documentation required due to this now being an auditable maintenance activity.
2. We also agree that maintenance activities with fast intervals, especially the 3 month ones, should be
adjusted to 4 months to allow for the actual interval the entities use to be 3 months. Having the
requirement at 3 months forces the utilities to schedule even faster (such as every month or 2 months) to
ensure compliance.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure define “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
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2. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the activity was performed.
The Detroit Edison Company
1. Countable Event - This definition should be clarified. As it stands, it appears that if a technician were to
adjust the settings on an electromechanical relay - even if it were not outside of the entity's acceptable
tolerance - it would need to be classified as a countable event. I would recommend that the definition be
limited to repairing or replacing a failed component during the maintenance activity. These activities would
address conditions that would potentially cause a Protection System misoperation (either a failure to trip or
an unintentional trip). Routine maintenance activities to bring component test values back within tolerance
should be excluded from the definition of a Countable Event. These activities are performed to keep the
protection systems performance at its most ideal state. In addition, the definition as stated appears to
classify battery maintenance activities such as cleaning corrosion, adding water, or applying an equalize
charge, as countable events. If this is the intent, I disagree. These are activities that are expected to occur
on a regular, routine basis due to the chemical properties of the battery (as described at length in the
Supplementary Reference). As such, they should also not be classified as countable events.
2. Table 1-1 and Table 1-5 Based on experience with DECo equipment, a 6 year interval for testing monitored
relays and performing tests on the breaker trip coil is substantially shorter than required. Currently, the
interval for both is 10 years. This interval lines up both with the Transmission Owner's interval for relay
maintenance as well as the maintenance interval for the associated current interrupting devices. I would
recommend that these intervals be extended, at minimum, back to the 7 year interval proposed in Draft 2 if not longer.
3. Table 1-4 (a, b, c, e) - Station dc supply using any type of battery recommend that the maintenance activity
to "Verify: Station dc supply voltage" be clarified to state that the voltage should be measured at the
positive and negative battery terminals. Until you get to page 72 of the Supplementary Reference, you do
not know if this means to check the battery voltage or the bus voltage. The "Station dc supply" could refer
to the entire dc system. It needs to be made clear in the table that you are referring to the battery.
4. Also, I noticed that there is no longer a requirement to measure individual cell voltages. I was wondering if
you could explain the rationale behind that. Checking for voltages that are out of specification in individual
cells helps to identify weak cells that may need to be replaced, if corrective action taken on them does not
improve their condition. Individual cell voltage readings, along with ohmic readings, have been an industry
standard that I believe many, if not most, companies adhere to.
5. Table 1-4 (a, b, c, d)I recommend eliminating the 3 month requirement. We have found annual inspections
to be sufficient in catching problems early enough to take corrective action. Page 30 of the Supplementary
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Reference states that the SDT believes that routine monthly inspections are the norm. While this may be
the case at manned stations, it is not at unmanned stations. The amount of paperwork that would be
required to demonstrate compliance is overwhelming and would be an immense burden. I have seen your
suggestion in past draft comments of the same nature that if we don't want to do the 3 month inspections,
then we should utilize more advanced monitoring. This is not something that can be implemented in a short
time frame. It would take years to put all of that technology in place, and is rather cost prohibitive.
Furthermore, some of the monitoring technologies that would enable you to forgo the 3 month requirement
do not exist yet (to my knowledge). I recommend keeping with the 18 month requirement. If that seems
too long, based on past experience I think a 12 month requirement would suffice.
6. Table 1-4 (c) I propose keeping the option to evaluate ohmic values to baseline.
7. Table 1-4 (a, b) For the requirement to evaluate the ohmic values to baseline, is a checkbox stating that
you did this sufficient, or would a report/graph/etc listing the actual baseline and current value be required?
8. Table 1-4 (f) The first attribute is regarding high and low voltage monitoring and alarming of the battery
charger voltage to detect charger overvoltage and charger failure. Would a low voltage alarm combined
with high voltage shutdown (but not a high voltage alarm) meet this requirement? The high voltage
shutdown will shut the charger down in a high voltage condition, and therefore result in a low voltage alarm,
so the outcome is the same.
Response: Thank you for your comments.
1.”Tweaking the settings” on a component that is not outside tolerances is not a Countable Event, which is partially defined as “A component which has failed and
requires repair or replacement, any condition discovered during the verification maintenance activities in Tables 1-1 through 1-5 which requires corrective action
…”. However, as described in Clause 9.2 (Question 4) of the Supplementary Reference Document, a device which is outside tolerances should be considered to
have experienced a “calibration failure” and thus has experienced a countable event.
2. If an entity’s experience is that these components require less-frequent maintenance, a performance-based program in accordance with R2 and Attachment A is
an option. The intervals were revised after Draft 3 such that the various intervals are multiples of each other, such that entities may establish a systematic PSMP.
3. Your observation that in section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT stated that “verification of dc
supply voltage is simply an observation of battery voltage” is correct, but the SDT does not agree that the location where voltage should be measured (verified) be
contained in PRC-005-2 or the Supplementary Reference document. Due to the variances in topography of dc control circuitry for Protection Systems, a single
location for verification of dc supply voltage cannot be specified and must be determined by the Protection System owner.
4. As you correctly stated taking Individual cell voltage readings has been a standard that many companies adhere to. However, this maintenance activity was
removed from the standard because it was a “how to requirement”.
5. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
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intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the activity was performed.
6. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT explains why in Table 1-4 (c) (Station dc supply
using NiCad batteries) the option to evaluate ohmic values to baseline is not available.
7. The SDT believes that just providing “a checkbox stating that you did this” is sufficient proof. Section 15.4 of “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” provides additional discussion on this topic. However, the SDT is unable to fully predict what evidence may be required by the
Compliance Enforcement Authority to demonstrate compliance.
8. “A low voltage alarm combined with high voltage shutdown (but not a high voltage alarm)” would only partially meet the requirement. To ensure that the
automatic shutdown of the battery charger for high voltage conditions is achieved, a high voltage alarm must be a component attribute of the monitoring system in
order.
Florida Keys Electric Cooperative
Assoc. (1)
Ballot
Comment Negative
Extreme unreasonableness and undue hardships on entities, specifically smaller entities. Just one example is
"battery inspections". What is an inspection - simply visual or cell readings? Some entities may have to assign
full time battery maintenance duties. Can SCADA monitor DC voltage trends?
Response: Thank you for your comments. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” – that was provided
for review and comment with PRC-005-2 – details what should be inspected for visual battery cells. The SDT disagrees that the PRC-005-2 with its accompanying
Table 1 imposes “extreme unreasonableness and undue hardships on entities, specifically smaller entities” to maintain a reliable Protection Systems. Monitoring
the dc voltages via SCADA is an option.
FirstEnergy
FE offers the following additional comments and suggestions:
We do not agree with the wording of requirement R3. The entity is only required to meet the minimum
maintenance intervals of the standard as outlined in Tables 1 and 2. We offer a scenario where an entity
states that they will go above the standard and maintain relays on a 4 year cycle. The standard, in meeting an
adequate level of reliability, sates that this activity must be performed every 6 years. If the entity happened to
miss the 4 year timeframe, deciding from a business standpoint to delay the maintenance to the 5th year, an
auditor can find the entity non-compliant per the guidance and wording of the requirements in this standard.
However, the entity still exceeded an adequate level of reliability by performing the maintenance within 5
years. This scenario would be very unfortunate to the entity that has essentially done their part in providing
reliability to the bulk power system, yet they would be punished for not meeting their more stringent
timeframes. This standard’s guidance and requirements sends an adverse message to industry. It essentially
punishes an entity for going above and beyond the standard except on a few rare occasions. If this were to
happen, that entity, and possibly others, would not see the value in going above a standard. It would make
entities meet the bare minimum requirements, essentially reducing overall system reliability. Therefore, we
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suggest the following wording for requirement R3:
“R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP to
ensure adherence to the minimum requirements as outlined in Tables 1 and 2, and initiate resolution of any
identified maintenance correctable issues.”
Response: Thank you for your comments. The Standard requires an entity to implement a PSMP that meets the minimum requirements to the standard. An entity
may choose to implement a program that exceeds the requirements.
City of Farmington (3)
Ballot
Comment Affirmative
FEUS would like to thank the Drafting Team. The proposed PRC-005-2 standard is an improvement over the
four standards that it will replace.
However, section 4.2 identifies five types of protection systems that the standard is applicable to, but the
language of Requirement 1 indicates that applicable entities need to establish a Protection System
Maintenance Program (PSMP) for the Protection Systems designed to provide protection for BES Element(s)
(Part 4.2.1 of Section 4.2). We believe the intent is to have a PSMP for all Protection Systems identified in
Section 4.2 and that the language of Requirement 1 may cause confusion or be misleading. We suggest
changing the language of Requirement 1 from: Each Transmission Owner, Generator Owner, and Distribution
Provider shall establish a Protection System Maintenance Program (PSMP) for its Protection Systems
designed to provide protection for BES Element(s). to: Each Transmission Owner, Generator Owner, and
Distribution Provider shall establish a Protection System Maintenance Program (PSMP) for its Protection
Systems identified in Section 4.2.
Response: Thank you for your comments. R1 has been modified as you suggest.
FirstEnergy Energy Delivery
FirstEnergy Solutions
Ballot
Comment Affirmative
FirstEnergy appreciates the efforts of the drafting team and supports PRC-005-2. We would also like the team
to address our comments and suggestions submitted through the separate comment period.
Ohio Edison Company
(1) (3) (4) (5) (6)
Response: Thank you for your comments. Please see our responses to your comments submitted with the Formal Comments.
ITC
1. For Battery System:- Table 1-4(a)o The maximum maintenance interval for the majority of the battery
maintenance is listed at “18 calendar months”. The current ITC Standard is”once per calendar year and a
calendar year is defined as a twelve-month period beginning January 1st and ending December 31st “.
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ITC would like the maximum maintenance interval at “once per calendar year”
2. Table 1-4(b)
o VRLA (Valve Regulated Lead Acid) batteries have an additional inspection at 6 calendar months that
includes inspecting the condition of all individual units by measuring the battery cell/unit internal ohmic
values. This is in addition to the “18 calendar months” inspection. ITC would like to be consistent with the
VLA (Vented Lead Acid) batteries and have only one internal ohmic value inspection once per calendar
year.
3. For Battery System:- Table 1-4(a)
o The maximum maintenance interval for the majority of the battery maintenance is listed at “18 calendar
months”. The current ITC Standard is “once per calendar year and a calendar year is defined as a twelvemonth period beginning January 1st and ending December 31st “. ITC would like the maximum
maintenance interval at “once per calendar year”
4. Table 1-4(b) VRLA (Valve Regulated Lead Acid) batteries have an additional inspection at 6 calendar
months that includes inspecting the condition of all individual units by measuring the battery cell/unit
internal ohmic values. This is in addition to the ”18 calendar months” inspection. ITC would like to be
consistent with the VLA (Vented Lead Acid) batteries and have only one internal ohmic value inspection
once per calendar year.
5. Auxiliary Relays:
ITC does not agree with the 6 year interval for Aux relays in the trip circuit. Although they are EM relays
they are simple and have very few moving parts. We believe the maintenance period for auxiliary relays
should be 12 years and they should be in conjunction with the control circuit. We recognize that Draft 4 only
includes auxiliary relays that are directly in the trip path. That is an improvement in Draft 4. In general,
auxiliary relays are very reliable; only certain relay types have been proven to be problematic. A known
relay type (HEA) has been proven to be problematic if not exercised frequently. The standard should not
require a 6 year interval period for all other auxiliary relays. We believe problematic relays should be
addressed through use of a NERC Alert process. Don’t cut down the tree for a bad apple.
Response: Thank you for your comments.
1. In choosing the 18 calendar month interval for the maximum maintenance interval for the maintenance activities of table 1-4(a) the SDT was aware that the
majority of these activities are recommended to be performed in IEEE 450 “Recommended Practice for Maintenance, Testing, and Replacement of Vented LeadAcid Batteries for Stationary Applications “at the Yearly inspection. The SDT does not agree that “once per calendar year” would be a more appropriate interval
for these activities but notes that entities may choose to perform required activities more frequently than the maximum intervals expressed in the Tables.
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2. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” – that was provided for review and comment with PRC-005-2
explaining why the for VRLA battery systems (Table 1-4(b)) the maximum maintenance intervals and maintenance activities cannot be consistent with the intervals
and activities of VLA battery systems (Table 1-4(a)).
3. In choosing the 18 calendar month interval for the maximum maintenance interval for the maintenance activities of table 1-4(a) the SDT was aware that the
majority of these activities are recommended to be performed in IEEE 450 “Recommended Practice for Maintenance, Testing, and Replacement of Vented LeadAcid Batteries for Stationary Applications “at the Yearly inspection. However, the SDT has considered that IEEE 450 presents these activities as recommended
activities in a vacuum, without considering other activities that are being performed at the 3-calendar-month interval and has established the 18-calendar-month
interval to comport to the most aggressive intervals being used in common practice. The SDT does not agree that “once per calendar year” would be a more
appropriate interval for these activities but notes that entities may choose to perform required activities more frequently than the maximum intervals expressed in
the Tables.
4. Section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” (question – “What are cell/unit internal ohmic measurements “–
that was provided for review and comment with PRC-005-2 – explains why the for VRLA battery systems (Table 1-4(b)) the maximum maintenance intervals and
maintenance activities cannot be consistent with the intervals and activities of VLA battery systems (Table 1-4(a)).
5. The SDT believes that electromechanical devices share performance attributes (and failure modes) with electromechanical relays and need to be tested at
similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices supports those intervals. If an
entities’ experience is that these components require less-frequent maintenance, a performance-based program in accordance with R3 and Attachment A is an
option.
Manitoba Hydro
Manitoba Hydro (1) (3) (5) (6)
-Grace periods Grace periods should be permitted on the maintenance time intervals. While we understand
that grace periods can be built into a PSMP, maintenance decisions that compromise reliability may still have
to be made just to meet the specified time
Ballot
Comment Negative
Manitoba Hydro is voting negative for the following reasons:
-Grace periods Grace periods should be permitted on the maintenance time intervals. While we understand
that grace periods can be built into a PSMP, maintenance decisions that compromise reliability may still have
to be made just to meet the specified time intervals and avoid penalty. An example of this would be removing
a hydraulic generator from service at a time of low reserve to meet a maintenance interval and avoid noncompliance (removing an asset in a time of constraint). Grace periods are also required in the case of
extreme weather conditions. Such conditions may make it unsafe to perform maintenance within the
maintenance interval or may create a risk to reliability if the equipment being maintained is removed from
service during these conditions. Utilities need to retain a reasonable amount of discretion and flexibility to
make maintenance decisions that are best for reliability without risking non-compliance.
Response: Thank you for your comments. “Grace Periods” within the standard are not measurable, and would probably lead to persistently increasing intervals.
However, an entity may establish an internal program with grace-period allowance, as long as the entire program (including grace periods) does not exceed the
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intervals within the standard.
Georgia System Operations
Corporation (3)
Ballot
Comment
GSOC supports comments submitted by Georgia Transmission Corporation
Response: Thank you for your comments. Please see the SDT response to the comments submitted by Georgia Transmission Corporation.
Electric Market Policy
IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not maximums.
An entity wishing to avoid non-compliance for an interval that might extend past three calendar months must
implement a policy of two months with one month of grace period thereby increasing the number of
inspections each year by half again. This is unnecessarily frequent. We suggest changing the maximum
interval for battery inspections to 4 calendar months. For consistency, Dominion suggests that all battery
maintenance intervals expressed as 3 calendar months be changed to 4 calendar months.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the
activity was performed.
Alliant Energy Corp. Services,
Inc. (4)
Ballot
Comment Negative
1. If PRC-005-2 is going to incorporate PRC-008 (UFLS) and PRC-011 (UVLS) the Purpose needs to be
revised to include Distribution Protection Systems designed to protect the BES.
2. We do not believe a distribution relaying system, designed to protect the distribution assets, that may open
a transmission element (ie; breaker failure) should be considered part of the BES Protection System. R1
should add the following sentence “Distribution Protection Systems intended solely for the protection of
distribution assets are not included as a BES Protection System, even if they may open a BES Element.”
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure define “Reliability standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition. UFLS and UVLS are described in the Applicability
as being included within the Protection System addressed within the standard if they are applied per other NERC Standards.
2. Section 202 of the NERC Rules of Procedure define “Reliability standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirement, as written, supports this.
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Exelon
Yes or No
Question 5 Comment
1. In response to Exelon’s comments provided to drafts 1, 2, and 3 of PRC-005, the SDT did not explain why
a conflict with an existing regulatory requirement is acceptable. The SDT previously responded that a
conflict does not exist and that the removal of grace periods simply is there to comply with FERC Order
directive 693. In response to draft 3 of PRC-005, the SDT stated that "If several different regulatory
agencies have differing requirements for similar equipment, it seems that the entity must be compliant with
the most stringent of the varying requirements. In the cited case, an entity may need to perform
maintenance more frequently than specified within the requirements to assure that they are compliant."
Again this does not explain why a conflict with an existing regulatory requirement is acceptable. This
response does not answer or address dual regulation by the NRC and by the FERC. Specifically, the
request has not been adequately considered for an allowance for NRC-licensed generating units to default
to existing Operating License Technical Specification Surveillance Requirements if there is a maintenance
interval that would force shutting down a unit prematurely or become non-compliant with PRC-005.
Therefore, Exelon again requests that the SDT communicate with the NRC and with the FERC to ensure a
conflict of dual regulation is not imposed on a nuclear generating unit without the necessary evaluation. In
addition, the SDT still did not fully evaluate or address the concern related to the uniqueness of nuclear
generating unit refueling outage schedules.
2. Although Exelon Nuclear agrees with the SDT that the maximum allowed battery capacity testing intervals
of not to exceed 6 calendar years for vented lead acid or NiCad batteries (not to exceed 3 calendar years
for VRLA batteries) could be integrated within the plant’s routine 18 month to 2 year interval refueling
outage schedule, the SDT has not considered that nuclear refueling outages may be extended past the 18
month to 2 year "normal" periodicity. There are some unique factors related to nuclear generating units that
the SDT has not taken into consideration in that these units are typically online continuously between
refueling outages without shutting down for any other required maintenance. Historically, generating units
have at times extended planned refueling outage shutdown dates days and even weeks due to requests
from transmission operations, fuel issues and electrical demand. Without the grace period exclusion
currently allowed by existing maintenance programs, a nuclear plant will be forced to either extend outage
duration to include testing on an every other refueling outage (i.e., every four years to ensure compliance
for a typical boiling water reactor) or leave the testing on a six year periodicity with the vulnerability of a
forced shut down simply to perform maintenance to meet the six year periodicity or a self report of noncompliance. To ensure compliance, the nuclear industry will be forced to schedule battery testing on a four
year periodicity to ensure the six year periodicity is met, thus imposing a requirement on nuclear generating
units that would not apply to other types of generating units. The SDT response to this question in draft 3 is
that "(t)he 18-month (and shorter) interval activities are activities that can be completed without outages primarily inspection-related activities. An entity may need to perform maintenance more frequently than
specified within the requirements to assure that they are compliant." Respectfully Exelon requests that the
SDT review and evaluate the concern.
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Response: Thank you for your comments.
1. It appears that the SDT’s response was mis-understood. The SDT intended that the response be understood as” in order to be compliant with all requirements,
regardless of the different agencies imposing those requirements, the entity will likely have to be compliant with the most stringent of the requirements”.
Regarding PRC-005-2, an entity must be compliant with the included requirements, even if they are more stringent than other regulatory requirements.
2. The SDT believes that the activities addressed in the comment can be integrated with the 18-24 month plant refueling outage. This may result in the activities
being performed more frequently than specified.
Entergy (3)
Entergy Services, Inc. (6)
Ballot
Comment Negative
In Section 4.2, ‘Facilities’ add the following subsection 4.2.6: Protection Systems for generating units in
extended forced outage or in inactive reserve status are excluded from the requirements of this standard.
However, the required maintenance and testing of the Protection Systems at these units must be completed
prior to connecting the units to the Bulk Electric System (BES). Reason for the above comment: The above
units are not connected to the BES and therefore do not affect the reliability of the BES. However, to ensure
the reliability of the BES, required maintenance and testing of the Protection Systems at these units must be
completed prior to connecting them to the BES.
Response: Thank you for your comments. Please refer to Compliance Application Notice CAN-0011, footnote 5, which states, “The registered entity’s Protection
System maintenance and testing program is only applicable for Protection System devices in service …” The SDT believes that this guidance will remain durable
for PRC-005-2.
Entergy Services
In Section 4.2, “Facilities” add the following subsection 4.2.6: Protection Systems for generating units in
extended forced outage or in inactive reserve status are excluded from the requirements of this standard.
However, the required maintenance and testing of the Protection Systems at these units must be completed
prior to connecting the units to the Bulk Electric System (BES).
Reason for the above comment: The above units are not connected to the BES and therefore do not affect
the reliability of the BES. However, to ensure the reliability of the BES, required maintenance and testing of
the Protection Systems at these units must be completed prior to connecting them to the BES.
Response: Thank you for your comments. Please refer to Compliance Application Notice CAN-0011, footnote 5, which states, “The registered entity’s Protection
System maintenance and testing program is only applicable for Protection System devices in service …” The SDT believes that this guidance will remain durable
for PRC-005-2.
MRO's NERC Standards Review
Subcommittee
In the checkbox for Requirement R3 please change the wording to read, “Maintenance Correctable Issue Failure of a component to operate within design parameters such that it cannot be restored to functional order
by repair or calibration during performance of the initiating on-site activity. Therefore this issue requires follow-
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up corrective action.”
Response: Thank you for your comments. The definition of maintenance correctable issue has been revised to be clearer:
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
Bonneville Power Administration
1. In the header of Tables 1-1, 1-2, 1-3, and 1-5 there is a note that says "Table requirements apply to all
components of Protection Systems except as noted." Since each table only applies to the specific
component type shown in the header, we do not understand what this note means. The definition given for
component only makes the note more confusing. Please clarify the note.
2. Additionally, BPA is voting no during this round due to an issue with the Applicability Section and Section
4.2. Once this issue is clarified, BPA would be in support of a yes vote.
Issue: Section 4.2 Facilities lists 5 separate items that the standard is applicable for (4.2.1. - 4.2.5).
However Requirement 1 uses language that only addresses one of the items (4.2.1). There is no language
contained anywhere within any of the requirements in PRC-005-2 that apply to the types of protection
systems described in Applicability Sections 4.2.2 - 4.2.5. Therefore, it could be argued that this leaves it
open to interpretation as to whether UFLS/UVLS/SPS are addressed by R1.In the NOPR (¶ 105), FERC
states that “the Requirements within a standard define what an entity must do to be compliant” Further, in
Order 693 (¶ 253) FERC explicitly states that “compliance will in all cases be measured by determining
whether a party met or failed to meet the Requirement”. Given this, then from a compliance perspective,
the actual applicability of the standard appears to not be as broad as intended. We ask that this issue be
resolved by modifying the language in R1 in a manner that explicitly encompasses all types of protection
systems to which it is intended to be applied.
Response: Thank you for your comments.
1. In Table 1-1, for example, this note means that all activities apply to all protective relay components unless specifically differentiated within individual table
entries. Because Tables 1-1, 1-2, and 1-3 do not include any additional differentiation within the table, the note was removed from these tables in consideration of
your comment.
2. The R1 requirement has been revised in consideration of your comments.
JEA (3)
Ballot
Comment Negative
JEA maintains testing of lockout relays will have major reliability impact to the JEA system.
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Response: Thank you for your comments. The SDT believes that electromechanical devices share performance attributes (and failure modes) with
electromechanical relays and need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of
these devices supports those intervals.
Tri-State G&T
1. M1 - Why is the document necessary to be “current or updated?” Eliminate “or updated.”
2. R1 VSL - Second item in Severe VSL is not addressed in any lower VSL. Should there also be a
comparable violation in Lower and Moderate?
3. R2 VSL - Keep the comment about the redundancy in Lower VSL and High VSL for clarifying the difference
between the two.
Response: Thank you for your comments.
1. M1 has been revised as suggested and the phrase, “or updated” has been removed
2. The VSL for R1 has been revised to add phased VSLs for Moderate and High related to this item.
3. The High VSL has been modified from three years to four years.
Ameren
1. Measure M3 on page 5 should apply to 99% of the components. “Each __shall have evidence that it has
implemented the Protection System Maintenance Program for 99% of its components and initiate” PRC005-2 unrealistically mandates perfection without providing technical justification. A basic premise of
engineering is to allow for reasonable tolerances, even Six Sigma allows for defects. Requiring perfection
may well harm reliability in that valuable resources will be distracted from other duties.
2. Define BES perimeter in accordance with Project 2009-17 Interpretation. Facilities Section 4.2.1 “or
designed to provide protection for the BES” needs to be clarified so that it incorporates the latest Project
2009-17 interpretation. The industry has deliberated and reached a conclusion that provides a meaningful
and appropriate border for the transmission Protection System; this needs to be acknowledged in PRC005-2 and carried forward. The BOT adopted this 2/17/2011.
3. Battery inspection every 4 months is sufficient. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for an
interval that might extend past three calendar months due to storms and outages must set a target interval
of two months thereby increasing the number of inspections each year by half again. This is unnecessarily
frequent. We suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar
months.
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Response: Thank you for your comments.
1. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation.
2. The referenced interpretation relates to a quasi-definition of “transmission Protection System”, and in the context of the approved PRC-004-1 and PRC-005-1,
presents a consistent context for this term. However, the interpretation was constrained to not introduce any requirements or applicability not already included
within the approved standards. PRC-005-2 does not use this term, and expands upon the applicability in the interpretation to address what seems to the SDT to
be an appropriate applicability for PRC-005-2. The applicability of the interpretation to PRC-004 is not affected by PRC-005-2.
3. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the activity was performed.
Madison Gas and Electric Co. (4)
Ballot
Comment Affirmative
MGE is voting affirmative with the following recommendation to the definition of Maintenance Correctable
Issue. Maintenance Correctable Issue - Failure of a component to operate within design parameters such that
it cannot be restored to functional order by repair or calibration during performance of the "initiating" on-site
activity. Therefore this issue requires follow-up corrective action. The removal of the word “initial” will cause
less confusion because the industry does not understand if this is initial (commissioning) or is initial used as
when a component requires repair. Recommend “initiating” replace “initial”.
Response: Thank you for your comments. The definition of maintenance correctable issue has been revised to be clearer:
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
Arizona Public Service Company
NERC continues to be too prescriptive in the standard. For example, Table 1-4(a) requires battery
verifications and inspection every three months. We have been performing similar tests every four months for
over a decade, with no adverse consequences. Although FERC Order 693 directs NERC to establish
maximum allowable intervals, the maximum interval must be “appropriate to the type of protection system and
its impact on the reliability of the Bulk-Power System.” (Order 693 at 1475)The Standard Drafting Team
(SDT) has not demonstrated a mechanism that connects the maximum maintenance interval with its impact
on the reliability of the Bulk-Power System. An example can be found on the bottom of page 18 and the top
of page 19 of the Consideration of Comments on Protection System Maintenance [Project 2007-17] for draft
3. Although the commenting organization provided a concrete example of successful maintenance under a
longer interval, the Standards Drafting Team commented that it “believes that 18-months is the proper interval
for this activity.” (Emphasis added) An organization cannot challenge the SDT’s beliefs, only facts. The basis
for each maximum maintenance interval, with appropriate linkage to its impact on the reliability of the Bulk-
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Power System, needs to be published and voted upon so that factual based proposals to modify the
maximum interval can be rationally challenged.
Response: Thank you for your comments. The basis for the intervals established within the standard is described throughout the Supplementary Reference
document.
Northern Indiana Public Service
Co. (3)
Ballot
Comment Negative
One of our concerns is that, while the present standard is 2 pages and is the most highly violated and fined
standard, the new proposed standard is 22 pages, the implementation plan is 4 pages and the Supplemental
FAQ document is 87 pages.
Response: Thank you for your comments. The SDT has established maximum allowable intervals in accordance with FERC Order 693. Additionally, the SDT has
addressed many of the common program-related causes of observed violations, and has provided the Supplementary Reference and FAQ to assist entities in
implementing their program.
PJM Interconnection, L.L.C. (2)
Ballot
Comment Negative
PJM has a general problem with how this current draft defines "protection system". The issue is that PJM
believes the standard should only apply to Protection relays that are designed to protect the BES. It should
not apply to relays that protect the asset itself.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements as written directly support this definition.
Western Area Power
Administration
Please explain or clarify the term “mitigating devices” used in Table 1-5 Control Circuitry, Page 19. This term
is not well defined in the industry and not easily understood as “interrupting device” or “circuit breaker.”
Response: Thank you for your comments. This term is primarily focused on Special Protection Systems, where they may perform some activity other than
“interrupt” to address their design objectives.
Shermco Industries
1. Please provide clarification on "Communications" in regards to the following: If our customers are
utilizing Schweitzer SEL311 relays and utilizing the fiber for transfer trip, is this considered a
communications circuit? Our experiences in regards to testing these devices that have transfer trips out
into a main substation that could affect a main ring tie or open a major 138kV loop, are that the T&D
utilities will not allow us to perform these tests and trip their breakers. Therefore, what is required to
satisfy testing?
2. In regards to Function / Trip testing, if we have a sudden pressure device, this is considered an auxiliary
relay and the sudden pressure relay itself is not required to be tested. However, the trip path is required
to be tested for DC tripping, if it directly trips the breaker feeding the BES, on the DC Control verification
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testing. Please clarify if this is correct.
Response: Thank you for your comments.
1. The fiber you indicate is a relay communications circuit. The SEL311 monitors the condition of the fiber. It will provide an alarm on loss of communications. If
this alarm is not monitored then the entity will be required to check it every 3 months and verify it is still operational. If the communications alarm is brought back
to the control center, and the error rate or pilot signal is verified continuously, the interval will be 12 years.
2. Yes, this is correct.
ExxonMobil Research and
Engineering
1. PRC-005-2 is a highly prescriptive standard that prevents small entities from establishing a risk-based
approach to protective system maintenance that is commonly used in other industry sectors and forces
the small entity to utilize the time-based program. Many registered entities do not have a population size
of 60 for each type of protective device. However, they do possess historical records that can be used to
calculate the mean time between failures for each equipment type that adequately reflects the service
conditions in which the equipment is installed. The SDT should consider allowing registered entities to
utilize historical records in their supporting documentation for defining a performance based program.
2. Additionally, by restricting populations by manufacturer model, as referenced in PRC-005-2 Attachment
A, the Standard Drafting Team is bordering on anti-competitive behavior as those entities that utilize
performance-based programs may be discouraged to utilize alternative suppliers because utilization of a
time-based maintenance program on the alternative supplier’s equipment may present a cost-benefit
analysis hurdle that the supplier of the equipment is not able to overcome.
3. Lastly, the SDT has chosen not to provide a tolerance band for the maximum maintenance intervals it
defines in its time-base program. Given that the SDT has not provided sound technical justification (i.e. a
study, industry recommended practice, etc.), the SDT should reconsider its stance on providing a
tolerance band on the time intervals specified in the time-based program. What is the increase in risk
owned by an entity when a protective device is tested at the 6 year and 30 day mark instead of the 6 year
mark?
Response: Thank you for your comments.
1. If the historical records fully address the criteria in Attachment A, they would be useful in establishing the basis for a performance-based maintenance program.
If the population is not in accordance with the definition of segment in Attachment A, the SDT does not believe that the entity has a statistically-significant sample
on which to base a PBM.
2. In order to properly apply a performance-based maintenance program, the components within a segment must be such that they will exhibit similar behavior.
Similarly-functioning components from different manufacturers will likely not satisfy this criterion. If an entity does not have sufficient component populations to
apply performance-based maintenance, they must revert to time-based maintenance per the Tables or find another entity with whom they can aggregate
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components within a performance-based maintenance program. Please see Section 9 of the Supplementary Reference Document for a discussion regarding
aggregating components between entities within a performance-based maintenance program.
3. There may be minimal additional risk for missing the required interval by only a small amount. However, “grace periods” within the standard are not
measurable, and would probably lead to persistently increasing intervals. However, an entity may establish an internal program with grace-period allowance, as
long as the entire program (including grace periods) does not exceed the intervals within the standard. Also, this concern is only a practical one if an entity is
persistently maintaining its Protection System components at the very end of each maximum allowable interval.
Luminant
The red-lined version did not appear to agree with the clean copy. In reading the "red lined" document it
appears that R3 was intended to be "Each Transmission Owner, Generation Owner, and distribution Provider
shall implement and follow its PSPM and initiate resolution of any identified maintenance correctable issues."
Response: Thank you for your comments. The red-lining tools in Microsoft Word can sometimes be misleading, but the red-line is provided in an effort to illustrate
the changes made to the document. We recommend that the entity use the “clean” version in order to see the final resulting text.
MidAmerican Energy Company
Requirement R3 of the standard discusses resolution of “identified maintenance correctable issues”. M3
requires evidence of “resolution of Maintenance Correctable Issues”. The definition of Maintenance
Correctable Issue in the standard includes “during performance of the initial on-site activity”. The “initial onsite activity” seems to imply that the corrective steps that need to be tracked are those resulting from the
periodic testing that is done for compliance with the standard. It is not clear if the SDT meant to require that
records be kept of any required maintenance that is done as a result of a discovered problem or failure that is
not identified during the periodic testing.
Response: Thank you for your comments. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may
take an extended period (perhaps even several years) to complete effectively, during which time the degraded system must be reported and reflected within the
operation of the BES in accordance with other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete”
during the scheduled interval for these more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of
maintenance correctable issues and rely on the operating focus on the degraded system to ensure that they are completed. The definition of maintenance
correctable issue has been revised, though, to be clearer.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
Consumers Energy (5)
Ballot
Comment Negative
While most of the changes are quite good, I believe R3 may not be what was intended. R3 concludes with
"initiate resolution of any identified maintenance correctable issues." My copy of Webster's Dictonary defines
initiate as "to set going : start". Thus to meet R3, I need never order a replacement component I just need to
write a purchase order (it's the start of the process). If rewiring is needed, I only need to write a maintenance
order, rather than sending out an electrician with tools and wire. I believe reliability would be better served to
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require resolution of the problem rather than just starting a process to begin work.
Response: Thank you for your comments. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may
take an extended period (perhaps even several years) to complete effectively, during which time the degraded system must be reported and reflected within the
operation of the BES in accordance with other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete”
during the scheduled interval for these more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of
maintenance correctable issues and rely on the operating focus on the degraded system to ensure that they are completed.
Constellation Energy
Commodities Group (6)
Ballot
Comment Negative
Constellation Power Source
Generation, Inc. (5)
1. R3 is vague and can be easily interpreted in a variety of ways. For example, “initiate resolution” may mean
closing a work order on a correctable issue or it may mean simply to create a work order with the intent of
closing it out. The difference is not just in compliance evidence but it potentially allows an auditor to
interpret the requirement to state that closed work orders should be completed in a timely manner.
2. Lastly, the technical man power and compliance documentation needed to implement a performance based
protection system maintenance program are so onerous that it is highly unlikely that any entity would use
it.”
Response: Thank you for your comments.
1. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even
several years) to complete effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance
with other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for
these more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues
and rely on the operating focus on the degraded system to ensure that they are completed. The definition of maintenance correctable issue has been revised
to be clearer.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
2. The SDT understands that the requirements to establish and operate a performance-based PSMP may be beyond what many entities will wish to pursue.
However, these are provided for the use of those entities who wish to make use of the analytical resources to optimize their field maintenance.
MISO Standards Collaborators
1. R3 speaks of a Maintenance Correctable Issue and implementing your Protection System Maintenance
Program (PSMP). In the definition of Maintenance Correctable Issue, it states "...of the initial on-site
activity". The intent seems to be that during any maintenance activity, and something is found not working
properly, you should repair it. Some may look at the word "initial" as during the commissioning of a facility.
We recommend the SDT delete the word "initial" to cause less confusion.
2. We recommend the SDT change the text of Standard PRC-005-2 - Protection System Maintenance Table
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1-5 on page 19, Row 1, Column 3 to “Verify that each a trip coil is able to operate the circuit breaker,
interrupting device, or mitigating device.”
Or alternately,
“Electrically operate each interrupting device every 6 years.”
Trip coils are designed to be energized no longer than the breaker opening time (3-5 cycles). They are
robust devices that will successfully operate the breaker for 5,000-10,000 electrical operations. The most
likely source of trip coil failure is the breaker operating mechanism binding, thereby preventing the breaker
auxiliary stack from opening and keeping the trip coil energized for too long of a time period. Therefore,
trip coil failure is a function of the breaker mechanism failure. Exercising the breakers and circuit switchers
is an excellent practice. We would encourage language that would suggest this task be done every 2
years, not to exceed 3 years. Exercising the interrupting devices would help eliminate mechanism binding,
reducing the chance that the trip coils are energized too long. The language as currently written in Table 15, Row 1, will also have the unintentional effect of changing an entities existing interrupting device
maintenance interval (essentially driving interrupting device testing to a less than 6 year cycle).
3. We recommend the SDT change the text of Standard PRC-005-2 - Protection System Maintenance Table
1-5 on page 19, Row 3, Column 2 to
“12 calendar years”.
The maximum maintenance interval for “Electromechanical lockout and/or tripping devices which are
directly in a trip path from the protective relay to the interrupting device trip coil” should be consistent with
the “Unmonitored control circuit” interval which is 12 calendar years.
4. In order to test the lockout relays, it may be necessary to take a bus outage (due to lack of redundancy and
associated stability issues with delayed clearing). Increasing the frequency of bus outages (with
associated lines or transformers) will also increase the amount of time that the BES is in a less intact
system configuration. Increasing the time the BES is in a less intact system configuration also increases
the probability of a low frequency, high impact event occurring. Therefore, the Maximum Maintenance
Interval should be 12 years for lockout relays.
5. We recognize the substantial efforts and improvements to PRC-005-2 that have been made and appreciate
the dedicated work of the SDT. We appreciate the removal of Requirement R1.5 and R4 and other
clarifications from draft 3.
6. Our remaining concern for PRC-005-2 is with definition and timelines established in Table 1-5. We believe
that, as written, the testing of “each” trip coil and the proposed maintenance interval for lockout testing will
result in the increased amount of time that the BES is in a less intact system configuration. We hope that
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the SDT will consider these changes.
Response: Thank you for your comments.
1. The word, “initial” is intended to emphasize that an identified concern becomes a Maintenance Correctable Issue when the entity is not able to immediately
resolve it, and must return to correct the problem. The definition of maintenance correctable issue has been revised to be clearer.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
2. The SDT considers it important to verify each breaker trip coil will indeed operate within the established intervals. While breakers may be operated much more
frequently at times (and allow the entity to document these operation to address this activity), other breakers may not be called on to operate for many years.
3. The SDT believes that electromechanical devices contain moving parts and share performance attributes (and failure modes) with electromechanical relays and
need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices supports those
intervals.
4. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.
5. Thank you.
6. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.
NERC - EA & I
Recommend entities be explicitly required to document the Relay Maintenance Program in one document.
Many entities presently maintain their Protection Maintenance Program in several documents, such as one for
relays, one for batteries, etc. This complicates compliance review and contributes to non-compliance since
personnel in different departments writing these have different levels of understanding of NERC standards.
Separate documents also allow inconsistencies to slip in. Recommend Requirement 1 to changed to the
following to address this problem. "Each Transmission Owner, Generator Owner, and Distribution Provider
shall establish a Protection System Maintenance Program (PSMP), RECORDED AND UPDATED AS A
SINGLE DOCUMNET for its Protection Systems designed to provide protection for BES Element(s). "
Response: Thank you for your comments. The SDT believes that, because of the diversity of different entities and their business arrangements that such a
requirement could serve to decrease the quality of an entity’s PSMP, particularly for a vertically-integrated entity that includes several of the specified Applicable
Entities. For example, the Generator Owner and Transmission Owner are likely to have significant differences for very good reasons.
Florida Municipal Power Agency
(4) (5) (6)
Ballot
Comment Negative
1. Section 4.2.1 states that the Standard is applicable to “Protections Systems designed to provide protection
BES Elements.” Section 15.1 of the Supplementary Reference Document defines the scope as those
“devices that receive the input signal from the current and voltage sensing devices and are used to isolate a
faulted element of the BES.” These two statements are not exactly equivalent, and in fact, are in conflict
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Florida Municipal Power Pool (6)
Question 5 Comment
with the Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State, Approved by the Board
of Trustees on February 17, 2011.
2. Section 4.2.1 should be changed to “Any Protection System that is installed for the purpose of detecting
faults on transmission elements (lines, buses, transformers, etc.) identified as being included in the Bulk
Electric System (BES) and trips an interrupting device that interrupts current supplied directly from the
BES.”
Response: Thank you for your comments.
1. The referenced interpretation relates to a quasi-definition of “transmission Protection System”, and in the context of the approved PRC-004-1 and PRC-005-1,
presents a consistent context for this term. However, the interpretation was constrained to not introduce any requirements or applicability not already included
within the approved standards. PRC-005-2 does not use this term, and expands upon the applicability in the interpretation to address what seems to the SDT to
be an appropriate applicability for PRC-005-2. The applicability of the interpretation to PRC-004 is not affected by PRC-005-2.
2. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements as written directly support this definition.
US Army Corps of Engineers
1. Section 4.2.5.4 - please clarify generator connected station service transformer. We believe this to mean a
station service transformer with no breaker between the transformer and the generator bus.
2. R3 - the term 'initiate resolution' is vague and needs to be further defined. Does this mean putting in a
work order or is further action required.
3. Data Retention: The proposed standard clarifies that two of the most recent records of maintenance are to
be retained to demonstrate compliance with the prescribed maintenance intervals. When equipment is
replaced, the reference information indicates that the information associated with the original equipment
must be retained to show compliance with the standard until the performance with the new equipment can
be established. This is not explicitly stated in the requirements and warrants a comment.
Response: Thank you for your comments.
1. The commenter is correct.
2. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even
several years) to complete effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with
other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these
more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues and rely on
the operating focus on the degraded system to ensure that they are completed. The definition of maintenance correctable issue has been revised to be clearer.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
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performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
3. The data retention section is stated to describe what an entity must do to demonstrate compliance to an auditor on a persistent basis. The additional
clarification in the Supplemental Reference Document is provided to share the experiences of SDT members with other entities, and to suggest a possible
effective practice.
Public Utility District No. 1 of
Lewis County (5)
Ballot
Comment Negative
Standard does not recognize the affects and great burdens to smaller utilities that have limited staff and great
distance to travel out west. Generally, our facilities to not affect the BES. We believe that the battery testing
requirements are overkill. The intervals for testing should be placed at minimum of 2 or 3 years
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the
activity was performed.
As for the other shorter-duration activities, the SDT believes that all of these activities, at the specified intervals, are necessary to assure reliability. From the
experience of the SDT members, and as supported by various IEEE Standards, it seems clear that delaying the battery maintenance activities to 2-3 years would
be detrimental to the reliability of the BES.
AtCO Electric ltd
1. Table 1-2: the requirement for 12 calendar year verification for the channel and essential signals’
performance should be removed. We do not see benefit in the maintenance activities under level 2 (the 12
calendar year requirement) and suggest merging it with level 3 (the “no periodic maintenance specified”
requirement). The “loss of function” alarm, will be considered as a countable event to fall under requirement
R3 and dealt as maintenance correctable issue.
2. Table 1-5: the requirement of 6 calendar year verification for electrical operation of electromechanical
lockout and/or tripping auxiliary devices should be revisited, considering that: ” It is not feasible to exercise
a lockout relay during maintenance due to high risk to the in-service facility, as well as the complexity of
lockout relay connections and protection schemes. Instead, we propose a DC ring test, which verifies the
continuity of control circuitry and eliminates the risk impact of lockout or auxiliary tripping device
operations.” The interval is too frequent. The requirement would become achievable if the 6 calendar year
frequency were increased to 12 calendar years, to be in line with microprocessor relay maintenance
frequency
Response: Thank you for your comments.
1. Though a channel with continuous alarming may not be in an alarm state during a quiescent state, the alarm function alone does not identify if the channel will
fail during fault conditions. Fault noise level and, fault location impact a channels’ noise immunity margin. The activities are specified are to ensure reliable
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performance of the communication channel.
2. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.The SDT believes that electromechanical devices with
moving parts share performance attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals. Performance-Based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
CPS Energy
1. Table 1-5 The new standard requires that every 6 years it is verified that “each trip coil is able to operate
the breaker,”. The supplementary reference states that this requirement can be met by tracking real-time
fault-clearing operations on the circuit breakers. With transmission breakers typically having dual trip coils,
how can tracking real-time operations meet this requirement? Would a breaker operations where relays in
both the primary and secondary trip coils indicated operation be sufficient or would some type of trip coil
monitoring that showed coil energization be needed?
2. Additionally, regarding the verification of all trip paths of the trip circuit. If a microprocessor relay is used to
trip a breaker, and two contacts are paralleled on the relay through a single test switch for breaker tripping,
would it be necessary to verify each contact independently or could an assertion of both contacts through
the test switch be adequate? In this instance, the functionality of each contact would be fully identical.
3. Table 1-2A 3-month inspection is required for communications equipment that does not have “continuous
monitoring or periodic automated testing for the presence of the channel function, and alarming for loss of
function” has to be verified that the communication equipment is “functional” with a 3-month site visit.
Would a carrier on-off system, that did not perform periodic check back testing, but did have an alarm
contact (loss of power, failure, etc.) that was monitored through SCADA would need to have a 3-month
inspection? According to the supplemental reference, this inspection should be to verify that the equipment
is “operable through a cursory inspection and site visit”. It sounds as if this cursory inspection and site visit
would accomplish the same as the alarm contact. It does not appear that end-end functional testing of the
blocking signal is required by what is provided in the supplemental reference. Is this correct?
4. Table 1-3 - The maintenance activity for the 12 calendar year testing should include a little more specificity.
It should have something stating the values provided to the relay are accurate. I know that this discussed
in the supplemental reference, but requirement in Table1-3 sounds as if any relay that measured for loss of
signal, such as a loss-of-potential function, would be sufficient when the purpose to verify that the signal not
only gets to the relay but also has some accuracy as needed by the application of the relay.
Response: Thank you for your comments.
1. If you are able to independently track both trip coils via real-time operations tracking, you could use this tracking to address this activity. If not, you will likely
need to perform focused maintenance activities.
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2. This would be adequate.
3. This is not correct. As you indicate, the 3 month check for unmonitored relay channels is to verify that the channel is functional. For a guard signal, a visual
inspection will indicate if a guard or pilot signal is being received. A blocking channel can only be verified by either a checkback test or an end to end signal check.
A visual check that the equipment is not failed does not indicate that the channel medium or auxiliary devices are still intact. We will revise the supplementary
reference to clear this up (See Section 15.5.1, question “What is needed for the 3-month inspection of communications-assisted trip scheme equipment?”).
4. If the voltage and current signals are measured by the relay and verified to be correct, this would satisfy the required activity in the Table. Please note that, in
the definition of Protection System Maintenance Program, “verify” means, “determine that the component is functioning correctly”.
NextEra Energy
Thank you for your diligent efforts in writing the draft standard. The draft standard and associated documents
are well written and we believe, after approval, will be instrumental to improving the reliability of the BES. We
have the following specific comments:
a. The maximum maintenance interval of unmonitored Vented Lead-Acid (VLA) batteries should be changed
from 3 calendar months to 12 calendar months. Today’s lead-calcium and lead-selenium-low antimony
batteries do not have rapid water loss as compared to the legacy lead-antimony batteries. FPL’s operating
experience has shown that electrolyte in today’s VLA cells do not require watering within a 12-month
interval. In fact, battery manufacturers now recommend watering intervals of 2 to 3 years for some new
batteries.
b. The maximum maintenance interval to verify that unmonitored communications systems are functional
should be changed from 3 calendar months to 12 calendar months. FPL’s operating experience has shown
that power line carrier (PLC) failures are primarily due to PLC protective devices (MOVs, gas tubes & spark
gaps). Automated testing such as PLC check-back schemes cannot test for failed PLC protective devices.
We believe a 12 calendar month functional test is sufficient because of FPL’s operating experience. FPL’s
operating experience has shown that power line carrier (PLC) failures are primarily due to PLC protective
devices (MOVs, gas tubes & spark gaps).
c. We believe the data retention requirements for R2 and R3 should be documentation for the two most recent
maintenance activities.
d. Regarding Maintenance Correctable Issue (page2) where it states: “.such that it cannot be restored to
functional order during performance of the initial on-site activity”. This terminology is vague: Particularly
“initial on-site activity”. Not sure what “functional order” means? The suggestion is to change to “..such that
the deficiency cannot be restored to meet applicable acceptance criteria during the performance of the
scheduled maintenance activity”.
e. Regarding Maintenance Correctable Issue (page 2) and R4 on Page 5, the suggestion is an entirely new
“Maintenance Correctable” definition especially: “Therefore this issue requires followup corrective action”.
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Regarding this new definition: Why is it here? Is its purpose to ask us to do something with these issues if
we discover them? Do issues identified as “Maint. Correctable” need to be tracked and reported in some
manner? The referenced term “Maint. Correctable” is only used in PRC-005-2 in R4 (page 5). The
suggestion is to provide clarification. Is this maintenance correctable terminology implying that NERC
PRC005-2 is opening up a new requirement for tracking and reporting resolution of “Maint Correctable”
issues? The suggestion is to change to:
This issue includes any activity requiring further follow-up corrective action to restore operability outside
of the applicable maint activity
f. Regarding Countable Event (Page 3), the suggestion is an entirely new “Countable Event” definition. Why
is this new term and definition “countable event” included in PRC-005-2 ? Note: In the PRC005-2 text
“countable event” is actually only referred to in PRC-005-2 in Attachment A under “Performance Based
Programs” (not referred to in time based programs section). The recommendation is that the PRC-005-2
version explicitly clarify the definition of â ”countable event” to clearly indicate that this term is applicable
ONLY to “Performance Based Programs”.
g. Regarding Countable Event (page 3), where the text says “Any failure of a component which requires
repair or replacement, any condition discovered during the verification activities in Tables 1-1/1-5 which
requires corrective action..”, in the definition for “countable event” what does “corrective action” mean?
PRC005-2 is unclear. Does the term “countable event” have any ties to”Maint Correctable” issues. The
suggestion is to Consider changing wording from “corrective action” to “which requires > 7 days to correct”
and clarify whether or not “countable event” has any correlation to “Maint Correctable” events as discussed
on page 2 and in R4? If so please provide language clarifying this correlation.
Response: Thank you for your comments.
a. This activity is primarily inspection-related, and addresses an inspection of electrolyte levels, dc grounds, and station dc supply voltages. Good practice is that
entities will conduct a visual inspection of the overall battery condition during these activities, although the Standard does not require it. Also, please note that,
while some batteries may reliably go longer between “watering”, this activity is to detect gross failures, rather than specifically to address “watering”. Please see
Section 15.4 of the Supplementary Reference Document for further discussion.
b. A relay communications channel and equipment provide logic for a pilot protective relay system to operate correctly to clear faults instantaneously. Channel
failure would cause the protective system to not operate or to operate incorrectly. An unmonitored channel failure will decrease reliability of that protective system
until its failure is discovered. One year is too long to risk BES protective systems out of service. The three month interval is devised to maintain BES system
reliability. If an entity’s experience suggests that longer intervals are appropriate, they may employ performance-based maintenance per R2 and Attachment A.
The definition of maintenance correctable issue has been revised to be clearer.
c. From SDT members’ experiences, it is clear that auditors will generally wish to monitor compliance all the way back to the previous audit. Please see
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Compliance Application Notice CAN-008 for a discussion about pre-2007 data.
d. The definition has been modified in consideration of your comment.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
e. Yes – the entity is expected to do something in response to an identified Maintenance Correctable Issue, but it is left to the entity to determine the best method
for them to track the initiation of resolution of Maintenance Correctable issues. The definition of maintenance correctable issue has been revised to be clearer..
Please refer to M3 for some sample types of evidence.
f. Countable events are used only within Attachment A.
g. “Countable Event” applies only to performance-based maintenance, and is used solely to determine and evaluate the PBM maintenance intervals. A countable
event may (or may not) be a maintenance correctable issue, depending on whether the deficiency is corrected while performing the maintenance activity or
requires additional follow-up.
U.S. Bureau of Reclamation (5)
Ballot
Comment Affirmative
The application of the PSMP should be explicitly defined in the standard. Currently the PSMP is required to
protect rather than a PSMP to identify the components defined by the standard. The language should be
altered to ensure the PSMP is developed for the component types specified in the standard. The following
language should be considered: "Each Transmission Owner, Generator Owner, and Distribution Provider
shall establish a Protection System Maintenance Program (PSMP) for its Protection Systems identified in
Section 4.2".
Response: Thank you for your comments. R1 has been modified as you suggest.
NIPSCO
1. The present PRC-005 standard is 2 pages while the proposed PRC-005-2 is 22 pages, with an
implementation plan of 4 pages and a supplemental document of 87 pages. The review process appears to
be somewhat daunting especially considering that NERC is trying to simply things with such concepts as
the “traffic ticket” approach.
2. In R3 we’re not sure if there is a time requirement regarding the completion of the resolution process. We
like the use of "calendar year" in requirements which should provide flexibility in getting the work
completed.
3. Another comment for our response concerns Table 1-2, Communications Systems (page 11):The first
maintenance interval is 3 calendar months. Does this mean the same as 1 calendar quarter?1. Example
for 3 calendar months: Maintenance performed on 1/4/11. Next maint due by 4/30/11. Maintenance
performed on 4/12/11. Next maint due by 7/31/11. Maintenance performed on 7/30/11. Next maint due by
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10/31/11. This would yield 3 inspections for 2011. Maintenance performed on 10/12/11. Next maint due
by 1/31/12.2. Example for 1 calendar quarter: Maintenance performed on 1/4/11. Next maint due by
6/30/11. This would yield 4 inspections for 2011 (1 per quarter).
Response: Thank you for your comments.
1. The SDT has established maximum allowable intervals in accordance with FERC Order 693. Additionally, the SDT has addressed many of the common
program-related causes of observed violations, and has provided the Supplementary Reference and FAQ to assist entities in implementing their program. The
“traffic ticket” approach is focused on how the compliance monitor will assess violations, and has no bearing on the Standard itself.
2. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even
several years) to complete effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with
other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these
more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues and rely on
the operating focus on the degraded system to ensure that they are completed.
3. The intervals, “3 calendar months” and “once per calendar quarter” are not synonymous. “Once per calendar quarter” would effectively permit entities to have
six months (less two days) between successive activities, while a “3 calendar month” interval limits an entity to four months (less two days) between activities.
See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about “calendar month” Basically every “3
Calendar Months” means to add 3 months from the last time the activity was performed.
Tenaska, Inc. (5)
Ballot
Comment Negative
1. The biggest concern we have with the proposed standard is the inclusion of 4.2.5.4. As written it is not
clear, but more importantly it is overly broad and provides little, if any, increase to reliability. It needs to be
deleted.
2. In Section 4.2, five types of protection systems are identified as being applicable, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance
Program (PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1
of Section 4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2
and that the language of Requirement 1 may cause confusion or be misleading. We suggest changing the
language of Requirement 1 from:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
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System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Response: Thank you for your comments.
1. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1.
2. R1 of the standard has been modified as you suggest.
Seattle City Light (1) (3) (4)
Ballot
Comment Negative
Seattle City Light (SCL) commends the Standard Drafting Team (SDT) for the many improvements in the
latest draft of proposed standard PRC-005-2. The proposed PRC-005-2 standard is an improvement over the
four standards that it will replace. Each draft has been better than that preceding, and the supporting material
is very helpful in understanding the impact and implementation of the proposed Standard. However, SCL
votes NO for this draft because of
1) the inclusion and treatment of electromechanical lockout relays within the scope of draft Standard and
2) 2) confusion about language between section 4.2 and Requirement 1.
1. Regarding electromechanical lockout relays, SCL is highly concerned about the reliability risks and
logistical difficulties associated with meeting the requirements proposed for these relays. Lockout relays
operate rarely and are known for reliable service. For many such relays, the proposed maintenance would
require clearance of entire bus sections or even multiple bus sections (such as for a bus differential lockout
relay). In SCL's opinion, the reliability risks posed by such switching and outages to the Bulk Electric
System outweigh the reliability benefits of including lockout relays in the scope of PRC-005-2. If the SDT
deems it necessary to include electromechanical lockout relays within PRC-005-2, SCL recommends that a
difference be made between the maintenance activities specified for monitored and unmonitored types. The
draft Standard describes the requirements for "electromechanical lockout and/or tripping auxiliary devices"
in Table 1-5 (p.19) and assigns a 6-year maximum maintenance interval, the same as for other
unmonitored relays. Modern electromechanical lockout relays may be specified with a built-in selfmonitoring trip-coil alarm. SCL believes the maintenance requirements for electromechanical lockout relays
with such an alarm should be similar to those for other alarmed or monitored relays. As such we
recommend that a new entry be added to Table 1-5 for monitored electromechanical lockout relays, as
follows:
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• Component Attributes: Electromechanical lockout and/or tripping auxiliary devices which are directly in a
trip path from the protective relay to the interrupting device trip coil AND include built-in self-monitoring tripcoil alarm
• Maximum Maintenance Interval: 12 calendar years
• Maintenance Activities: Verify electrical operation of electromechanical trip and auxiliary devices. Verify
that the alarm path conveys alarm signals to a location where corrective action can be initiated.
2. We also would like to comment regarding confusion over language in section 4.2.This section identifies
five types of Facilities that the standard is applicable to, whereas Requirement 1 indicates that applicable
entities need to establish a Protection System Maintenance Program (PSMP) for the Protection Systems
designed to provide protection for BES Element(s) (Part 4.2.1 of Section 4.2). As such, it is not clear if
PRC-005-2 applies to five Facilities or to certain Protection Systems. SCL believes the intent is to have a
PSMP for all Protection Systems identified in "Part A, Section 4.2 - Facilities" and that the language of
Requirement 1 may cause confusion or be misleading. We suggest changing the language of Requirement
1 from:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Facilities identified in Part A, Section 4.2.
Response: Thank you for your comments.
1. The SDT believes that performing these maintenance activities will benefit the reliability of the BES. The SDT believes that electromechanical devices having
moving parts share performance attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals. Performance-Based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
2. R1 has been modified as you suggest.
Seattle City Light (5) (6)
Ballot
Comment Negative
Seattle City Light (SCL) commends the Standard Drafting Team (SDT) for the many improvements in the
latest draft of proposed standard PRC-005-2. The proposed PRC-005-2 standard is an improvement over the
four standards that it will replace. Each draft has been better than that preceding, and the supporting material
is very helpful in understanding the impact and implementation of the proposed Standard. However, SCL
votes NO for this draft because of
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1) the inclusion and treatment of electromechanical lockout relays within the scope of draft Standard and
2) confusion about language between section 4.2 and Requirement 1.
1. Regarding electromechanical lockout relays, SCL is highly concerned about the reliability risks and
logistical difficulties associated with meeting the requirements proposed for these relays. Lockout relays
operate rarely and are known for reliable service. For many such relays, the proposed maintenance would
require clearance of entire bus sections or even multiple bus sections (such as for a bus differential lockout
relay). In SCL's opinion, the reliability risks posed by such switching and outages to the Bulk Electric
System outweigh the reliability benefits of including lockout relays in the scope of PRC-005-2. If the SDT
deems it necessary to include electromechanical lockout relays within PRC-005-2, SCL recommends that a
difference be made between the maintenance activities specified for monitored and unmonitored types. The
draft Standard describes the requirements for "electromechanical lockout and/or tripping auxiliary devices"
in Table 1-5 (p.19) and assigns a 6-year maximum maintenance interval, the same as for other
unmonitored relays. Modern electromechanical lockout relays may be specified with a built-in selfmonitoring trip-coil alarm. SCL believes the maintenance requirements for electromechanical lockout relays
with such an alarm should be similar to those for other alarmed or monitored relays. As such we
recommend that a new entry be added to Table 1-5 for monitored electromechanical lockout relays, as
follows:
• Component Attributes: Electromechanical lockout and/or tripping auxiliary devices which are directly in a
trip path from the protective relay to the interrupting device trip coil AND include built-in self-monitoring
trip-coil alarm o Maximum Maintenance Interval: 12 calendar years
• Maintenance Activities: Verify electrical operation of electromechanical trip and auxiliary devices. Verify
that the alarm path conveys alarm signals to a location where corrective action can be initiated.
2. Regarding confusion over language, section 4.2 section identifies five types of Facilities that the standard is
applicable to, whereas Requirement 1 indicates that applicable entities need to establish a Protection
System Maintenance Program (PSMP) for the Protection Systems designed to provide protection for BES
Element(s) (Part 4.2.1 of Section 4.2). As such, it is not clear if PRC-005-2 applies to five Facilities or to
certain Protection Systems. SCL believes the intent is to have a PSMP for all Protection Systems identified
in "Part A, Section 4.2 - Facilities" and that the language of Requirement 1 may cause confusion or be
misleading. We suggest changing the language of Requirement 1 from:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
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•
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Facilities identified in Part A, Section 4.2.
Response: Thank you for your comments.
1. The SDT believes that performing these maintenance activities will benefit the reliability of the BES. The SDT believes that electromechanical devices having
moving parts share performance attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals. Performance-Based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
2. R1 has been modified as you suggest.
Colorado Springs Utilities (1)
Ballot
Comment Negative
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. We suggest changing the language of
Requirement 1 from:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Even with this change, the standard is still vague given the fact that there is no clear definition of "BES" or
"Protective relay".
Response: Thank you for your comments. R1 has been modified as you suggest.
Western Electricity Coordinating
Council (10)
Ballot
Comment Affirmative
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. To address the potential for confusion we
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suggest changing the language of Requirement 1 from:
Western Electricity Coordinating
Council
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. We suggest changing the language of
Requirement 1 from:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for
BES Element(s). to:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Response: Thank you for your comments. R1 has been modified as you suggest.
California Energy Commission (9)
Entegra Power Group, LLC
(5)Idaho Power Company (1)
NorthWestern Energy (1)
Platte River Power Authority (1)
Ballot
Comment –
Affirmative
(except for
PUD of
Grant
County Negative
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. We suggest changing the language of
Requirement 1 from:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
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Question 5 Comment
•
(3) (6)
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Public Utility District No. 1 of
Douglas County (4)
Public Utility District No. 2 of
Grant County (3)
Utah Public Service Commission
(9)
Response: Thank you for your comments. The Standard has been modified as you suggest.
Tucson Electric Power Co. (1)
Ballot
Comment Negative
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). I believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. Suggest changing the language of
Requirement 1 to:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Response: Thank you for your comments. The Standard has been modified as you suggest.
Ingleside Cogeneration LP
The removal of R1.5 and R7 which required Protection System owners to identify and verify calibration
tolerances or equivalent parameters upon conclusion of a maintenance activity was fundamental to Ingleside
Cogeneration’s yes vote. The amount of ambiguity introduced by the requirements and associated
documentation did not serve to improve BES reliability in our view.
Response: Thank you for your comments.
Transmission Access Policy
The scope of the equipment to which the draft standard applies is over-broad.
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Specifically, PRC-005-2 should not apply to non-relay equipment for UFLS and UVLS systems. Subjecting
UFLS and UVLS batteries, instrument transformers, DC control circuitry, and communications to the
requirements of PRC-005-2 would drastically increase the scope of equipment covered by the standard, with
no corresponding benefit to reliability, for the following reasons. In contrast to transmission and generation
protection systems and SPSs, for which there are typically two protection systems per facility and therefore
per fault, UFLS and UVLS deal with widespread events. For any under-voltage or under-frequency event,
there are literally hundreds of UFLS/UVLS relays to respond. It is therefore far less critical if one UFLS or
UVLS relay fails to operate properly.
Furthermore, transmission is typically not radial (in fact, radials to load are excluded from the BES). But
distribution circuits, where UFLS and UVLS systems are located, are usually radial. Testing some of the nonrelay equipment to which the draft standard applies would require blacking out the customers served by that
radial. In other words, the draft standard would require entities to definitely cause blackouts in an attempt to
prevent very unlikely potential blackouts. This is plainly not justified from a harm/benefit perspective.
Finally, many of the types of non-relay equipment to which the standard would apply are in effect tested by
faults. Specifically, faults happen on distribution circuits (where UFLS and UVLS systems are located) more
frequently than on transmission circuits, due to such things as animal contacts and car accidents. Any such
fault is in fact a test of the all the equipment that is involved in clearing the fault. There is no need to require
separate tests of that equipment, any more than we would require tests of a phone line that is used on an
everyday basis; you already know that the phone works.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
Illinois Municipal Electric Agency
The scope of the equipment to which the draft standard applies is still overly broad. Specifically, PRC-005-2
should not apply to non-relay equipment for UFLS and UVLS systems. Subjecting UFLS and UVLS batteries,
instrument transformers, DC control circuitry, and communications to the requirements of PRC-005-2 would
drastically increase the scope of equipment covered by the standard, with no corresponding benefit to
reliability of the BES. This comment/recommendation is provided to address the resource and customer
service interests of a TO and/or DP systems serving distribution load. Illinois Municipal Electric Agency
supports comments submitted by the Transmission Access Policy Study Group.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure define “Reliability standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
ISO/RTO Standards Review
The SRC disagrees with the change to the term under 4.2.1. “Protection Systems designed to provide
protection for BES elements.” We support keeping the previous version’s wording of 4.2.1. “Protection
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Systems applied on, or designed to provide protection for the BES.” The revised wording expands the
fundamental purpose of the NERC PRC-005 standard from being focused on ensuring relays intended to
protect the reliability of the BES are maintained to a standard whose intent is to ensure all BES facilities have
relay maintenance programs. Although we do not disagree with maintaining all relays, regardless of what their
intended purposes are, it should not be the purpose of a NERC standard to police all protection schemes
beyond those needed for interconnected reliability. There are numerous protective relays employed on
facilities interconnected to the BES but their purpose may be for operating preference or service/equipment
quality purposes such as reclosing schemes and transformer sudden pressure relays. We believe the NERC
PRC-005 standard should be focused on maintenance of those protective relays which are needed to ensure
that the loss of a single element does not cause cascading effects on the bulk power system.
Response: Thank you for your comments. Clause 4.2.1 has been modified to improve consistency with the Interpretation that has become part of PRC-005-1a.
Duke Energy
The Standard Drafting Team has done an outstanding job on this standard. We are voting “Affirmative” but
note that implementation questions remain, particularly with regards to classifying component attributes as
“monitored,” “unmonitored,” “internal self diagnosis,” “alarming,” “alarming for excessive error” and “alarming
for excessive performance degradation”. The sheer size of the population of protective relays,
communications systems, voltage and current sensing devices, batteries, and dc supply components means
that the size of the effort required to categorize each individual component could drive us to test and maintain
on the more frequent unmonitored time intervals, simply because of the difficulty in assembling “monitored”
compliance documentation.
Response: Thank you for your comments. The opportunity to use “monitoring” to extend the intervals and reduce the activities, as well as the opportunity to use
performance-based maintenance, is provided for those entities who wish to apply the administrative resources in order to minimize the field maintenance. If
entities choose not to use those opportunities, the SDT believes that the un-monitored intervals and activities will establish an effective PSMP.
Pepco Holdings Inc
There were numerous comments submitted for each of the previous drafts indicating that the 3 month interval
for verifying unmonitored communication systems was much too short. The SDT declined to change the
interval and in their response stated: "The 3 month intervals are for unmonitored equipment and are based on
experience of the relaying industry represented by the SDT, the SPCTF and review of IEEE PSRC work.
Relay communications using power line carrier or leased audio tone circuits are prone to channel failures and
are proven to be less reliable than protective relays." Statistics on the causes of BES protective system
misoperations, however, do not support this assertion. The PJM Relay Subcommittee has been tracking
230kV and above protective system misoperations on the PJM system for many years. For the six year
period from 2002 to 2007, the number of protective system misoperations due to communication system
problems was lower (and in many cases significantly lower) than those caused by defective relays, in every
year but one. Similarly, RFC has conducted an analysis of BES protection system misoperations for 2008
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Question 5 Comment
and 2009, and found the number of misoperations caused by communication system problems to be in line
with the number attributed to relay related problems. If unmonitored protective relays have a 6 year maximum
maintenance/inspection interval, it does not seem reasonable to require the associated communication
system to be inspected 24 times more frequently, particularly when relay failures are statistically more likely to
cause protective system misoperations. As such, a 12 or 18 calendar month interval for inspection of
unmonitored communication systems would seem to be more appropriate. FAQ II 6 B states that the concept
should be that the entity verify that the communication equipment...is operable through a cursory inspection
and site visit. However, unlike FSK schemes where channel integrity can easily be verified by the presence
of a guard signal, ON-OFF carrier schemes would require a check-back or loop-back test be initiated to verify
channel integrity. If the carrier set was not equipped with this feature, verification would require personnel to
be dispatched to each terminal to perform these manual checks. The SDT responded that they still felt the 3
month interval as stated in the standard was appropriate. PHI respectfully requests that the SDT reconsider
this issue and also cite what "specific statistical data" they used to validate that unmonitored communication
systems are 24 times more prone to failure than unmonitored protective relays.
Response: Thank you for your comments.
The SDT believes that relay communications channels are more susceptible to failure from an outside influence than a protective relay. Leased circuits from
communications providers and carrier channels are highly exposed to lightning, automobiles, backhoes, etc. We believe the existing statistics from PJM and RFC
on relay communications system based misoperation causes is due to the present practice of periodic channel verifications being performed. Many utilities
presently use channel monitoring and carrier checkbacks to ensure reliable operation.
Liberty Electric Power LLC (5)
Ballot
Comment Negative
While the SDT has done a very good job at responding to the most objectionable parts of the previous
version, there are still a number of issues which makes the standard problematic.
1. The standard introduces the term "initiate resolution". This is an interpretable term, and has the potential for
an auditor and an entity to disagree on an action. Would issuing a work order be considered "initiating
resolution"? What if the WO had a completion date many years into the future? I would suggest adding the
term to the list of definitions which will remain with the standard, and defining it as "performing any task
associated with conducting maintenance activities, including but not limited to issuing purchase orders,
soliciting bids, scheduling tasks, issuing work requests, and performing studies".
2. Some clarity is needed to differentiate system connected and generator connected station service
transformers. A statement that a station service transformer connected radially to the generator bus is
considered a system connected transformer if the transformer cannot be used for service unless connected
to the BES.
3. The "bookends" issue, brought up in the prior round of comments, still exists. Although the SDT rightly
notes a CAN has been issued regarding bookends, the CAN covers the documentation for system
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components that entities were required to self-certify to on June 18, 2007. PRC-005-2 adds additional
components to the protection system scheme which were not part of that certification, and has the potential
to put entities into violation space due to a lack of records for those components.
4. The SDT should add to M3 a statement that entities may demonstrate compliance with the standard by
demonstrating that required activities took place twice within the maximum maintenance interval -starting
from the effective date of the standard - for all components not listed in PRC-005-1.
Response: Thank you for your comments.
1. The SDT believes that issuing a work order would satisfy this requirement. M3 presents several examples of relevant evidence. The SDT has considered that,
while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even several years) to complete
effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with other standards. The SDT
is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these more extended activities to
“correct the maintenance correctable issue”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues and
rely on the operating focus on the degraded system to ensure that they are completed.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
3. The Implementation Plan specifies that entities may implement PRC-005-2 incrementally throughout the intervals specified, and that they shall follow their
existing program for components not yet implemented. The SDT believes that the “bookends” issue to which you refer is therefore addressed.
4. The Standard requires that activities only take place once within the established interval.
SPP reliability standard
development Team
Would like more clarification in table 1-5 to address verification tests on different circuits. Is this an end to end
test or partial test can you test one part of the circuit one way and another a different way? Should table 1-5
read Complete a terminal test of unmonitored circuitry?
Response: Thank you for your comments. The SDT does not believe that the suggested text adds clarity to the standard. Please see Section 15.3 of the
Supplementary Reference Document for additional discussion.
Lakeland Electric (1)
Ballot
Comment Negative
The new PRC-005-2 includes non-relay components into UFLS and UVLS. The problem is, for UFLS and
UVLS, these non-relay components are mostly distribution class equipment; hence, the result of this version 2
standard will be inclusion of most distribution class protection system components into PRC-005-2. This is a
huge expansion of the scope of equipment covered by the standard with negligible benefit to BES reliability.
While Lakeland Electric agrees wholeheartedly with the inclusion of non-relay components for BES Protection
Systems. It is critical that BES Protection Systems work and clear the fault (e.g., on > 100 kV Facilities).
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However, UFLS and UVLS are quite different. For an event requiring UFLS and UVLS operation, there are
many, e.g., hundreds and possibly thousands of relays, that operate to shed load automatically and if a small
percentage of those do not operate as expected, the impact is minimal. So, it is not important for BES
reliability to include non-relay components of UFLS and UVLS in the PRC-005-2 standard.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
City of Bartow, Florida (3)
Ballot
Comment Negative
There is an unnecessary expansion of the scope of equipment covered by this standard into the distribution
system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument transformers, DC
control circuitry and communications in addition to the relays for BES protection systems. PRC-008 (UFLS)
and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included in those standards.
The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The problem is, for UFLS
and UVLS, these non-relay components are mostly distribution class equipment; hence, the result of this
version 2 standard will be inclusion of most distribution class protection system components into PRC-005-2.
This is a huge expansion of the scope of equipment covered by the standard with negligible benefit to BES
reliability. We agree wholeheartedly with the inclusion of non-relay components for BES Protection Systems.
It is critical that BES Protection Systems work and clear the fault (e.g., on > 100 kV Facilities). However,
UFLS and UVLS are quite different. For an event requiring UFLS and UVLS operation, there are many, e.g.,
hundreds and possibly thousands of relays, that operate to shed load automatically and if a small percentage
of those do not operate as expected, the impact is minimal. So, it is not important for BES reliability to include
non-relay components of UFLS and UVLS in the PRC-005-2 standard. In addition, testing of protection
systems on distribution circuits is difficult for distribution circuits that are radial in nature. For instance, testing
trip coils of a distribution breakers will likely results in service interruption to customers on that distribution
circuit in order to test the breaker or to perform break-before-make switching on the distribution system often
required to manage maximum available fault current on the distribution system for worker safety, etc.. Hence,
the standard would be sacrificing customer service quality for an infinitesimal increase in BES reliability. In
addition, non-relay protection components operate much more frequently on distribution circuits than on
transmission Facilities due to more frequent failures due to trees, animals, lightning, traffic accidents, etc., and
have much less of a need for testing since they are operationally tested.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
Lakeland Electric (6)
Ballot
Comment -
Unnecessary expansion of the scope of equipment covered by this standard into the distribution system
related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument transformers, DC control
circuitry and communications in addition to the relays for BES protection systems. PRC-008 (UFLS) and
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Negative
PRC-011 (UVLS) are ambiguous as to whether non-relay components are included in those standards. The
new PRC-005-2 includes these non-relay components into UFLS and UVLS. The problem is, for UFLS and
UVLS, these non-relay components are mostly distribution class equipment; hence, the result of this version 2
standard will be inclusion of most distribution class protection system components into PRC-005-2. This is a
huge expansion of the scope of equipment covered by the standard with negligible benefit to BES reliability.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
Beaches Energy Services (1)
Ballot
Comment Negative
We believe that there is an unnecessary expansion of the scope of equipment covered by this standard into
the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included in
those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment; hence,
the result of this version 2 standard will be inclusion of most distribution class protection system components
into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard with negligible
benefit to BES reliability. We agree wholeheartedly with the inclusion of non-relay components for BES
Protection Systems. It is critical that BES Protection Systems work and clear the fault (e.g., on > 100 kV
Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS and UVLS operation,
there are many, e.g., hundreds and possibly thousands of relays, that operate to shed load automatically and
if a small percentage of those do not operate as expected, the impact is minimal. So, it is not important for
BES reliability to include non-relay components of UFLS and UVLS in the PRC-005-2 standard. In addition,
testing of protection systems on distribution circuits is difficult for distribution circuits that are radial in nature.
For instance, testing trip coils of distribution breakers will likely result in service interruption to customers on
that distribution circuit in order to test the breaker or to perform break-before-make switching on the
distribution system often required to manage maximum available fault current on the distribution system for
worker safety, etc.. Hence, the standard would be sacrificing customer service quality for an infinitesimal
increase in BES reliability. In addition, non-relay protection components operate much more frequently on
distribution circuits than on Transmission Facilities due to more frequent failures due to trees, animals,
lightning, traffic accidents, etc., and have much less of a need for testing since they are operationally tested.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
Keys Energy Services (1)
Ballot
Comment -
1. KEYS believes that there is an unnecessary expansion of the scope of equipment covered by this standard
into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
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Negative
Question 5 Comment
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included
in those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment;
hence, the result of this version 2 standard will be inclusion of most distribution class protection system
components into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard
with negligible benefit to BES reliability. KEYS agrees wholeheartedly with the inclusion of non-relay
components for BES Protection Systems. It is critical that BES Protection Systems work and clear the fault
(e.g., on > 100 kV Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS
and UVLS operation, there are many, e.g., hundreds and possibly thousands of relays, that operate to shed
load automatically and if a small percentage of those do not operate as expected, the impact is minimal.
So, it is not important for BES reliability to include non-relay components of UFLS and UVLS in the PRC005-2 standard. In addition, testing of protection systems on distribution circuits is difficult for distribution
circuits that are radial in nature. For instance, testing trip coils of a distribution breakers will likely results in
service interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault current
on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing customer service
quality for an infinitesimal increase in BES reliability. In addition, non-relay protection components operate
much more frequently on distribution circuits than on transmission Facilities due to more frequent failures
due to trees, animals, lightning, traffic accidents, etc., and have much less of a need for testing since they
are operationally tested.
2. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
Lakeland Electric (3)
Ballot
Comment Negative
1. LAK believes that there is an unnecessary expansion of the scope of equipment covered by this standard
into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included
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in those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment;
hence, the result of this version 2 standard will be inclusion of most distribution class protection system
components into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard
with negligible benefit to BES reliability. LAK agrees wholeheartedly with the inclusion of non-relay
components for BES Protection Systems. It is critical that BES Protection Systems work and clear the fault
(e.g., on > 100 kV Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS
and UVLS operation, there are many, e.g., hundreds and possibly thousands of relays, that operate to shed
load automatically and if a small percentage of those do not operate as expected, the impact is minimal.
So, it is not important for BES reliability to include non-relay components of UFLS and UVLS in the PRC005-2 standard. In addition, testing of protection systems on distribution circuits is difficult for distribution
circuits that are radial in nature. For instance, testing trip coils of a distribution breakers will likely results in
service interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault current
on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing customer service
quality for an infinitesimal increase in BES reliability. In addition, non-relay protection components operate
much more frequently on distribution circuits than on transmission Facilities due to more frequent failures
due to trees, animals, lightning, traffic accidents, etc., and have much less of a need for testing since they
are operationally tested.
2. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
City of Green Cove Springs (3)
Ballot
Comment Negative
1. GCS believes that there is an unnecessary expansion of the scope of equipment covered by this standard
into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included
in those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment;
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hence, the result of this version 2 standard will be inclusion of most distribution class protection system
components into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard
with negligible benefit to BES reliability. GCS agrees wholeheartedly with the inclusion of non-relay
components for BES Protection Systems. It is critical that BES Protection Systems work and clear the fault
(e.g., on > 100 kV Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS
and UVLS operation, there are many, e.g., hundreds and possibly thousands of relays, that operate to shed
load automatically and if a small percentage of those do not operate as expected, the impact is minimal.
So, it is not important for BES reliability to include non-relay components of UFLS and UVLS in the PRC005-2 standard. In addition, testing of protection systems on distribution circuits is difficult for distribution
circuits that are radial in nature. For instance, testing trip coils of a distribution breakers will likely results in
service interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault current
on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing customer service
quality for an infinitesimal increase in BES reliability. In addition, non-relay protection components operate
much more frequently on distribution circuits than on transmission Facilities due to more frequent failures
due to trees, animals, lightning, traffic accidents, etc., and have much less of a need for testing since they
are operationally tested.
2. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
Gainesville Regional Utilities (1)
Ballot
Comment Negative
GRU (GVL) agrees with the following comments provided by the FMPA:
1. FMPA believes that there is an unnecessary expansion of the scope of equipment covered by this standard
into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included
in those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment;
hence, the result of this version 2 standard will be inclusion of most distribution class protection system
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components into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard
with negligible benefit to BES reliability. FMPA agrees wholeheartedly with the inclusion of non-relay
components for BES Protection Systems. It is critical that BES Protection Systems work and clear the fault
(e.g., on > 100 kV Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS
and UVLS operation, there are many, e.g., hundreds and possibly thousands of relays, that operate to shed
load automatically and if a small percentage of those do not operate as expected, the impact is minimal.
So, it is not important for BES reliability to include non-relay components of UFLS and UVLS in the PRC005-2 standard. In addition, testing of protection systems on distribution circuits is difficult for distribution
circuits that are radial in nature. For instance, testing trip coils of a distribution breakers will likely results in
service interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault current
on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing customer service
quality for an infinitesimal increase in BES reliability. In addition, non-relay protection components operate
much more frequently on distribution circuits than on transmission Facilities due to more frequent failures
due to trees, animals, lightning, traffic accidents, etc., and have much less of a need for testing since they
are operationally tested.
2. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
Alliant Energy
1. If PRC-005-2 is going to incorporate PRC-008 (UFLS) and PRC-011 (UVLS) the Purpose needs to be
revised to include Distribution Protection Systems designed to protect the BES.
2. We do not believe a distribution relaying system, designed to protect the distribution assets, that may open
a transmission element (ie; breaker failure) should be considered part of the BES Protection System. R1
should add the following sentence “Distribution Protection Systems intended solely for the protection of
distribution assets are not included as a BES Protection System, even if they may open a BES Element.”
3. Table 1-5 (Component Type - Control Circuitry) Item 4 “Unmonitored control circuitry associated with
protective functions” require a 12 calendar year maximum maintenance interval. We believe UFLS and
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UVLS control circuitry should be exempted from this requirement. It would take multiple failures to have
any impact, and the impact on the BES would be minimal.
Response: Thank you for your comments.
1. There is no distinction in the purpose between “Distribution Protection Systems” and “Transmission Protection Systems”. The SDT believes that the
Applicability appropriately describes both the entities and the facilities.
2. The SDT modified Applicability 4.2.1 for better consistency with the interpretation that is reflected in PRC-005-1a, and believes that this change may address
your concern.
3. The Table 1-5 activities for UFLS/UVLS are constrained to those activities that the SDT considers to be appropriate relative to the reliability impact of these
applications. Please see Section 15.3 of the Supplemental Reference Document for additional discussion on this topic.
Y-W Electric Association, Inc. (4)
Ballot
Comment Affirmative
Y-WEA thanks the SDT for its long, hard work on this standard and for its consideration of previous
comments.
Response: Thank you for your comments.
BGE
PNGC Power
No comments.
Thank you for the opportunity to comment on the draft Standard PRC-005-2 – Protection System Maintenance.
We appreciate the work that NERC has put into a new standard to encapsulate and replace the current PRC005, PRC-008, PRC-011 and PRC-017. But, we believe that the draft Standard needs one important revision
before the NERC Board of Trustees should approve it.
Specifically, NERC should revise the draft version of PRC-005-2 so that the beginning of Section 4.2 reads as
follows:
“4.2. Facilities:
Protection Systems that (1) are not facilities used in the local distribution of electricity, (2) are
facilities and control systems necessary for operating an interconnected electric energy
transmission network, and (3) are any of the following:”
This revision is necessary to capture the limits that Congress placed on FERC, NERC, and the Regional Entities
in developing and enforcing mandatory reliability standards. Specifically, Section 215(i) of the Federal Power Act
provides that the Electric Reliability Organization (ERO) “shall have authority to develop and enforce compliance
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with reliability standards for only the Bulk-Power System.” And, Section 215(a)(1) of the statute defines the term
“Bulk-Power System” or “BPS” as: (A) facilities and control systems necessary for operating an interconnected
electric energy transmission network (or any portion thereof); and (B) electric energy from generation facilities
needed to maintain transmission system reliability. The term does not include facilities used in the local
distribution of electric energy.”
With this language, Congress expressly limited FERC, NERC, and the Regional Entities’ jurisdiction with regard
to local distribution facilities as well as those facilities not necessary for operating a transmission network. Given
that these facilities are statutorily excluded from the definition of the BPS, reliability standards may not be
developed or enforced for facilities used in local distribution.
In Order No. 672, FERC adopted the statutory definition of the BPS. In Order No. 743-A, issued earlier this year,
the Commission acknowledged that “Congress has specifically exempted ‘facilities used in the local distribution
of electric energy’” from the BPS definition. FERC also held that to the extent any facility is a facility used in the
local distribution of electric energy, it is exempted from the requirements of Section 215.
In Order No. 743-A, FERC delegated to NERC the task of proposing for FERC approval criteria and a process to
identify the facilities used in local distribution that will be excluded from NERC and FERC regulation. The critical
first step in this process is for NERC to propose criteria for approval by FERC to determine which facilities are
used in local distribution, and are therefore not BPS facilities. The criteria to be developed by NERC must
exclude any facilities that are used in the local distribution of electric energy, because all such facilities are
beyond the scope of the statutory definition of the BPS, which establishes the limit of FERC and NERC
jurisdiction. Accordingly, it is critical that NERC draft the new PRC-005-2 standard to expressly exclude facilities
used in local distribution.
NERC must also expressly exclude from PRC-005-2 those facilities “not necessary for operating an
interconnected electric energy transmission network (or any portion thereof)”. Similar to the local distribution
exclusion, the facilities not necessary for operating a transmission network are not part of the BPS and therefore
must be expressly excluded from the standard.
We understand, but disagree with, the argument that, because the FPA clearly excludes local distribution
facilities and facilities necessary for operating an interconnected electric transmission network from FERC,
NERC, and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in reliability
standards. This approach might be legally accurate, but could lead to significant confusion for entities attempting
to implement the new PRC-005-2 standard. There are numerous examples of Regional Entities, particularly
WECC, attempting to assert jurisdiction over such facilities, and regulated entities face significant uncertainty as
to which facilities they should consider as within jurisdiction. Clarifying FERC, NERC, and Regional Entity
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jurisdiction in the BES definition, even if such clarification is already provided in the FPA, would avoid such
problems under the new PRC-005-2 standard.
Again, we appreciate the work NERC has put in so far on a new Standard. We look forward to working within
the drafting process to help implement our recommended revision.
Response: Thank you for your comments. The SDT has revised R1 to refer to Applicability 4.2. The SDT believes that your comments are otherwise already
reflected in the Standard, and that no further changes are necessary. The Standard currently addresses maintenance of all Protection Systems that are applied
on or to protect BES elements, as well as maintenance of UFLS installed for the BES per PRC-007, UVLS installed on or for the BES per PRC-010, and Special
Protection Systems installed on or for the BES per PRC-012, PRC-013, PRC-014, and PRC-015. Therefore, the Standard is already constrained as you suggest.
Additionally, Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power
system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
ReliabilityFirst
Ballot
Comment Affirmative
ReliabilityFirst votes affirmative but offers the following suggestions/comments:
1. R3 should be split into two separate requirements since there are two distinct actions being requested (e.g.
“…shall implement and follow its PSMP” is one requirement and “… shall initiate resolution of any identified
maintenance correctable issues” is the second requirement.
2. There are a number of terms which are defined only for the use of the PRC-005-2 standard which will not be
moved to the Glossary of Terms., and even though I completely agree with this concept, I believe this concept
is not mentioned nor is it allowed per the NERC Standard Processes Manual.
Response: Thank you for your comments.
1. The SDT believes that the two activities are intertwined and should remain within a single requirement.
2. The SDT has been advised by NERC Standards staff that this is acceptable, and has adopted the methodology for doing so as suggested by staff.
136
Consideration of Comments
Protection System Maintenance and Testing – Project 2007-17
The Protection System Maintenance and Testing Drafting Team would like to thank all commenters
who submitted comments on the first draft of the PRC-005-2 standard for Protection System
Maintenance and Testing (Project 2007-17). This standard and its associated documents were posted
for a 45-day public comment period from August 15, 2011 through September 29, 2011. Stakeholders
were asked to provide feedback on the standard and associated documents through a special
electronic comment form. There were 48 sets of comments, including comments from approximately
147 different people and approximately 98 companies representing 9 of the 10 Industry Segments as
shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards and Training, Herb Schrayshuen, at 404446-2560 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process. 1
Summary Consideration of all Comments Received:
SAR:
The SDT made several changes to the SAR. The proposed title of the standard was changed to
‘Protection System Maintenance’; Reliability Principle item #4 was removed as it does not apply to the
standard; and the ‘Transmission and Generation’ descriptor of Protection Systems was removed from
the Detailed Description area of the SAR.
Applicability:
The SDT revised Applicability 4.2.5.4 to indicate that, for generator-connected station service
transformers, only the Protection Systems that trip the generator, either directly or via a lockout relay,
are included in the standard.
Requirements:
Requirement R1 part 1.3 has been removed.
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_20110825.pdf.
The SDT split Requirement R3 into three separate requirements for better clarity.
Requirement R3 has been revised so that, for time-based programs, entities must comply with the
standard’s tables rather than their PSMP. Requirement R3 now reads:
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System components that are
included within the time-based maintenance program in accordance with the minimum
maintenance activities and maximum maintenance intervals prescribed within Tables 1-1
through 1-5, Table 2, and Table 3.
Requirement R4 has been added to address performance-based maintenance. The new Requirement
R4 is as follows:
Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System components that are included within
the performance-based program.
R4.
Requirement R5 has been added to address Unresolved Maintenance Issues. The definition of the term
‘Unresolved Maintenance Issues’ has been enhanced for additional clarity, and now reads:
Unresolved Maintenance Issue - A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance and requires follow-up corrective
action.
The new Requirement R5 is as follows:
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues.
Measures
The SDT revised and drafted new measures to comport with the requirements.
Tables
Most commenters seemed to agree in general that the restructured Tables added clarity and some
commenters offered suggestions for further improvement. Minor clarifying changes were made to the
Tables themselves, and additional discussion was added to the “Supplementary Reference and FAQ”
document to address various comments.
In Table 1-5 (Component Type - Control Circuitry Associated With Protective Functions), the SDT
removed the auxiliary relays from the 6 year periodic maintenance associated with electromechanical
lockout devices, and included them in the 12 year periodic maintenance associated with the
unmonitored control circuitry associated with protective functions.
Table 1-4(f) was modified to more accurately represent the monitoring attributes and related activities
for monitored Vented Lead-Acid and Valve-Regulated Lead-Acid batteries.
2
Implementation Plan
Minor clarifying changes were made to the Implementation Plan.
VLSs:
Changes were made to the make the VSLs conform to the new and changed requirements.
Supplementary Reference Document
Changes were made to the “Supplementary Reference and FAQ” document, corresponding to all
changes to the standard.
Unresolved Minority Views:
•
A few commenters continued to object to the establishment of maximum allowable intervals for
the maintenance of various Protection System component types. The SDT continued to respond
that FERC Order 693 and the approved SAR direct the SDT to develop a standard with maximum
allowable intervals and minimum maintenance activities. The SDT believes that the intervals
established within the Tables are appropriate as continent-wide maximum allowable intervals.
•
Several commenters were concerned that an entity has to be “perfect” in order to be compliant;
the SDT responded that NERC Standards currently allow no provision for any degree of nonperformance relative to the requirements.
•
Several commenters continued to insist that “grace periods” should be allowed. The SDT continued
to respond that grace periods would not be measurable.
•
Several commenters continued to question the propriety of including distribution system
Protection Systems, almost all related to UFLS/UVLS. The SDT obtained a position from NERC legal
staff, and cited this position in responding that these devices are indeed within NERC’s authority
because they are installed for the reliability of the BES.
•
A few commenters questioned the inclusion of the direct current (dc) control circuitry for sudden
pressure relays even though the relays themselves are excluded from the definition of “Protection
System”; the SDT reiterated its position that this dc control circuitry is included because the dc
control circuitry is associated with protective functions.
•
A few commenters objected to the language in the Data Retention section regarding the retention
of the maintenance records for two full intervals. The SDT explained that this expectation is
consistent with the Compliance Monitoring and Enforcement Program.
3
Index to Questions, Comments, and Responses
1.
Do you have any comments regarding the existing SAR for this project? .................................11
2.
In response to comments, the term “Maintenance Correctable Issue” was revised to “Unresolved
Maintenance Issue”. Do you agree with this change? If you do not agree, please provide specific
suggestions for improvement. .........................................................................................19
3.
In response to comments, the SDT revised the previous “3 calendar months” interval to “4
calendar months” for communications systems and station dc supply. Do you agree with this
change? If you do not agree, please provide specific suggestions for improvement. ..................29
4.
The SDT extracted the maintenance activities and intervals for distributed UFLS and UVLS systems
from Table 1-1 through 1-5 and placed them into a new Table 3 to more clearly illustrate the
requirements related to these systems. Do you agree with this change? If you do not agree, please
provide specific suggestions for improvement. ...................................................................39
5. The SDT has revised the “Supplementary Reference and FAQ” document which is supplied to
provide supporting discussion for the Requirements within the standard. Do you agree with the
changes? If not, please provide specific suggestions for change. ............................................55
6.
If you have any other comments on this Standard that you have not already provided in response
to the prior questions, please provide them in the comment section. ...................................79
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC NPCC 10
2.
Gregory Campoli
New York Independent System Operator NPCC 2
3.
Kurtis Chong
Independent Electricity System Operator NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Michael Schiavone
National Grid
NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7.
Brian Evans-Mongeon Utility Services
NPCC 8
8.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
9.
Kathleen Goodman
ISO - New England
NPCC 2
FPL Group, Inc.
NPCC 5
10. Chantel Haswell
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. David Kiguel
Hydro One Networks Inc.
NPCC 1
12. Michael Lombardi
Northeast Utilities
NPCC 1
13. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
14. Bruce Metruck
New York Power Authority
NPCC 6
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
16. Robert Pellegrini
The United Illuminating Company
NPCC 1
17. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
19. Saurabh Saksena
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Donald Weaver
New Brunswick System Operator
NPCC 2
22. Ben Wu
Orange and Rockland Utilities
NPCC 1
2.
Group
Dave Davidson
Tennessee Valley Authority
2
3
4
X
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Rusty Harison
TOM Support
SERC
1
2. Pat Caldwell
TOM Support
SERC
1
3. Paul Barnett
Tom Support
SERC
1
4. David Thompson
TVA Compliance
SERC
5
5. Jerry Finley
Power Control Systems
SERC
1
6. Frank Cuzzort
TVA Generation - Nuclear SERC
5
7. Robert Brown
TVA Generation - Nuclear SERC
5
8. Roberts Mares
TVA Generation - Fossil
SERC
5
9. Annette Dudley
TVA Generation - Hydro
SERC
5
3.
Group
Additional Member
Ron Sporseen
PNGC Comment Group
Additional Organization
X
X
X
X
Region Segment Selection
1.
Bud Tracy
Blachly-Lane Electric Cooperative WECC 3
2.
Dave Markham
Central Electric Cooperative
WECC 3
3.
Dave Hagen
Clearwater Power
WECC 3
4.
Roman Gillen
Consumer's Power
WECC 1, 3
5.
Roger Meader
Coos-Curry Electric Cooperative
WECC 3
6.
Dave Sabala
Douglas Electric Cooperative
WECC 3
6
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
7.
Bryan Case
Fall River Electric Cooperative
WECC 3
8.
Rick Crinklaw
Lane Electric Cooperative
WECC 3
9.
Michael Henry
Lincoln Electric Cooperative
WECC 3
10. Richard Reynolds
Lost River
WECC 3
11. Jon Shelby
Northern Lights
WECC 3
12. Ray Ellis
Okanogan Electric Cooperative
WECC 3
13. Aleka Scott
PNGC Power
WECC 4
14. Heber Carpenter
Raft River Electric Cooperative
WECC 3
15. Ken Dizes
Salmon River Electric Cooperative WECC 1, 3
16. Steve Eldrige
Umatilla Electric Cooperative
17. Marc Farmer
West Oregon Electric Cooperative WECC 3
18. Margaret Ryan
PNGC Power
WECC 8
19. Stuart Sloan
Consumer's Power
WECC 1
4.
Chris Higgins
Group
Additional Member
SPC Technical Svcs
WECC 1
2. John Kerr
Technical Operations
WECC 1
3. Lorissa Jones
Transmission Internal Ops
WECC 1
4. Greg Vassallo
Customer Service Engineering WECC 1
5. Mason Bibles
Sub Maint and HV Engineering WECC 1
6. Deanna Phillips
FERC Compliance
WECC 1, 3, 5
Mike Garton
Dominion
Group
Additional Member
Additional Organization
Virginia Electric and Power Company SERC
1, 3
2. Michael Gildea
Dominion Resources Services, Inc.
MRO
5
3. Louis Slade
Dominion Resources Services, Inc.
RFC
5
Group
Sam Ciccone
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
Region Segment Selection
1. Michael Crowley
6.
4
Region Segment Selection
1. Dean Bender
5.
3
WECC 3, 1
Bonneville Power Administration
Additional Organization
2
FirstEnergy
X
Additional Member Additional Organization Region Segment Selection
1. Jim Kinney
FE
RFC
1
2. Craig Boyle
FE
RFC
1
3. Frank Hartley
FE
RFC
1
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Bill Duge
FE
RFC
5
5. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
7.
Group
Southwest Power Pool Standards Review
Group
Robert Rhodes
Additional Member
Additional Organization
City Utilities of Springfield, Missouri
2. Forrest Brock
Western Farmers Electric Cooperative SPP
1, 3, 5
3. Anthony Cassmeyer Western Farmers Electric Cooperative SPP
1, 3, 5
4. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
5. Louis Guidry
CLECO Power
SPP
1, 3, 5
6. Jonathan Hayes
Southwest Power Pool
SPP
2
7. Terri Pyle
Oklahoma Gas & Electric
SPP
1, 3, 5
8. Ashley Stringer
Oklahoma Municipal Power Authority SPP
Group
Frank Gaffney
3
4
5
6
7
8
9
10
X
Region Segment Selection
1. John Allen
8.
2
SPP
1, 4
4
Florida Municipal Power Agency
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority FRCC
3
3. Jim Howard
Lakeland Electric
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
FRCC
9.
Group
Mallory Huggins
No additional members listed.
NERC Staff Technical Review
10.
Pepco Holdings Inc & Affiliates
Group
David Thorne
Additional Member Additional Organization Region Segment Selection
1. Carlton Bradshaw
11.
Delmarva Power and Light RFC
Group
Additional Member
Carol Gerou
1
MRO's NERC Standards Review Forum
Additional Organization
X
Region Segment Selection
1.
Mahmood Safi
Omaha Public Utility District
MRO
1, 3, 5, 6
2.
Chuck Lawrence
American Transmission Company
MRO
1
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
Tom Webb
Wisconsin Public Service Corporation MRO
3, 4, 5, 6
4.
Jodi Jenson
Western Area Power Administration
MRO
1, 6
5.
Ken Goldsmith
Alliant Energy
MRO
4
6.
Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
7.
Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
8.
Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
9.
Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
10. Scott Nickels
Rochester Public Utilties
MRO
4
11. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
12. Marie Knox
Midwest ISO Inc.
MRO
2
13. Lee Kittelson
Otter Tail Power Company
MRO
1, 3, 4, 5
14. Scott Bos
Muscatine Power and Water
MRO
1, 3, 5, 6
15. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
16. Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
12.
Jason Marshall
Group
Additional Member
Additional Organization
2
3
4
5
ACES Power Collaborators
6
7
8
10
X
Region Segment Selection
1. James Jones
AEPCO/SWTC
2. Lindsay Shepard
Sunflower Electric Power Corporation SPP
WECC 1, 3, 5
1, 3, 5
Individual
14. Individual
Janet Smith, Regulaory
Compliance Supervisor
Bill Shultz
Arizona Public Service Company
Southern Company Generation
X
15.
Individual
Bo Jones
Westar Energy
16.
Individual
Max Emrick
Tacoma Power
X
X
X
X
17.
Individual
Jim Eckelkamp
Progress Energy
X
X
18.
Individual
Brandy A. Dunn
Western Area Power Administration
X
19.
Individual
Sandra Shaffer
PacifiCorp
X
20.
Individual
Mary Jo Cooper
ZGlobal Engineering and Energy Solutions
X
21.
Individual
Nicholas R. Finney
Saft America, Inc.
X
22.
Individual
Tony Eddleman
Nebraska Public Power District
13.
9
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
9
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
23.
Individual
X
John Bee
Exelon
Individual
25. Individual
Don Jones
Steve Alexanderson
Texas Reliability Entity
Central Lincoln
26.
Individual
Dan Roethemeyer
Dynegy Inc.
27.
Individual
Thad Ness
American Electric Power
X
28.
Individual
Eric Ruskamp
Lincoln Electric System
29.
Individual
Joe O'Brien
30.
Individual
31.
24.
2
3
4
X
5
6
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
NIPSCO
X
X
X
X
Edward Davis
Entergy Services
X
X
X
X
Individual
Michael Falvo
Independent Electricity System Operator
32.
Individual
Daniel Duff
Liberty Electric Power LLC
33.
Individual
Kirit Shah
Ameren
X
X
X
34.
Individual
Michael Lombardi
Northeast Utilities
X
X
X
35.
Individual
Gary Kruempel
MidAmerican Energy Company
X
X
X
36.
Individual
Joe Petaski
Manitoba Hydro
X
X
X
37.
Individual
Andrew Z. Pusztai
American Transmission Company
X
38.
Individual
Antonio Grayson
Southern Company Transmission
X
X
X
39.
Individual
Brian Evans-Mongeon
Utility Services, Inc
40.
Individual
Michael Moltane
ITC Holdings
Individual
42. Individual
Michelle D'Antuono
Armin Klusman
Igleside Cogeneration LP
CenterPoint Energy
X
43.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
44.
Individual
Tracy Richardson
Springfield Utility Board
45.
Individual
Andrew Gallo
City of Austin dba Austin Energy
X
46.
Individual
Gerry Schmitt
BGE
X
47.
Individual
Amir Hammad
Constellation Power Generation
48.
Individual
Brenda Powell
Constellation Energy Commodities Group
41.
7
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10
1.
Do you have any comments regarding the existing SAR for this project?
Summary Consideration: In response to the comments, the SDT made several changes to the SAR.
1.
The proposed title of the standard was changed to ‘Protection System Maintenance.’
2
Reliability Principle item #4 was removed as it does not apply to the standard.
3
The ‘Transmission and Generation’ descriptor of Protection Systems was removed from the Detailed Description area of the
SAR.
Several comments were offered, suggesting that the SAR address validating the accuracy of settings calculations provided to the
field test personnel. The SDT declined to modify the SAR because they believe validating the accuracy of settings as provided to
testing personnel is an internal management issue that should be addressed by the entity, and is beyond the scope of a
‘maintenance and testing’ standard.
Several comments were offered, suggesting that “the requirements should reflect the inherent differences between various
protection system technologies,” however the requirements should not mandate different testing methods and testing intervals
based on that technology.” The SDT declined to modify the SAR because they believe the current PRC-005-2 draft does not
mandate specific testing methods; the responsible entity has latitude in establishing its PSMP. Specific activities (such as those for
various technologies of “station dc supply”) are prescribed, but the entity still has discretion in determining the most appropriate
method of conducting those activities.
Organization
Yes or No
Northeast
Power
Coordinating
Council
Yes
Question 1 Comment
Maintenance and testing of protection systems is the final step in the process that begins with the
calculation of settings. The calculation of settings is followed by the application of those settings
to the equipment. Maintenance and testing ensures that the settings given to testing personnel
have been applied as given. This Standard addresses the Maintenance and Testing of protection
systems. It should also address the need to validate the accuracy of the settings given to the field.
A statement should be added to the SAR to address this need.
Response: Thank you for your comment. You are correct in your observation that the standard, as established in the project
scope, addresses the maintenance and testing of Protection Systems. The SDT believes validating the accuracy of settings as
11
Organization
Yes or No
Question 1 Comment
provided to testing personnel is an internal management issue that should be addressed by the entity, and is beyond the scope
of a ‘maintenance and testing’ standard. Thus, the SDT does not believe that the SAR should be modified.
ZGlobal
Engineering
and Energy
Solutions
Yes
Table 1-4(a-c) excludes distributed UFLS and UVLS for batteries but references Table 3. Table 3
does not mention an interval for batteries. Is this an error?
Response: Thank you for your comment. In Table 3 we address the dc supply for tripping only non-BES interrupting devices as
part of the UFLS and UVLS system. Table 3 explicitly limits the activities and intervals for station dc supply (relative to
distributed UVLS/UFLS) to verifying the Protection System dc supply voltage every 12 calendar years, and requires nothing
beyond that for station batteries in this application. This is not an error within the standard.
Utility Services,
Inc
Yes
We would urge that the SAR be modified to include Validation of Protection System settings.
Presently, the standard does not provide for the explicit validation of the settings and it is
possible that such mis-settings could be the reason for a misoperation. If a validation of the
settings was explicitly called for in the standard, then the misoperation would be less likely to
occur for that reason.
Response: Thank you for your comment. The SDT believes validating the accuracy of settings as provided to testing personnel is
an internal management issue that should be addressed by the entity, and is beyond the scope of a ‘maintenance and testing’
standard. Thus, the SDT does not believe that the SAR should be modified. If this becomes a “Misoperation” problem for the
entity, NERC Reliability Standard PRC-004-2 requires the entity to develop and implement a Corrective Action Plan to address
the cause of the Misoperation.
Constellation
Power
Generation
Yes
Although Constellation Power Generation agrees with some of the refinements prescribed in the
SAR, there are a few items of concern. Constellation Power Generation agrees that “the
requirements should reflect the inherent differences between various protection system
technologies,” however the requirements should not mandate different testing methods and
testing intervals based on that technology. The Registered Entity should be given the latitude to
address different technologies through its PSMP, and the requirements should reflect that.
12
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comment. The SDT believes the current PRC-005-2 draft does not mandate specific testing
methods; the responsible entity has latitude in establishing its PSMP. Specific activities (such as those for various technologies
of “station dc supply”) are prescribed, but the entity still has discretion in determining the most appropriate method of
conducting those activities.
Constellation
Energy
Commodities
Group
Yes
Although Constellation Energy Commodities Group agrees with some of the refinements
prescribed in the SAR, there are a few items of concern. Constellation Energy Commodities
Group agrees that “the requirements should reflect the inherent differences between various
protection system technologies,” however the requirements should not mandate different
testing methods and testing intervals based on that technology. The Registered Entity should be
given the latitude to address different technologies through its PSMP, and the requirements
should reflect that.
Response: Thank you for your comment. The SDT believes the current PRC-005-2 draft does not mandate specific testing
methods; the responsible entity has latitude in establishing its PSMP. Specific activities (such as those for various technologies
of “station dc supply”) are prescribed, but the entity still has discretion in determining the most appropriate method of
conducting those activities.
Saft America,
Inc.
Yes
Manitoba
Hydro
No
1. Detailed Description: The phrase “Transmission & Generation Protection Systems” used in
paragraph 1 should be “Transmission and generation Protection Systems”. “Transmission” and
“Protection System” are defined words in the NERC Glossary of Terms; “Generation” is not a
defined term and should not be capitalized.
2. Applicable Reliability Principles: Is item 4 [Plans for emergency operation and system
restoration of interconnected bulk electric systems shall be developed, coordinated,
maintained and implemented.] applicable to Protection System Maintenance?
Response: Thank you for your comment.
13
Organization
Yes or No
Question 1 Comment
1. The SAR has been modified in consideration of your comment. The SDT removed the “Transmission & Generation”
descriptors from the sentence.
2. The SAR has been modified in consideration of your comment. The Applicable Reliability Principle 4 has been unchecked as
it is not applicable to this standard.
Tennessee
Valley
Authority
No
PNGC
Comment
Group
No
Bonneville
Power
Administration
No
Dominion
No
FirstEnergy
No
Southwest
Power Pool
Standards
Review Group
No
Florida
Municipal
Power Agency
No
NERC Staff
No
14
Organization
Yes or No
Question 1 Comment
Technical
Review
Pepco Holdings
Inc & Affiliates
No
MRO's NERC
Standards
Review Forum
No
ACES Power
Collaborators
No
Arizona Public
Service
Company
No
Southern
Company
Generation
No
Westar Energy
No
Tacoma Power
No
Progress
Energy
No
Western Area
Power
Administration
No
15
Organization
Yes or No
PacifiCorp
No
Nebraska
Public Power
District
No
Exelon
No
Texas
Reliability
Entity
No
Central Lincoln
No
Dynegy Inc.
No
Lincoln Electric
System
No
NIPSCO
No
Entergy
Services
No
Independent
Electricity
System
Operator
No
Liberty Electric
Power LLC
No
Question 1 Comment
16
Organization
Yes or No
Ameren
No
Northeast
Utilities
No
MidAmerican
Energy
Company
No
American
Transmission
Company
No
Southern
Company
Transmission
No
ITC Holdings
No
Igleside
Cogeneration
LP
No
Oncor Electric
Delivery
Company LLC
No
Springfield
Utility Board
No
City of Austin
No
Question 1 Comment
17
Organization
Yes or No
Question 1 Comment
dba Austin
Energy
BGE
No
No comment.
Response: Thank you for your comment.
18
2.
In response to comments, the term “Maintenance Correctable Issue” was revised to “Unresolved Maintenance Issue”. Do you
agree with this change? If you do not agree, please provide specific suggestions for improvement.
Summary Consideration: Most commenters agreed with the change in the term from “Maintenance Correctable Issue” to
“Unresolved Maintenance Issue”, with some offering further suggestion for improvement and clarification. Several commenters
expressed concern that, without further clarity, auditors may confuse initiation of resolution for an issue with completion of the
activities necessary to ultimately resolve the issue, but the SDT believes that this term (and its use within the Standard) is
unequivocal. In response to comments, the SDT has clarified the intent of the requirement to initiate resolution of Unresolved
Maintenance Issues by including it separately as Requirement R5 (shown below) and revising the language such that the responsible
entity must demonstrate its efforts to correct Unresolved Maintenance Issues. Demonstrating the entity has initiated resolution can
include such things as documentation of a work order, replacement component order, invoice, or purchase order, etc… Producing
evidence of this nature would then indicate adherence to the requirement.
Requirement R5 now reads:
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate efforts to correct identified Unresolved
Maintenance Issues.
Organization
Occidental
Chemical
Yes or No
Affirmative
Ballot
Question 2 Comment
In response to comments, the term “Maintenance Correctable Issue” was revised to
“Unresolved Maintenance Issue”. Do you agree with this change? If you do not agree, please
provide specific suggestions for improvement.
Yes. The original term inferred that the problem detected was correctible through follow-up
maintenance – which is not always the case. The term “Unresolved Maintenance Issue” is
more appropriate.
Response: Thank you for your comment and your Affirmative Ballot.
Independent
Electricity
System
Yes
The IESO agrees with the revision to the term. However, we observed the inconsistent
format of this defined term used throughout the draft standard and would like to point it out
to the Drafting Team. The capitalized term “Unresolved Maintenance Issue” is defined on
Page 2 and used as a capitalized term in the blue box on Page 5. The defined term was made
19
Organization
Yes or No
Operator
Question 2 Comment
lowercase and used in other areas of the document as “unresolved maintenance issues” (eg.
Page 5 and Page 8). We recommend that the format of this defined term be consistent
throughout the draft standard.
Response: Thank you for your comment. The SDT has capitalized the term throughout the standard for consistency.
MidAmerican
Energy
Company
Yes
1. Requirement R3 includes the following: “and initiate resolution of any unresolved
maintenance issues”. For clarification it is recommended that the following change be
made to this phrase: “initiate resolution of any unresolved Protection System
maintenance issues”.
2. Also it is recommended that the following be added to the list in M3: “work management
system information”.
Response: Thank you for your comment.
1. The SDT observes that your concern is addressed by the Applicability of the standard (specifically addressing Protection
Systems), and that the change you suggest is unnecessary.
2. The language of Measure M3 specifies “may include but is not limited to dated maintenance records …” and could include
records and information from a work management system without excluding other maintenance records an entity might have
outside a work management system.
Utility Services,
Inc
Yes
While this helps, we are concerned that during the term of the Unresolved Maintenance
Issue is being resolved, a question of compliance to the standard might be pending out. It
should be clarified that during this term, compliance to the standard is being satisfied and
not deemed to be non-compliant.
Response: Thank you for your comment. The SDT has clarified the intent of the requirement to initiate resolution of Unresolved
Maintenance Issues by including it separately as Requirement R5 and revising the language such that the responsible entity must
demonstrate its efforts to correct Unresolved Maintenance Issues.
Igleside
Yes
The original term inferred that the problem detected was correctible through follow-up
20
Organization
Yes or No
Cogeneration
LP
Question 2 Comment
maintenance -which is not always the case. The term “Unresolved Maintenance Issue” is
more appropriate.
Response: Thank you for your comment.
Springfield
Utility Board
Yes
This change has no impact on how Springfield Utility Board currently operates.
Response: Thank you for your comment.
Dominion
Yes
FirstEnergy
Yes
Southwest
Power Pool
Standards
Review Group
Yes
Florida
Municipal
Power Agency
Yes
NERC Staff
Technical
Review
Yes
Pepco Holdings
Inc & Affiliates
Yes
ACES Power
Yes
21
Organization
Yes or No
Question 2 Comment
Collaborators
Arizona Public
Service
Company
Yes
Westar Energy
Yes
Tacoma Power
Yes
Western Area
Power
Administration
Yes
PacifiCorp
Yes
Saft America,
Inc.
Yes
Nebraska Public
Power District
Yes
Exelon
Yes
Dynegy Inc.
Yes
Lincoln Electric
System
Yes
Entergy
Services
Yes
22
Organization
Yes or No
Liberty Electric
Power LLC
Yes
Ameren
Yes
Northeast
Utilities
Yes
Manitoba
Hydro
Yes
American
Transmission
Company
Yes
ITC Holdings
Yes
Oncor Electric
Delivery
Company LLC
Yes
City of Austin
dba Austin
Energy
Yes
Bonneville
Power
Administration
No
Question 2 Comment
BPA agrees that the term “Maintenance Correctable Issue” is an improvement over
“Unresolved Maintenance Issue”, however, BPA feels that the idea of a “Maintenance
Correctable Issue” is very vague, and would perhaps be better left out of the standard. As
written, it is unclear when an issue is a “Maintenance Correctable Issue” and exactly how
it has to be dealt with. R3 requires the initiation of resolution of any unresolved
23
Organization
Yes or No
Question 2 Comment
maintenance issues.
Response: Thank you for your comment.
The SDT has clarified the intent of the requirement to initiate resolution of Unresolved Maintenance Issues by including it
separately as Requirement R5 and revising the language such that the responsible entity must demonstrate its efforts to correct
Unresolved Maintenance Issues.
MRO's NERC
Standards
Review Forum
No
Requirement R3 includes the following: “and initiate resolution of any unresolved
maintenance issues”. The addition of unresolved maintenance issues to the standard is not
included in the SAR and has the potential to cause confusion and misinterpretation. It is
suggested that this phrase be removed.
Response: Thank you for your comment. The SAR was developed and submitted by the NERC System Protection and Control Task
Force (SPCTF) who later prepared and submitted the Technical Reference “Protection System Maintenance” as a guide for the SDT
to use in developing PRC-005-2. In crafting the elements of PRC-005-2, the SDT has endeavored to follow the SAR, which directs
addressing FERC Order 693 directives; recommendations from the SPCTF Assessment of Standards PRC-005-1, PRC-008-0, PRC-0110, PRC-017-0; and consideration of stakeholder comments received during the development of the Version 0 and Phase III & IV
standards.
In the Detailed Description section of the SAR, bullet point four recommends the SDT define the terms “maintenance programs”
and “testing programs” while recognizing other terms may be necessary for clarity. The SPCTF Assessment further recommends
that PRC-005-2 “…should clarify that two goals are being covered: The maintenance portion should have requirements that keep
the protection system equipment operating within manufacturers’ design specifications throughout the service life” and the
“testing portion should… verify the functional performance of protection systems”. Additionally, in the SPCTF Technical Reference
“Protection System Maintenance”, the term “maintenance” is defined as “An ongoing program by which Protection System
function is proved, and restored if needed.”
The SDT developed and defined the term “Protection System Maintenance Program” (PSMP) and its elements (which includes the
testing portion) to achieve the goal of the recommendations of the SAR, SPCTF Assessment, and guidance given in the SPCTF
Technical Reference. Consistent with this guidance, a PSMP is defined in PRC-005-2 as “An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is restored.” The term
“Unresolved Maintenance Issue” defines those things identified as needing follow-up action in order to restore them to proper
24
Organization
Yes or No
Question 2 Comment
operation. This may include repair or replacement activities that cannot be performed during the periodic PSMP activity through
which the deficiency was discovered. Demonstrating the entity has initiated resolution of these issues might then include such
things as documentation of a work order, replacement component order, invoice, or purchase order, etc… For clarity, the SDT has
included these examples in the associated Measure for this requirement in the current draft.
The SDT has clarified the intent of the requirement to initiate resolution of Unresolved Maintenance Issues by including it
separately as Requirement R5 and revising the language such that the responsible entity must demonstrate its efforts to correct
Unresolved Maintenance Issues.
Southern
Company
Generation
No
The measure associated with the requirement that includes this term is non-specific with
regards to what an auditor will require as proof of the initiation of resolving the issue. It is
suggested that one of these two courses be followed: either a) eliminate the requirement to
initiate resolution, or b) fully describe what evidence is expected for this part.
Response: Thank you for your comment. The SDT believes that an effective PSMP must include correction of deficiencies, but
management of completion of any Unresolved Maintenance Issues is a complex topic which may involve a wide variety of
activities (with varying completion timelines). The associated Measure lists examples of what may be effective evidence (more
examples have been added); specific evidence, for any specific situation, will vary based on the particulars of that situation. The
SDT has clarified the intent of the requirement to initiate resolution of Unresolved Maintenance Issues by including it separately
as Requirement R5 and revising the language such that the responsible entity must demonstrate its efforts to correct Unresolved
Maintenance Issues.
American
Electric Power
No
The definition’s wording is satisfactory, and we agree with the removal of “failure of a
component to operate within design parameters”. However, we do not agree with the use of
the word “unresolved” within the term itself, as we believe this word may convey that the
issue was not known or identified. We suggest replacing “Unresolved Maintenance Issue”
with “Corrective Maintenance Issue”.
Response: Thank you for your comment. The SDT has clarified the intent of the requirement to initiate resolution of Unresolved
Maintenance Issues by including it separately as Requirement R5 and revising the language such that the responsible entity must
demonstrate its efforts to correct Unresolved Maintenance Issues.
25
Organization
Yes or No
Southern
Company
Transmission
No
Question 2 Comment
The measure associated with the requirement that includes this term is non-specific with
regards to what an auditor will require as proof of the initiation of resolving the issue. It is
suggested that one of these two courses be followed: either a) eliminate the requirement to
initiate resolution, or b) fully describe what evidence is expected for this part.
Response: Thank you for your comment.
The SDT believes that an effective PSMP must include correction of deficiencies, but management of completion of any
Unresolved Maintenance Issues is a complex topic which may involve a wide variety of activities (with varying completion
timelines). The associated Measure lists examples of what may be effective evidence (more examples have been added); specific
evidence, for any specific situation, will vary based on the particulars of that situation. The SDT has clarified the intent of the
requirement to initiate resolution of Unresolved Maintenance Issues by including it separately as Requirement R5 and revising the
language such that the responsible entity must demonstrate its efforts to correct Unresolved Maintenance Issues.
BGE
No
No comment about the change itself, but the terms were not consistently applied in the
Supplemental Reference Manual (see last comment).
Response: Thank you for your comment. The SDT has further reviewed and revised the Supplementary Reference and FAQ
document to facilitate consistent use of the terms.
Constellation
Power
Generation
No
As R3 is currently written, Constellation Power Generation is concerned that this
requirement may decrease the reliability of the BES under certain circumstances. The
severity of the “deficiency” found will dictate the method and timing of a “follow up
correction action”. For a generator, the corrective action may not be “initiated” until the
next planned outage, which may be a few years. However, R3 suggests that to comply, a
generation site may have to extend an outage or take a forced and unplanned outage, to
perform the corrective action. This would decrease the available resources in a given BA’s
footprint and potentially decrease the reliability of the BES.
Response: Thank you for your comment.
PRC-005-2 only requires the entity “… initiate resolution” of the issue found. The SDT recognizes that performance of the activities
26
Organization
Yes or No
Question 2 Comment
necessary to resolve an issue are entirely dependent upon the circumstances surrounding that issue and, consequently, will
require varying amounts of resources and time to complete the process. The SDT has clarified the intent of the requirement to
initiate resolution of Unresolved Maintenance Issues by including it separately as Requirement R5 and revising the language such
that the responsible entity must demonstrate its efforts to correct Unresolved Maintenance Issues. Demonstrating the entity has
initiated resolution can include such things as documentation of a work order, replacement component order, invoice, or purchase
order, etc… Producing evidence of this nature would then indicate adherence to the requirement.
Constellation
Energy
Commodities
Group
No
As R3 is currently written, Constellation Energy Commodities Group is concerned that this
requirement may decrease the reliability of the BES under certain circumstances. The
severity of the “deficiency” found will dictate the method and timing of a “follow up
correction action”. For a generator, the corrective action may not be “initiated” until the
next planned outage, which may be a few years. However, R3 suggests that to comply, a
generation site may have to extend an outage or take a forced and unplanned outage, to
perform the corrective action. This would decrease the available resources in a given BA’s
footprint and potentially decrease the reliability of the BES.
Response: Thank you for your comment.
PRC-005-2 only requires the entity “… initiate resolution” of the issue found. The SDT recognizes that performance of the activities
necessary to resolve an issue are entirely dependent upon the circumstances surrounding that issue and, consequently, will
require varying amounts of resources and time to complete the process. The SDT has clarified the intent of the requirement to
initiate resolution of Unresolved Maintenance Issues by including it separately as Requirement R5 and revising the language such
that the responsible entity must demonstrate its efforts to correct Unresolved Maintenance Issues. Demonstrating the entity has
initiated resolution can include such things as documentation of a work order, replacement component order, invoice, or purchase
order, etc… Producing evidence of this nature would then indicate adherence to the requirement.
PNGC
Comment
Group
Central Lincoln
No
Either term works if defined properly.
27
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment.
28
3.
In response to comments, the SDT revised the previous “3 calendar months” interval to “4 calendar months” for communications
systems and station dc supply. Do you agree with this change? If you do not agree, please provide specific suggestions for
improvement.
Summary Consideration: Most commenters agreed with the change; however, several commenters suggested further extension of
these intervals. The SDT did not make any further changes to those intervals, explaining their belief that the established intervals are
appropriate maximum intervals for this continent-wide standard. A few commenters continued to object to the establishment of
maximum allowable intervals as specified in FERC Order 693; the SDT did not adopt any related suggestions, and instead reminded the
commenters of FERC’s directives.
Organization
CPS Energy
Yes or No
Affirmative
Ballot
Question 3 Comment
The 4 month maintenance and testing interval for station DC supply is too short based on
programs that have been in service for many years where twelve months have been proven as
reliable for operation.
Response: Thank you for your comments
This 4 month interval is an “inspect and verify” activity not testing. FERC Order 693 and the approved SAR direct the SDT to
develop a standard with maximum allowable intervals and minimum maintenance activities. The SDT believes that the intervals
established within the Tables are appropriate as continent-wide maximum allowable intervals, with due consideration for any
monitoring functionality that may be present (per Table 1-4f).
Occidental
Chemical
Affirmative
Ballot
In response to comments, the SDT revised the previous “3 calendar months” interval to “4
calendar months” for communications systems and station dc supply. Do you agree with this
change? If you do not agree, please provide specific suggestions for improvement.
Yes. Ingleside Cogeneration LP agrees that the intervals on the activities in question should be
extended to 4 calendar months. However on Page 20 of the Supplementary Reference document,
the calculation of the next due date using units of “calendar months” is inconsistent with the
calculation using a “calendar year”. In the case of “calendar years”, an activity must take place
somewhere between Jan 1 and Dec 31. For “four calendar months”, a follow-up activity must be
performed within four months from the completion of the prior one. We believe that “four
29
Organization
Yes or No
Question 3 Comment
calendar months” should be calculated in the same manner as a “calendar year”. This means that
an activity should take place at least once between January 1 and April 30; and repeated once
during May 1 through August 31, and again between September 1 and December 31. The pattern
would continue in ongoing years. Not only is this method consistent with the “calendar year”
derivation, it allows the most flexibility in scheduling – especially if an unexpected event causes a
delay. The vast majority of the maintenance activities will still take place at four months plus or
minus a week or two; with an occasional outlier that adds minimal risk to reliability.
Response: Thank you for your comments.
Section 7.1 of the Supplementary Reference and FAQ document has been modified in consideration of your comment.
Wisconsin
Electric Power
Co.
Wisconsin
Electric Power
Marketing
Affirmative
Ballot
Focusing on batteries which are required to be done on a time-based maintenance program:
1. The big picture is that it is not just testing anymore - there are many more mandated tasks to
be performed - Table 1-4(a). - Verifications & inspections are now part of the plan criteria, and
have been moved from 3 months to a 4 month maximum interval.
2. We would like to see clarification on what is meant by the extent of 4 months. Is it by the end
of the same calendar day or the previous calendar day, four months later; or is it 120 days or
what? Could plan to manage to every 3 months, but not greater than 4 months. Same for
Battery testing - manage to 1 year, but not greater than 18 months.
3. What is meant by battery continuity? Is battery float current an acceptable test methodology?
It is not defined as clearly as an "impedance" or "resistance" test.
Response: Thank you for your comments.
1. The SDT believes that all of the maintenance activities within the “definition” of PSMP and as listed in the Tables are
necessary components of an effective PSMP. Testing alone cannot assure that the Protection System components are in
good working order.
2. Section 7.1 of the Supplementary Reference and FAQ document provides an expanded discussion of this topic, and has been
revised to add further clarity.
30
Organization
Yes or No
Question 3 Comment
3. “Continuity” can be tested via several methods, and is described in detail in Section 15.4 of the Supplementary Reference
and FAQ document. Battery float current is one of the many methods discussed within the Supplementary Reference
Document.
PNGC Comment
Group
Yes
We agree with this change. Smaller utilities, especially in the WECC region, in many cases have
large territories to cover with limited resources. In many instances sub-stations are inaccessible
during the winter and the 4 month interval will assist these smaller entities in getting the work
done.
Response: Thank you for your comment
MRO's NERC
Standards
Review Forum
Yes
We agree 4 calendar months is better than 3 Calendar months. The 4 month activities should be
removed from Tables 1-4(a, b, c, d). These requirements are blurring the distinction between a
best practice and functionally verifying the component. IEEE already sets the industries best
practices, if a Reliability Standard includes best maintenance practices it is encroaching on IEEE’s
ability to keep the industry informed and optimized. The Standard Drafting Team should restrain
itself to only making requirements that functionally verify components and initiate corrective
action wherever possible. We recommend that this time frame be a maximum of 6 Calendar
Months which will allow entities to establish their own time frame based on the seasonal changes
that occur where the batteries are located.
Response: Thank you for your comments.
Station dc supply (including station batteries) must perform properly for the Protection System to function correctly. In order to
establish that station batteries are functioning properly, the SDT believes that all of the listed maintenance activities must be
performed, within the specified maximum intervals, with due consideration for any monitoring functionality that may be present.
The SDT has drawn from the relevant IEEE standards (and other sources) to determine those activities that it has deemed
appropriate to assure proper performance of the station battery. The SDT specifically believes that the 4-month maximum
interval is proper for these activities for unmonitored DC supply systems and is consistent with the prevailing industry practice.
Tacoma Power
Yes
A similar change in interval should be applied to intervals of “6 calendar months".
31
Organization
Yes or No
Question 3 Comment
Response: Thank you for your comments
The SDT believes that the six-month interval is appropriate.
Nebraska Public
Power District
Yes
We agree 4 calendar months is better than 3 Calendar months. The 4 month activities should be
removed from Tables 1-4 (a, b, c, d). These requirements are blurring the distinction between a
best practice and functionally verifying the component. IEEE already sets the industries best
practices, if a Reliability Standard includes best maintenance practices it is encroaching on IEEE’s
ability to keep the industry informed and optimized. The Standard Drafting Team should restrain
itself to only making requirements that functionally verify components and initiate corrective
action wherever possible.
Response: Thank you for your comments.
Station dc supply (including station batteries) must perform properly for the Protection System to function correctly. In order to
establish that station batteries are functioning properly, the SDT believes that all of the listed maintenance activities must be
performed, within the specified maximum intervals. The SDT has drawn from the relevant IEEE standards (and other sources) to
determine those activities that it has deemed appropriate to assure proper performance of station batteries. The SDT specifically
believes that the 4-month maximum interval is proper for these activities for unmonitored DC supply systems and is consistent
with the prevailing industry practice.
Central Lincoln
Yes
Thank you for making this change. As we pointed out in draft 2, a three month maximum would
require a bi-monthly target to allow for contingencies; increasing maintenance from four times a
year (per the IEEE battery standards) to six.
Response: Thank you for your comment.
Ameren
Yes
Our experience with a very large number of communication systems and station dc supplies
substantiates an even longer interval as sufficient for reliable Protection Systems.
Response: Thank you for your comment. If your experience suggests that longer intervals for communications systems will
produce appropriate performance, you may employ performance-based maintenance (per the draft standard). However, SDT
32
Organization
Yes or No
Question 3 Comment
believes that all of the listed maintenance activities for station dc supply must be performed, within the specified maximum
intervals, with due consideration for any monitoring functionality that may be present.
Ingleside
Cogeneration
LP
Yes
Ingleside Cogeneration LP agrees that the intervals on the activities in question should be
extended to 4 calendar months. However on Page 20 of the Supplementary Reference document,
the calculation of the next due date using units of “calendar months” is inconsistent with the
calculation using a “calendar year”. In the case of “calendar years”, an activity must take place
somewhere between Jan 1 and Dec 31. For “four calendar months”, a follow-up activity must be
performed within four months from the completion of the prior one. We believe that “four
calendar months” should be calculated in the same manner as a “calendar year”. This means that
an activity should take place at least once between January 1 and April 30; and repeated once
during May 1 through August 31, and again between September 1 and December 31. The pattern
would continue in ongoing years. Not only is this method consistent with the “calendar year”
derivation, it allows the most flexibility in scheduling - especially if an unexpected event causes a
delay. The vast majority of the maintenance activities will still take place at four months plus or
minus a week or two; with an occasional outlier that adds minimal risk to reliability.
Response: Thank you for your comments. Section 7.1 of the Supplementary Reference and FAQ document provides an expanded
discussion of this topic, and has been revised to add further clarity.
BGE
Yes
BGE appreciates the SDT demonstrating flexibility by extending these maintenance intervals.
Response: Thank you for your comment.
Springfield
Utility Board
Yes
This change has no impact on how Springfield Utility Board currently operates.
Response: Thank you for your comment.
MidAmerican
Energy
Yes
None
33
Organization
Yes or No
Question 3 Comment
Company
Bonneville
Power
Administration
Yes
Dominion
Yes
FirstEnergy
Yes
Southwest
Power Pool
Standards
Review Group
Yes
Florida
Municipal
Power Agency
Yes
Pepco Holdings
Inc & Affiliates
Yes
ACES Power
Collaborators
Yes
Southern
Company
Generation
Yes
Westar Energy
Yes
34
Organization
Yes or No
Progress Energy
Yes
Western Area
Power
Administration
Yes
PacifiCorp
Yes
Saft America,
Inc.
Yes
Exelon
Yes
Dynegy Inc.
Yes
Lincoln Electric
System
Yes
Entergy
Services
Yes
Independent
Electricity
System
Operator
Yes
Liberty Electric
Power LLC
Yes
American
Transmission
Yes
Question 3 Comment
35
Organization
Yes or No
Question 3 Comment
Company
Southern
Company
Transmission
Yes
ITC Holdings
Yes
Oncor Electric
Delivery
Company LLC
Yes
City of Austin
dba Austin
Energy
Yes
Northeast
Utilities
Yes
Manitoba
Hydro
No
Manitoba Hydro maintains that the battery inspection interval should be extended to 6 months.
The 4 month interval is too frequent based on our experience and while IEEE std 450 (which
seems to be the basis for table 1-4) does recommend intervals, it also states that users should
evaluate these recommendations against their own operating experience. Our experience shows
that 6 month battery inspections are more than adequate to maintain system reliability.Manitoba
Hydro has more than ten years of experience using its existing battery inspection intervals, and
Manitoba Hydro’s reliability data has proven that the 6 month inspection interval is suitable for
Manitoba Hydro. Manitoba Hydro’s battery maintenance tasks were derived from a reliability
study of Manitoba Hydro stationary batteries, and the tasks and intervals are suitable given
Manitoba Hydro’s installed plant, design criteria, climate, and reliability performance. A more
frequent inspection interval might be more suitable to specific utilities with material differences in
climate, design, installed apparatus, and performance, but it is not suitable for Manitoba Hydro
36
Organization
Yes or No
Question 3 Comment
and may be more than is required for many other utilities. To use a more frequent inspection
interval would significantly penalize Manitoba Hydro which has been diligently performing battery
inspections for many years, with no resulting increase in reliability. With the 4 month battery
check frequency and no allowance for a grace period, there may be a negative impact on reliability
caused by diverting resources away from projects that are critical to reliability to meet this
maintenance interval.
Response: Thank you for your comments.
This 4 month interval is an “inspect and verify” activity not testing. FERC Order 693 and the approved SAR direct the SDT to
develop a standard with maximum allowable intervals and minimum maintenance activities. The SDT believes that the intervals
established within the Tables are appropriate as continent-wide maximum allowable intervals, with due consideration for any
monitoring functionality that may be present (per Table 1-4f).
Arizona Public
Service
Company
No
APS has been testing batteries nominally every 4 months plus 25% for over 20 years with no
adverse consequences. Requiring a maximum of testing every 4 months doesn't allow for any
flexibility, would require an additional 400 tests per year and APS does not consider the 4 months
a maximum time limit for battery testing.
Response: Thank you for your comments.
This 4 month interval is an “inspect and verify” activity not testing. FERC Order 693 and the approved SAR direct the SDT to
develop a standard with maximum allowable intervals and minimum maintenance activities. The SDT believes that the intervals
established within the Tables are appropriate as continent-wide maximum allowable intervals, with due consideration for any
monitoring functionality that may be present (per Table 1-4f).
Utility Services,
Inc
No
The standard should provide guidance what tasks need to be accomplished for compliance and
not mandates on specifics like this. Registered Entities should be left to determine the
appropriate intervals based upon their experience and good utility practices.
Response: Thank you for your comments
FERC Order 693 and the approved SAR direct the SDT to develop a standard with maximum allowable intervals and minimum
37
Organization
Yes or No
Question 3 Comment
maintenance activities. The SDT believes that the intervals established within the Tables are appropriate as continent-wide
maximum allowable intervals, with due consideration for any monitoring functionality that may be present. If an entity’s
experience is that some components require less-frequent maintenance than specified in the Tables, a performance-based
program in accordance with Requirement R2 and Attachment A is an option unless specifically precluded.
American
Electric Power
No
Though we agree with extending the interval from what it was previously, AEP recommends that
the interval in Table 1-2 for Communications Systems be increased to 6 months.
Response: Thank you for your comments
The SDT believes that the revised 4-month maximum interval is proper for unmonitored communications systems.
Tennessee
Valley Authority
No
38
4.
The SDT extracted the maintenance activities and intervals for distributed UFLS and UVLS systems from Table 1-1 through 1-5
and placed them into a new Table 3 to more clearly illustrate the requirements related to these systems. Do you agree with this
change? If you do not agree, please provide specific suggestions for improvement.
Summary Consideration: Most commenters appreciated the break-out of distributed UFLS/UVLS maintenance activities into Table 3.
Several commenters, however, continued to object to inclusion of this maintenance within the standard, and some questioned NERC’s
jurisdiction to address devices installed on the distribution system. The SDT consulted with NERC legal staff on the jurisdiction
question, and cited the position from NERC Legal in responding that these devices are indeed within NERC’s authority because they
are installed for the reliability of the BES. Several commenters also objected to the requirements relating to periodic operation of
electromechanical devices, maintenance of voltage and current sensing devices, and/or maintenance of the dc supply within the new
Table 3, and the SDT provided responses supporting the SDT’s belief that all of these activities are relevant and necessary for inclusion
within the standard. Several other commenters suggested formatting changes, most of which were adopted. While considering these
comments, the SDT also made assorted clarifying changes to Table 3.
Organization
Occidental
Chemical
Yes or No
Question 4 Comment
Affirmative
Ballot
The SDT extracted the maintenance activities and intervals for distributed UFLS and UVLS systems
from Table 1-1 through 1-5 and placed them into a new Table 3 to more clearly illustrate the
requirements related to these systems. Do you agree with this change? If you do not agree, please
provide specific suggestions for improvement.
Yes. We believe that distributed UFLS and UVLS relay systems have a very different operating
purpose than those that are not distributed. It is appropriate to separate the maintenance
activities and intervals for these relay systems.
Response: Thank you for your support.
Southern
Company
Generation
Yes
1. Separating this classification of equipment into its own table is a good idea to make it easier for
the owners of this equipment to figure out what they must do.
2. Consider also moving the UVLS note (found in column 1 of Tables 1-4a-d) into the header with
39
Organization
Yes or No
Question 4 Comment
the other "UFLS and UVLS note" to simplify the table. The header note could read "Excludes
UFLS and UVLS systems - see Table 1-4e for non-distributed UFLS and UVLS systems and see
Table 3 for distributed UFLS and UVLS systems").
3. Table 1-5: Need clarification on "continuity and energization or ability to operate". What does
this mean?
4. For UF and UV schemes, Table 3 does not specifically state to check the alarm(s) to a control
center (for monitored components). There are some references to Table 2 (i.e. See Table 2),
but does that mean that you have to verify the alarm(s)? We think that the Table 2 details
need to be included specifically in Table 3. Or, make it very clear that this test is required for
UF and UV schemes.
Response:
1. Thank you for your support.
2. Thank you for your comment, Table 1-4 (a, b, c, d) has been revised accordingly.
3. This entry in Table 1-5 has been modified to “Control circuitry whose integrity is monitored and alarmed”. Section 15.3 of the
Supplementary Reference and FAQ document provides additional discussion on this topic.
4. The SDT has revised the Table 2 for clarity.
Ameren
Yes
Please consistently state UFLS before UVLS; Table 1-4(e) differs from other parts of the standard.
Response: Thank you for your suggestion; the SDT has revised the standard.
Northeast
Utilities
Yes
The migration of the UFLS and UVLS requirements to Table 3 is appreciated. The Table 3
Component Attributes in rows 6 and 7 (“Control circuitry between the UFLS or UVLS relays and
electromechanical lockout and/or tripping auxiliary devices” and Electromechanical lockout and/or
tripping auxiliary devices associated only with UFLS or UVLS systems” respectively) do not identify
that the trip coils are excluded. Although row 9 states “Trip coils of non-BES interrupting devices in
UFLS or UVLS systems” do not have any period maintenance specified, our recommendation is to
40
Organization
Yes or No
Question 4 Comment
annotate rows 6 and 7 to explicitly indicate the trip coils are excluded.
Response: Thank you for support. The SDT has revised Table 3 accordingly.
MidAmerican
Energy
Company
Yes
None
Southern
Company
Transmission
Yes
For UF and UV schemes, Table 3 does not specifically state to check the alarm(s) to a control center
(for monitored components). There are some references to Table 2 (i.e. See Table 2), but does
that mean that you have to verify the alarm(s)? I think Table 2 details need to be included
specifically in Table 3. Or make it very clear that this test is required for UF and UV schemes.
Response: Thank you for your comment. The SDT has revised Table 2 for clarity.
Ingleside
Cogeneration
LP
Yes
We believe that distributed UFLS and UVLS relay systems have a very different operating purpose
than those that are not distributed. It is appropriate to separate the maintenance activities and
intervals for these relay systems.
Response: Thank you for your support.
Springfield
Utility Board
Yes
Although numerous tables can become overwhelming to navigate, it is far less ambiguous if specific
systems are spelled out in separate and distinct tables.
Response: Thank you for your support.
Ameren
Yes
Please consistently state UFLS before UVLS; Table 1-4(e) differs from other parts of the standard.
Response: Thank you for your suggestion. The SDT has revised the standard.
Oncor Electric
Delivery
Yes
41
Organization
Yes or No
Question 4 Comment
Company LLC
City of Austin
dba Austin
Energy
Yes
PNGC Comment
Group
Yes
Bonneville
Power
Administration
Yes
Dominion
Yes
FirstEnergy
Yes
Southwest
Power Pool
Standards
Review Group
Yes
City of Austin
dba Austin
Energy
Yes
Pepco Holdings
Inc & Affiliates
Yes
MRO's NERC
Standards
Yes
42
Organization
Yes or No
Question 4 Comment
Review Forum
ACES Power
Collaborators
Yes
Arizona Public
Service
Company
Yes
Westar Energy
Yes
Tacoma Power
Yes
Progress Energy
Yes
Western Area
Power
Administration
Yes
PacifiCorp
Yes
Saft America,
Inc.
Yes
Nebraska Public
Power District
Yes
Exelon
Yes
Texas Reliability
Entity
Yes
43
Organization
Yes or No
Central Lincoln
Yes
Dynegy Inc.
Yes
American
Electric Power
Yes
Lincoln Electric
System
Yes
Entergy
Services
Yes
Independent
Electricity
System
Operator
Yes
Liberty Electric
Power LLC
Yes
Manitoba
Hydro
Yes
American
Transmission
Company
Yes
Utility Services,
Inc
Yes
Question 4 Comment
44
Organization
Yes or No
ITC Holdings
Yes
Flathead
Electric
Cooperative
Negative
Ballot
Question 4 Comment
I appreciate the drafting team’s effort to separate requirements for distributed UFLS, however
fundamentally it is unclear how mandatory and enforceable requirements can be applied to nonBES elements as there is no statutory authority over local distribution networks.
Response: Thank you for comment. In regards to your concern, the SDT received the following position from NERC Legal:
“While UFLS and UVLS equipment are located on the distribution network, their job is to protect the Bulk Electric System. This
is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines “bulk-power system as (A) facilities and control systems necessary for operating
an interconnected electric energy transmission network (or any portion thereof).” That definition then is limited by a later
statement which adds the term bulk-power system “does not include facilities used in the local distribution of electric energy.”
Also, section 215 also covers users, owners, and operators of bulk-power facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage instability for BES reliability) are not
“used in the local distribution of electric energy” despite their location on local distribution networks. Further, if UFLS/UVLS
facilities were not covered by the Reliability Standards, then in order to protect the integrity of the BES during underfrequency or under-voltage events, that load would have to be shed at the transmission bus to ensure the load-generation
balance and voltage stability is maintained on the BES.”
Lakeland
Electric
Negative
Ballot
The standard reaches further into the distribution system for UFLS and UVLS. It will be burdensome
to present all the evidence of distribution class protection system maintenance and testing at
audits.
Response: The existing standards (PRC-008 & PRC-011) already require maintenance and testing of components of UFLS and UVLS
protection systems, including those installed to operate distribution-level interrupting devices.
Beaches Energy
Negative
The standard reaches further into the distribution system than we would like for UFLS and UVLS
45
Organization
Services
Yes or No
Ballot
Question 4 Comment
(Table 3). We have two parts to this concern.
First, it will be somewhat onerous to present all the evidence of distribution class protection
system maintenance and testing at audits.
And second, our biggest concern is in the testing required to "exercise" a lockout or tripping relay.
This may require installation of test blocks to allow such exercising of the lockout or tripping relay
without tripping the distribution circuit, and such a test could be difficult to perform without
impacting customer continuity of service if the lockout/tripping relay for the UFLS is the same as
the lockout/tripping relay for distribution fault protection.
Response: Thank you for your comment.
First, the existing standards (PRC-008 & PRC-011) already require maintenance and testing of components of UFLS and UVLS
protection systems, including those installed to operate distribution-level interrupting devices.
Second, the UVLS and UFLS systems are included as part of the Project 2007-17 Standard Authorization Request (SAR). The SDT
believes that electromechanical devices, such as auxiliary or lockout relays which contain “moving parts”, need periodic operation
in order to remain reliable. As such, these devices are required to be exercised at the 12 year interval for UVLS and UFLS systems.
The SDT recognizes the risk of human error trips when working with testing of lockout devices but believes these risks can be
managed.
46
Organization
Yes or No
Florida Keys
Electric
Cooperative
Assoc.
Negative
Ballot
Question 4 Comment
The standard reaches further into the distribution system than we would like for UFLS and UVLS
(Table 3). We have two parts to this concern.
First, it will be somewhat onerous to present all the evidence of distribution class protection
system maintenance and testing at audits.
And second, our biggest concern is in the testing required to "exercise" a lockout or tripping relay.
This may require installation of test blocks to allow such exercising of the lockout or tripping relay
without tripping the distribution circuit, and such a test could be difficult to preform without
impacting customer continuity of service if the lockout/tripping relay for the UFLS is the same as
the lockout/tripping relay for distribution fault protection. However, most of FMPA's members
have microprocessor-based relays for distribution circuits with the UFLS / UVLS embedded within
the microprocessor based relay where the path from the UFLS / UVLS relay to the lockout / tripping
relay is internal to the micro-processor based relay, so, testing the UFLS/UVLS relay will at the same
time test the internal lockout / switching relay. However, for older electro-mechanical UFLS
schemes, this type of testing could be problematic.
Response: Thank you for your comment.
First, the existing standards (PRC-008 & PRC-011) already require maintenance and testing of components of UFLS and UVLS
protection systems, including those installed to operate distribution-level interrupting devices.
Second, the UVLS and UFLS systems are included as part of the Project 2007-17 Standard Authorization Request (SAR). The SDT
believes that electromechanical devices, such as auxiliary or lockout relays which contain “moving parts”, need periodic operation
in order to remain reliable. As such, these devices are required to be exercised at the 12 year interval for UVLS and UFLS systems.
The SDT recognizes the risk of human error trips when working with testing of lockout devices but believes these risks can be
managed.
47
Organization
Yes or No
Florida
Municipal
Power Agency
Negative
Ballot
Negative
Poll
Question 4 Comment
The standard reaches further into the distribution system than we would like for UFLS and UVLS
(Table 3). We have two parts to this concern.
First, it will be somewhat onerous to present all the evidence of distribution class protection
system maintenance and testing at audits.
And second, our biggest concern is in the testing required to "exercise" a lockout or tripping relay.
This may require installation of test blocks to allow such exercising of the lockout or tripping relay
without tripping the distribution circuit, and such a test could be difficult to preform without
impacting customer continuity of service if the lockout/tripping relay for the UFLS is the same as
the lockout/tripping relay for distribution fault protection. However, most of FMPA's members
have microprocessor-based relays for distribution circuits with the UFLS / UVLS embedded within
the microprocessor based relay where the path from the UFLS / UVLS relay to the lockout / tripping
relay is internal to the micro-processor based relay, so, testing the UFLS/UVLS relay will at the same
time test the internal lockout / switching relay. However, for older electro-mechanical UFLS
schemes, this type of testing could be problematic. Borderline concerning whether this causes us
to vote Negative or not. As a result, FMPA recommends a Negative vote with the second and third
comments, emphasizing that it is the second comment that causes us to vote negative but we also
would like the 3rd comment addressed. Feedback appreciated. Vote and comments are due next
Wednesday, 9/28.
Response: Thank you for your comment.
First, the existing standards (PRC-008 & PRC-011) already require maintenance and testing of components of UFLS and UVLS
protection systems, including those installed to operate distribution-level interrupting devices.
Second, the UVLS and UFLS systems are included as part of the Project 2007-17 Standard Authorization Request (SAR). The SDT
believes that electromechanical devices, such as auxiliary or lockout relays which contain “moving parts”, need periodic operation
in order to remain reliable. As such, these devices are required to be exercised at the 12 year interval for UVLS and UFLS systems.
The SDT recognizes the risk of human error trips when working with testing of lockout devices but believes these risks can be
managed.
48
Organization
Yes or No
Florida
Municipal
Power Pool
Negative
Ballot
Negative
Poll
Question 4 Comment
The standard reaches further into the distribution system than we would like for UFLS and UVLS
(Table 3). We have two parts to this concern.
First, it will be somewhat onerous to present all the evidence of distribution class protection
system maintenance and testing at audits.
And second, our biggest concern is in the testing required to "exercise" a lockout or tripping relay.
This may require installation of test blocks to allow such exercising of the lockout or tripping relay
without tripping the distribution circuit, and such a test could be difficult to preform without
impacting customer continuity of service if the lockout/tripping relay for the UFLS is the same as
the lockout/tripping relay for distribution fault protection. However, most of FMPA's members
have microprocessor-based relays for distribution circuits with the UFLS / UVLS embedded within
the microprocessor based relay where the path from the UFLS / UVLS relay to the lockout / tripping
relay is internal to the micro-processor based relay, so, testing the UFLS/UVLS relay will at the same
time test the internal lockout / switching relay. However, for older electro-mechanical UFLS
schemes, this type of testing could be problematic. Borderline concerning whether this causes us
to vote Negative or not.
Response: Thank you for your comment.
First, the existing standards (PRC-008 & PRC-011) already require maintenance and testing of components of UFLS and UVLS
protection systems, including those installed to operate distribution-level interrupting devices.
Second, the UVLS and UFLS systems are included as part of the Project 2007-17 Standard Authorization Request (SAR). The SDT
believes that electromechanical devices, such as auxiliary or lockout relays which contain “moving parts”, need periodic operation
in order to remain reliable. As such, these devices are required to be exercised at the 12 year interval for UVLS and UFLS systems.
The SDT recognizes the risk of human error trips when working with testing of lockout devices but believes these risks can be
manageds.
Lincoln Electric
System
Negative
Ballot
Please see comments submitted in addition to the following comment. LES recommends the
standard drafting team clarify the expected maintenance activities for BES related batteries that
also serve UFLS systems. In particular, what would be the required maintenance activities for a
battery bank serving both BES transmission elements and UFLS elements? Table 1.4 clearly
49
Organization
Yes or No
Question 4 Comment
excludes UFLS elements and Table 3 indicates it only applies to “non-BES interrupting devices”. As
such, if a joint use battery is excluded from Table 1.4 because of its association with UFLS, BES
related batteries would have no place in any of the tables.
Response: Thank you for your comment.
The SDT responded to your other comments in the sections where they were submitted.
A battery bank serving both BES and UFLS/UVLS protection systems would be maintained per table 1-4. A battery bank that serves
only distributed UFLS or UVLS system would be maintained per table 3.
The headers of the various sections of Table 1-4 now exclude station dc supply that is used only for UFLS/UVLS from Table 1-4.
CenterPoint
Energy
No
1. For the “Control circuitry between the UFLS or UVLS relays and electromechanical lockout
and/or tripping auxiliary devices”, the Table 3 requirement is to “Verify the path from the relay
to the lockout and/or tripping auxiliary relay (including essential supervisory logic)” every 12
calendar years. CenterPoint Energy recommends this requirement be revised to “No periodic
maintenance specified”. CenterPoint Energy believes that wire checking a panel is a
commissioning task, not a preventive maintenance task. CenterPoint Energy performs such
checks on new stations and whenever expansion or modification of existing stations dictates
such testing.
2. In addition, CenterPoint Energy recommends the requirement in Table 3 to “Verify that current
and/or voltage signal values are provided to the protective relays” every 12 years be revised to
“No periodic maintenance specified”.
3. Likewise, we recommend the requirement in Table 3 to “Verify Protection System dc supply
voltage” every 12 years be revised to “No periodic maintenance specified”. Preventive
maintenance tasks such as the three above are unnecessary for distributed UFLS and UVLS
system components. The overriding performance, or “risk-based”, NERC Reliability Standards
for UFLS are PRC-006 and PRC-007 where an entity is required to shed their obligated firm load
amount.
50
Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment.
1. While much of the control circuitry associated with a distribution device is regularly exercised, the SDT believes that the control
circuitry associated directly with UFLS/UVLS that are applied for BES reliability need be periodically verified to assure that these
components will function properly when called upon to do so.
2. The SDT believes that the voltage/current signals that support proper operation of UFLS/UVLS that are applied for BES
reliability need be periodically verified to assure that these components will function properly when called upon to do so. The
specific degree of this verification is constrained within Table 3 to those activities necessary to assure proper operation of the
UFLS/UVLS.
3. The SDT believes that the station dc supply that supports only proper operation of UFLS/UVLS that are applied for BES reliability
need be periodically verified to assure that these components will function properly when called upon to do so. The specific
degree of this verification is constrained within Table 3 to only periodic measurement of the dc voltage.
BGE
No
Although BGE does not disagree with moving the distributed UFLS/UVLS maintenance activities and
intervals into the new Table-3, BGE requests further clarification from the SDT on how to correctly
interpret the headings and content of this table.
Response: Thank you for your support. Table 3 has been modified since it was last released for comment. Table 3 should be used
to determine maintenance activities and intervals for distributed UFLS and UVLS systems. Distributed systems are further
elaborated upon in the Supplementary Reference and FAQ document, Section 15.7.
Constellation
Power
Generation
No
Moving the UFLS and UVLS systems from Tables 1-1 through 1-5 into a separate Table 3 is a useful
improvement in illustrating the requirements. However, our objection is not really with the
format, it is will the content of the Tables. From a generation perspective, the maintenance
intervals and activities described in all of the Tables are too prescriptive and we are concerned that
they may conflict with the existing PSMPs built by Registered Entities based on years of operational
experience with the testing methods and testing frequencies that work best for the specific asset.
In the worst case, the specifics dictated in the Tables may move Entities away from more stringent
PSMPs that are currently in practice. For this reason, Constellation suggests that the drafting team
revisit the concept of the Tables to better balance to convey useful guidance without creating a
51
Organization
Yes or No
Question 4 Comment
compliance requirement that may be contrary to improved reliability. The Registered Entity should
be given more flexibility to dictate how a protection system component should be tested, and at
what frequency. Lastly, the technical manpower and compliance documentation demands to
implement a performance based protection system maintenance program are so onerous that it is
highly unlikely that any small generation entity would use it.
Response: Thank you for your comment.
FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
maintenance activities. The SDT believes that the intervals established within the Tables are appropriate as continent-wide
maximum allowable intervals, with due consideration for any monitoring functionality that may be present. The ability to utilize
performance-based maintenance is provided for those entities who wish to pursue it; it is understood that many entities may
instead choose to simply implement a PSMP based on the Tables.
Constellation
Energy
Commodities
Group
No
Moving the UFLS and UVLS systems from Tables 1-1 through 1-5 into a separate Table 3 is a useful
improvement in illustrating the requirements. However, our objection is not really with the
format, it is will the content of the Tables. From a generation perspective, the maintenance
intervals and activities described in all of the Tables are too prescriptive and we are concerned that
they may conflict with the existing PSMPs built by Registered Entities based on years of operational
experience with the testing methods and testing frequencies that work best for the specific asset.
In the worst case, the specifics dictated in the Tables may move Entities away from more stringent
PSMPs that are currently in practice. For this reason, Constellation suggests that the drafting team
revisit the concept of the Tables to better balance to convey useful guidance without creating a
compliance requirement that may be contrary to improved reliability. The Registered Entity should
be given more flexibility to dictate how a protection system component should be tested, and at
what frequency. Lastly, the technical manpower and compliance documentation demands to
implement a performance based protection system maintenance program are so onerous that it is
highly unlikely that any small generation entity would use it.
Response: Thank you for your comment.
FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
52
Organization
Yes or No
Question 4 Comment
maintenance activities. The SDT believes that the intervals established within the Tables are appropriate as continent-wide
maximum allowable intervals, with due consideration for any monitoring functionality that may be present. The ability to utilize
performance-based maintenance is provided for those entities who wish to pursue it; it is understood that many entities may
instead choose to simply implement a PSMP based on the Tables.
Florida
Municipal
Power Agency
No
We like the new Table 3, but, have remaining concerns. The standard reaches further into the
distribution system than we would like for UFLS and UVLS. We have two parts to this concern.
First, it will be somewhat onerous to present all the evidence of distribution class protection
system maintenance and testing at audits.
And second, our biggest concern is in the testing required to "exercise" a lockout or tripping relay.
This may require installation of test blocks to allow such exercising of the lockout or tripping relay
without tripping the distribution circuit, and such a test could be difficult to perform without
impacting customer continuity of service if the lockout/tripping relay for the UFLS is the same as
the lockout/tripping relay for distribution fault protection. However, most of FMPA's members
have microprocessor-based relays for distribution circuits with the UFLS / UVLS embedded within
the microprocessor based relay where the path from the UFLS / UVLS relay to the lockout / tripping
relay is internal to the micro-processor based relay, so, testing the UFLS/UVLS relay will at the same
time test the internal lockout / switching relay. However, for older electro-mechanical UFLS
schemes, this type of testing could be problematic.
Response: Thank you for your comment.
First, the existing standards (PRC-008 & PRC-011) already require maintenance and testing of components of UFLS and UVLS
protection systems, including those installed to operate distribution-level interrupting devices.
Second, the UVLS and UFLS systems are included as part of the Project 2007-17 Standard Authorization Request (SAR). The SDT
believes that electromechanical devices, such as auxiliary or lockout relays which contain “moving parts”, need periodic operation
in order to remain reliable. As such, these devices are required to be exercised at the 12 year interval for UVLS and UFLS systems.
The SDT recognizes the risk of human error trips when working with testing of lockout devices but believes these risks can be
managed.
53
Organization
NERC Staff
Technical
Review
Yes or No
Question 4 Comment
No
We agree in principle with the change; however, we have identified discrepancies among these
tables with respect to the reference to UFLS and UVLS systems. The headings in Tables 1-1 through
1-4(b) and Table 1-5 refer to “Excluding distributed UFLS and UVLS”; Table 1-4(c) refers to
“Excluding UFLS and non-distributed UVLS”; while Table 1-4(d) refers to “Excluding UFLS and
distributed UVLS.” We believe the drafting team intended for consistency among these tables and
that the intent is to exclude distributed UFLS and distributed UVLS schemes as opposed to
distributed UFLS and all UVLS schemes. To make this clear we recommend changing the second line
in the heading of each of these tables to “Excluding distributed UFLS and distributed UVLS.”
Corresponding changes should be made in the “Component Attributes” sections of Tables 1-4(a)
through 1-4(e) and to the title of Table 3.
Response: Thank you for your comment. The standard has been modified as you suggest.
Tennessee
Valley Authority
No
54
5. The SDT has revised the “Supplementary Reference and FAQ” document which is supplied to provide supporting discussion
for the Requirements within the standard. Do you agree with the changes? If not, please provide specific suggestions for
change.
Summary Consideration: Many commenters objected to Requirement R3 and to the explanation that entities would be held to
compliance on “either the Tables or their PSMP, whichever is more stringent”. In response to these comments, the SDT modified the
standard to remove Requirement R1 part 1.3, and revised Requirement R3 so that, for time-based programs, entities shall comply
with the Tables rather than their PSMP. The SDT added Requirement R4 to address performance-based maintenance, and added
Requirement R5 to address Unresolved Maintenance Issues. The Supplementary Reference and FAQ document was updated to reflect
these changes.
Several commenters questioned the inclusion of the dc control circuitry for sudden pressure relays even though the relays themselves
are excluded from the definition of “Protection System”; the SDT reiterated its position that this dc control circuitry is indeed included
because the dc control circuitry is associated with protective functions. No change was made to the standard based on these
comments.
Numerous commenters suggested minor revisions or clarifying text for the Supplementary Reference and FAQ document. These
changes were generally adopted.
Organization
Ameren
Services
Yes or No
Question 5 Comment
Affirmative
1. Although the explanation of ‘Restore’ is enlightening on page 12, ‘Restore’ no longer appears in
the PS Maintenance definition in the last few drafts.
Ballot
2. We disagree with the added burden of retaining maintenance records for removed or replaced
equipment. This will actually reduce reliability because of the confusion it can cause as to what
55
Organization
Yes or No
Question 5 Comment
equipment is providing BES protection. At most, only the last maintenance date of the
removed or replaced component should be retained if there’s really a need to prove that the
interval was met regarding the BES protection.
3. Remove ‘Reverse power relays’ from the list on page 32. They provide thermal of the steam
turbine, not electrical protection of the generator.
4. Now that FERC has approved the Project 2009-17 Interpretation, please acknowledge more
directly in the Supplement that the ‘transmission Protection System’ that is now approved.
NERC interprets “transmission Protection System,” as it appears in Requirements R1 and R3 of
PRC-004-1 and Requirements R1 and R2 of PRC-005-1, to mean “any Protection System that is
installed for the purpose of detecting faults on transmission elements (lines, buses,
transformers, etc.) identified as being included in the Bulk Electric System (BES) and trips an
interrupting device that interrupts current supplied directly from the BES".
5. Please consistently state UFLS before UVLS; Table 1-4(e) differs from other parts of the
standard.
Response:
1. Thank you for your suggestion; the SDT has revised the Supplementary Reference and FAQ document to remove the “restore”
reference from the definition.
2. The records for removed/replaced equipment need to be retained to provide documentation that you were in compliance for
the entire compliance monitoring period.
3. The SDT agrees that for many steam units, reverse power relays provide alarm only of a condition which could result in
eventual overheating of steam turbine components. However, for many combustion turbine generators, a reverse power
condition can lead to imminent failure of teeth on the speed reduction gear and thus, reverse power relays on combustion
turbine generators are frequently wired as a direct trip to the generator breaker to immediately remove the motoring
condition. Furthermore, in the Supplementary Reference document, the preface to the list of relays to which you refer is as
follows: “Examples of typical devices and systems that may directly trip the generator, or trip through a lockout relay may
include but are not necessarily limited to:”. The SDT was attempting to provide a list of possible relays that might need to be
included. The list is not meant to be all inclusive nor do all relays of the types on the list necessarily need to be included in an
56
Organization
Yes or No
Question 5 Comment
entity's PSMP.
4. The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is
not used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection
Systems that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary
Reference and FAQ document for additional discussion.
5. Thank you for your suggestion; the SDT has revised the standard.
Madison Gas
and Electric Co.
Affirmative
Ballot
Note that the Guidance document over states that an entity will be held accountable for have a
more restrictive PMSP than the maximum intervals in attachment 1. Please review FERC Order
693, section 278 which states: "While we appreciate that many entities may perform at a higher
level than that required by the Reliability Standards, and commend them for doing so, the
Commission is focused on what is required under the Reliability Standards, and we do not require
that they exceed the Reliability Standards".
Response: Thank you for your comment. The standard and the Supplementary Reference and FAQ document have been changed
to address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for
time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
Northeast
Power
Coordinating
Council, Inc.
Affirmative
Ballot
An issue was raised here in the Northeast regarding requiring an entity to adhere to their
protection system maintenance program, PSMP. If an entity has a maintenance program in place
that has shorter intervals, i.e. more stringent than those in the appendix of the standard, and the
entity misses completing his maintenance, the entity will be found non-compliant irrespective of
the entity to demonstrate they still were within the longer intervals listed in the actual standard.
NPCC would suggest that the SDT consider revising this to only result in a non-compliance
assessment result if an entity missed the intervals in the appendix of the standard not those
specified in their PSMP. The concern is that some entities will forego more stringent programs and
revise their documents "downward" in order to ensure compliance at the potential for a reduction
in reliability. There is no mechanism currently in place to preclude entities from doing this.
57
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment. The standard and the Supplementary Reference and FAQ document have been changed to
address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for
time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
Occidental
Chemical
Affirmative
Ballot
The SDT has revised the “Supplementary Reference” document which is supplied to provide
supporting discussion for the Requirements within the standard. Do you agree with the changes? If
not, please provide specific suggestions for change. Yes. Ingleside Cogeneration LP found the
Supplementary Reference document to be helpful, thorough, and technically accurate. The only
suggestion we have is that demonstrated adherence to the Reference should be admissible of
evidence of compliance at an audit or spot check. Today, all References have no official regulatory
standing – which seems to defeat the purpose of developing them to begin with.
Response: Thank you for your comment. The document is explanatory but also illustrates the intent of the SDT. The rationale and
methods explained within the Supplementary Reference and FAQ document represent the thoughts of the SDT regarding
approaches to application of the standard, but may (or may not) be of use to demonstrate compliance. FERC approves standards as
mandatory and enforceable; FERC does not approve reference documents.
Occidental
Chemical
Affirmative
Ballot
We need to clarify the following: A transmission owner has established a maintenance cycle which
is more stringent (less time between maintenance or test cycles) than the NERC Standard requires.
The transmission owner fails to comply fully with the transmission owner's maintenance and
testing schedule; however, the maintenance and/or testing is performed within the time frame
mandated by the NERC Standard. Must the transmission owner report his failure to comply with
his own maintenance/testing program even though the maintenance or testing was completed
well within the time frame or interval required by the applicable NERC Standard? Must he
transmission owner report such a failure of his own maintenance procedures which are more
stringent than the NERC maintenance/testing standard? Will such a self report be considered a
non-compliance?
Response: Thank you for your comment. The standard and the Supplementary Reference and FAQ document have been changed to
address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for
58
Organization
Yes or No
Question 5 Comment
time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
Oncor Electric
Delivery
Company LLC
Yes
Oncor would like to see the “Supplementary Reference & FAQ” expanded to provide examples of
what documentation would satisfy that the entity is compliant with initiating “resolution of any
Unresolved Maintenance Issues.” Also it would be helpful to all entities if the Drafting Team would
expand on what, if any, tracking of the resolution of an unresolved maintenance issue is required.
Oncor believes that keeping track of the initiation of “resolution of any unresolved maintenance
issues” is necessary but that the standard does not currently address retention requirements
related to this compliance obligation.
Response: Thank you for your comment. The measure related to this requirement has been expanded to include additional
suggestions of relevant documentation. There is no tracking requirement listed for the resolution of unresolved maintenance
issue, only the initiation of a resolution. The SDT recognizes that performance of the activities necessary to resolve an issue are
entirely dependent upon the circumstances surrounding that issue and, consequently, will require varying amounts of resources
and time to complete the process. Requiring tracking and deadlines is not within the scope of this standard. The SDT has clarified
the intent of the requirement to initiate resolution of Unresolved Maintenance Issues by including it separately as Requirement R5
and revising the language such that the responsible entity must demonstrate its efforts to correct Unresolved Maintenance Issues.
Springfield
Utility Board
Yes
Because Springfield Utility Board's (SUB) current maintenance and testing program is time-based,
the revised "Supplementary Reference" document does not impact SUB operations. SUB agrees
with the document changes because the changes result in alternatives for entities, rather than
being prescriptive.
Response: Thank you for your comment.
Ingleside
Cogeneration LP
Yes
Ingleside Cogeneration LP found the Supplementary Reference document to be helpful, thorough,
and technically accurate. The only suggestion we have is that demonstrated adherence to the
Reference should be admissible of evidence of compliance at an audit or spot check. Today, all
References have no official regulatory standing - which seems to defeat the purpose of developing
them to begin with.
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Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment. The document is explanatory but also illustrates the intent of the SDT. The rationale and
methods explained within the Supplementary Reference and FAQ document represent the thoughts of the SDT regarding
approaches to application of the standard, but may (or may not) be of use to demonstrate compliance. FERC approves standards
as mandatory and enforceable; FERC does not approve reference documents.
MidAmerican
Energy
Company
Yes
The changes to the “Supplementary Reference” document appear to be acceptable, but the
following are suggested as changes to enhance clarity.
1. On page 9 of the Supplementary Reference and FAQ draft the following statement is included:
“Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.” On page 67, the third
sentence of Section 15.3 states: “It includes [referring to control circuitry] the wiring from every
trip output to every trip coil.” Later in that section the following is included: “...from a
protective relay that are necessary for the correct operation of the protective functions.” While
this later statement may be interpreted to exclude circuitry associated with relays that do not
respond to non-electrical inputs or impulses it would be better to make this more explicit. It
would seem illogical to require testing of circuitry that is not needed for the protective
functions covered by the standard. It is suggested that a sentence like the following be added
to the first paragraph of Section 15.3: “Control circuitry associated with relays that respond to
non-electrical inputs or impulses is not covered by this standard and need not be tested.”
2. On page 31 of the Supplementary Reference it indicates that a procedure that includes intervals
less than the standard could result in a noncompliance finding even if the maximum intervals in
the standard are complied with. This is contrary to previous Commission rulings on what is
mandatory and enforceable (i.e. only the standard itself Ref. Order 733 p105). This FAQ
response should be changed to reflect those rulings.
Response: Thank you for your comment.
1. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing
elements. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is
60
Organization
Yes or No
Question 5 Comment
consistent with the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to
be consistent with the position of FERC staff.
2. The standard and the Supplementary Reference and FAQ document have been changed to address your concerns. Specifically,
Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs, entities shall
comply with the tables; Requirement R4 has been added to address performance-based maintenance, and Requirement R5 has
been added to address Unresolved Maintenance Issues.
Ameren
Yes
1. Although the explanation of ‘Restore’ is enlightening on page 12, ‘Restore’ no longer appears in
the PS Maintenance definition in the last few drafts.
2. We disagree with the added burden of retaining maintenance records for removed or replaced
equipment. This will actually reduce reliability because of the confusion it can cause as to what
equipment is providing BES protection. At most, only the last maintenance date of the removed or
replaced component should be retained if there’s really a need to prove that the interval was met
regarding the BES protection.
3) Remove ‘Reverse power relays’ from the list on page 32. They provide thermal of the steam
turbine, not electrical protection of the generator.
Response:
1. Thank you for your suggestion; the SDT has revised the Supplementary Reference and FAQ document to remove the “restore”
reference from the definition.
2. The records for removed/replaced equipment need to be retained to provide documentation that you were in compliance for
the entire compliance monitoring period.
3. The SDT agrees that for many steam units, reverse power relays provide alarm only of a condition which could result in eventual
overheating of steam turbine components. However, for many combustion turbine generators, a reverse power condition can
lead to imminent failure of teeth on the speed reduction gear and thus, reverse power relays on combustion turbine generators
are frequently wired as a direct trip to the generator breaker to immediately remove the motoring condition. Furthermore, in
the Supplementary Reference and FAQ document, the preface to the list of relays to which you refer is as follows: “Examples of
typical devices and systems that may directly trip the generator, or trip through a lockout relay may include but are not
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Organization
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Question 5 Comment
necessarily limited to:”. The SDT was attempting to provide a list of possible relays that might need to be included. The list is
not meant to be all inclusive nor do all relays of the types on the list necessarily need to be included in an entity's PSMP.
Tacoma Power
Yes
It is not clear to what extent can an entity (or auditor) can rely on information contained within the
Supplementary Reference to support their position during an audit. There is a disclaimer at the
beginning of the Supplementary Reference stating that “this supplementary reference to PRC-0052 is neither mandatory nor enforceable.” It seems that interpretation of the draft standard
depends heavily upon this Supplementary Reference. At the same time, the Supplementary
Reference does not rise to the level of a standard.
Response: Thank you for your comment. The document is explanatory but also illustrates the intent of the SDT. The rationale and
methods explained within the Supplementary Reference and FAQ document represent the thoughts of the SDT regarding
approaches to application of the standard, but may (or may not) be of use to demonstrate compliance. FERC approves standards as
mandatory and enforceable; FERC does not approve reference documents.
Bonneville
Power
Administration
Yes
Dominion
Yes
Entergy Services
Yes
Independent
Electricity
System
Operator
Yes
City of Austin
dba Austin
Energy
Yes
62
Organization
Yes or No
ITC Holdings
Yes
Dominion
Yes
Southwest
Power Pool
Standards
Review Group
Yes
Pepco Holdings
Inc & Affiliates
Yes
Independent
Electricity
System
Operator
Yes
Northeast
Utilities
Yes
Westar Energy
Yes
Progress Energy
Yes
PacifiCorp
Yes
Saft America,
Inc.
Yes
Exelon
Yes
Question 5 Comment
63
Organization
Yes or No
Central Lincoln
Yes
Dynegy Inc.
Yes
Baltimore Gas &
Electric
Company
Negative
Ballot
Question 5 Comment
BGE's negative ballot is based on our response to Q5: While we do not disagree with the revisions
to the Supplemental Reference, there remains an important item to correct. The supplementary
reference on page 31, under the question beginning “Our maintenance plan calls…” states that an
entity is “out of compliance” if maintenance occurs at a time longer than that specified in the
entity’s plan, even if that maintenance occurred at less than the maximum interval in PRC-005-2.
But then on page 35-36, under the question, “How do I achieve a grace period without being out of
compliance?” the response provides a presumably compliant example of scheduling maintenance
at four year intervals in order to manage scheduling complexities and assure completion in less
than the maximum time of six calendar years. This advice conflicts with the previous guidance.
The FAQ /supplementary reference should be revised so that it does not imply that an entity is out
of compliance by performing maintenance more frequently than required than the bright-line
maxima in the tables. Entities may opt to test more frequently than dictated in the tables for a
variety of reasons that may or may not be related to reliable protection system performance –
compliance management, scheduling, operational preference, etc.
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
AEP
Negative
Ballot
This negative vote is driven primarily by the concerns AEP has regarding the proposed
supplementary reference documentation. If an entity adopts a more stringent maintenance
program but fails to meet it, that entity could be found non-compliant despite continuing to abide
by the minimum requirements of the standard itself. Entities should have the ability, if they so
choose, to include additional maintenance activities or more stringent intervals than specified
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Organization
Yes or No
Question 5 Comment
within the standard without concern of penalty in the event they are unable to accomplish them.
In addition, AEP is concerned by the volume of information provided in the supplementation
documentation, and is uncertain how much weight that documentation might carry during audits.
Note: Additional comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power.
Response: Thank you for your comments.
The standard and the Supplementary Reference and FAQ document have been changed to address your concerns. Specifically,
Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs, entities shall
comply with the tables; Requirement R4 has been added to address performance-based maintenance, and Requirement R5 has
been added to address Unresolved Maintenance Issues.
The document is explanatory but also illustrates the intent of the SDT. The rationale and methods explained within the
Supplementary Reference and FAQ document represent the thoughts of the SDT regarding approaches to application of the
standard, but may (or may not) be of use to demonstrate compliance. FERC approves standards as mandatory and enforceable;
FERC does not approve reference documents.
Manitoba Hydro
Negative
Ballot
Maintenance Activities Exceeding NERC Requirements In both the industry webinar discussion and
the supplementary reference document, it was indicated that if an entity had more maintenance
activities in its plan than the minimum required by PRC-005-2, then an entity would be audited to
the "higher standard". We understand that an entity could write some flexibility in its program, as
long as the NERC minimums were met. We are concerned that auditing to the "higher standard"
could discourage entities from performing maintenance tasks beyond the NERC minimum criteria.
Response: Thank you for your comments. The standard and the Supplementary Reference and FAQ document have been changed
to address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for
time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
PJM
Interconnection,
Negative
PJM remains concerned with a position taken by the SDT related to statements found within their
Supplementary Reference & FAQ as well as the manner in which Requirement R3 has been
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Organization
L.L.C.
Yes or No
Question 5 Comment
Ballot
drafted. The SDT's position sends industry the wrong message; a message that entities should not
go beyond what is in the text of the standards and that in some cases they can even be found noncompliant by merely failing to meet their own more stringent internal practice. Therefore, PJM is
voting NEGATIVE at this time. The NERC reliability standards aim to ensure an Adequate Level of
Reliability (ALR). If NERC's reliability standard establishes that an ALR is achieved by a maximum
allowable relay maintenance period of every 6 years in a time-based Protection System
Maintenance Program (PSMP), then an entity striving to complete its maintenance every 4 years
should not be found non-compliant for completing it in 5 years. We have heard NERC say in CAN
Webinars and NERC Workshops that "auditors must audit to the standard", however, the position
taken by the SDT within their Supplementary Reference and FAQ document and the wording of
Requirement R3 is contrary to this position.
Negative
Poll
Response: Thank you for your comments. The standard and the Supplementary Reference and FAQ document have been changed
to address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for
time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
FirstEnergy
No
We do not agree with aspects of the Supplementary Reference document as discussed in Question
6.
Response: Thank you for your comments. Please see our response to your comments in Question 6.
NERC Staff
Technical
Review
No
We recommend changes to Supplementary Reference. It appears the 3 calendar month interval
referenced in the second FAQ in section 7.1 on page 20, Example 1 on page 21, Example 2 on page
22, and on page 23 should be updated to 4 calendar months consistent with the changes to the
standard for verification of station dc supply voltage and inspection of electrolyte level and
unintentional grounds.
We recommend modifying references to UFLS and UVLS to clarify the intervals for distributed
systems applies to both UFLS and UVLS similar to the recommended change to the standard in our
comment on question 4. See pp. 26, 30, 33, 86, and 87 of the supplementary reference.
66
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment.
1. Thank you for comment; the Supplementary Reference and FAQ document has been changed.
2. Changes have been made to the standard and its Supplementary Reference and FAQ document.
MRO's NERC
Standards
Review Forum
No
a. Page 9, “Is a Sudden Pressure Relay an auxiliary tripping relay? “1) During the webinar on
Thursday, September 15th it was asked whether the trip path for a sudden pressure relay needed
to be confirmed. Based on this question, we believe that the FAQ should be modified as follows:i.
Is a Sudden Pressure Relay an auxiliary tripping relay? No. IEEE C37.2-2008 assigns the device
number 94 to auxiliary tripping relays. Sudden pressure relays are assigned device number 63.
Sudden pressure relays are excluded from the Standard because it does not utilize voltage and/or
current measurements to determine anomalies. Since the sudden pressure relay is not included, it
also follows that trip path testing for this relay type is also excluded.
b. On page 26 of the Supplementary Reference document, it states, “If your PSMP (plan) requires
more activities than you must perform and document to this higher standard.” This penalizes
utilities from including best practices in their PSMP, and encourages utilities to implement the
standard maintenance practice instead of a higher maintenance practice. Why would a utility
accept the additional risk of a NERC penalty or sanction when they can stay in compliance by
accepting the minimum requirements of the standard? By stating this, the PSMP will include only
those required items at the minimum frequency to avoid a compliance violation. For the reliability
of the BES, recommend the wording be changed to, “If your PSMP (plan) requires more activities
than required by PRC-005-2, you will be held accountable only to the minimum requirements in
the standard. NERC encourages utilities to implement best practices to improve the reliability of
the BES, so utilities will not be penalized for exceeding the standards.” In FERC Order 693, section
278 FERC states: While we appreciate that many entities may perform at a higher level than that
required by the Reliability Standards, and commend them for doing so, the Commission is focused
on what is required under the Reliability Standards, we do not require that they exceed the
Reliability Standards”.
c. Page 78, last paragraph: If the same type of ohmic testing is done (impedance, conductance or
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Organization
Yes or No
Question 5 Comment
resistance), may a different manufacturer’s test equipment be used for this testing?
d. Page 79, second paragraph of “Why verify voltage?”:
1) “The verification of the dc supply voltage is simply an observation of battery voltage to
prove that the charger has not been lost or is not malfunctioning.” i. Is it the intent of the
PSMT SDT that this measurement is taken at the battery terminals, or will a reading taken
from the battery charger panel meter meet this requirement?
2) “The maintenance activity of verifying the float voltage of the battery charger is not to
prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits.” i. Is it
the intent of the PSMT SDT that this measurement is taken at the battery terminals, or will a
reading taken from the battery charger panel meter meet this requirement?
e. Except as noted above, the changes to the “Supplementary Reference” document appear to be
acceptable, but the following are suggested as changes to enhance clarity.
1) On page 9 of the Supplementary Reference and FAQ draft the following statement is
included: “Relays that respond to non-electrical inputs or impulses (such as, but not limited to,
vibration, pressure, seismic, thermal or gas accumulation) are not included.” On page 67, the
third sentence of Section 15.3 states: “It includes [referring to control circuitry] the wiring
from every trip output to every trip coil.” Later in that section the following is included:
“...from a protective relay that are necessary for the correct operation of the protective
functions.” While this later statement may be interpreted to exclude circuitry associated with
relays that do not respond to non-electrical inputs or impulses it would be better to make this
more explicit. It would seem illogical to require testing of circuitry that is not needed for the
protective functions covered by the standard. It is suggested that a sentence like the following
be added to the first paragraph of Section 15.3: “Control circuitry associated with relays that
respond to non-electrical inputs or impulses is not covered by this standard and need not be
tested.”
2) On page 31 of the Supplementary Reference it indicates that a procedure that includes
intervals less than the standard could result in a noncompliance finding even if the maximum
68
Organization
Yes or No
Question 5 Comment
intervals in the standard are complied with. This is contrary to previous Commission rulings on
what is mandatory and enforceable (i.e. only the standard itself Ref. Order 733 p105). This
FAQ response should be changed to reflect those rulings.
Response: Thank you for your comment.
1. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing elements.
The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the
currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to be consistent with the
position of FERC staff.
2. The standard and the Supplementary Reference and FAQ document have been changed to address your concerns. Specifically,
Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs, entities shall
comply with the tables; Requirement R4 has been added to address performance-based maintenance, and Requirement R5 has
been added to address Unresolved Maintenance Issues.
3. Yes. Your concern, of course should be that your results can be trended from test to test. The Supplementary Reference and FAQ
document has been changed.
4. The Supplementary Reference and FAQ document has been changed to add clarity.
5. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing elements.
The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the
currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to be consistent with the
position of FERC staff. As to part 2, The standard and the Supplementary Reference and FAQ document have been changed to
address your concerns. Specifically, R1 part 1.3 has been removed; R3 has been revised so that, for time-based programs, entities
shall comply with the tables; R4 has been added to address performance-based maintenance, and R5 has been added to address
Unresolved Maintenance Issues.
ACES Power
Collaborators
No
There are some changes that are needed to the document.
1. On Page 19, the second question refers to R1.4. There is no R1.4 in the standard. We assume
69
Organization
Yes or No
Question 5 Comment
that document is intended to refer to part 1.4 under R1. This needs to be clarified and
corrected.
2. The reference document creates an improper incentive to eliminate best practices and utilize
the maximum time intervals established in the standard. The document states that an entity
will be subject to compliance violations if it has a maintenance and testing program with time
intervals that are more stringent than the maximum time intervals in the standard and it does
not meet its more stringent intervals. This would hold true even if the registered entity meets
the maximum intervals established in the standard. To reduce compliance risk, registered
entities will be incented to increase its time intervals to the maximum allowed by the standard.
This is contrary to supporting reliability. Penalizing entities for failing to meet their more
stringent plan requirements is also contrary to guidance provided by the Commission. Doug
Curry, General Counsel of Lincoln Electric System, spoke to the Commission at the November
18, 2010 FERC technical conference on reliability monitoring, enforcement and compliance
about his company’s experience with the vegetation management standard. They exceeded
the requirements for annual inspections by including six aerial patrols each year but were
found in violation of the standard and paid penalties when they did not complete but one
aerial patrol in the first five months of the year. The auditors concluded that the company’s
ground patrol fully satisfied the minimum requirements of the standard. In the end, LES
removed the aerial inspections from the vegetation management plan. The Commissioners
acknowledged that this was contrary to their goal of an adequate level of reliability and agreed
that an entity should not be penalized for failing to meet their more stringent requirements
when they meet the standard requirements.
3. On Page 34, the FAQ about commissioning does not appear to be consistent with CAN-0011.
While we believe the reference document is more correct, the drafting team should compare
the advice given in the reference document to that in the CAN to ensure that it is not
conflicting. Given that NERC is in the process of revising all of the CANs, the best approach may
simply be to add a statement referencing the CAN-0011 for further information.
4. Comments about “gaming the PBM system” regarding restoring segment performance should
be removed from the reference document. Comments like these indicate intent by a
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Organization
Yes or No
Question 5 Comment
registered entity to manipulate the compliance process. Only after a thorough investigation
can such intent be determined. Thus, there shouldn’t be a presumption that registered entities
will attempt this. Better comments would be to focus on the consistency that the three year
period provides in determining segment performance.
5. In section 12.1 on page 58, the reference document discusses out of service equipment. NERC
recently issued a lesson learned on removing unused relaying equipment on August 10, 2011.
The drafting team may wish to reference that lesson learned in the reference document.
Response: Thank you for your comment.
1. The Supplementary Reference and FAQ document has been changed.
2. The standard and the Supplementary Reference and FAQ document have been changed to address your concerns. Specifically,
Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs, entities shall
comply with the tables; Requirement R4 has been added to address performance-based maintenance, and Requirement R5 has
been added to address Unresolved Maintenance Issues.
3. The Supplementary Reference and FAQ document has been changed.
4. The Supplementary Reference and FAQ document has been changed.
5. The Supplementary Reference and FAQ document has been changed to incorporate a discussion of the cited Lessons Learned.
Southern
Company
Generation
No
Several additional edits are needed so that the document matches the proposed standard:
1) In Section 5.1.1, page 16, add "and Table 3" in the Figure and at the end of FAQ after figure in
that section.
2) In Section 7.1, example #1, a 3 month battery interval is shown
3) In Section 8.1.1, a 3 month interval is shown for communication circuit
4) In Section 15.5.1, several references to "3 month" and "three month" intervals are shown for
communication circuits.
5) In Appendix B, the formatting is incorrect for Al McMeekin's company name.
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Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment. The Supplementary Reference and FAQ document has been changed to address each of
your suggestions.
Nebraska Public
Power District
No
a. On page 26 of the Supplementary Reference document, it states, “If your PSMP (plan) requires
more activities than you must perform and document to this higher standard.” This penalizes
utilities from including best practices in their PSMP, and encourages utilities to implement the
standard maintenance practice instead of a higher maintenance practice. Why would a utility
accept the additional risk of a NERC penalty or sanction when they can stay in compliance by
accepting the minimum requirements of the standard? By stating this, the PSMP will include only
those required items at the minimum frequency to avoid a compliance violation. For the reliability
of the BES, recommend the wording be changed to, “If your PSMP (plan) requires more activities
than required by PRC-005-2, you will be held accountable only to the minimum requirements in
the standard. NERC encourages utilities to implement best practices to improve the reliability of
the BES, so utilities will not be penalized for exceeding the standards.” In FERC Order 693, section
278 FERC states: While we appreciate that many entities may perform at a higher level than that
required by the Reliability Standards, and commend them for doing so, the Commission is focused
on what is required under the Reliability Standards, we do not require that they exceed the
Reliability Standards”.
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
American
Electric Power
No
With such a complex standard as this, the FAQ and Supplementary Reference documents do aid
the Protection System owner in demystifying the requirements. However, AEP is uncertain how
much weight the documents might carry during audits. We recommend that this additional
information be included within the actual standard (for example in an appendix) but in a more
compact version.
Section 15.7 of the supplementary reference includes the bullet point “No verification of trip path
72
Organization
Yes or No
Question 5 Comment
required between the lock-out and/or auxiliary tripping device(s).” This appears to contradict the
other bullet points within Section 15.7.
Response: Thank you for your comment.
1. Doing as you suggest would make the supporting information within the Supplementary Reference and FAQ document part of
the standard and this would add extensive and unnecessary prescription to the standard.
2. The Supplementary Reference and FAQ document has been changed.
Lincoln Electric
System
No
Please see the comments submitted by the MRO NSRF.
Response: Please see our response to the comments submitted by the MRO NSRF.
Liberty Electric
Power LLC
No
The reference contains language which makes it a violation should an entity choose a cycle time
less than the maximum from the table, and then fails to meet that cycle. (See page 27, "If your
PSMP (plan) requires activities more often than the Tables maximum then you must perform and
document those activities to your more stringent standard.") There is no reason to hold a RE in
violation if all work is performed within the maximum time from the table - either there was no
reliability risk, or the table is incorrect and a reliability risk in itself.
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
Manitoba Hydro
No
1. Page 26: In both the industry webinar discussion and the supplementary reference document,
it was indicated that if an entity had more maintenance activities in its plan than the minimum
required by PRC-005-2, then an entity would be audited to the "higher standard". We
understand that an entity could write some flexibility in its program, as long as the NERC
minimums were met. We are concerned that auditing to the "higher standard" could
73
Organization
Yes or No
Question 5 Comment
discourage entities from performing maintenance tasks beyond the NERC minimum criteria.
2. The discussion on page 9 indicates that although the relays which respond to mechanical
parameters are not included in the scope of PRC-005-2, the associated trip circuits are
included. We suggest that neither the relays which respond to mechanical parameters nor their
associated trip circuits are within the scope of this standard
3. References to the tables should be consistently updated to include the new Table 3. “Every 3
calendar months” should be updated throughout the document to “Every 4 calendar months”.
For example, Page 23: Example #3 should be revised.
4. In addition, there are a number of grammatical errors in the document, particularly
capitalization and punctuation, which make it difficult to read. There are terms which are
improperly capitalized implying that they are approved NERC Glossary of Terms definitions
when they are not.
Response Thank you for your comment.
1. The standard and the Supplementary Reference and FAQ document have been changed to address your concerns. Specifically,
Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs, entities shall
comply with the tables; Requirement R4 has been added to address performance-based maintenance, and Requirement R5 has
been added to address Unresolved Maintenance Issues.
2. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing elements.
The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the
currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to be consistent with the
position of FERC staff.
3. The Supplementary Reference and FAQ document has been changed.
4. The Supplementary Reference and FAQ document has had identified errors corrected.
American
Transmission
No
ATC provides the following suggestions for change:
74
Organization
Company
Yes or No
Question 5 Comment
1. Page 9, “Is a Sudden Pressure Relay an auxiliary tripping relay? “During the webinar on
Thursday, September 15th it was asked whether the trip path for a sudden pressure relay needed
to be confirmed. Based on this question, we believe that the FAQ should be modified as follows: Is
a Sudden Pressure Relay an auxiliary tripping relay?No. IEEE C37.2-2008 assigns the device number
94 to auxiliary tripping relays. Sudden pressure relays are assigned device number 63. Sudden
pressure relays are excluded from the Standard because it does not utilize voltage and/or current
measurements to determine anomalies. Since the sudden pressure relay is not included, it also
follows that trip path testing for this relay type is also excluded.
2. Page 78, last paragraph:If the same type of ohmic testing is done (impedance, conductance or
resistance), modify the FAQ to allow the use of a different manufacturer’s test equipment to
conduct the testing.
3. Page 80, second paragraph: ”The verification of the dc supply voltage is simply an observation of
battery voltage to prove that the charger has not been lost or is not malfunctioning.” Insert the
following: “A reading taken from the battery charger panel meter will meet this requirement.”
”The maintenance activity of verifying the float voltage of the battery charger is not to prove that a
charger is lost or producing high voltages on the station dc supply, but rather to prove that the
charger is properly floating the battery within the proper voltage limits.” Insert the following.“ A
reading taken from the battery charger panel meter will meet this requirement.”
Response: Thank you for your comments.
1. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing
elements. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to
be consistent with the position of FERC staff.
2. In the Supplementary Reference and FAQ document, the SDT is discussing methods of performing ohmic testing but is not
specifying any particular test or test equipment.
3. The Supplementary Reference and FAQ document has been changed.
75
Organization
Yes or No
Southern
Company
Transmission
No
Question 5 Comment
1.
Page 16: ‘Add and Table 3’ in Figure and end of FAQ after figure
2.
Page 20: change reference from 3 to 4 months. This applies throughout document.
Response: Thank you for your comments.
1. The Supplementary Reference and FAQ document has been changed.
2. The Supplementary Reference and FAQ document has been changed.
CenterPoint
Energy
No
CenterPoint Energy appreciates that there is now only one document, instead of the two originally
proposed. However, we question the name of the document which shows “Supplemental
Reference and FAQ”. The use of “Supplemental Reference” could infer it contains requirements
not found in the PRC-005-2 standard. Also, we suggest that NERC standardize on the names of
documents associated with standards and other NERC initiatives. CenterPoint Energy recommends
the name of the document be “Technical Reference”.
Response: Thank you for your comment. The Supplementary Reference and FAQ document is explanatory in nature.
BGE
No
While we do not disagree with the revisions to the Supplemental Reference, there remains an
important item to correct. The supplementary reference on page 31, under the question beginning
“Our maintenance plan calls...” states that an entity is “out of compliance” if maintenance occurs
at a time longer than that specified in the entity’s plan, even if that maintenance occurred at less
than the maximum interval in PRC-005-2. But then on page 35-36, under the question, “How do I
achieve a grace period without being out of compliance?” the response provides a presumably
compliant example of scheduling maintenance at four year intervals in order to manage scheduling
complexities and assure completion in less than the maximum time of six calendar years. This
advice conflicts with the previous guidance. The FAQ /supplementary reference should be revised
so that it does not imply that an entity is out-of-compliance by performing maintenance more
frequently than required than the bright-line maxima in the tables. Entities may opt to test more
frequently than dictated in the tables for a variety of reasons that may or may not be related to
reliable protection system performance - compliance management, scheduling, operational
76
Organization
Yes or No
Question 5 Comment
preference, etc.
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
Constellation
Power
Generation
No
While we do not disagree with the revisions to the Supplemental Reference, there remains an
important item to correct. The supplementary reference on page 31, under the question beginning
“Our maintenance plan calls...” states that an entity is “out of compliance” if maintenance occurs
at a time longer than that specified in the entity’s plan, even if that maintenance occurred at less
than the maximum interval in PRC-005-2. But then on page 35-36, under the question, “How do I
achieve a grace period without being out of compliance?” the response provides a presumably
compliant example of scheduling maintenance at four year intervals in order to manage scheduling
complexities and assure completion in less than the maximum time of six calendar years. This
advice conflicts with the previous guidance. The FAQ /supplementary reference should be revised
so that it does not imply that an entity is out-of-compliance by performing maintenance more
frequently than required than the bright-line maxima in the tables. Entities may opt to test more
frequently than dictated in the tables for a variety of reasons that may or may not be related to
reliable protection system performance - compliance management, scheduling, operational
preference, etc. The discussion of “grace period” may be best clarified as a term to include in an
entity’s PSMP that grants entities the flexibility to maintain compliance if testing occurs between
an entity’s plan interval and the bright-line interval.
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
Constellation
Energy
No
While we do not disagree with the revisions to the Supplemental Reference, there remains an
important item to correct. The supplementary reference on page 31, under the question beginning
77
Organization
Yes or No
Commodities
Group
Question 5 Comment
“Our maintenance plan calls...” states that an entity is “out of compliance” if maintenance occurs
at a time longer than that specified in the entity’s plan, even if that maintenance occurred at less
than the maximum interval in PRC-005-2. But then on page 35-36, under the question, “How do I
achieve a grace period without being out of compliance?” the response provides a presumably
compliant example of scheduling maintenance at four year intervals in order to manage scheduling
complexities and assure completion in less than the maximum time of six calendar years. This
advice conflicts with the previous guidance. The FAQ /supplementary reference should be revised
so that it does not imply that an entity is out-of-compliance by performing maintenance more
frequently than required than the bright-line maxima in the tables. Entities may opt to test more
frequently than dictated in the tables for a variety of reasons that may or may not be related to
reliable protection system performance - compliance management, scheduling, operational
preference, etc. The discussion of “grace period” may be best clarified as a term to include in an
entity’s PSMP that grants entities the flexibility to maintain compliance if testing occurs between
an entity’s plan interval and the bright-line interval.
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
Western Area
Power
Administration
No
See comments under question 6
Response: Please see our response to your comments in Question 6.
Tennessee
Valley Authority
No
78
6.
If you have any other comments on this Standard that you have not already provided in response to the prior questions, please
provide them in the comment section.
Summary Consideration:
Many commenters objected to Requirement R3 and to the explanation that entities would be held to compliance on “either the
Tables or their PSMP, whichever is more stringent”. In response to these comments, the SDT modified the standard to remove
Requirement R1 part 1.3, and revised Requirement R3 so that, for time-based programs, entities shall comply with the Tables rather
than their PSMP. The SDT added Requirement R4 to address performance-based maintenance, and added Requirement R5 to address
Unresolved Maintenance Issues. The Supplementary Reference and FAQ document was updated to reflect these changes.
Several commenters questioned the inclusion of the dc control circuitry for sudden pressure relays even though the relays
themselves are excluded from the definition of “Protection System”; the SDT reiterated its position that this dc control circuitry is
indeed included because the dc control circuitry is associated with protective functions.
Several comments were offered objecting that the VSLs establish that any non-compliance is a violation, and that “perfection is
unrealistic”. The SDT responded that the VSL Guidelines do not provide for an entity to be out of performance to some degree
without incurring a violation.
Several comments were offered regarding “Unresolved Maintenance Issues”. Some of these comments suggested that the entity
should be required to resolve such issues, rather than initiating resolution. Others offered concerns regarding the definition of this
term itself or the related VSLs. The SDT revised the definition to: “A deficiency identified during a maintenance activity that causes
the component to not meet the intended performance, and requires follow-up corrective action.” The VSLs for the old Requirement
R3 (new Requirement R5) were revised from graduated “%” to graduated “hard counts” of violations. The SDT also clarified the
intent of the requirement to initiate resolution of Unresolved Maintenance Issues by including it separately as Requirement R5 and
revising the language such that the responsible entity must demonstrate its efforts to correct Unresolved Maintenance Issues.
Other comments were offered regarding Data Retention, generally objecting to retaining the maintenance records for two full
intervals. The SDT explained that this expectation is consistent with the Compliance Monitoring and Enforcement Program.
Several commenters questioned the verification of lockout and auxiliary relays every 6 years. The SDT explained their rationale for
this requirement relative to lockout relays, and did move the auxiliary relays to the 12-year control circuitry verification.
Several comments were offered on the Implementation plan, resulting in several clarifying changes.
Many comments were offered, questioning the Applicability of the standard relative to the recently-approved Interpretation of
“transmission Protection System”. The SDT explained that PRC-005-2 does not use this term; thus the interpretation does not apply.
The SDT also explained that the Applicability in PRC-005 is correct and that it supports the reliability of the BES.
In response to comments, the SDT revised Applicability 4.2.5.4 to indicate that, for generator-connected station service transformers,
only the Protection Systems that trip the generator, either directly or via a lockout relay are included in the standard.
In response to comments, Table 1-4(f) was modified to more accurately represent the monitoring attributes and related activities for
monitored Vented Lead-Acid and Valve-Regulated Lead-Acid batteries.
Organization
Yes or No
Question 6 Comment
City of Austin
dba Austin
Energy
Affirmative
Ballot
(1) The following language should be clarified to make it clear that a Registered Entity does not have
to include its detailed maintenance procedures in its PSMP: 1.4. Include all applicable monitoring
attributes and related maintenance activities applied to each Protection System component type
consistent with the maintenance intervals specified in Tables 1-1 through 1-5, Table 2, and Table 3.
Affirmative
Poll
(2) For a modern digital relay panel, designed with monitored components and electromechanical
lockouts, the maintenance interval would otherwise be a maximum of 12 years except that the
lockout must be electrically operated every 6 years. We cannot see justification for a separate
maintenance activity to just test the lockouts, due to the increased human error associated with
testing lockouts and the low likelihood of a lockout failure. We recommend that the lockouts be
tested on a 12 year basis, perhaps in association with the “Unmonitored control circuitry associated
with protective functions” as found in Table 1-5. By doing so, we feel that the risk of an undesired
operation due to human error can be minimized and not degrade system reliability.
(3) If sudden pressure relays are exempt from the Standard, the DC circuitry for those relays should
also be exempt.
(4) If a Registered Entity has a PSMP that is more stringent than the intervals in PRC-005-2, the
Registered Entity should not be considered out of compliance if it fails to meet its internal interval
but remains within the interval set forth in PRC-005-2.
80
Response: Thank you for your comments.
1. The SDT’s intent with the R1.4 wording is to convey that the entity’s PSMP must document that the monitoring attributes of
any given component type meet the Table-specified monitoring attributes in order to justify exclusion of the maintenance
activities and/or the lengthening of maintenance intervals as provided for in the Tables. PRC-005-2 does not have
requirements for inclusion of detailed maintenance procedures in an entity’s PSMP as the tables within the standard have
taken the place of the “summary of maintenance and testing procedures” required by R1.2 of PRC-005-1.
2. The SDT believes that electromechanical lockout relays need periodic operation in order to remain reliable. As such, these
devices are required to be exercised at the same 6 year interval required for electromechanical relays. The SDT recognizes
the risk of human error trips when working with testing of lockout devices but believes these risks can be managed.
Performance-based maintenance is an option if you want to extend your intervals beyond 6 years. The SDT, however, has
modified Table 1-5 to remove other auxiliary relays, etc, from this activity, and clarified that the verification of such devices is
included within the 12-year unmonitored control circuitry verification.
3. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is
omitted from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the
sensing elements. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this
to be consistent with the position of FERC staff.
4. The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
81
City of
Tacoma,
Department of
Public Utilities,
Light Division,
dba Tacoma
Power
Affirmative
Ballot
1. The implementation plan for R2 and R3 is unclear on whether each maintenance activity has its
own implementation schedule. The implementation plan can also be interpreted to mean that the
implementation schedule for a given protection system component is driven by the smallest
maximum maintenance (allowable) interval. For example, for unmonitored communications
systems, it is unclear whether all maintenance activities indicated in Table 1-2, including those
corresponding to 6 calendar years, must be completed on all unmonitored communications systems
by the first calendar quarter 15 months following applicable regulatory approval, or if this timeline
only applies to the maintenance activity specified in Table 1-2 corresponding to a maximum
maintenance interval of 4 calendar months.
2. Assuming that there is a different implementation schedule for different maintenance activities
for some protection system component types (namely station DC supply and communication
systems), the middle bullet on page 1 of the implementation plan does not seem to consider that it
may not be possible to identify whether some protection system components are completely being
addressed by PRC-005-2 or the Program developed for the previous standards. In other words,
during implementation, some maintenance activities for the same protection system component
may be addressed by PRC-005-2, while other maintenance activities may be addressed by the
Program developed for the previous standards.
3. It is unclear whether control circuitry (trip paths) from protective relays that respond to
mechanical quantities is included. This issue is addressed in the supplementary reference but is
vague in the draft standard itself.
4. This draft of PRC-005-2 requires the Protection System Maintenance Program (PSMP) to “include
all applicable monitoring attributes and related maintenance activities” per the Tables and requires
an entity to “implement and follow its PSMP.” Under the draft standard, it is unclear whether an
entity has to document in the PSMP and/or maintenance records how they accomplish(ed) the
maintenance activities or simply to indicate that the maintenance activities are included and have
been completed within the defined intervals. It is clear that entities are afforded some latitude in
how they conduct the required maintenance activities. However, the level of detail required to
document (1) how an entity chooses to perform the maintenance activities and (2) that applicable
maintenance activities have been completed is not clear.
82
5. In Table 1-2, there is a maintenance activity related to communication systems to “verify essential
signals to and from other Protection System components.” It is unclear if this statement is referring
to control circuitry associated with the communication system end devices, end device input and
output operation (as in Table 1-1 for protective relays), or something else. It is recommended that
the requirement be to “verify operation of communication system inputs and outputs that are
essential to proper functioning of the Protection System.” This language is consistent with that used
for protective relays in Table 1-1.
6. Referring to Table 1-2, it is unclear whether an entity has the sole authority decide which
‘performance criteria’ are ‘pertinent.’ Additionally, it is unclear if an entity must document the
‘communications technology applied’ and the associated ‘performance criteria’ in its PSMP.
7. In Table 1-4, it is unclear if there is a distinction between the terms ‘resistance’ and ‘ohmic values.’
If there is a distinction, then this distinction should be clarified.
8. In Table 1-4, it is unclear if there is a distinction between the terms ‘battery terminal connection
resistance’ and ‘unit-to-unit connection resistance.’ If there is a distinction, then this distinction
should be clarified.
9. In Table 1-4, replace the term ‘resistance’ with ‘impedance.’
10. Recommend that the 6 calendar month interval in Table 1-4(b) be lengthened to 18 calendar
months to be more consistent with similar maintenance activities for other battery types. At
minimum, lengthen the interval to at least 7 calendar months in a similar way that 3 calendar
months was lengthened to 4 calendar months for other maintenance activities.
83
11. Referring to Table 1-5, no periodic maintenance is required for “control circuitry whose
continuity and energization or ability to operate are monitored and alarmed.” It is unclear whether
or not it is acceptable to verify DC voltage at the actuating device trip terminals at least once every
12 calendar years for “unmonitored control circuitry associated with protective functions.” It is
recommended that periodically verifying DC voltage in this manner be an acceptable means of
accomplishing the maintenance activity identified in Table 1-5 for unmonitored control circuitry
associated with protective functions.
12. Referring to 4.2. Facilities of the draft standard, it is unclear whether protection systems for
transformers that step down from over 100kV to below 15kV are applicable to the standard. Even if
there are normally-open distribution feeder ties for purposes of transferring load in a make-beforebreak fashion, these transformers are generally not considered BES elements.
13. Referring to 4.2.5 of the draft standard, it is unclear whether protection for generator excitation
systems are applicable to the standard.
14. It is unclear whether external timing relays (e.g., Zone 2) are considered control circuitry
components (like lockout and auxiliary relays) or protective relay components.
Response:
Thank you for your comments.
1. The SDT agrees with your observation and has changed the relevant parts of the implementation plan to clarify that
they apply to the maintenance activities for the relevant maintenance intervals.
2. The SDT agrees with your observation and has revised the Implementation plan to clarify.
84
3. The trip paths from protective relays that respond to mechanical quantities and are intended to detect faults are a
part of the Protection System control circuitry. The sensing elements are omitted from PRC-005-2 testing
requirements because the SDT is unaware of industry recognized testing protocols for these sensing elements. The
SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with
the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to be
consistent with the position of FERC staff. Note that trip signals from devices sensing mechanical parameters not
directly indicative of an electrical fault need not be tested per this standard.
4. The SDT has removed parts 1.1 and 1.3 from Requirement R1, addressing part of your comment. The SDT agrees
that PRC-005-2 allows some leeway in how an entity fulfills the testing requirements of the standard. Section 15 of
the Supplementary Reference and FAQ document provides numerous examples of possible testing techniques for the
various component types making up a Protection System. An entity’s PSMP should clearly define how the testing
requirements of the standard are fulfilled. The Measures for each requirement, as well as Section 15.8 of the
Supplementary Reference and FAQ document, provide some examples of possible compliance documentation for
completion of testing.
5. The SDT agrees with your suggestion and has changed the standard accordingly.
6. The entity has the authority to establish its own acceptable performance criteria. This criteria does not need to be
in the PSMP, but should reside somewhere within the maintenance documentation.
7. As utilized on Table 1-4, the term “ohmic value” is a generic reference to the measurement of a battery cell or units
ability to pass current flow. This may be done using conductance, resistance or impedance measurements; the
various battery test equipment manufacturers use different measurement methods and the term “ohmic value” is
meant to be technology neutral. See FAQ on page 78 of the Supplementary Reference and FAQ document. The term
“resistance” as used in Table 1-4 refers specifically to the dc resistance of the battery terminal connections and the
battery intercell/inter-unit physical connectors. See related FAQ on pages 74-75 of the Supplementary Reference and
FAQ document.
85
8. Battery terminal connection resistance is a measurement of the resistance of a connection at a battery terminal.
Battery intercell or unit-to-unit connection resistance is a measurement of the resistance of the external conductor
interconnecting two adjacent battery cells or two adjacent multi-cell battery units. The SDT believes these are
common battery maintenance terms used throughout the industry.
9. The SDT disagrees and believes that resistance as used in Table 1-4 is the appropriate term for the parameters to be
measured and is consistent with standard battery system maintenance terminology.
10. The SDT disagrees with your recommendation to standardize maintenance intervals between different battery
types that have distinctly different failure mechanisms. See related FAQ on pages 80-81 of the Supplementary
Reference and FAQ document for further discussion of requirements for ohmic measurements of VRLA batteries.
Concerning your recommendation to allow for 7 calendar months, the SDT believes that the six-month interval
specified is appropriate.
11. The SDT has modified this specific portion of the Table, and believes that the modifications address your concern.
Please see Section 15.3 of the Supplementary Reference and FAQ document for a discussion of this topic.
12. The standard does not include the Protection Systems for transformers that step down from over 100kV to below
15kV if these transformers are not BES elements. If Protection Systems are installed for purposes of detecting Faults
on BES elements, these Protection Systems are included.
13. Paragraph 4.2.5.1 indicates that the excitation system protection system would only be in scope if the excitation
system generates signals that trip the generator output breaker either directly or via lockout or auxiliary tripping
relays.
14. As timing is critical to proper Protection System function, timers are considered protective relays.
86
Ameren
Services
Affirmative
Ballot
Measure M3 on page 5 should only apply to 99.5% of the components. Please revise to state: “Each
… shall have evidence that it has implemented the Protection System Maintenance Program for
99.5% of its components and initiated….” PRC-005-2 unrealistically mandates perfection without
providing technical justification. A basic premise of engineering is to allow for reasonable tolerances,
even Six Sigma allows for defects. Requiring perfection may well harm reliability by distracting
valuable resources from higher priority duties concerning the Protection System. We are not asking
for the VSL to be changed. No one is perfect and it is impractical to imply perfection is achievable.
The consequence of a very small number of components having a missed or late maintenance
activity is insignificant to BES reliability. Our proposed reasonable tolerance sets an appropriate level
of performance expectation. We disagree with the notion that this is “non-performance”.
An alternate approach regarding the unrealistic perfection of M3 is to correctly recognize that the
protection of the primary BES is the objective. Most Protection Systems are redundant by design and
the entity needs to be afforded the opportunity to show that a redundant component met the PSMP
thereby providing the required protection. The entity should be allowed a reasonable time frame of
one calendar increment to maintain the component in question. Our concern stems from the tens of
thousands of components in a PSMP, and the reality that rarely but occasionally a data base error or
outage scheduling issue may result in a very small number component exceeding their maximum
interval. As long as the entity can show that BES protection was sustained and maintains the
component quickly (e.g. within one calendar month of discovery), BES reliability has been
maintained.
Response: Thank you for comment.
The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation. The
graded approach of the VSL for Requirement R3 allows the RRO to provide discretion when assessing severity of the violation when
only a relatively small number of maintenance activities have been missed.
87
City of Austin
dba Austin
Energy
Affirmative
Ballot
1. The following language should be clarified to make it clear that a Registered Entity does not have
to include its detailed maintenance procedures in its PSMP: "all applicable monitoring attributes and
related maintenance activities ". Reference: R1.4. Include all applicable monitoring attributes and
related maintenance activities applied to each Protection System component type consistent with
the maintenance intervals specified in Tables 1-1 through 1-5, Table 2, and Table 3.
2. For a modern digital relay panel, designed with monitored components and electromechanical
lockouts, the maintenance interval would otherwise be a maximum of 12 years except that the
lockout must be electrically operated every 6 years. We cannot see justification for a separate
maintenance activity to just test the lockouts, due to the increased human error associated with
testing lockouts and the low likelihood of a lockout failure. We recommend that the lockouts be
tested on a 12 year basis, perhaps in association with the “Unmonitored control circuitry associated
with protective functions” as found in Table 1-5. By doing so, we feel that the risk of an undesired
operation due to human error can be minimized and not degrade system reliability.
3. If sudden pressure relays are exempt from the Standard, the DC circuitry for those relays should
also be exempt.
Response: Thank you for your comments.
1. The SDT’s intent with the Requirement R1.4 (new Requirement R1.2) wording is to convey that the entity’s PSMP must
document that the monitoring attributes of any given component type meet the Table-specified monitoring attributes in
order to justify exclusion of the maintenance activities and/or the lengthening of maintenance intervals as provided for in the
Tables. PRC-005-2 does not have requirements for inclusion of detailed maintenance procedures in an entity’s PSMP as the
tables within the standard have taken the place of the “summary of maintenance and testing procedures” required by R1.2 of
PRC-005-1.
2. The SDT believes that electromechanical lockout relays need periodic operation in order to remain reliable. As such, these
devices are required to be exercised at the same 6 year interval required for electromechanical relays. The SDT recognizes
the risk of human error trips when working with testing of lockout devices but believes these risks can be managed.
Performance-based maintenance is an option if you want to extend your intervals beyond 6 years. The SDT, however, has
modified Table 1-5 to remove other auxiliary relays, etc, from this activity, and clarified that the verification of such devices is
included within the 12-year unmonitored control circuitry verification.
3. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is
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omitted from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the
sensing elements. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this
to be consistent with the position of FERC staff.
International
Transmission
Company
Holdings Corp
Affirmative
Ballot
While voting "Affirmative" on this ballot, ITC continues to have concerns with testing intervals. These
comments have been submitted via the Comment Form associated with this project.
Response: Thank you for your affirmative vote. Please see our responses to our comments elsewhere in this report.
Occidental
Chemical
Affirmative
Ballot
If you have any other comments on this Standard that you have not already provided in response to
the prior questions, please provide them here. Ingleside Cogeneration, LP, continues to believe that
the six year requirement to verify channel performance on associated communications equipment
will prove to be more detrimental than beneficial on older relays. Clearly newer technology relays
which provide read-outs of signal level or data-error rates will easily verified, but the tools which
measure power levels and error rates on non-monitored communication links are far more intrusive.
After the technician uncouples and re-attaches a fiber optic connection, the communications
channel may be left in worse shape after verification than it was prior to the start of the test.
Response: Thank you for your comment and affirmative vote.
There are less intrusive ways to verify channel performance that do not require disconnecting communication terminations. It is
up to the entity to determine specific maintenance techniques.
89
Oncor Electric
Delivery
Affirmative
Ballot
PRC-005-2 is a vast improvement over the vagueness of the existing standard (PRC-005-1), that the
new standard makes compliance much easier than the present standard. The new standard
recognizes the advances in relay technology and reliability, particularly the benefits of
microprocessor based relays. The standard also provides greater flexibility on its implementation
while recognizing the benefits of a performance based methodology, particularly as it relates to
battery testing. The revised standard eliminates the requirement for a “summary of maintenance
and testing procedures” which was vague and provided no real value to the registered entities.
Operational and administrative efficiencies can be realized by consolidating the relay testing and
maintenance requirements into one standard (PRC-005-1, PRC-008-0, PRC-011-0, PRC-017-0)
Response: Thank you for your comment and affirmative vote.
Public
Utility
District
No. 2 of
Grant
County
Affirmative
Ballot
We are ok with this standard, however, we would like to see some recognition of the use of non-calendar
based maintenance practices such as predictive maintenance practices or condition based maintenance
practices. When you use one of those methodologies for the basis for your plant maintenance it is very
labor intensive to interpret those results to a calendar based requirement.
Response: Thank you for your comment and affirmative vote.
Please see Sections 5, 6, and 7 of the Supplementary Reference and FAQ for a discussion of how the SDT has attempted to
incorporate condition-based maintenance practices (utilizing installed monitoring capabilities) and performance-based
maintenance practices within PRC-005-2.
Tacoma
Public
Utilities
Affirmative
Ballot
1. The implementation plan for R2 and R3 is unclear on whether each maintenance activity has its own
implementation schedule. The implementation plan can also be interpreted to mean that the
implementation schedule for a given protection system component is driven by the smallest maximum
maintenance (allowable) interval. For example, for unmonitored communications systems, it is unclear
whether all maintenance activities indicated in Table 1-2, including those corresponding to 6 calendar
years, must be completed on all unmonitored communications systems by the first calendar quarter 15
months following applicable regulatory approval, or if this timeline only applies to the maintenance
activity specified in Table 1-2 corresponding to a maximum maintenance interval of 4 calendar months.
90
2. Assuming that there is a different implementation schedule for different maintenance activities for
some protection system component types (namely station dc supply and communication systems), the
middle bullet on page 1 of the implementation plan does not seem to consider that it may not be possible
to identify whether some protection system components are completely being addressed by PRC-005-2
or the Program developed for the previous standards. In other words, during implementation, some
maintenance activities for the same protection system component may be addressed by PRC-005-2, while
other maintenance activities may be addressed by the Program develoepd for the previous standards.
3. It is unclear whether control circuitry (trip paths) from protective relays that respond to mechanical
quantities is included. This issue is addressed in the supplementary reference but is vague in the draft
standard itself.
4. This draft of PRC-005-2 requires the Protection System Maintenance Program (PSMP) to “include all
applicable monitoring attributes and related maintenance activities” per the Tables and requires an entity
to “implement and follow its PSMP.” Under the draft standard, it is unclear whether an entity has to
document in the PSMP and/or maintenance records how they accomplish(ed) the maintenance activities
or simply to indicate that the maintenance activities are included and have been completed within the
defined intervals. It is clear that entities are afforded some latitude in how they conduct the required
maintenance activities. However, the level of detail required to document (1) how an entity chooses to
perform the maintenance activities and (2) that applicable maintenance activities have been completed is
not clear.
5. In Table 1-2, there is a maintenance activity related to communication systems to “verify essential
signals to and from other Protection System components.” It is unclear if this statement is referring to
control circuitry associated with the communication system end devices, end device input and output
operation (as in Table 1-1 for protective relays), or something else. It is recommended that the
requirement be to “verify operation of communication system inputs and outputs that are essential to
proper functioning of the Protection System.” This language is consistent with that used for protective
relays in Table 1-1.
91
6. Referring to Table 1-2, it is unclear whether an entity has the sole authority decide which ‘performance
criteria’ are ‘pertinent.’ Additionally, it is unclear if an entity must document the ‘communications
technology applied’ and the associated ‘performance criteria’ in its PSMP.
7. In Table 1-4, it is unclear if there is a distinction between the terms ‘resistance’ and ‘ohmic values.’ If
there is a distinction, then this distinction should be clarified.
8. In Table 1-4, it is unclear if there is a distinction between the terms ‘battery terminal connection
resistance’ and ‘unit-to-unit connection resistance.’ If there is a distinction, then this distinction should be
clarified.
9. In Table 1-4, replace the term ‘resistance’ with ‘impedance.’
10. Recommend that the 6 calendar month interval in Table 1-4(b) be lengthened to 18 calendar months
to be more consistent with similar maintenance activities for other battery types. At minimum, lengthen
the interval to at least 7 calendar months in a similar way that 3 calendar months was lengthened to 4
calendar months for other maintenance activities.
11. Referring to Table 1-5, no periodic maintenance is required for “control circuitry whose continuity and
energization or ability to operate are monitored and alarmed.” It is unclear whether or not it is acceptable
to verify DC voltage at the actuating device trip terminals at least once every 12 calendar years for
“unmonitored control circuitry associated with protective functions.” It is recommended that periodically
verifying DC voltage in this manner be an acceptable means of accomplishing the maintenance activity
identified in Table 1-5 for unmonitored control circuitry associated with protective functions.
12. Referring to 4.2. Facilities of the draft standard, it is unclear whether protection systems for
transformers that step down from over 100kV to below 15kV are applicable to the standard. Even if there
are normally-open distribution feeder ties for purposes of transferring load in a make-before-break
fashion, these transformers are generally not considered BES elements.
13. Referring to 4.2.5 of the draft standard, it is unclear whether protection for generator excitation
systems are applicable to the standard.
92
14. It is unclear whether external timing relays (e.g., Zone 2) are considered control circuitry components
(like lockout and auxiliary relays) or protective relay components.
Response:
Thank you for your comments.
1. The SDT agrees with your observation and has changed the relevant parts of the implementation plan to clarify that
they apply to the maintenance activities for the relevant maintenance intervals
2. The SDT agrees with your observation and has revised the Implementation plan to clarify.
3. The trip paths from protective relays that respond to mechanical quantities and are intended to detect faults are a
part of the Protection System control circuitry. The sensing elements are omitted from PRC-005-2 testing
requirements because the SDT is unaware of industry recognized testing protocols for these sensing elements. The
SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with
the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to be
consistent with the position of FERC staff. Note that trip signals from devices sensing mechanical parameters not
directly indicative of an electrical fault need not be tested per this standard.
4. The SDT has removed parts 1.1 and 1.3 from Requirement R1, addressing part of your comment. The SDT agrees
that PRC-005-2 allows some leeway in how an entity fulfills the testing requirements of the standard. Section 15 of
the Supplementary Reference and FAQ document provides numerous examples of possible testing techniques for the
various component types making up a Protection System. An entity’s PSMP should clearly define how the testing
requirements of the standard are fulfilled. The Measures for each requirement, as well as Section 15.8 of the
Supplementary Reference and FAQ document, provide some examples of possible compliance documentation for
completion of testing.
5. The SDT agrees with your suggestion and has changed the standard accordingly.
6. The entity has the authority to establish its own acceptable performance criteria. This criteria does not need to be
in the PSMP, but should reside somewhere within the maintenance documentation.
93
7. As utilized on Table 1-4, the term “ohmic value” is a generic reference to the measurement of a battery cell or units
ability to pass current flow. This may be done using conductance, resistance or impedance measurements; the
various battery test equipment manufacturers use different measurement methods and the term “ohmic value” is
meant to be technology neutral. See FAQ on page 78 of the Supplementary Reference and FAQ document. The term
“resistance” as used in Table 1-4 refers specifically to the dc resistance of the battery terminal connections and the
battery intercell/inter-unit physical connectors. See related FAQ on pages 74-75 of the Supplementary Reference and
FAQ document.
8. Battery terminal connection resistance is a measurement of the resistance of a connection at a battery terminal.
Battery intercell or unit-to-unit connection resistance is a measurement of the resistance of the external conductor
interconnecting two adjacent battery cells or two adjacent multi-cell battery units. The SDT believes these are
common battery maintenance terms used throughout the industry.
9. The SDT disagrees and believes that resistance as used in Table 1-4 is the appropriate term for the parameters to be
measured and is consistent with standard battery system maintenance terminology.
10. The SDT disagrees with your recommendation to standardize maintenance intervals between different battery
types that have distinctly different failure mechanisms. See related FAQ on pages 80-81 of the Supplementary
Reference and FAQ document for further discussion of requirements for ohmic measurements of VRLA batteries.
Concerning your recommendation to allow for 7 calendar months, the SDT believes that the six-month interval
specified is appropriate.
11. The SDT has modified this specific portion of the Table, and believes that the modifications address your concern.
Please see Section 15.3 of the Supplementary Reference and FAQ document for a discussion of this topic.
12. The standard does not include the Protection Systems for transformers that step down from over 100kV to below
15kV if these transformers are not BES elements. If Protection Systems are installed for purposes of detecting Faults
on BES elements, these Protection Systems are included.
13. Paragraph 4.2.5.1 indicates that the excitation system protection system would only be in scope if the excitation
system generates signals that trip the generator output breaker either directly or via lockout or auxiliary tripping
relays.
94
14. As timing is critical to proper Protection System function, timers are considered protective relays.
Wisconsin
Electric
Power Co.
Affirmative
Ballot
Do we need to track the maintenance of another owner's Protection System Component which is part of
my Protection System? For example, if our Protection System includes and trips another owner's circuit
breaker, do we need to track maintenance and testing for that circuit breaker?
Wisconsin
Electric
Power
Marketing
Response: Thank you for your comment and affirmative ballots.
The owner is responsible for the maintenance of Protection System Components. You do not need to track the maintenance of
other owner’s Protection System Components.
Beaches
Energy
Services
Negative
Ballot
1. Standard requires 100% perfection, e.g., missing any one interval for any one piece of equipment leads
to a violation. This is; however, mitigated by the fact that the intervals are long enough to allow
implementation of business practices with shorter intervals to add some "buffer".
95
2. The "Applicability" section is not consistent with the recent Y-W and Tri-State PRC-005 interpretation
(Project 2009-17). The Applicability 4.2.1 states that the standard includes: "Protection Systems that are
installed for the purpose of detecting faults on BES Elements (lines, buses, transformers, etc.)" whereas
the Y-W and Tri-State interpretation basically says that "transmission Protection Systems" both detect
AND trip BES Elements; Hence, the new standard alters the existing "and" statement in the Y-W and triState interpretation and eliminates the consideration of tripping BES Elements from applicability. This will
have the consequence of including Protection Systems on step-down transformers that "look backwards"
into the BES system as applicable to the standard. For instance, a distribution network fed from multiple
transmission interconnections will have protective relaying (directional overcurrent most likely) to look
backwards into the transmission system to trip the step-down transformer to prevent back-feed from the
distribution network). This step-down transformer protection would be included in the new standard
because it's purpose to the detect faults on the BES (event though the purpose of the protection is
actually to protect overloading of the distribution and for worker safety on the BES); whereas the Y-W
and Tri-State interpretation excludes that protection from the existing PRC-005-1 standard.
Response: Thank you for your comments.
1. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation.
The graded approach of the VSL for Requirement R3 allows the RE to provide discretion when assessing severity of the violation
when only a relatively small number of maintenance activities have been missed.
2. The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is
not used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection
Systems that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary
Reference and FAQ document for additional discussion. If, as in your example, a protective relay is installed to prevent back
feeding (rather than for detecting BES faults), it would not be applicable even if it has a secondary result of incidentally
detecting faults on the BES.
96
Florida
Municipal
Power
Pool
Negative
Ballot
1. Standard requires 100% perfection, e.g., missing any one interval for any one piece of equipment leads
to a violation. This is; however, mitigated by the fact that the intervals are long enough to allow
implementation of business practices with shorter intervals to add some "buffer", e.g., if the standard
says an interval is 6 years, then, through business practice we can shorten actual maintenance and testing
intervals to something like 4 years to allow ourselves a 2 year buffer to catch equipment that may have
been missed due to difficulty in scheduling outages and the like. Does not cause us to vote negative.
Negative
Poll
2. The "Applicability" section is not consistent with the recent Y-W and Tri-State PRC-005 interpretation
(Project 2009-17). The Applicability 4.2.1 states that the standard includes: "Protection Systems that are
installed for the purpose of detecting faults on BES Elements (lines, buses, transformers, etc.)" whereas
the Y-W and Tri-State interpretation basically says that "transmission Protection Systems" both detect
AND trip BES Elements; Hence, the new standard alters the existing "and" statement in the Y-W and triState interpretation and eliminates the consideration of tripping BES Elements from applicability. This will
have the consequence of including Protection Systems on step-down transformers that "look backwards"
into the BES system as applicable to the standard. For instance, a distribution network fed from multiple
transmission interconnections will have protective relaying (directional overcurrent most likely) to look
backwards into the transmission system to trip the step-down transformer to prevent back-feed from the
distribution network). This step-down transformer protection would be included in the new standard
because it's purpose to the detect faults on the BES (event though the purpose of the protection is
actually to protect overloading of the distribution and for worker safety on the BES); whereas the Y-W
and Tri-State interpretation excludes that protection from the existing PRC-005-1 standard. Causes us to
vote Negative.
97
Response: Thank you for your comments.
1. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation.
The graded approach of the VSL for Requirement R3 allows the RE to provide discretion when assessing severity of the
violation when only a relatively small number of maintenance activities have been missed.
2. The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The
SDT observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this
term is not used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses
“Protection Systems that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the
Supplementary Reference and FAQ document for additional discussion. If, as in your example, a protective relay is installed
to prevent back feeding (rather than for detecting BES faults), it would not be applicable even if it has a secondary result of
incidentally detecting faults on the BES.
Constellation
Power Source
Generation,
Inc.
Negative
Ballot
Negative
Poll
Constellation Power Generation is voting against the approval of this standard because, from a
generation perspective, the maintenance intervals and activities described in all of the Tables are too
prescriptive. Constellation Power Generation is concerned that the Tables may conflict with the
existing PSMPs built by Registered Entities based on years of operational experience with the testing
methods and testing frequencies that work best for the specific asset. In the worst case, the specifics
dictated in the Tables may move Entities away from more stringent PSMPs that are currently in
practice. For this reason, Constellation Power Generation suggests that the drafting team revisit the
concept of the Tables to better convey useful guidance without creating a compliance requirement
that may be contrary to improved reliability. The Registered Entity should be given more flexibility to
dictate how a protection system component should be tested, and at what frequency. Furthermore,
the technical manpower and compliance documentation demands to implement a performance
based protection system maintenance program are so onerous that it is highly unlikely that any small
generation entity would use it. Please refer to Constellation Power Generation’s submitted
comments for other issues identified with this standard.
Response: Thank you for your comment.
FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
maintenance activities. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that
may be consistently monitored for compliance.
98
Duke Energy/
Fort Pierce
Utilities
Authority
Negative
Ballot
Duke Energy disagrees with the wording in the Applicability section 4.2.1. The wording change from
PRC-005-2 draft 4 to PRC-005-2 draft 5 expands the reach of the standard to relaying schemes that
detect faults on the BES but are not intended to provide protection for the BES. Duke Energy’s
standard protection scheme for dispersed generation at retail stations would be subject to the
standard due to the changes in section 4.2.1. These protection schemes are design to detect faults
on the BES, but do not operate BES elements nor do they interrupt network current flow from the
BES. In the most recent draft the relays, current transformers, potential transformers, trip paths,
auxiliary relays, batteries, and communication equipment associated with the dispersed generation
protection scheme would be subject to the requirements in PRC-005-2. Previous drafts of the
standard would not have required Duke Energy to maintain the protection system components
associated with dispersed generation schemes at retail stations in accordance to the requirements in
PRC-005-2. The new wording in section 4.2.1 would add significant O&M costs and resource
constraints due to the inclusion of protection system devices at retail stations without increasing the
reliability of the BES. Duke Energy does not believe it was the intent of the standard to include
elements that did not have an impact on the reliability of the BES. Duke Energy would prefer the
definition used in PRC-005-1A Appendix 1 “any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being
included in the Bulk Electric System (BES) and trips an interrupting device that interrupts current
supplied directly from the BES.”
Response: Thank you for your comment.
The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is not
used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems
that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and
FAQ document for additional discussion.
99
Lakeland
Electric
Negative
Ballot
First Concern is that evidence of maintenance and testing at this level will be very difficult to obtain,
track and report.
Second is the word exercise - what is really meant by this. This may be difficult or impossible to do
without impacting or tripping the circuit.
The "Applicability" section is not consistent with the recent Y-W and Tri-State PRC-005 interpretation
(Project 2009-17).
Response: Thank you for your comments
1.
FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
maintenance activities. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion
that may be consistently monitored for compliance. Nonetheless, the SDT agrees that significant effort will be necessary to
implement these requirements and to prove compliance.
2.
The SDT is unsure to which utilization of the word “exercise” you refer.
3.
The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is
not used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection
Systems that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary
Reference and FAQ document for additional discussion.
Illinois
Municipal
Electric Agency
Negative
Ballot
IMEA greatly appreciates SDT efforts to address/resolve issues, improve PRC-005, and consolidate
various PRC Reliability Standards. However, IMEA is voting Negative based on the inconsistency
between the current Applicability language and the PRC-004 and PRC-005 interpreation (Project
2009-17) recently approved by FERC. IMEA supports comments submitted by Florida Municipal
Power Agency which address this inconsistency, and encourages the SDT to address this issue which
is important to municipal entities.
100
Response: Thank you for your comment.
The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is not
used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems
that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and
FAQ document for additional discussion. If, as in your example, a protective relay is installed to prevent back feeding (rather than
for detecting BES faults), it would not be applicable even if it has a secondary result of incidentally detecting faults on the BES.
Consumers
Energy
Negative
Ballot
R3 continues to have "...initiate resolution of unresolved maintenance issues." Initiate means to start
or set going, it does not mean closure of the item. If a remediation project is initiated and not closed
out in a timely manner an auditor could penalize an entity based on what the auditor considers
timely. We suggest definitive language indicating closure of the unresolved maintenance issue. Also,
it would be beneficial to specify time frame for closing the issue.
Response: Thank you for your comment.
PRC-005-2 only requires the entity “… initiate resolution” of the issue found. The SDT recognizes that performance of the activities
necessary to resolve an issue are entirely dependent upon the circumstances surrounding that issue and, consequently, will require
varying amounts of resources and time to complete the process. The SDT has clarified the intent of the requirement to initiate
resolution of Unresolved Maintenance Issues by including it separately as Requirement R5 and revising the language such that the
responsible entity must demonstrate its efforts to correct Unresolved Maintenance Issues. Demonstrating the entity has initiated
resolution can include such things as documentation of a work order, replacement component order, invoice, or purchase order,
etc… Producing evidence of this nature would then indicate adherence to the requirement.
101
Florida Keys
Electric
Cooperative
Assoc.
Negative
Ballot
The "Applicability" section is not consistent with the recent Y-W and Tri-State PRC-005 interpretation
(Project 2009-17). The Applicability 4.2.1 states that the standard includes: "Protection Systems that
are installed for the purpose of detecting faults on BES Elements (lines, buses, transformers, etc.)"
whereas the Y-W and Tri-State interpretation basically says that "transmission Protection Systems"
both detect AND trip BES Elements; Hence, the new standard alters the existing "and" statement in
the Y-W and tri-State interpretation and eliminates the consideration of tripping BES Elements from
applicability. This will have the consequence of including Protection Systems on step-down
transformers that "look backwards" into the BES system as applicable to the standard. For instance,
a distribution network fed from multiple transmission interconnections will have protective relaying
(directional overcurrent most likely) to look backwards into the transmission system to trip the stepdown transformer to prevent back-feed from the distribution network). This step-down transformer
protection would be included in the new standard because it's purpose to the detect faults on the
BES (event though the purpose of the protection is actually to protect overloading of the distribution
and for worker safety on the BES); whereas the Y-W and Tri-State interpretation excludes that
protection from the existing PRC-005-1 standard.
Response: Thank you for your comment.
The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is not
used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems
that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and
FAQ document for additional discussion.
102
Independent
Electricity
System
Operator
Negative
Ballot
The IESO disagrees with the concept that auditors use the standards as minimum requirements and
evaluate compliance based on a registered entity’s own governance. We believe that the entity
could be found non-compliant with Requirement R3 if they fail to follow the internal maintenance
intervals established in their PSMP, even though actual maintenance intervals are no less frequent
than the prescribed maximum intervals established in the draft standard. The potential for such a
finding will discourage conscientious entities from setting higher internal targets for their planned
maintenance and promote compliance with only the minimum requirements of the standard.
We therefore propose the following revision to Requirement R3:
R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement and
follow its PSMP and initiate resolution of any unresolved maintenance issues. In the case of timebased maintenance programs, each Transmission Owner, Generator Owner, and Distribution
Provider is permitted to deviate from its PSMP provided that actual maintenance intervals do not
exceed those specified in Tables 1-1 through 1-5, Table 2 and Table 3. [Violation Risk Factor: High]
[Time Horizon: Operations Planning]
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
Florida
Municipal
Power Agency
Negative
Ballot
We have three remaining concerns. The second concern leads us to recommend a negative vote.
103
Negative
Poll
1. Standard requires 100% perfection, e.g., missing any one interval for any one piece of equipment
leads to a violation. This is; however, mitigated by the fact that the intervals are long enough to
allow implementation of business practices with shorter intervals to add some "buffer", e.g., if the
standard says an interval is 6 years, then, through business practice we can shorten actual
maintenance and testing intervals to something like 4 years to allow ourselves a 2 year buffer to
catch equipment that may have been missed due to difficulty in scheduling outages and the like.
Does not cause us to vote negative.
2. The "Applicability" section is not consistent with the recent Y-W and Tri-State PRC-005
interpretation (Project 2009-17). The Applicability 4.2.1 states that the standard includes:
"Protection Systems that are installed for the purpose of detecting faults on BES Elements (lines,
buses, transformers, etc.)" whereas the Y-W and Tri-State interpretation basically says that
"transmission Protection Systems" both detect AND trip BES Elements; Hence, the new standard
alters the existing "and" statement in the Y-W and tri-State interpretation and eliminates the
consideration of tripping BES Elements from applicability. This will have the consequence of
including Protection Systems on step-down transformers that "look backwards" into the BES system
as applicable to the standard. For instance, a distribution network fed from multiple transmission
interconnections will have protective relaying (directional overcurrent most likely) to look backwards
into the transmission system to trip the step-down transformer to prevent back-feed from the
distribution network). This step-down transformer protection would be included in the new standard
because it's purpose to the detect faults on the BES (event though the purpose of the protection is
actually to protect overloading of the distribution and for worker safety on the BES); whereas the YW and Tri-State interpretation excludes that protection from the existing PRC-005-1 standard.
Causes us to vote Negative.
104
3. The standard reaches further into the distribution system than we would like for UFLS and UVLS
(Table 3). We have two parts to this concern. First, it will be somewhat onerous to present all the
evidence of distribution class protection system maintenance and testing at audits. And second, our
biggest concern is in the testing required to "exercise" a lockout or tripping relay. This may require
installation of test blocks to allow such exercising of the lockout or tripping relay without tripping the
distribution circuit, and such a test could be difficult to perform without impacting customer continuity
of service if the lockout/tripping relay for the UFLS is the same as the lockout/tripping relay for
distribution fault protection. However, most of FMPA's members have microprocessor-based relays for
distribution circuits with the UFLS / UVLS embedded within the microprocessor based relay where the
path from the UFLS / UVLS relay to the lockout / tripping relay is internal to the micro-processor based
relay, so, testing the UFLS/UVLS relay will at the same time test the internal lockout / switching relay.
However, for older electro-mechanical UFLS schemes, this type of testing could be problematic.
Borderline concerning whether this causes us to vote Negative or not.
As a result, FMPA recommends a Negative vote with the second and third comments, emphasizing that
it is the second comment that causes us to vote negative but we also would like the 3rd comment
addressed. Feedback appreciated. Vote and comments are due next Wednesday, 9/28.
105
Response: Thank you for your comments
1. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation.
The graded approach of the VSL for Requirement R3 allows the RE to provide discretion when assessing severity of the
violation when only a relatively small number of maintenance activities have been missed.
2. The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The
SDT observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this
term is not used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses
“Protection Systems that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the
Supplementary Reference and FAQ Document for additional discussion. If, as in your example, a protective relay is installed
to prevent back feeding (rather than for detecting BES faults), it would not be applicable even if it has a secondary result of
incidentally detecting faults on the BES.
3. UVLS and UFLS systems are required to be included as part of the Project 2007-17 Standard Authorization Request (SAR).
The SDT believes that electromechanical lockout relays require periodic operation. As such, these devices are required to
be exercised at the 12 year interval for UVLS and UFLS systems. The SDT recognizes the risk of human error trips when
working with testing of lockout devices but believes these risks can be managed.
Lakeland
Electric
Negative
Poll
The "Applicability" section is not consistent with Tri-State PRC-005 interpretation.
Response: Thank you for your comments
The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is not
used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems
that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and
FAQ document for additional discussion.
106
Liberty Electric
Power LLC
Negative
Ballot
With the development and publication of maximum maintenance and testing intervals (the Tables),
there is no longer a reliability need for a RE to identify the associated time-based maintenance
intervals for Protection System Components. Further, REs who wish to perform these activities in
shorter intervals than those allowed by the standard risk non-compliance (See Supplementary
Reference, page 27,"If your PSMP (plan) requires activities more often than the Tables maximum
then you must perform and document those activities to your more stringent standard.")If the entity
completes all activities within the maximum interval allowed by the standard, there can be no
reliability concern; if there is a reliability issue, then the table interval is incorrect. I would suggest
the following changes.
1. Change R1.2 to read "Identify any Protection System component where the RE is using a
performance based maintenance interval. No batteries associated with the station DC supply
component type of Protection System shall be included in a performance based system"
2. Change R1.3 to read "The intervals for time-based programs are established in Table 1-1 through
1-5, Table 2, and Table 3".
3. Change M1 to add the phrase "for performance-based components" after the words
"maintenance intervals".
4. In M1, replace the words "the type of maintenance program applied (time-based, performance
based, or a combination of these maintenance methods") with the words "the identification of any
protection system components using performance based intervals".
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues. The Measures have also been revised.
Manitoba
Hydro
Negative
Ballot
Manitoba Hydro is voting negative for the following reasons:
107
1. Grace Periods Grace periods should be permitted on the maintenance time intervals. While we
understand that grace periods can be built into a PSMP, maintenance decisions that compromise
reliability may still have to be made just to meet the specified time intervals and avoid penalty. An
example of this would be removing a hydraulic generator from service at a time of low reserve to
meet a maintenance interval and avoid non-compliance. Grace periods are also required in the case
of extreme weather conditions. Such conditions may make it unsafe to perform maintenance within
the maintenance interval (for example, performing a battery inspection at a remote station during
severe winter weather) or may create a risk to reliability if the equipment being maintained is
removed from service during these conditions. Utilities need to retain a reasonable amount of
discretion and flexibility to make maintenance decisions that are best for safety and reliability
without risking non-compliance. In addition, we disagree with the basis that the Drafting Team has
established that grace periods are not permitted because of FERC Order 693 which requires that
‘maximum’ time intervals are established within PRC-005-2. With grace periods, a maximum time
interval obviously becomes the required maintenance interval plus the maximum permitted grace
period. So we strongly feel that grace periods can be added to the standard while adhering to the
FERC Order. We also disagree with the line of reasoning that the Drafting Team used to establish the
maximum maintenance intervals for relays as outlined on page 38 of the Supplementary Reference
and FAQ document. To our knowledge, no document has been produced which provides evidence of
maximum time intervals that work well for ‘maintenance cycles that have been in use in generator
plants for decades’. Our Protection Systems Maintenance experience indicates that the proposed
intervals are acceptable as nominal time intervals with grace periods, but not as maximum time
intervals without grace periods. Without a grace period, the bulk of protection maintenance on a six
year maintenance cycle will have to be done one year earlier than previously required, in order to
allow for the last year of the maximum interval to be used as the grace period. Manitoba Hydro
considers this an unnecessary burden on resources with no benefit to reliability. Manitoba Hydro
recommends that grace periods be permitted within PRC-005-2 if an entity can demonstrate a
reliability or safety related need for using a grace period. This would require the Drafting Team to
develop reliability-related criteria for using a grace period.
108
2. Phased Implementation Plan Manitoba Hydro does not agree with the prescribed phased
implementation plan. Entities should be given a single compliance date for each of the maintenance
intervals, and be allowed the flexibility to schedule and complete their maintenance as required
while transitioning to the defined time intervals in PRC-005-2. For example, if a maximum
maintenance interval is 6 calendar years, the implementation plan should only require that “The
entity shall be 100% compliant on the first day of the first calendar quarter 84 months following
applicable regulatory approval, or in those jurisdictions where no regulatory approval is required, on
the first day of the first calendar quarter 96 months following Board of Trustees adoption.” (item
4c.). The existing standard PRC-005-1 already requires protection systems to be maintained as part
of a program. Prescribing how an entity must reach full compliance will provide a negligible
improvement in reliability, while significantly increasing the compliance burden. PRC-005-2 affects a
large number of assets, and proving compliance for prescribed percentages of assets during the
transition period creates unnecessary overhead with no added value. We suggest that items 3a., 3b.,
4a., 4b., 5a. and 5b be removed from the implementation plan and that NERC measure progress on
reaching PRC-005-2 intervals using means other than Compliance measures such as industry surveys.
Response: Thank you for your comments.
1. FERC Order 693 directs NERC to establish maximum allowable intervals. The SDT believes a “grace period” process as you
describe would not satisfy this directive. In essence, by specifying maximum allowable intervals the SDT is leaving the
establishment of normal maintenance intervals and grace periods to the entities discretion and to what works best for their
scheduling needs and program flexibility. Alternatively, if the SDT believes that 6 calendar years is the maximum allowable
interval for a given maintenance activity, it could have done as you suggested and defined a 4 year “normal” interval with a 2
year grace period for a maximum allowable interval of 6 years. The SDT believes the management of normal maintenance
intervals and grace periods is best left to the entity’s PSMP and thus chose only to specify the maximum allowed interval
within which entities must comply. Note that if data is available to prove reliability is maintained, performance-based
maintenance is available to achieve longer maintenance intervals.
2. The SDT believes that it is not practical for all entities to rapidly transition all of their Protection Systems to the new program,
especially with some component types on maintenance intervals of up to 12 years. Nonetheless, all in-scope Protection
Systems must be maintained by either a PRC-005-1 program or a PRC-005-2 program. The SDT believes the phased approach
mapped out in the Implementation plan is practical. If an entity wishes to implement PRC-005-2 on a more rapid rate than
laid out in the Implementation plan to lessen the complexity of documentation requirements, they are free to do so.
109
Muscatine
Power &
Water
Negative
Ballot
1. Section D.1.3, in Data Retention, requires an entity to retain the two most recent performances of
each distinct maintenance activity. This is an unreasonable and problematic requirement and does
not enhance reliability. Recommend the data retention be changed to require only the most recent
test record. A compliance audit should be focused on the present day and not in the past. PRC-005-2
allows testing intervals of up to 12 calendar years. If we are required to have the two most recent
test results, we could conceivably have to retain a relay test record for up to 24 years!
Hypothetically, if we have a test record from ten years ago, but we do not have the record from 12
years before that, how does that adversely affect the reliability of the BES today? The standard
should focus on – Is the Entity compliant TODAY?
2. Table 1-5 requires a maintenance activity to, “Verify that each trip coil is able to operate the
circuit breaker, interrupting device, or mitigating device.” Recommend this be changed to, “Verify
that a trip coil is able to operate the circuit breaker, interrupting device, or mitigating device.”
Alternately, change the wording to, “Electrically operate each interrupting device every 6 years.”
While requiring each trip coil to operate the breaker sounds good in theory, however, it creates
issues in the field and may create more problems than it solves. The trip coils are located in the
panel at the breaker and are not configured to test independently. Isolating one trip coil from the
other may include “lifting a wire” that may not get landed properly when the test is complete. Using
an actual event only tests one coil and we may not know which coil tripped the device. The current
language is a recipe for a compliance violation. The standard should focus on ensuring the control
circuitry is intact and trips the breaker without injecting additional, unneeded risk to the BES.
3. In the tables for dc Supply the term “unit-to-unit” is used along with “intercell” when referring to
measurement of connection resistance. From the applicable IEEE standards (e.g. IEEE 450), the
standard terminology seems to be “intercell”. It is recommended that the “unit-to-unit” term be
removed to avoid confusion regarding what is to be verified.
110
Response: Thank you for your comments.
1. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the
data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that entities
have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has
specified the data retention in the posted standard to establish this level of documentation. This seems to be consistent with
the current practices of several Regional Entities. Obviously, Compliance Monitors should not expect entities to be able
produce records for maintenance performed prior to there being requirements for that maintenance to be performed.
2. The description of the configuration of the second trip coil on circuit breakers you have provided is not typical of the
redundant approach taken by most entities. Typically, second trip coils are electrically isolated from the first trip coil and are
often fed by a separately fused dc control circuit with different relay trip output, lockout and auxiliary tripping contacts
utilized in each circuit. The SDT believes that it is important that redundant trip paths be maintained within the indicated
interval, and the prescribed interval already considers the reliability benefits of redundant equipment.
3. The term “unit-to-unit” is used for the conductor utilized to connect one multi-celled battery jar to an adjacent multi-celled
battery jar.
NorthWestern
Energy
Negative
Ballot
I recommend a no vote please see my comments below.
1. For Table 1-5 Trip coils or actuators of circuit breakers, interrupting devices, or mitigating devices
6 calendar years Verify that each trip coil is able to operate the circuit breaker, interrupting device,
or mitigating device. Provisions need to be added to allow non-tripping checks of coils on the BES
element that will Trip load. If I am reading the purposed correct the circuit switcher feeding
distribution banks at or above 100kV will need to be tripped taking out load.
2. It was my understanding the IEEE standard 450 allowed for 7 year load test interval for VLA and
NiCad batteries the standard calls out for 6 years. It appears that the standard has been recently
updated and should be verified. My last objection is Table 1-2
3. Any unmonitored communications system necessary for correct operation of protective functions,
and not having all the monitoring attributes of a category below. 4 calendar months Verify that the
communications system is functional. 4 calendar months is excessive on annual maint and will
discourage communications assisted tripping when not absolutely needed. 1 year is a more
reasonable and doable timeline.
111
Response: Thank you for your comments.
1. PRC-005-2 specifically addresses “Protection Systems that are installed for the purpose of detecting faults on BES Elements.” If
the Protection System in question is not protecting a BES component, it is not applicable to this standard. Please see Section
2.3 of the Supplementary Reference and FAQ document for additional discussion.
2. IEEE 450 only pertains to VLA batteries. IEEE 1106 pertains to NiCad batteries. The SDT believes that the 6 calendar year
interval specified in PRC-005-2 is appropriate.
3. The SDT believes that performing this maintenance activity at 4 month intervals is proper for unmonitored communications
systems.
Seattle City
Light
Negative
Ballot
Regarding Voltage and Current Sensing Device Maintenance & Testing Activities: Table 1-3 of the
standard lists the minimum required maintenance activities for voltage and current sensing devices
as "Verify that current and voltage signal values are provided to the protective relay." Consistent
with Table 1-3, Section 15.2.1 of the Supplementary Reference states that an entity "...must verify
that the protective relay is receiving the expected values from the voltage and current sensing
devices..." The Supplementary Reference further offers examples of how this requirement may be
satisfied with most of the examples reference the need to verify the signal at each relay in the
circuit. We recognize the need to verify a voltage signal at each protective relay, as these devices are
wired in parallel and an open circuit at one location may not impact the other devices on the circuit.
However, we do not agree that there is a need to verify a current signal at each protective relay.
Current devices are wired in series; an open circuit at any location will impact all other devices on
the circuit. For this reason, a single measurement of the current circuit is sufficient. We recommend
updating Table 1-3 and the supplementary reference to account for the different physical
characteristics of voltage and current circuits.
Response: Thank you for your comment.
An open circuit is not the only failure mechanism for a CT secondary circuit. Grounded CT secondary wiring can result in situations
where accurate current is present in the part of the secondary circuit upstream of the ground but current would be shunted to
ground and might not pass through devices downstream of the ground. Entities should not interpret PRC-005-2 as specifying
“how” to test but rather that PRC-005-2 only specifies “what” to test.
112
Seminole
Electric
Cooperative,
Inc.
Negative
Ballot
We recommend the SDT consider an interval of 12 calendar years for the component in row 3, of
Table 1-5 on page 19 of the standard. The maximum maintenance interval for “Electromechanical
lockout and/or tripping devices which are directly in a trip path from the protective relay to the
interrupting device trip coil” should be consistent with the “Unmonitored control circuit” interval
which is 12 calendar years. In order to test the lockout relays, it may be necessary to take a bus
outage (due to lack of redundancy and associated stability issues with delayed clearing). Increasing
the frequency of bus outages (with associated lines or transformers) will also increase the amount of
time that the BES is in a less intact system configuration. Increasing the time the BES is in a less intact
system configuration also increases the probability of a low frequency, high impact event occurring.
Therefore, the Maximum Maintenance Interval should be 12 years for lockout relays. We believe
that, as written, the testing of “each” trip coil and the proposed maintenance interval for lockout
testing will result in the increased amount of time that the BES is in a less intact system
configuration. We sincerely hope that the SDT will consider these changes.
Response: Thank you for your comments.
The SDT believes it is possible to manage the risks that you describe and that performance of this testing will be an overall benefit
to the reliability of the BES. It is the majority opinion of the subject matter experts forming the SDT that testing of
electromechanical devices with moving parts such as lockout relays be performed on a 6 year interval. Entities may use the PBM
process to extend this interval if they desire.
Tennessee
Valley
Authority
Negative
Ballot
It will take several years for TVA to implement checkback on 590 carrier blocking sets on the TVA
system and not have to perform the PRC 005-2 requirement of verifying functionality every 4 months
with no grace period. TVA carrier failure rate has not increased since the frequency was changed in
January 2008 from 4 tests/year to 2 tests/year. We are also implementing an extensive PM test in
October 2011 which will test 25% of the sets per year and will take readings of SWR, line loss, and
receiver margin.
Response: Thank you for your comment.
The SDT believes that performing this maintenance activity at 4 month intervals will benefit the reliability of the BES. The
Implementation plan allows for 15 months after regulatory approvals for entities to implement the program per PRC-005-2. You
may also find performance-based maintenance (per Requirement R2) useful.
113
Utility Services,
Inc.
Negative
Ballot
While we generally agree with most of the proposal, we are concerned about the need to address
validate of Protection System settings in the standard. We believe that there should be an explicit
requirement on validating the settings to ensure that misoperations don't occur due to incorrect
settings being programmed into the devices. Reliability will be enhanced if misoperations can be
avoided due to the explicit check on the accuracy of the settings.
Response: Thank you for your comment.
Rows 1 and 2 of Table 1-1 currently require verification that relay settings are as specified.
Westar Energy
Negative
Ballot
Westar agrees in general with most of the changes and modifications included in the proposed
Standard. Specifically, the change from 3 to 4 calendar months in Table 1-4.
1. However, we believe that the terms Distributed and Non-Distributed need to be more clearly
defined.
2. Clarification is also needed on an entities ability to use fault initiated trips as evidence for Table
1-5 - Control Circuitry.
Response: Thank you for your comments.
1. Please see Section 8.1.1 on pg 25-26 of the Supplementary Reference and FAQ document for discussions of the terms
“distributed” and “non-distributed”.
2. Please see paragraph 7 in Section 8.1.2 of the Supplementary Reference and FAQ document for further discussion of this topic.
Xcel Energy,
Inc.
Negative
Ballot
The VSL for R3 is confusing because of the lack of a specified time horizon. Are the percentages
quoted on an annual schedule basis, an audit period, or a continuous percentage measurement of
any previously scheduled maintenance activities? Greater clarity is needed on the intent of this VSL.
Response: Thank you for your comment.
The VSLs that use a graduated VSL have been revised based, in part, on the comments you have provided. The percentages relate to
the number of violations reported within the compliance monitoring period relative to the number of components within that
component type.
114
Xcel Energy,
Inc.
Negative
Ballot
I appreciate the effort the SDT has invested in bringing PRC-005 to ballot and refer them to
comments submitted by FirstEnergy. I agree with FE that PRC-005 encourages entities to set a low
bar when developing protective system maintenance programs and will penalize those with robust
programs that miss self-imposed schedules or targets.
Response: The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
Tennessee
Valley
Authority
Negative
Ballot
1. It will take several years for TVA to implement checkback on 590 carrier blocking sets on the TVA
system and not have to perform the PRC 005-2 requirement of verifying functionality every 4 months
with no grace period. TVA carrier failure rate has not increased since the frequency was changed in
January 2008 from 4 tests/year to 2 tests/year. We are also implementing an extensive PM test in
October 2011 which will test 25% of the sets per year and will take readings of SWR, line loss, and
receiver margin.
2. TVA disagrees with the requirement to measure internal ohmic values of the station dc supply
batteries every 18 months. The interval should be 36 months. Our experience from performing our
routine maintenance program including cell impedance testing at 3-year intervals has been that the
program is fully adequate in monitoring bank condition. An 18-month interval for internal
resistance/impedance testing is an unnecessary burden.
3. Are we required to test the trip circuit between the power transformer sudden pressure relay and
the switch house or are we only required to test the trip circuit between the electrical sensing relays
and the trip coils of the breakers?
115
Response: Thank you for your comments.
1. The SDT feels that performing this maintenance activity at 4 month intervals will benefit the reliability of the BES. The
Implementation Plan allows for 15 months after regulatory approvals for entities to implement the program per PRC-005-2.
You may also find that performance-based maintenance (per Requirement R2) useful.
2. The SDT believes the required 18 month interval is better in line with accepted industry practice. Please note that for VLA
batteries, an entity may entirely avoid internal ohmic measurements by implementing a VLA maintenance program using 18
month visual inspections and 6 yr capacity tests.
3. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing
elements. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to
be consistent with the position of FERC staff.
Northeast
Power
Coordinating
Council
The focus of the industry is on the field procedures necessary to ensure that protection systems are
maintained and tested. This includes the verification that settings have been applied correctly. The
accuracy of the settings calculated needs to be validated, and that step should be considered for
inclusion in this Standard.
Response: Thank you for comment.
Validating the accuracy of settings calculations is more properly a design function and not a maintenance function. The SDT agrees
that validating relays are left with the intended settings programmed in is important; as such, Row 1 and Row 2 of Table 1-1
require that settings be verified to be as specified.
116
PNGC
Comment
Group
Thank you for the opportunity to comment on the draft Standard PRC-005-2 - Protection System Maintenance. While the
feedback from the last round of comments is appreciated, we still cannot support the standard as written due to our concerns
outlined here. We appreciate the work that NERC has put into a new standard to encapsulate and replace the current PRC-005,
PRC-008, PRC-011 and PRC-017. But, we believe that the draft Standard needs one important revision before the NERC Board
of Trustees should approve it. Specifically, NERC should revise the draft version of PRC-005-2 so that the beginning of Section
4.2 reads as follows: “4.
2. Facilities:Protection Systems that (1) are not facilities used in the local distribution of electricity, (2) are facilities and control
systems necessary for operating an interconnected electric energy transmission network, and (3) are any of the following:”This
revision is necessary to capture the limits that Congress placed on FERC, NERC, and the Regional Entities in developing and
enforcing mandatory reliability standards. Specifically, Section 215(i) of the Federal Power Act provides that the Electric
Reliability Organization (ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” And, Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof); and
(B) electric energy from generation facilities needed to maintain transmission system reliability. The term does not include
facilities used in the local distribution of electric energy.” With this language, Congress expressly limited FERC, NERC, and the
Regional Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary for operating a
transmission network. Given that these facilities are statutorily excluded from the definition of the BPS, reliability standards
may not be developed or enforced for facilities used in local distribution. In Order No. 672, FERC adopted the statutory
definition of the BPS. In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress has
specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS definition. FERC also held that to
the extent any facility is a facility used in the local distribution of electric energy, it is exempted from the requirements of
Section 215. In Order No. 743-A, FERC delegated to NERC the task of proposing for FERC approval criteria and a process to
identify the facilities used in local distribution that will be excluded from NERC and FERC regulation. The critical first step in
this process is for NERC to propose criteria for approval by FERC to determine which facilities are used in local distribution, and
are therefore not BPS facilities. The criteria to be developed by NERC must exclude any facilities that are used in the local
distribution of electric energy, because all such facilities are beyond the scope of the statutory definition of the BPS, which
establishes the limit of FERC and NERC jurisdiction. Accordingly, it is critical that NERC draft the new PRC-005-2 standard to
expressly exclude facilities used in local distribution. NERC must also expressly exclude from PRC-005-2 those facilities “not
necessary for operating an interconnected electric energy transmission network (or any portion thereof)”. Similar to the local
distribution exclusion, the facilities not necessary for operating a transmission network are not part of the BPS and therefore
must be expressly excluded from the standard. We understand, but disagree with, the argument that, because the FPA clearly
excludes local distribution facilities and facilities necessary for operating an interconnected electric transmission network from
FERC, NERC, and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in reliability standards.
This approach might be legally accurate, but could lead to significant confusion for entities attempting to implement the new
PRC-005-2 standard. There are numerous examples of Regional Entities, particularly WECC, attempting to assert jurisdiction
over such facilities, and regulated entities face significant uncertainty as to which facilities they should consider as within
jurisdiction. Clarifying FERC, NERC, and Regional Entity jurisdiction in the BES definition, even if such clarification is already
provided in the FPA, would avoid such problems under the new PRC-005-2 standard. Again, we appreciate the work NERC has
put in so far on a new Standard. We look forward to working within the drafting process to help implement our recommended
revision.
117
Response: Thank you for your comment.
Other than the requirement relating expressly to UFLS/UVLS Protection Systems, the Applicability currently expressly addresses
Protection Systems applied for the purpose of detecting BES faults.
To the degree that such Protection Systems may be located on non-BES components, and as the Applicability addresses UFLS/UVLS
systems, the SDT has received the following position from NERC Legal:
While UFLS and UVLS equipment are located on the distribution network, their job is to protect the Bulk Electric System. This is not
beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines “bulk-power system as (A) facilities and control systems necessary for operating an
interconnected electric energy transmission network (or any portion thereof).” That definition then is limited by a later statement
which adds the term bulk-power system “does not include facilities used in the local distribution of electric energy.” Also, section
215 covers users, owners, and operators of bulk-power facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage instability for BES reliability) are not “used
in the local distribution of electric energy” despite their location on local distribution networks. Further, if UFLS/UVLS facilities
were not covered by the Reliability Standards, then in order to protect the integrity of the BES during under-frequency or undervoltage events, that load would have to be shed at the transmission bus to ensure the load-generation balance and voltage stability
is maintained on the BES.
118
Bonneville
Power
Administration
1. BPA understands that the VSLs for R3 are based on the percentage of unresolved maintenance
issues that an entity has failed to initiate a resolution for. This approach penalizes an entity for
having less unresolved maintenance issues. For example, if an entity has only one unresolved
maintenance issue and it failed to initiate a resolution for it, it would have failed to initiate a
resolution for 100% of its unresolved maintenance issues, which would be a severe VSL. If another
entity had 100 unresolved maintenance issues, and it failed to initiate resolution on ten of them, it
would have failed to initiate a resolution on 10% of its unresolved maintenance issues, which would
be a high VSL. Most likely, the first entity is doing a better job with its maintenance than the second
entity, but the first entity receives a more severe penalty. The VSL for R3 is not an accurate
measurement of a maintenance program’s effectiveness and needs to be revised. BPA recommends
removing the entire “Unresolved Maintenance Issue” topic from the standard.
2. In Table 1-1, it is not clear when a microprocessor relay meets the requirement for internal selfdiagnosis and alarming. It is not clear that any microprocessor relay with a relay failure alarm would
meet this requirement.
3. BPA believes that it seems like an omission in Table 1-1 for unmonitored microprocessor relays,
the verification of settings is not included as a maintenance activity.
4. BPA would also like to recommend clarifying language stating that the owner of the asset is the
responsible entity.
119
Response: Thank you for your comments.
1. The SDT believes that, if a component cannot be returned to “good working order” during the performance of the
maintenance program as defined within the entity’s criteria, the maintenance program must include those actions
necessary to restore the component (and thus the Protection System) to good working order. Therefore, the topic of
“Unresolved Maintenance Issues” cannot be removed from the standard. The VSL for the old Requirement R3 (now
Requirement R5) has been revised to indicate gradations on the actual count of violations of this requirement, rather than
percentages.
2. Microprocessor relay failure alarms meet this requirement as long as the alarm is sent back to a location where corrective
action can be initiated.
3. The first maintenance activity listed on Table 1-1 is to validate that relay settings are as specified and this statement is
applicable to unmonitored microprocessor relays. The activity has been revised to clarify.
4. The preface paragraphs for R1, R2, R3, R4, and R5 each state that the Transmission Owner, Generator Owner, and
Distribution Provider are responsible for implementation of the associated requirements.
FirstEnergy
1. We remain concerned with the proposed draft version of Requirement R3 as well as the SDT
developed statements in the Supplementary Reference & FAQ. The SDT's approach sends industry
the wrong message; a message that entities should not go beyond what is in the text of the
standards and that in some cases they can even be found non-compliant by failing to meet their own
more stringent internal practice. We have sent NERC Staff and Drafting Team leaders a separate
document detailing our concerns as well as proposed redlines to the standard. The separately
provided document can be viewed as FE’s ballot comments.
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2. FE supports the standard from a technical standpoint but offer the following additional comments
and suggestions:
A clarification to the supplementary reference document is necessary regarding Maintenance
Activities specified for electromechanical lockout and/or tripping auxiliary devices, as specified in
Table 1-5 of the standard. The standard states, “Verify electrical operation of electromechanical trip
and auxiliary tripping devices” which must be performed every 6 years. A question was asked during
the September 15th Webinar requesting clarification of what “verify electrical operation....” meant.
The verbal response from the SDT member was that this involves verifying that the relay actuates,
but does not require verification that its contacts changed state. However, the answer to the
question at the bottom of page 29 and top of page 30 in the Supplementary Reference and FAQ
(dated July 29, 2011) implies that checking the contacts is necessary. The following statement in the
published answer makes this clarification request necessary; “Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this Standard, to be checked.” This statement
implies that if outputs to annunciators and DME inputs do not need to be checked, then the other
outputs do need to be checked. Verification of the auxiliary tripping relays appears to be covered in
Table 1-5 of the standard under the "Unmonitored control circuitry associated with protective
functions" section at 12 calendar years. Thus, we ask the SDT clarify in the supplementary reference
the type of maintenance activities required for electromechanical lockout and/or tripping auxiliary
devices to satisfy the requirements of Table 1-5 of the standard. Since the standard specifically
dictates the output contacts verification for protective relays under Table 1-1, the output contacts of
aux tripping relays is left up to interpretation. Therefore, we suggest the following statement be
added after “Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required, by
this Standard, to be checked.” on page 30 of the document: “Auxiliary outputs that are in the trip
path shall be maintained as detailed in Table 1-5 of the standard under the ‘Unmonitored control
circuitry associated with protective functions" section’ at 12 calendar years.”
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Response: Thank you for your comments.
1. The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based
programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
2. Output contacts and auxiliary tripping relays that are not part of a trip path or essential for proper operation of an SPS need
not be tested per this standard. The Supplementary Reference and FAQ document will be revised as you suggest.
Southwest
Power Pool
Standards
Review Group
1. Please update Appendix B, Drafting Team Members, of the Supplementary Reference document.
2. We request that the detail for the breaker failure protection for generator protection in the
bulleted list at the bottom of page 31 and the top of page 32 of the Supplementary Reference
document be removed. We are not sure what the SDT is looking for here since there are several
types of breaker failure protection.
3. We ask that Section 4.2.5.4 of the draft standard under the Facilities be modified to read
'Protection Systems that trip the generator for generator-connected station service transformers for
generators that are part of the BES.'
4. We suggest that Section 1.3 Data Retention be rewritten to provide clarification that no data prior
to the date of the last audit need be retained.
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Response: Thank you for your comments.
1. The list of SDT members has been updated.
2. The preface to the list of relays to which you refer is as follows: “Examples of typical devices and systems that may directly trip
the generator, or trip through a lockout relay may include but are not necessarily limited to:”. The SDT was merely attempting
to provide a list of possible relays that might need to be included. The list is not meant to be all inclusive nor do all relays of the
types on the list necessarily need to be included.
3. In consideration of your comment and those of others received, the SDT has revised Section 4.2.5.4 as requested.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the
data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that entities have
been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified the
data retention in the posted standard to establish this level of documentation. This seems to be consistent with the current
practices of several Regional Entities.
Florida
Municipal
Power Agency
The "Applicability" section is not consistent with the recent Y-W and Tri-State PRC-005 interpretation
(Project 2009-17). The Applicability 4.2.1 states that the standard includes: "Protection Systems that
are installed for the purpose of detecting faults on BES Elements (lines, buses, transformers, etc.)"
whereas the Y-W and Tri-State interpretation basically says that "transmission Protection Systems"
both detect AND trip BES Elements; Hence, the new standard alters the existing "and" statement in
the Y-W and tri-State interpretation and eliminates the consideration of tripping BES Elements from
applicability. This will have the consequence of including Protection Systems on step-down
transformers that "look backwards" into the BES system as applicable to the standard. For instance,
a distribution network fed from multiple transmission interconnections will have protective relaying
(directional overcurrent most likely) to look backwards into the transmission system to trip the stepdown transformer to prevent back-feed from the distribution network). This step-down transformer
protection would be included in the new standard because it's purpose to the detect faults on the
BES (event though the purpose of the protection is actually to protect overloading of the distribution
and for worker safety on the BES); whereas the Y-W and Tri-State interpretation excludes that
protection from the existing PRC-005-1 standard.
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Response: Thank you for your comment.
The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is not
used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems
that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and
FAQ document for additional discussion.
Pepco
Holdings Inc &
Affiliates
Requirement 3 and the Supplementary Reference Document indicate that an entity should be held
to its internal PSMP (especially for a time based program) even if the plan is more stringent than the
NERC standard. This would be a deterrent for initiative and for excellence and punish utilities for
going above the standards and performing best practices. It also tends to drive the industry to
lowest common denominator practices. R3 and the accompanying Supplementary Reference
Document should be appropriately revised to reflect that entities would only be held auditably
accountable for the minimum requirements as stated in the standard and associated documents.
Response: Thank you for your comments. The standard and the Supplementary Reference and FAQ document have been changed
to address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for
time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
MRO's NERC
Standards
Review Forum
a. Section 4.2.5.4 includes station service transformers for generator facilities. As currently written,
the section includes all the protection systems for station service transformers for generators that
are a part of the BES. It states, “Protection Systems for generator-connected station service
transformers for generators that are part of the BES.” Generating facilities may have transfer
schemes on the auxiliary transformer to transfer equipment to a reserve transformer instead of
tripping the unit. These protection systems should not be included in the Facilities for PRC-005-2,
since the BES is not affected. Recommend changing Section 4.2.5.4 to read, “Protection Systems
that trip the generator for generator-connected station service transformers for generators that are
a part of the BES.”
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b. Data Retention, Section 1.3 (concerning R2 and R3) requires an entity to retain the two most
recent performances of each distinct maintenance activity. This is an unreasonable requirement and
does not enhance reliability. Recommend the data retention be changed to require only the most
recent (past) test record. An example exists where an entity recently registered and tested all their
relays prior to registering. They have one set of documentation and not two. PRC-005-2 allows
testing intervals of up to 12 calendar years. If we are required to have the two most recent tests, we
could conceivably have to retain a relay test record for 24 years. Recommend retention to be the
most current record or all records since the last audit.
c. Table 1-5 requires a maintenance activity to, “Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.” Recommend this be changed to, “Verify that
each a trip coil is able to operate the circuit breaker, interrupting device, or mitigating device.” Or
alternately, change the wording to, “Electrically operate each interrupting device every 6 years.”
While requiring each trip coil to operate the breaker sounds good in theory, practically it creates
issues in the field and may create more problems than it solves. The trip coils are located in the
panel at the breaker and aren’t configured to test independently. Isolating one trip coil from the
other may include “lifting a wire” that may not get landed properly when the test is complete. Then,
how do you prove for a compliance audit that both trip coils were independently tested to trip the
breaker? Using an actual event only tests one coil and we may not know which coil tripped the
device. To be compliant, it isn’t practical to be able to track a real-time fault clearing operation as
suggested on page 67 of the Supplementary Reference document. First, we don’t know which trip
coil operated, then we have a “one off” device in the substation that must be tracked separately
with a different testing cycle from the other devices in the substation. The standard should focus on
ensuring the control circuitry is intact and trips the breaker without injecting additional, unneeded
risk to the BES.
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d. General comment under Table 1-5: We do extensive testing of the control circuit during
commissioning and after a modification to the circuit. Testing of the control circuitry on a periodic
basis is not needed. The wear and tear on the equipment from functional testing and the potential
risk of the testing itself may create more issues than the benefits received from doing the tests. The
functional test injects significant opportunities for human performance errors during the test
(technician trips the wrong device, differential relay opens all protective devices for a bus instead of
a breaker, technician bumps another relay, screw driver falls into another device, etc.) and latent
errors after the test (i.e., if a wire was lifted during the test, was it landed back in proper location,
was the relay tripping function activated after the test was completed or was the relay left in test
mode, etc.). Request the drafting team provide a basis for requiring the functional test. Are there
documented instances where the control circuitry caused a significant event on the BES? Many
utilities, monitor circuit breakers for operations. If a breaker hasn’t operated for a defined period of
time, we set up a maintenance activity to operate the breaker (possibly to include a timing test to
ensure the breaker clears in the proper amount of cycles) - this ensures the operating linkages aren’t
bound and the breaker will operate. Misoperations are already monitored and reported through
PRC-004. Does recent misoperation data or TADS data indicate that control circuitry/trip coils are a
problem within the protection and control system? The current version of PRC-005 doesn’t require
functional tests. What is the basis for requiring additional compliance documentation (additional
functional testing)? A possible alternative: only perform testing following modifications or major
maintenance (like breaker change outs or panel modifications).
e. Change the text of “Standard PRC-005-2 - Protection System Maintenance” Table 1-5 on page 19,
Row 3, Column 2 to: “12 calendar years”. 1) The maximum maintenance interval for
“Electromechanical lockout and/or tripping devices which are directly in a trip path from the
protective relay to the interrupting device trip coil” should be consistent with the “Unmonitored
control circuit” interval which is 12 calendar years.2) In order to test the lockout relays, it may be
necessary to take a bus outage (due to lack of redundancy and associated stability issues with
delayed clearing). Increasing the frequency of bus outages (with associated lines or transformers)
will also increase the amount of time that the BES is in a less intact system configuration. Increasing
the time the BES is in a less intact system configuration also increases the probability of a low
frequency, high impact event occurring. Therefore, the Maximum Maintenance Interval should be
12 years for lockout relays.
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f. In the background section of the implementation plan in item two it states “..it is unrealistic for
those entities to be immediately in compliance with the new intervals.” A recent compliance
application notice (CAN-0012) indicated that auditors are requiring entities to include proof of
compliance to maintenance intervals by providing the most recent and prior maintenance dates.
Please provide clarity on CAN-0012 is applicable to PRC-005-2?
g. The purpose statement of the standard seems to be inconsistent with the applicability section. To
correct this it is suggested that the words “affecting the reliability” be removed from the purpose
statement
h. For consistency with the changes from 3 months to 4 months in the tables of the standard it is
suggested that the second item in Table 1-4(b) be changed from 6 calendar months to 7 calendar
months
i. In the tables for dc Supply the term “unit-to-unit” is used along with “intercell” when referring to
measurement of connection resistance. From the applicable IEEE standards (e.g. IEEE 450) the
standard terminology seems to be “intercell”. It is recommended that the “unit-to-unit” term be
removed to avoid confusion regarding what is to be verified.
j. The NSRF would like to extend our thanks to the drafting team. The 96 page Supplementary
Reference document allows us to discuss these issues before the standard is approved, instead of as
a potential violation later. Excellent job!
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Response: Thank you for your comments.
a) The SDT has modified paragraph 4.2.5.4 as you suggest.
b) In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need
the data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that
entities have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT
has specified the data retention in the posted standard to establish this level of documentation. This seems to be consistent
with the current practices of several Regional Entities.
c) The description of the configuration of the second trip coil on circuit breakers you have provided is not typical of the
redundant approach taken by most entities. Typically, second trip coils are electrically isolated from the first trip coil and
are often fed by a separately fused dc control circuit with different relay trip output, lockout and auxiliary tripping contacts
utilized in each circuit. The SDT believes that it is important that redundant trip paths be maintained within the indicated
interval, and the prescribed interval already considers the reliability benefits of redundant equipment.
d) The SDT believes that it is possible to manage the risks that you describe and that performance of these trip path
verifications will be an overall benefit to the reliability of the BES.
e) The SDT believes that electromechanical lockout relays need periodic operation. As such, these devices are required to be
exercised at the same 6 year interval required for electromechanical relays. The SDT recognizes the risk of human error
trips when working with testing of lockout devices but believes these risks can be managed. Performance-based
maintenance is an option if you want to extend your intervals beyond 6 years. The SDT, however, has modified Table 1-5 to
remove other auxiliary relays, etc, from this activity, and clarified that the verification of such.
f) The CAN cited applies to PRC-005-1, not PRC-005-2. The SDT intends that the Implementation plan associated with PRC005-2 will govern compliance to PRC-005-2 during the transition to the new standard.
g) The purpose of the standard expresses the general intent of the standard, and is further clarified by the Applicability.
h) The SDT believes that the 6-month interval is appropriate for these activities.
i) The term “unit-to-unit” is used for the conductor utilized to connect one multi-celled battery jar to an adjacent multi-celled
battery jar. The SDT does not believe this terminology causes wide spread confusion.
j) Thank you.
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Arizona Public
Service
Company
While we are supportive of the changes the SDT has made, APS is concerned the draft Standard will
not give entities the flexibility to continue to improve reliability based on changing industry norms
and best practices. In addition, when technology changes for the better, industry will need the
flexibility to optimize use of the new technology. Lastly, the more often protection equipment is
taken out of service for testing, the more often the line is vulnerable. The balance between the
correct amount of testing and correct amount of time the equipment is in the field and in service is
an important consideration when assuring the reliability of the BES. APS suggests the general
principles of the following two papers be applied to more equipment types than microprocessor
relays with self test capabilities. 1) 'An Improved Model for Protective-System Reliability,' P.M.
Anderson and S.K. Agrawal, Power Math Associates, Inc., IEEE Transactions on Reliability, Volume 41,
No. 3, September 1992;2) 'Philosophies for Testing Protective Relays,' J.J. Kumm, et. al., Schweitzer
Engineering Laboratory, Inc., 48th Annual Georgia Tech Protective Relaying Conference, May 1994.
Response: Thank you for your comments. FERC Order 693 and the approved SAR assign the SDT to develop a standard with
maximum allowable intervals and minimum maintenance activities. Wherever possible, the SDT has provided entities with the
flexibility to utilize capabilities of emerging technologies by using condition-based maintenance where effective, and also by using
performance-based maintenance should an entity wish to modify their intervals based on past performance.
Southern
Company
Generation
1) For Table 1-1 and Table 3, consider adding "(internal to the relay)" to the microprocessor relay 6
calendar year maintenance activities to clarify that these maintenance activities are not related to
items external to the relay).
Response: Thank you for your comments. Since the component type being addressed is the protective relay itself, it seems that
the clarification you request is unnecessary.
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Tacoma Power
1. The implementation plan for R2 and R3 is unclear on whether each maintenance activity has its
own implementation schedule. The implementation plan can also be interpreted to mean that the
implementation schedule for a given protection system component is driven by the smallest
maximum maintenance (allowable) interval. For example, for unmonitored communications
systems, it is unclear whether all maintenance activities indicated in Table 1-2, including those
corresponding to 6 calendar years, must be completed on all unmonitored communications systems
by the first calendar quarter 15 months following applicable regulatory approval, or if this timeline
only applies to the maintenance activity specified in Table 1-2 corresponding to a maximum
maintenance interval of 4 calendar months.
2. Assuming that there is a different implementation schedule for different maintenance activities
for some protection system component types (namely station DC supply and communication
systems), the middle bullet on page 1 of the implementation plan does not seem to consider that it
may not be possible to identify whether some protection system components are completely being
addressed by PRC-005-2 or the Program developed for the previous standards. In other words,
during implementation, some maintenance activities for the same protection system component
may be addressed by PRC-005-2, while other maintenance activities may be addressed by the
Program developed for the previous standards.
3. It is unclear whether control circuitry (trip paths) from protective relays that respond to
mechanical quantities is included. This issue is addressed in the supplementary reference but is
vague in the draft standard itself.
4. This draft of PRC-005-2 requires the Protection System Maintenance Program (PSMP) to “include
all applicable monitoring attributes and related maintenance activities” per the Tables and requires
an entity to “implement and follow its PSMP.” Under the draft standard, it is unclear whether an
entity has to document in the PSMP and/or maintenance records how they accomplish(ed) the
maintenance activities or simply to indicate that the maintenance activities are included and have
been completed within the defined intervals. It is clear that entities are afforded some latitude in
how they conduct the required maintenance activities. However, the level of detail required to
document (1) how an entity chooses to perform the maintenance activities and (2) that applicable
maintenance activities have been completed is not clear.
130
5. In Table 1-2, there is a maintenance activity related to communication systems to “verify essential
signals to and from other Protection System components.” It is unclear if this statement is referring
to control circuitry associated with the communication system end devices, end device input and
output operation (as in Table 1-1 for protective relays), or something else. It is recommended that
the requirement be to “verify operation of communication system inputs and outputs that are
essential to proper functioning of the Protection System.” This language is consistent with that used
for protective relays in Table 1-1.
6. Referring to Table 1-2, it is unclear whether an entity has the sole authority decide which
‘performance criteria’ are ‘pertinent.’ Additionally, it is unclear if an entity must document the
‘communications technology applied’ and the associated ‘performance criteria’ in its PSMP.
7. In Table 1-4, it is unclear if there is a distinction between the terms ‘resistance’ and ‘ohmic values.’
If there is a distinction, then this distinction should be clarified.
8. In Table 1-4, it is unclear if there is a distinction between the terms ‘battery terminal connection
resistance’ and ‘unit-to-unit connection resistance.’ If there is a distinction, then this distinction
should be clarified.
9. In Table 1-4, replace the term ‘resistance’ with ‘impedance.’
10. Recommend that the 6 calendar month interval in Table 1-4(b) be lengthened to 18 calendar
months to be more consistent with similar maintenance activities for other battery types. At
minimum, lengthen the interval to at least 7 calendar months in a similar way that 3 calendar
months was lengthened to 4 calendar months for other maintenance activities.
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11. Referring to Table 1-5, no periodic maintenance is required for “control circuitry whose
continuity and energization or ability to operate are monitored and alarmed.” It is unclear whether
or not it is acceptable to verify DC voltage at the actuating device trip terminals at least once every
12 calendar years for “unmonitored control circuitry associated with protective functions.” It is
recommended that periodically verifying DC voltage in this manner be an acceptable means of
accomplishing the maintenance activity identified in Table 1-5 for unmonitored control circuitry
associated with protective functions.
12. Referring to 4.2. Facilities of the draft standard, it is unclear whether protection systems for
transformers that step down from over 100kV to below 15kV are applicable to the standard. Even if
there are normally-open distribution feeder ties for purposes of transferring load in a make-beforebreak fashion, these transformers are generally not considered BES elements.
13. Referring to 4.2.5 of the draft standard, it is unclear whether protection for generator excitation
systems are applicable to the standard.
14. It is unclear whether external timing relays (e.g., Zone 2) are considered control circuitry
components (like lockout and auxiliary relays) or protective relay components.
Response:
Thank you for your comments.
1. The SDT agrees with your observation and has changed the relevant parts of the Implementation plan to clarify that
they apply to the maintenance activities for the relevant maintenance intervals.
2. The SDT agrees with your observation and revised the Implementation plan to clarify.
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3. The trip paths from protective relays that respond to mechanical quantities and are intended to detect faults are a
part of the Protection System control circuitry. The sensing elements are omitted from PRC-005-2 testing
requirements because the SDT is unaware of industry recognized testing protocols for these sensing elements. The
SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with
the currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and the SDT understands this to be
consistent with the position of FERC staff. Note that trip signals from devices sensing mechanical parameters not
directly indicative of an electrical fault need not be tested per this standard.
4. The SDT has removed parts 1.1 and 1.3 from Requirement R1, addressing part of your comment. The SDT agrees
that PRC-005-2 allows some leeway in how an entity fulfills the testing requirements of the standard. Section 15 of
the Supplementary Reference and FAQ document provides numerous examples of possible testing techniques for the
various component types making up a Protection System. An entity’s PSMP should clearly define how the testing
requirements of the standard are fulfilled. The Measures for each requirement, as well as Section 15.8 of the
Supplementary Reference and FAQ document, provide some examples of possible compliance documentation for
completion of testing.
5. The SDT agrees with your suggestion and has changed the standard accordingly.
6. The entity has the authority to establish its own acceptable performance criteria. This criteria does not need to be
in the PSMP, but should reside somewhere within the maintenance documentation.
7. As utilized on Table 1-4, the term “ohmic value” is a generic reference to the measurement of a battery cell or units
ability to pass current flow. This may be done using conductance, resistance or impedance measurements; the
various battery test equipment manufacturers use different measurement methods and the term “ohmic value” is
meant to be technology neutral. See FAQ on page 78 of the Supplementary Reference and FAQ document. The term
“resistance” as used in Table 1-4 refers specifically to the dc resistance of the battery terminal connections and the
battery intercell/inter-unit physical connectors. See related FAQ on pages 74-75 of the Supplementary Reference and
FAQ document.
133
8. Battery terminal connection resistance is a measurement of the resistance of a connection at a battery terminal.
Battery intercell or unit-to-unit connection resistance is a measurement of the resistance of the external conductor
interconnecting two adjacent battery cells or two adjacent multi-cell battery units. The SDT believes these are
common battery maintenance terms used throughout the industry.
9. The SDT disagrees and believes that resistance as used in Table 1-4 is the appropriate term for the parameters to be
measured and is consistent with standard battery system maintenance terminology.
10. The SDT disagrees with your recommendation to standardize maintenance intervals between different battery
types that have distinctly different failure mechanisms. See related FAQ on pages 80-81 of the Supplementary
Reference and FAQ document for further discussion of requirements for ohmic measurements of VRLA batteries.
Concerning your recommendation to allow for 7 calendar months, the SDT believes that the six-month interval
specified is appropriate.
11. The SDT has modified this specific portion of the Table, and believes that the modifications address your concern.
Please see Section 15.3 of the Supplementary Reference and FAQ document for a discussion of this topic.
12. The standard does not include the Protection Systems for transformers that step down from over 100kV to below
15kV if these transformers are not BES elements. If Protection Systems are installed for purposes of detecting Faults
on BES elements, these Protection Systems are included.
13. Paragraph 4.2.5.1 indicates that the excitation system protection system would only be in scope if the excitation
system generates signals that trip the generator output breaker either directly or via lockout or auxiliary tripping
relays.
14. As timing is critical to proper Protection System function, timers are considered protective relays.
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Progress
Energy
1. Standard, Table 1-4(a), second sentence under Component Attributes, should state “Protection
System Station dc supply for non-BES interrupting devices for SPS or non-distributed UFLS and
UVLS systems are excluded....” As written, the statement does not include the phrase “UFLS
and.” I believe it should.
2. Supplemental, Section 13, 2nd paragraph, first sentence should state: “...device match the
minimum requirements listed in Tables 1 and 3.”
Response: Thank you for your comments.
1. The SDT agrees. Table 1-4(a) has been modified as you suggest; this text has been relocated to the header of the table.
2. The SDT agrees and has modified the Supplementary Reference and FAQ document as you suggest.
135
Western Area
Power
Administration
Comment 1:Western Area Power Administration does not agree with penalizing utilities for
implementing maintenance programs that exceed the requirements defined in the NERC Standard
PRC-005-2 maintenance tables. Although the intent of the language in the Supplementary Reference
and FAQ document may have been to allow evolving maintenance programs to include conditionbased and performance based maintenance in their programs, penalizing utilities with more
stringent programs will more likely provide a disincentive for program development. Utilities will
discontinue any additional maintenance activities that could put them at risk for non-compliance.
This will cause maintenance programs to stagnate and new maintenance ideas to improve system
reliability to not be implemented. It is the opinion of the Western Area Power Administration that
the following text should be removed from the Supplementary Reference and FAQ document and
entities should be audited to the minimum requirement of the standard regardless of their individual
programs. Recommendation: Remove the following text from the Supplementary Reference & FAQ
document:1. Page 26 - The bullet “If your PSMP (plan) requires more activities then you must
perform and document to this higher standard.”
2. Page 27 - The bullet “If your PSMP (plan) requires activities more often than the Tables maximum
then you must perform and document those activities to your more stringent standard.” 3. Page 27 The paragraph “It has been noted here that an entity may have a PSMP that is more stringent than
PRC-005-2. There may be any number of reasons that an entity chooses a more stringent plan than
the minimums prescribed within PRC-005-2, most notable of which is an entity using performance
based maintenance methodology. (Another reason for having a more stringent plan than is required
could be a regional entity could have more stringent requirements.) Regardless of the rationale
behind an entity’s more stringent plan, it is incumbent upon them to perform the activities, and
perform them at the stated intervals, of the entity’s PSMP. A quality PSMP will help assure system
reliability and adhering to any given PSMP should be the goal.” Revise R3 of PRC-005-2 and add
statement to the Supplementary Reference & FAQ document.1. R3: Each Transmission Owner,
Generator Owner and Distribution Provider shall implement and follow its PSMP plan within the
prescribed intervals of Tables 1, 2 and 3. and correct any unresolved maintenance issues.2. FAQ: Any
utility maintaining Protection System equipment that exceeds the requirements and tables because
of historical testing data and/or failure documentation should not be held non-compliant or
penalized for not meeting its PSMP, as long as they do not exceed the maximum allowable intervals
or meet the minimum maintenance activities of the standard.
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Comment 2:R3 of PRC-005-2 states “Each Transmission Owner, Generator Owner, and Distribution
Provider shall implement and follow its PSMP and initiate resolution of any unresolved maintenance
issues.” The Western Area Power Administration would like more clarification on potential data
request for requirement R3 of PRC-005-2. Because the requirement uses the term initiates
resolution, the entity could make the assumption that providing just a list of maintenance request
for unresolved maintenance issues will serve to prove compliance. Although it would seem implied
that whatever method used to initiate resolution would lead to some type of corrective
maintenance, the requirement does not make that absolutely clear. To ensure the maintenance
practices are meeting the intent of the requirement, the requirement needs to clarify the
expectations for completing corrective maintenance that was initiated to resolve maintenance
issues.
Recommendation: Add additional clarification to Supplementary Reference & FAQ document to
further clarify expectation for this requirement.
Response: Thank you for your comments.
1. The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based programs,
entities shall comply with the tables; Requirement R4 has been added to address performance-based maintenance, and
Requirement R5 has been added to address Unresolved Maintenance Issues.
2. Additional clarification has been added to the Supplementary Reference and FAQ document. Additional examples have also
been added to the Measure for this Requirement.
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PacifiCorp
1. The data retention requirement for producing evidence that the entity performed maintenance
for the 2 most recent maintenance intervals is excessive. As an example, if a registered entity’s
maintenance/test interval is 12 years, such entity may be required to keep records for up to 35
years. PacifiCorp recommends a revision to the data retention requirement to provide for either a
maximum retention period of 10 years or, in cases in which the interval exceeds 10 years, the most
recent maintenance/test cycle only.
2. The requirement to identify all PTs is very onerous and not needed to verify maintenance
compliance and therefore serves a limited reliability benefit. PacifiCorp believes that, as long as a
registered entity can demonstrate that it can verify that all CTs/PTs providing input into a Protection
System have been tested and maintained according to its established procedures, then a separate
and independent requirement to maintain a list of these devices is not necessary. As an example, if
an entity performed their protection system maintenance on a “scheme” basis, and as part of that
maintenance documentation identified all CT’s and PT’s providing input into the scheme and verified
their accuracy, then having a “master list” would provide no benefit. A list of all CT’s associated with
one device such as a circuit breaker would have little value in this case as these CT’s may provide
input into multiple relay schemes and would not be maintained on an individual circuit breaker basis.
Response: Thank you for your comments.
1. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the
data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that entities
have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has
specified the data retention in the posted standard to establish this level of documentation. This seems to be consistent with
the current practices of several Regional Entities.
2. The SDT does not believe the current standard contains a “separate and independent requirement to maintain a list of these
devices”. As your comment correctly indicates, if an entity can provide evidence that the inputs from all CTs and PTs are
accurately being received by the associated relays for in scope Protection Systems, this is acceptable. It is up to the entity to
best determine how to track this – whether by a “master list” of CTs and/or PTs, on a “scheme” basis, by physical location of
the instrument transformer, or some other effective tracking method.
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Saft America,
Inc.
Saft Comments on NERC Standard PRC-005-2 - Protection System Maintenance - Please find herein
Saft’s comments to NERC PRC-005-2 regarding ohmic testing of Nickel-Cadmium (NiCad) batteries.
As drafted, the proposed NERC Standard PRC-005-2 will lead to the removal of high quality, reliable
NiCad battery power units from Protection Systems, which is counter to the NERC stated purpose of
PRC-005-2, which is to ‘document and implement programs for the maintenance of all Protection
Systems affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems
are kept in working order.’ There is broad consensus within the battery industry that ohmic testing
of Valve Regulated Lead-Acid (VRLA) batteries provides a means for trending the condition of the
battery over time. Such a consensus does not exist for Vented Lead-Acid (VLA) batteries, because
ohmic measurements are more difficult to trend, thereby providing a go/no-go assessment of the
battery's availability at that precise moment in time, rather than a measure of VLA battery condition.
Ohmic testing of NiCad batteries provides a similar go/no-go assessment to ohmic testing of VLA
batteries. As with VLA batteries, ohmic testing of NiCad batteries does not provide meaningful
trending information, but rather provides a status update of battery condition at a specific moment
in time. Due to the similar information provided by ohmic testing of VLA and NiCad batteries, Saft
recommends that ohmic testing of NiCad batteries be included under the Maintenance Activities for
NiCad batteries. Specifically, Saft recommends that NERC add the following language to the
Maintenance Activities column in Table 1-4(d), ‘Verify that the station battery can perform as
designed by evaluating the measured cell/unit internal ohmic values to station battery baseline’, at a
maximum maintenance interval of 18 months, as in the requirement for VLA batteries noted in Table
1-4(a).
Response: Thank you for your comments.
The SDT disagrees. The SDT is aware of studies that indicate a correlation between ohmic measurements and battery condition (or
remaining life) for VLA and VRLA batteries when trended against a baseline ohmic measurement taken when the battery was new.
These same studies concluded no such correlation exists for NiCad batteries. We are unaware of any published studies that
conclude otherwise for NiCad batteries. The standard does not favor one technology over another but simply allows flexibility in
testing techniques when the attributes of a technology allow for technically justifiable application of that flexibility and achieve the
objective of the standard.
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Nebraska
Public Power
District
a. Section 4.2.5.4 includes station service transformers for generator facilities. As currently written,
the section includes all the protection systems for station service transformers for generators that
are a part of the BES. It states, “Protection Systems for generator-connected station service
transformers for generators that are part of the BES.” Generating facilities may have transfer
schemes on the auxiliary transformer to transfer equipment to a reserve transformer instead of
tripping the unit. These protection systems should not be included in the Facilities for PRC-005-2,
since the BES is not affected. Recommend changing Section 4.2.5.4 to read, “Protection Systems
that trip the generator for generator-connected station service transformers for generators that are
a part of the BES.”
b. Section 1.3 requires an entity to retain the two most recent performances of each distinct
maintenance activity. This is an unreasonable requirement and does not enhance reliability.
Recommend the data retention be changed to require only the most recent test record. An audit
should be focused on the present day and not in the past. Is an entity compliant today and not can
we find a way to issue a fine for something in the past? An example exists where an entity recently
registered and tested all their relays prior to registering. They have one set of documentation and
not two. Why should they be forced into testing again and incurring additional expense for
customers only to have two tests available for an auditor? This does not enhance reliability. PRC005-2 allows testing intervals of up to 12 calendar years. If we are required to have the two most
recent tests, we could conceivably have to retain a relay test record for 24 years! Hypothetically, if
we have a test record from ten years ago, but we don’t have the record from 24 years ago, how does
that adversely affect the reliability of the BES today? The standard should focus on - Are we
compliant today?
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c. Table 1-5 requires a maintenance activity to, “Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.” Recommend this be changed to, “Verify that a
trip coil is able to operate the circuit breaker, interrupting device, or mitigating device.” Or
alternately, change the wording to, “Electrically operate each interrupting device every 6 years.”
While requiring each trip coil to operate the breaker sounds good in theory, practically it creates
issues in the field and may create more problems than it solves. The trip coils are located in the
panel at the breaker and aren’t configured to test independently. Isolating one trip coil from the
other may include “lifting a wire” that may not get landed properly when the test is complete. Then,
how do you prove for a compliance audit that both trip coils were independently tested to trip the
breaker? Using an actual event only tests one coil and we may not know which coil tripped the
device. To be compliant, it isn’t practical to be able to track a real-time fault clearing operation as
suggested on page 67 of the Supplementary Reference document. First, we don’t know which trip
coil operated, then we have a “one off” device in the substation that must be tracked separately
with a different testing cycle from the other devices in the substation - this is a recipe for a
compliance violation. The standard should focus on ensuring the control circuitry is intact and trips
the breaker without injecting additional, unneeded risk to the BES.
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d. General comment under Table 1-5: We do extensive testing of the control circuit during
commissioning and after a modification to the circuit. Testing of the control circuitry on a periodic
basis is not needed. The wear and tear on the equipment from functional testing and the potential
risk of the testing itself may create more issues than the benefits received from doing the tests. The
functional test injects significant opportunities for human performance errors during the test
(technician trips the wrong device, differential relay opens all protective devices for a bus instead of
a breaker, technician bumps another relay, screw driver falls into another device, etc.) and latent
errors after the test (i.e., if a wire was lifted during the test, was it landed back in proper location,
was the relay tripping function activated after the test was completed or was the relay left in test
mode, etc.). Request the drafting team provide a basis for requiring the functional test. Are there
documented instances where the control circuitry caused a significant event on the BES? Many
utilities, including us, monitor our circuit breakers for operations. If a breaker hasn’t operated for a
defined period of time, we set up a maintenance activity to operate the breaker (possibly to include
a timing test to ensure the breaker clears in the proper amount of cycles) - this ensures the
operating linkages aren’t bound and the breaker will operate. We have many maintenance activities
performed on devices for the BES that do not require a NERC standard. If a utility chooses not to
perform best practice maintenance, customers will experience more frequent and longer outages.
The utility will receive customer feedback on outages which should translate into the utility
increasing its maintenance. In other words, we don’t have to include a functional test as a NERC
requirement. Misoperations are already monitored and reported through PRC-004. Does recent
misoperation data or TADS data indicate that control circuitry/trip coils are a problem within the
protection and control system? The current version of PRC-005 doesn’t require functional tests.
What is the basis for requiring additional compliance documentation (additional functional testing)?
A possible alternative: only perform testing following modifications or major maintenance (like
breaker change outs or panel modifications).
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e. Recommend NERC provide training specifically on how to audit PRC-005-2 to auditors in all eight
Regional Entities. PRC-005 is the most violated standard since enforcement began on June 18, 2007.
This is an excellent opportunity for NERC to get all eight regions on the same page for what to audit.
NERC provides training on standard auditing guidelines and sample selection, but doesn’t provide
training on how to audit specific standards. RSAW’s and CAN’s have been an attempt to get
consistency across the regions, but differences are still obvious. NERC is in the perfect position to
observe potential violations (PV) from an auditor and as a PV is written that goes beyond the
standard or is not in accordance with the initial training; NERC can dismiss the PV and retrain the
auditor. Auditors aren’t perfect, nor are any of us. Training is a basic tool for the auditor to perform
their job properly.
Response: Thank you for your comments
a) The SDT has modified paragraph 4.2.5.4 as you suggest.
b) In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need
the data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that
entities have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT
has specified the data retention in the posted standard to establish this level of documentation. This seems to be consistent
with the current practices of several Regional Entities.
c) The description of the configuration of the second trip coil on circuit breakers you have provided is not typical of the
redundant approach taken by most entities. Typically, second trip coils are electrically isolated from the first trip coil and are
often fed by a separately fused dc control circuit with different relay trip output, lockout and auxiliary tripping contacts
utilized in each circuit. The SDT believes that it is important that redundant trip paths be maintained within the indicated
interval, and the prescribed interval already considers the reliability benefits of redundant equipment.
d) The SDT believes that it is possible to manage the risks that you describe and that performance of these trip path verifications
will be an overall benefit to the reliability of the BES.
e) The SDT will forward this comment to NERC Compliance for their consideration.
Exelon
Texas
(1) General - defined terms need to be capitalized throughout this standard.
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Reliability
Entity
(2) Requirement R3 only addresses initiation of resolution to any Unresolved Maintenance Issues.
Requirement R3 should require completion of corrective action to deal with Unresolved
Maintenance Issues within a reasonable timeframe.
(3) Section 1.3, Data Retention, should require each entity to keep all versions of its PSMP that were
in effect since its last compliance audit, in order to demonstrate compliance at all relevant times (not
just the current version).
(4) In the Severe VSL for R2, add “Annually” to the second bullet under part 5.
5) The VSLs for R3 should contain a time frame (annual?). The second part of these VSLs should refer
to initiation and completion of resolution of Unresolved Maintenance Issues. (See comment on
Requirement R3 above.)
(6) Consider making the R3 VSLs based on a percent of the number of maintenance activities
required by the PSMP in a stated time period, rather than on a percent of the total number of
Components.
(7) There is no maintenance activity listed to verify that protection system component settings meet
the design intent of the protection system. In other words, there is no required activity to confirm
that the “specified” settings are correct and appropriate. This introduces a potential reliability gap
into the Protection System maintenance program.
(8) In Table 1-1, the term “acceptable measurement of power system input values” is somewhat
vague. A tolerance value or reference to industry standards should be provided.
(9) In Table 1-3, the activity should include verifying that the current and voltage signal values are
within design tolerances, not just that signal values are present.
(10) In Table 1-4(a) Component Attributes - the reference to UFLS systems is missing in the exclusion
that refers to UVLS systems. (UFLS is included in Tables 1-4(b) through 1-4(d).)
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( 11) In table 1-4(f), there should be a reference to “alarming” in addition to “monitoring” in the first
cell of the next-to-last row
(12) In table 1-4(f), why is the last row limited to VRLA station batteries? Should the same exclusion
apply to VLA batteries?
(13) In Table 1-5, a “12 calendar year” interval is too long for “Unmonitored control circuitry
associated with SPS” and “Unmonitored control circuitry associated with protective functions.” We
suggest this be changed to 6 years. Similar unmonitored attributes related to battery maintenance
have a 6 calendar year interval.
(14) In Table 2, the phrase “location where corrective action can be initiated” is unclear, and we
suggest that a more definitive description be used. Also, why is the word “DETECTION” in all-caps?
(15) In Table 3, the maintenance activity should include verifying that Protection System Component
settings meet the design intent of the Protection System. For example, any reclosing function should
be disabled on UFLS and UVLS relay systems.
(16) In Table 3, In Table 1-1, the term “acceptable measurement of power system input values” is
somewhat vague. A tolerance value or reference to industry standards should be provided.
(17) The Implementation Plan is overly long and complicated. Entities (including Regional Entities)
will have to track and apply multiple versions of this standard for 14 years. It would be preferable to
have a much shorter implementation plan, so that only one version of the standard will be
applicable, recognizing that for some Components no action will be required under the standard for
a number of years.
Response:
Thank you for your comments.
1. The SDT will attempt to properly capitalize defined terms throughout the standard.
145
2. The SDT specifically chose the phrase “initiate resolution” because of the concern that many more complex
Unresolved Maintenance Issues might require greater than the remaining maintenance interval to resolve. For
example, a problem might be identified on a VRLA battery during a 6 month check. In instances such as one that
requiring battery replacement as part of the long term resolution, it is highly unlikely that the battery could be
replaced in time to meet the 6 calendar month requirement for this maintenance activity. The SDT does not believe
entities should be found in violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective actions should be
timely but concludes it would be impossible to postulate all possible remediation projects and therefore, impossible
to specify bounding time frames for resolution of all possible Unresolved Maintenance Issues or what documentation
might be sufficient to provide proof that effective corrective action has been initiated. The SDT has clarified the intent
of the requirement to initiate resolution of Unresolved Maintenance Issues by including it separately as Requirement
R5 and revising the language such that the responsible entity must demonstrate its efforts to correct Unresolved
Maintenance Issues.
3. The SDT agrees with your observation and has modified the data retention requirements accordingly.
4. The SDT agrees with your observation and has modified VSL for Requirement R2 accordingly.
5. The percentages relate to the number of violations of the respective requirement reported within the compliance
monitoring period relative to the number of components within that component type. PRC-005-2 only requires the
entity “… initiate resolution” of the issue found. The SDT recognizes that performance of the activities necessary to
resolve an issue are entirely dependent upon the circumstances surrounding that issue and, consequently, will require
varying amounts of resources and time to complete the process. It is for this reason the SDT crafted the requirement
to only require initiation of the process.
6. The SDT disagrees. The entity must complete all required activities on any specific component in order to be
compliant, regardless of the number of activities scheduled for that component.
7. The SDT believes that adequacy of settings is more properly a design issue and should not be included in a
maintenance standard.
146
8. The SDT believes it is more appropriate for entities themselves to establish acceptance criteria that meet the
performance requirements necessary for the proper operation of their Protection Systems.
9. The action, “verify” is specified within the PSMP definition as “Determine that the component is functioning
correctly.” Therefore, the SDT believes that the suggested change is unnecessary.
10. The SDT agrees. Table 1-4(a) has been modified as you suggest. The modified text has been moved to the header
of the tables.
11. The SDT agrees. Table 1-4(f) has been modified as you suggest.
12. The SDT agrees. Table 1-4(f) has been modified as you suggest.
13. The SDT disagrees and believes that the 12 year requirement for SPS’s is in alignment with the Table 1-5 row 4
requirement for testing of unmonitored trip paths for control circuitry with protective function in other Protection
Systems.
14. Based on a lack of other comments received on this topic, the SDT believes that this description has sufficient
clarity. The word “detection” on Table 2 has been corrected to lower case font.
15. The first row of Table 3 requires that settings be verified to be as specified. The SDT believes this to be a proper
maintenance function but that the determination of the adequacy of settings (or, for that matter, design criteria) is
more properly a design issue and should not be included in a maintenance standard.
16. The SDT believes it is more appropriate for entities themselves to establish acceptance criteria that meet the
performance requirements necessary for the proper operation of their Protection Systems.
147
17. The SDT disagrees. It is not practical for all entities to rapidly transition all of their protection systems to the new
program, especially with some component types on maintenance intervals of up to 12 years. Nonetheless, all in scope
Protection Systems must either be being maintained by either a PRC-005-1 program or a PRC-005-2 program. The SDT
believes the graded approach mapped out in the Implementation plan is practical. Finally, if in order to lessen the
complexity of documentation requirements, an entity wishes to implement PRC-005-2 on a more rapid rate than laid
out in the Implementation plan, they are free to do so.
Central Lincoln
We are concerned about what exactly “initiate resolution” means in R3. We foresee this being a
potential area of disagreement between registrants and CEAs when a registrant believes an open
work order suffices and the CEA wants to see schedules or purchase orders. Neither M3 nor the
FAQs address this.
Response: Thank you for your comment.
The SDT has clarified the intent of the requirement to initiate resolution of Unresolved Maintenance Issues by including it
separately as Requirement R5 and revising the language such that the responsible entity must demonstrate its efforts to correct
Unresolved Maintenance Issues because of the concern that many more complex Unresolved Maintenance Issues might require
greater than the remaining maintenance interval to resolve. For example, a problem might be identified on a VRLA battery during a
6 month check. In instances such as one that requiring battery replacement as part of the long term resolution, it is highly unlikely
that the battery could be replaced in time to meet the 6 calendar month requirement for this maintenance activity. The SDT does
not believe entities should be found in violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective actions should be timely but
concludes it would be impossible to postulate all possible remediation projects and therefore, impossible to specify bounding time
frames for resolution of all possible Unresolved Maintenance Issues or what documentation might be sufficient to provide proof
that an entity is correcting these issues.
Dynegy Inc.
For Facilities listed under 4.2, are Reserve Auxiliary Transformers supposed to be included?
148
Response: Thank you for your comment.
No, Reserve Auxiliary Transformers or system connected station service transformers were intentionally removed from the
Applicability in a previous draft. Generator-connected station service transformers are often connected to the generator bus
directly without an interposing breaker; thus, the Protection Systems on these transformers will trip the generator as discussed in
4.2.5.1. and are thus included. Reserve auxiliary or system connected station service transformers Protection Systems will not
directly result in the trip of a generator and as such are omitted from the Applicability of the standard.
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American
Electric Power
1. As it stands, if an entity adopts a more stringent maintenance program but fails to meet it, that
entity could be found non-compliant despite continuing to abide by the minimum requirements of
the standard itself. Entities should have the ability, if they so choose, to include additional
maintenance activities or more stringent intervals than specified within the standard without
concern of penalty in the event they are unable to accomplish them. In short, entities should only be
audited against the requirements stated within the standard. Table 1-3 of the standard lists the
minimum required maintenance activities for voltage and current sensing devices as "Verify that
current and voltage signal values are provided to the protective relay."
2. Consistent with Table 1-3, Section 15.2.1 of the Supplementary Reference states that an entity
“...must verify that the protective relay is receiving the expected values from the voltage and current
sensing devices...” The Supplementary Reference further offers examples of how this requirement
may be satisfied with most examples referencing the need to verify the signal at each relay in the
circuit. We recognize the need to verify a voltage signal at each protective relay, as these devices
are wired in parallel and an open circuit at one location may not impact the other devices on the
circuit. However, we do not agree that there is a need to verify a current signal at each protective
relay. Current devices are wired in series, and an open circuit at any location will impact all other
devices on the circuit. For this reason, a single measurement of the current circuit is sufficient. We
recommend updating Table 1-3 and the supplementary reference to account for the different
physical characteristics of voltage and current circuits.
3. This standard encompasses a very broad range of component types and functionality across broad
segments of the BES. The proposed VSLs and VRFs place the same level of severity or priority on
facilities that serve local load with that of an EHV facility. The percentages indicated in the VSLs seem
to be too strict based upon the vast quantity of elements in scope and broad range of application.
Other standards have applicability for certain thresholds of voltage levels, etc. Why not this standard
as well?
150
Response: Thank you for your comments.
1. The standard and the Supplementary Reference and FAQ document have been changed to address your concerns.
Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for time-based
programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
2. An open circuit is not the only failure mechanism for a CT secondary circuit. Grounded CT secondary wiring can result in
situation where accurate current is present in the part of the secondary circuit upstream of the ground but current would be
shunted to ground and might not pass through devices downstream of the ground. Entities should not interpret PRC-005-2
as specifying “how” to test but rather that PRC-005-2 only specifies “what” to test. Entities are free to determine creative
ways to fulfill requirements.
3. VSLs characterize “how bad did you miss a requirement”, rather than on the impact to the BES. The percentages indicated
in the VSLs follow demarcation guidelines given by NERC to Standard Drafting Teams. With the magnitude of the total
number of Protection System components for many entities likely to be very large, exceeding 5% of that total equates to
failing to perform maintenance and testing on a (potentially) large number of components, and should be reflected by a
Severe VSL. The SDT further believes that this standard should be applied uniformly to the applicable facilities, rather than
stratifying it to reflect different system voltages.
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Lincoln Electric
System
In reference to the zero tolerance policy evident within PRC-005-2, LES offers the following
suggestion: Set up an annual review of a random set sample (20% for example) of Protection System
equipment to self-verify compliance. If issues arise, allow the entity the opportunity to correct the
issue, make the necessary procedural and/or documentation adjustments and not be considered
non-compliant. The idea is to allow entities the opportunity to continually improve their practices
and procedures; in essence, allow them to show they are attempting to follow a “culture of
compliance”. If habitual problems arise, then non-compliance will be evident. One example that
justifies this approach is software glitches or improper programming. As more and more systems
become automated, scheduling of maintenance will be done automatically through various types of
software. If a program has even one attribute set incorrectly, it could not function as intended and
would potentially set up incorrect intervals for maintenance and testing. It was not intended this
way by the entity and they are not intentionally disregarding the standards, but could nevertheless
be put in a situation where a maintenance interval is missed. An annual review would catch things
like this and allow an entity to continuously improve their program without self-reporting. This
concept is expanded from a current draft version of several CIP standards; therefore, it is being at
least considered by other drafting teams.
Response: Thank you for your comments.
The NERC criteria for VSLs do not permit any level of non-performance without being in violation. The graded approach of the VSL
for Requirement R3 provides for an escalating degree of severity for increasing degrees of non-compliance.
NIPSCO
The new standard itself, the implementation plan and supplemental reference/FAQ makes up more
than 100 pages of material. Granted that several standards are being combined here, still it is simply
too involved to monitor. And there is still not enough detail in the standard leaving items which are
ambiguous and open to interpretation, and therefore open to fines. In order to remove such
interpretation, maintenance documentation will need to be precise and extensive. This will
necessitate more and more staff to control and validate data. Adding staff is great but it does not
seem to ensure that there is increased reliability.
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Response: Thank you for your comment.
FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
maintenance activities. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that
may be consistently monitored for compliance.
Entergy
Services
We understand and disagree with the SDT position on the following recommendation. We do not
agree with proposed Section 4.2.1 applicability since it captures only a portion of the previously
approved applicability Interpretation (PRC-005-1a) which was developed specifically for PRC-005-1.
We suggest the draft standard be revised to conform to the wording in the Interpretation:
“Protection Systems that are installed for the purpose of detecting faults on BES Elements (lines,
buses, transformers, etc.) and trips an interrupting device that interrupts current supplied directly
from the BES Elements.”
Response: Thank you for your comment.
The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is not
used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems
that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and
FAQ document for additional discussion.
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Independent
Electricity
System
Operator
The IESO disagrees with the concept that auditors use the standards as minimum requirements and
evaluate compliance based on a registered entity’s own governance. We believe that the entity
could be found non-compliant with Requirement R3 if they fail to follow the internal maintenance
intervals established in their PSMP, even though actual maintenance intervals are no less frequent
than the prescribed maximum intervals established in the draft standard. The potential for such a
finding will discourage conscientious entities from setting higher internal targets for their planned
maintenance and promote compliance with only the minimum requirements of the standard. We
therefore propose the following revision to Requirement R3:R3. Each Transmission Owner,
Generator Owner, and Distribution Provider shall implement and follow its PSMP and initiate
resolution of any unresolved maintenance issues. In the case of time-based maintenance programs,
each Transmission Owner, Generator Owner, and Distribution Provider is permitted to deviate from
its PSMP provided that actual maintenance intervals do not exceed those specified in Tables 1-1
through 1-5, Table 2 and Table 3. [Violation Risk Factor: High] [Time Horizon: Operations Planning]
Response: Thank you for your comments. The standard and the Supplementary Reference and FAQ document have been
changed to address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so
that, for time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performancebased maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
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Liberty Electric
Power LLC
With the development and publication of maximum maintenance and testing intervals (the Tables),
there is no longer a reliability need for a RE to identify the associated maintenance intervals for
Protection System Components. Further, REs who wish to perform these activities in shorter
intervals than those allowed by the standard (See Supplementary Reference, page 27,"If your PSMP
(plan) requires activities more often than the Tables maximum then you must perform and
document those activities to your more stringent standard.")As noted in Question 5, if the entity
completes all activities within the maximum interval allowed by the standard, there can be no
reliability concern; if there is a reliability issue, then the table interval is incorrect. I would suggest
the following changes.1. Change R1.2 to read "Identify any Protection System component where the
RE is using a performance based maintenance interval. No batteries associated with the station DC
supply component type of Protection System shall be included in a performance based system".2.
Change R1.3 to read "The intervals for time-based programs are established in Table 1-1 through 1-5,
Table 2, and Table 3".3. Change M1 to add the phrase "for performance-based components" after
the words "maintenance intervals".4. In M1, replace the words "the type of maintenance program
applied (time-based, performance based, or a combination of these maintenance methods)' with the
words "the identification of any protection system components using performance based intervals".
Response Thank you for your comments. The standard and the Supplementary Reference and FAQ document have been changed
to address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for
time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
155
Ameren
(1)Measure M3 on page 5 should only apply to 99.5% of the components. Please revise to state:
“Each ... shall have evidence that it has implemented the Protection System Maintenance Program
for 99.5% of its components and initiated....” PRC-005-2 unrealistically mandates perfection without
providing technical justification. A basic premise of engineering is to allow for reasonable
tolerances, even Six Sigma allows for defects. Requiring perfection may well harm reliability by
distracting valuable resources from higher priority duties concerning the Protection System. We are
not asking for the VSL to be changed. No one is perfect and it is impractical to imply perfection is
achievable. The consequence of a very small number of components having a missed or late
maintenance activity is insignificant to BES reliability. Our proposed reasonable tolerance sets an
appropriate level of performance expectation. We disagree with the notion that this is “nonperformance”.
(2) An alternate approach regarding the unrealistic perfection of M3 is to correctly recognize that the
protection of the primary BES is the objective. Most Protection Systems are redundant by design
and the entity needs to be afforded the opportunity to show that a redundant component met the
PSMP thereby providing the required protection. The entity should be allowed a reasonable time
frame of one calendar increment to maintain the component in question. Our concern stems from
the tens of thousands of components in a PSMP, and the reality that rarely but occasionally a data
base error or outage scheduling issue may result in a very small number component exceeding their
maximum interval. As long as the entity can show that BES protection was sustained and maintains
the component quickly (e.g. within one calendar month of discovery), BES reliability has been
maintained.
(3) Now that FERC has approved the Project 2009-17 Interpretation, please acknowledge more
directly in the Supplement that the ‘transmission Protection System’ that is now approved. NERC
interprets “transmission Protection System,” as it appears in Requirements R1 and R3 of PRC-004-1
and Requirements R1 and R2 of PRC-005-1, to mean “any Protection System that is installed for the
purpose of detecting faults on transmission elements (lines, buses, transformers, etc.) identified as
being included in the Bulk Electric System (BES) and trips an interrupting device that interrupts
current supplied directly from the BES.”
156
Response: Thank you for your comments.
1. The NERC criteria for VSLs do not permit any level of non-performance without being in violation. The graded approach of
the VSL for Requirement R3 provides for an escalating degree of severity for increasing degrees of non-compliance.
2. Regarding redundancy, the SDT believes that it is important that redundant components be maintained within the indicated
interval, and the prescribed interval already considers the reliability benefits of redundant equipment. It should be noted
that misoperations not only occur for failure to operate for valid faults but also operation of a protection system for an
invalid, non-fault condition. It is important that both components be maintained within the specified intervals to help
preclude this second type of misooperation – e.g., over tripping of relays.
3. The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The
SDT observes that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this
term is not used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses
“Protection Systems that are installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the
Supplementary Reference and FAQ document for additional discussion.
157
Northeast
Utilities
1. The definition of “Component” in PRC-005-2 Draft 1, states “Another example of where the entity
has some discretion on determining what constitutes a single component is the voltage and current
sensing devices, where the entity may choose either to designate a full three-phase set of such
devices or a single device as a single component.” However, in Section 15.2 of Supplementary
Reference & FAQ it states: “The intent of the maintenance activity is to verify the input to the
protective relay from the device that produces the current or voltage signal sample.” Please
consider reconciling these two sections (definition of “Component” and Section 15.2) to allow the
entity to consider a relay as the single component versus the voltage and current sensing devices,
and pursuant with Section 15.2 perform the voltage and current checks to the inventoried relays.
This approach will ensure that the CT and PT check to each relay is performed. Section 15.2 of
Supplementary Reference & FAQ states in the second paragraph “The intent of the maintenance
activity is to verify the input to the protective relay from the device that produces the current or
voltage signal sample.” Please consider revising the last bullet in Section 15.2, paragraph 3 from
“Any other method that provide documentation that the expected transformer values as applied to
the inputs to the protective relays are acceptable” to “Any other method that verifies the input to
the protective relay from the device that produces the current or voltage signal sample.”
2. As shown (see Figure A-2) and discussed in Appendix A of Supplementary Reference & FAQ list,
there are four elements that are not verified. Following the identification of the four elements that
are not verified, a practical solution is provided for testing methods on three of the four elements.
Please provide a practical solution for the fourth element.
Response: Thank you for your comments.
1. The SDT does not believe a discrepancy exists. CTs and PTs or other current and voltage sensing devices are indeed Protection
System Components. Section 15.2 of the Supplementary Reference and FAQ document is describing a maintenance activity
that is to be performed to validate proper function of that Component type. The Supplementary Reference and FAQ document
has been revised to clarify.
2. Appendix A to the Supplementary Reference and FAQ document (with the imbedded figures) is intended to provide an example
of the application of monitoring to minimize maintenance activities and maximize maintenance intervals, but is not intended to
be a comprehensive treatise of the subject.
158
MidAmerican
Energy
Company
1. The following comment was submitted in the last comment period: In the background section of
the implementation plan in item two it states “..it is unrealistic for those entities to be immediately
in compliance with the new intervals.” Recent compliance application notices indicate that auditors
are requiring entities to include proof of compliance to maintenance intervals by providing the most
recent and prior maintenance dates. The implementation document could be improved by providing
clarity to what is expected with regard to when an entity is expected to provide evidence of
maintenance interval compliance given the quoted item above. As an example in the section the
implementation plan for a 6 year interval item it states: “ The entity shall be at least 30% compliant
on the first day of the first calendar quarter 3 years following applicable regulatory approval..”
In keeping with the previously quoted “reasonableness” criteria it would seem that 30% compliant
would mean only one test action would be needed to be completed by the indicated deadline and
the next one would be required no later than 6 years from that first test. It is recommended that the
implementation plan document be improved to clarify this issue. The consideration of comments
response to the above did not completely address the issue that led to the comment. In the Tables
in PRC-005-2 there are maintenance items that an entity may not have had in their PRC-005-1
compliance program even though they did have a compliant maintenance program (e.g. battery
continuity testing) for that Protection System component. As the transition is made to the PRC-005-2
requirement the above clarification should be made to better define what achievement of PRC-005-2
compliance is for that component.
2. Section 4.2.2 includes UFLS systems installed per the ERO requirements - excluding any additional
UFLS systems that a utility has on their system. Section 4.2.3 includes UVLS systems “installed to
prevent system voltage collapse or voltage instability for BES reliability”. It is assumed that this
would only include UVLS systems required by the ERO, but it is not clear as to what is in scope. It is
suggested that the wording of 4.2.3 be changed to match the wording in 4.2.2.
3. In the implementation plan in the R2 and R3 requirements plans, in item a. of each there is a
parenthetical statement regarding generating plant scheduled outage intervals. A similar
parenthetical statement should be added to the b. and c. items of each of these plans.
159
4. The purpose statement of the standard seems to be inconsistent with the applicability section. To
correct this it is suggested that the words “affecting the reliability” be removed from the purpose
statement.
5. For consistency with the changes from 3 months to 4 months in the tables of the standard it is
suggested that the second item in Table 1-4(b) be changed from 6 calendar months to 7 calendar
months.
6. In the tables for dc Supply the term “unit-to-unit” is used along with “intercell” when referring to
measurement of connection resistance. From the applicable IEEE standards (e.g. IEEE 450) the
standard terminology seems to be “intercell”. It is recommended that the “unit-to-unit” term be
removed to avoid confusion regarding what is to be verified.
160
Response: Thank you for your comments.
1. The SDT agrees with your comment and has modified the Implementation plan to better indicate that, for activities being
added to an entity’s program as part of PRC-005-2 implementation, evidence will be available to show only a single
performance of the activity until a full maintenance interval has transpired following initial implementation.
2. Entities are required to install UFLS per PRC-007; there are no standards which require entities to install UVLS. However, if
entities choose to install UVLS to meet minimum system performance requirements, several standards (including the
current PRC-011 and the proposed PRC-005-2) apply. Section 4.2.3 is specifically intended to address these UVLS.
3. The SDT provided the allowance for generator plants to allow them until their first maintenance outage to begin program
implementation. It is believed that the entity would then likely perform all maintenance on the protection system for a
given generator, GSU and, if so equipped, generator connected station auxiliary transformer during that maintenance
window. It seems unlikely that an entity would perform maintenance on only a portion of a protection system. Thus, the
SDT concludes that inclusion of the parenthetical to the 2nd and 3rd bullets would only add confusion and provide little or
no benefit to generator plants in the implementation of their program.
4. The purpose of the standard expresses the general intent of the standard, and is further clarified by the Applicability.
5. The SDT believes that a 6-month interval is appropriate for these activities.
6. The term “unit-to-unit” is used for the conductor utilized to connect one multi-celled battery jar to an adjacent multi-celled
battery jar. The SDT does not believe this terminology causes wide spread confusion.
Manitoba
Hydro
-Definition of Protection System Maintenance Program: The definition included in the proposed PRC005-2 is not the same as the definition provided in the document “Definition for Approval”, which
also includes items “Upkeep” and “Restore”.
Response: Thank you for your comments.
The SDT agrees with your observation and will review the associated documents to attain consistency.
161
American
Transmission
Company
a) Change the text of “Standard PRC-005-2 - Protection System Maintenance” Table 1-5 on page 19,
Row 1, Column 3 to: ”Verify that each a trip coil is able to operate the circuit breaker, interrupting
device, or mitigating device.” Or alternatively, “Electrically operate each interrupting device every 6
years.” Trip coils are designed to be energized no longer than the breaker opening time (3-5 cycles).
They are robust devices that will successfully operate the breaker for 5,000-10,000 electrical
operations. The most likely source of trip coil failure is the breaker operating mechanism binding,
thereby preventing the breaker auxiliary stack from opening and keeping the trip coil energized for
too long of a time period. Therefore, trip coil failure is a function of the breaker mechanism failure.
Exercising the breakers and circuit switchers is an excellent practice. We would encourage language
that would suggest this task be done every 2 years, not to exceed 3 years. Exercising the
interrupting devices would help eliminate mechanism binding, reducing the chance that the trip coils
are energized too long. The language as currently written in Table 1-5 row 1, will also have the
unintentional effect of changing an entities existing interrupting device maintenance interval
(essentially driving interrupting device testing to a less than 6 year cycle).
b) Change the text of “Standard PRC-005-2 - Protection System Maintenance” Table 1-5 on page 19,
Row 3, Column 2 to: “12 calendar years” The maximum maintenance interval for “Electromechanical
lockout and/or tripping devices which are directly in a trip path from the protective relay to the
interrupting device trip coil” should be consistent with the “Unmonitored control circuit” interval
which is 12 calendar years.In order to test the lockout relays, it may be necessary to take a bus
outage (due to lack of redundancy and associated stability issues with delayed clearing). Increasing
the frequency of bus outages (with associated lines or transformers) will also increase the amount of
time that the BES is in a less intact system configuration. Increasing the time the BES is in a less
intact system configuration also increases the probability of a low frequency, high impact event
occurring. Therefore, the Maximum Maintenance Interval should be 12 years for lockout relays.
c) ATC's remaining concern for PRC-005-2 is with definition and timelines established in Table 1-5.
ATC is recommending a negative ballot since, as written, the testing of “each” trip coil and the
proposed maintenance interval for lockout testing will result in the increased amount of time that
the BES is in a less intact system configuration. ATC hopes that the SDT will consider these changes.
162
Response: Thank you for your comments.
a) While the SDT agrees with much of your observation about circuit breaker operations, this standard applies to Protection
System maintenance and per the Protection System definition does not include the entire circuit breaker. As such we are
limited to exercising the trip coils and seeing that they have the intended effect on the interrupting device. A simple cycling
of the breaker should have minimal impact on the scheduling of the entities breaker maintenance program.
b) The SDT believes that electromechanical lockout relays need periodic operation. As such, these devices are required to be
exercised at the same 6 year interval required for electromechanical relays. The SDT recognizes the risk of human error trips
when working with testing of lockout devices but believes these risks can be managed. Performance-based maintenance is
an option if you want to extend your intervals beyond 6 years. The SDT, however, has modified Table 1-5 to remove other
auxiliary relays, etc, from this activity, and clarified that the verification of such devices is included within the 12-year
unmonitored control circuitry verification.
c) As noted above, the SDT has modified Table 1-5 to remove other auxiliary relays, etc, from the 6-year activity, and clarified
that the verification of such devices is included within the 12-year unmonitored control circuitry verification. However, the
SDT believes that the other activities addressed in your comment need to be performed as reflected in Table 1-5.
Southern
Company
Transmission
Table 1-5: Need clarification on "continuity and energization or ability to operate". What does this
mean?
Response: Thank you for comment.
This entry in Table 1-5 has been modified to “Control circuitry whose integrity is monitored and alarmed”. Section 15.3 of the
Supplementary Reference and FAQ document provides additional discussion on this topic.
Utility Services,
Inc
Thank you for the opportunity to address the new documentation and for your efforts.
Response: Thank you for comment.
163
ITC Holdings
ITC Holdings continues to object to the requirement to exercise auxiliary relays on a 6 year interval.
We repeat our previous comments as follows: “It has been our experience that trip failures are rare
and that our present 10 year control, trip tests, and other related testing are sufficient in verifying
the integrity of the scheme. Section 8.3 of the Supplementary Reference notes statistical surveys
were done to determine the maintenance intervals. Were auxiliary relays included in these surveys
in such a way to verify that they indeed require a 6 year maintenance interval? We recommend they
be considered part of the control circuitry, with a 12 year test cycle.” Previous responses from the
SDT were: “The SDT believes that the appropriate interval for electromechanical devices such as aux
or lockout relays should remain at 6 years, as these devices contain “moving parts” which must be
periodically exercised to remain reliable.“ ITC requests that the statistical basis for the 6 year interval
be published. If it is not clear that lockout relays and other auxiliary relays must be exercised on a 6
year interval, then the requirement should be changed to 12 years.
Response: Thank you for your comments.
The SDT believes that electromechanical lockout relays need periodic operation. As such, these devices are required to be
exercised at the same 6 year interval required for electromechanical relays. The SDT recognizes the risk of human error trips when
working with testing of lockout devices but believes these risks can be managed. Performance-based maintenance is an option if
you want to extend your intervals beyond 6 years. The SDT has modified Table 1-5 to remove other auxiliary relays, etc, from this
activity, and clarified that the verification of such devices is included within the 12-year unmonitored control circuitry verification
as you have suggested.
Ingleside
Cogeneration
LP
Ingleside Cogeneration, LP, continues to believe that the six year requirement to verify channel
performance on associated communications equipment will prove to be more detrimental than
beneficial on older relays. Clearly newer technology relays which provide read-outs of signal level or
data-error rates will easily verified, but the tools which measure power levels and error rates on nonmonitored communication links are far more intrusive. After the technician uncouples and reattaches a fiber optic connection, the communications channel may be left in worse shape after
verification than it was prior to the start of the test.
164
Response: Thank you for your comments.
There are less intrusive ways to verify channel performance that do not require disconnecting communication terminations. It is
up to the entity to determine specific maintenance techniques.
CenterPoint
Energy
For the “Unmonitored control circuitry associated with protective functions”, the Table 1-5
requirement is to “Verify all paths of the trip circuits through the trip coil(s) of the circuit breakers or
other interrupting devices” every 12 calendar years. CenterPoint Energy recommends this
requirement be revised to “No periodic maintenance specified”. CenterPoint Energy believes that
verifying all tripping paths is a commissioning task, not a preventive maintenance task. CenterPoint
Energy performs such checks on new stations and whenever expansion or modification of existing
stations dictates such testing. This type of testing can negatively impact BES system reliability with
the outages that are required and by exposing the electric system to incorrect tripping. Likewise,
CenterPoint Energy recommends the requirement in Table 1-5 to “Verify all paths of the control
circuits essential for proper operation of the SPS” every 12 years be revised to “No periodic
maintenance specified”.
Response: Thank you for your comments.
The SDT believes that it is possible to manage the risks that you describe and that performance of these trip path verifications will
be an overall benefit to the reliability of the BES.
Oncor Electric
Delivery
Company LLC
PRC-005-2 is a vast improvement over the vagueness of the existing standard (PRC-005-1), that the
new standard makes compliance much easier than the present standard. The new standard
recognizes the advances in relay technology and reliability, particularly the benefits of
microprocessor based relays. The standard also provides greater flexibility on its implementation
while recognizing the benefits of a performance based methodology, particularly as it relates to
battery testing. The revised standard eliminates the requirement for a “summary of maintenance
and testing procedures” which was vague and provided no real value to the registered entities.
Operational and administrative efficiencies can be realized by consolidating the relay testing and
maintenance requirements into one standard (PRC-005-1, PRC-008-0, PRC-011-0, PRC-017-0).
Response: Thank you for your comments.
165
City of Austin
dba Austin
Energy
If a Registered Entity has a PSMP that is more stringent than the intervals in PRC-005-2, the
Registered Entity should not be considered out of compliance if it fails to meet its internal interval
but remains within the interval set forth in PRC-005-2.
Response: Thank you for your comments. The standard and the Supplementary Reference and FAQ document have been changed
to address your concerns. Specifically, Requirement R1 part 1.3 has been removed; Requirement R3 has been revised so that, for
time-based programs, entities shall comply with the tables; Requirement R4 has been added to address performance-based
maintenance, and Requirement R5 has been added to address Unresolved Maintenance Issues.
BGE
When the term “Maintenance Correctable Issue” was revised to “Unresolved Maintenance Issue”, it
appears that the PRC-005-2 Protection System Maintenance / Supplementary Reference and FAQ
document was not properly updated to reflect this change. There are inconsistencies throughout the
entire document were the old term is still showing up instead of the new term, and vice versa.
Response: Thank you for your comments.
The SDT has attempted to correct the terminology inconsistencies you have mentioned between the Standard and the
Supplementary Reference and FAQ document.
VRFs/VSLs
Xcel Energy,
Inc.
Negative
Ballot
The VSL for R3 is confusing because of the lack of a specified time horizon. Are the percentages
quoted on an annual schedule basis, an audit period, or a continuous percentage measurement of
any previously scheduled maintenance activities? Greater clarity is needed on the intent of this VSL.
Response: Thank you for your comment.
The VSLs that use a graduated VSL have been revised based, in part, on the comments you have provided. The percentages relate
to the number of violations reported within the compliance monitoring period relative to the number of components within that
component type.
166
Ameren
Services
Negative
Poll
The VRF for R3 should be Low. Many entities presently do not perform some of the specified
maintenance activities on some of their components. The risk to the BES is quite low as proven by
the extremely reliable BES performance. We are not aware of such omissions in Protection System
performance leading to widespread outages, cascading or uncontrolled separation. This coupled
with NERC's insistence on 100% perfect completion of all maintenance for even the Lower VSL leads
to an inappropriate and unjustified VRF/VSL combination.
Response: The VRF value of “high” stems from consideration of an entity not performing any maintenance and testing of their
Protection System. Specifically, a “high” VRF, for a planning time horizon requirement, addresses violations of requirements that
could directly cause or contribute to BES instability, separation, or cascading. While not every failure to properly perform
maintenance WILL do these things, they can very well contribute to them, as evidenced by involvement of Protection Systems in
every recent significant BES disturbance.
Flathead
Electric
Cooperative
Negative
Poll
do not believe the severe VSL should apply to distributed UFLS
Response: The VSL is a measure of the completeness of the execution of a requirement. Where a binary evaluation of compliance
with a particular requirement is prescribed, the NERC VSL guidelines require the violation level to be severe. If the compliance can
be demonstrated to be partially complete, a graduated violation severity level is allowed. The NERC Criteria for setting Violation
Severity Levels states that it is preferable to have four VSLs for each requirement.
Independent
Electricity
System
Operator
Negative
Poll
The IESO continues to disagree with the High VRF for R3 which asks for implementing the
maintenance plan (and initiate corrective measures) whose development and content requirements
(R1 and R2) themselves have a Medium VRF. Failure to develop a maintenance program with the
attributes specified in R1, and stipulation of the maintenance intervals or performance criteria as
required in R2, will render R3 not executable. Hence, we reiterate our position that the VRF for R3 be
changed to Medium.
167
Response: The VRF value of “high” stems from consideration of an entity not performing any maintenance and testing of their
Protection System. Specifically, a “high” VRF, for a planning time horizon requirement, addresses violations of requirements that
could directly cause or contribute to BES instability, separation, or cascading. While not every failure to properly perform
maintenance WILL do these things, they can very well contribute to them, as evidenced by involvement of Protection Systems in
every recent significant BES disturbance.
Liberty Electric
Power LLC
Negative
Poll
The percentage structure on unresolved maintenance issues presents problems. Smaller entities are
unlikely to ever have more than a handful of unresolved issues, meaning a single failure to initiate
would automatically be a High VSL. There would also be a disincentive to close out issues from fear
that "resolving" them could potentially increase a violation level on a discovered issue.
Response: The VSLs relating to Unresolved Maintenance Issues have been revised to graduated VSLs using a count of violations,
rather than a percentage.
Xcel Energy,
Inc.
Negative
Poll
The VSL for R3 is confusing because of the lack of a specified time horizon. Are the percentages
quoted on an annual schedule basis, an audit period, or a continuous percentage measurement of
any previously scheduled maintenance activities? Greater clarity is needed on the intent of this VSL.
Response: Thank you for your comment.
The VSLs that use a graduated VSL have been revised based, in part, on the comments you have provided. The percentages relate
to the number of violations reported within the compliance monitoring period relative to the number of components within that
component type.
END OF REPORT
168
Consideration of Comments
Project 2007-17
Protection System Maintenance and Testing
The Project 2007-17 Protection System Maintenance and Testing Standard Drafting Team thanks all
commenters who submitted comments on PRC-005-2. These documents were posted for a 30-day
public comment period from February 28, 2012 through March 28, 2012. Stakeholders were asked to
provide feedback on the standard and associated documents through a special electronic comment
form. There were 56 sets of comments, including comments from approximately 118 different people
from approximately 98 companies representing 9 of the 10 Industry Segments, as shown in the table
on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to
give every comment serious consideration in this process! If you feel there has been an error or
omission, you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-4462560 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process. 1
Summary Consideration of all Comments Received:
Definitions:
The SDT revised the “Inspect” element of the definition of Protection System Maintenance Program
(PSMP) to: “Examine for signs of component failure, reduced performance or degradation.”
The definition of the term ‘Unresolved Maintenance Issue’ has been enhanced for additional clarity.
The definition now reads: “A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance
interval, and requires follow-up corrective action.”
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
1
The definition of Countable Event was modified to: “A failure of a Component requiring repair or
replacement, any condition discovered during the maintenance activities in Tables 1-1 through 1-5 and
Table 3 which requires corrective action, or a Misoperation attributed to hardware failure or calibration
failure. Misoperations due to product design errors, software errors, relay settings different from
specified settings, Protection System Component configuration errors, or Protection System application
errors are not included in Countable Events.” This change was acknowledged in Attachment A.
Applicability:
The SDT revised Applicability Clause 4.2.5.4 to: “Protection Systems for station service or excitation
transformers connected to the generator bus of generators which are part of the BES, that act to trip
the generator either directly or via lockout or tripping auxiliary relays.”
Requirements:
A minor editorial change was made to Requirement R1 to remove the nested parentheticals.
Tables
In Table 1-2, the interval for the second portion of the first row of the table was changed from six years
to 12 years, and extensive changes were made to the last row of the table.
Several activities within Table 1-4a, Table 1-4b, Table 1-4c, Table 1-4d, and Table 1-4f, relating to
verification that the station battery can perform properly, were modified with the assistance of
representatives of the IEEE Stationary Battery Committee.
Measures
Measure M5 has been revised to include: “…project schedules with completed milestones …”
VSLs
In the High VSL for R1, “entities’” was corrected to “entity’s”.
The VSLs for Requirement R2 were modified from “reduce Countable Events to less than 4%” to “reduce
Countable Events to no more than 4%”.
Supplementary Reference Document
Complementary changes were made to the Supplementary Reference Document corresponding to all
changes to the standard.
Unresolved Minority Views:
•
A few commenters continued to object to the establishment of maximum allowable intervals for
the maintenance of various Protection System component types. The SDT continued to respond
that FERC Order 693 and the approved SAR direct the SDT to develop a standard with maximum
allowable intervals comments and minimum maintenance activities. The SDT believes that the
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
2
intervals established within the tables are appropriate as continent-wide maximum allowable
intervals.
•
Several commenters were concerned that an entity has to be “perfect” in order to be compliant;
the SDT responded that NERC standards currently allow no provision for any degree of nonperformance relative to the requirements.
•
Several commenters continued to question NERC’s propriety of including distribution system
Protection Systems, almost all related to UFLS/UVLS. The SDT obtained a position from NERC legal
staff, and cited this position in responding that these devices are, indeed, within NERC’s authority
because they are installed for the reliability of the BES.
•
A few commenters questioned the inclusion of the dc control circuitry for sudden pressure relays,
even though the relays themselves are excluded from the definition of “Protection System;” the
SDT reiterated its position that this dc control circuitry is included because the dc control circuitry is
associated with protective functions.
•
A few commenters objected to the language in the Data Retention section regarding the retention
of the maintenance records for two full intervals. The SDT explained that this expectation is
consistent with the Compliance Monitoring and Enforcement Program.
•
Several commenters suggested removal of Requirement R5, and others expressed concerns
regarding Requirement R5 and Unresolved Maintenance Issues. The SDT explained its rationale for
the requirement as drafted; and made a minor change to Unresolved Maintenance Issues, as
detailed above.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
3
Index to Questions, Comments, and Responses
1. In response to comments, the PSMTSDT revised Requirement R1 to state that an entity’s Protection
System Maintenance Program (PSMP) shall include, for each Protection System component type,
an identification of the maintenance method(s) used, and the identification of the relevant
monitoring attributes applied. Do you agree with this change? If you do not agree, please provide
specific suggestions for improvement. ............................................................................................... 13
2. As a result of the changes to Requirement R1, the previous Requirement R3 was separated into
three requirements:
a. Requirement R3 now requires that an entity utilizing a time-based program maintain its
Protection System components in accordance with the maximum maintenance intervals listed
in the Tables. This change removes the compliance jeopardy associated with an entity having
more stringent intervals (in its PSMP) than those listed in the Tables
b. Requirement R4 (new) requires an entity utilizing a performance-based program maintain its
Protection System components in accordance with its performance based Protection System
Maintenance Program
c. Requirement R5 (new) requires an entity to demonstrate efforts to correct identified
unresolved maintenance issues. The previous language in Requirement R3 directed that an
entity initiate resolution
Do you agree with this change? If you do not agree, please provide specific suggestions for
improvement. ...................................................................................................................................... 26
3. The Supplemental Reference and FAQ document was revised to reflect changes made to the draft
standard and to address additional issues raised. Do you agree with the changes? If you do not
agree, please provide specific suggestions for improvement............................................................. 49
4. If you have any other comments on this Standard that you have not already provided in response
to the prior questions, please provide them here. ............................................................................. 64
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Guy Zito
2
3
4
5
6
7
8
Northeast Power Coordinating Council
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2.
Greg Campoli
New York Independent System Operator
NPCC
2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
4.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc.
NPCC
1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
6.
Mike Garton
Dominion Resources Services, Inc.
NPCC
5
7.
Kathleen Goodman
ISO - New England
NPCC
2
8.
Chantel Haswell
FPL Group, Inc.
NPCC
5
9.
David Kiguel
hydro One Networks Inc.
NPCC
1
10. Michael R. Lombardi
Northeast Utilities
NPCC
1
11. Randy MacDonald
New Brunswick Power Transmission
NPCC
9
12. Bruce Metruck
New York Power Authority
NPCC
6
13. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
9
10
X
5
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
14. Robert Pellegrini
The United Illuminating Company
NPCC
1
15. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
16. David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
17. Brian Robinson
Utility Services
NPCC
8
18. Saurabh Saksena
National Grid
NPCC
1
19. Michael Schiavone
National Grid
NPCC
1
20. Wayne Sipperly
New York Power Authority
NPCC
5
21. Tina Teng
Independent Electricity System Operator
NPCC
2
22. Donald Weaver
New Brunswick System Operator
NPCC
2
23. Ben Wu
Orange and Rockland Utilities
NPCC
1
24. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
2. Group
Jim Eckelkamp
No additional members listed.
3. Group
3
4
5
6
7
8
Progress Energy
Kent Kujala
DTE Energy
1. Steven Kerkmaz
RFC
3, 4, 5
2. David Szulczewski
RFC
3, 4, 5
4. Group
2
WILL SMITH
1.
MAHMOOD SAFI
OPPD
MRO 1, 3, 5, 6
2.
CHUCK LAWRENCE
ATC
MRO 1
3.
TOM WEBB
WPS
MRO 3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO 1, 6
5.
KEN GOLDSMITH
ALTW
MRO 4
6.
ALICE IRELAND
XCEL(NSP)
MRO 1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO 1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO 1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO 3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO 4
11. TERRY HARBOUR
MEC
MRO 3, 5, 6, 1
12. MARIE KNOX
MISO
MRO 2
MRO NSRF
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
X
X
X
X
X
X
X
6
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
13. LEE KITTELSON
OTP
MRO 1, 3, 4, 5
14. SCOTT BOS
MPW
MRO 1, 3, 5, 6
15. TONY EDDLEMAN
NPPD
MRO 1, 3, 5
16. MIKE BRYTOWSKI
GRE
MRO 1, 3, 5, 6
17. THERESA ALLARD
MPC
MRO 1, 3, 5, 6
5. Group
Kieth Morisette
No additional members listed.
6. Group
IID WECC
1, 3, 4, 5, 6
2. Epi Martinez
IID WECC
1, 3, 4, 5, 6
3. Nando Gutierrez
IID WECC
1, 3, 4, 5, 6
7. Group
Imperial Irrigation District (IID)
Louis Slade
NERC Compliance Policy
RFC
5, 6
2. Michael Crowley
Electric Transmission
SERC
1, 3
3. Sean Iseminger
Fossil & Hydro
SERC
5
4. Chip Humphrey
Fossil & Hydro
MRO
5
5. Jeff Bailey
Nuclear
6. Connie Lowe
NERC Compliance Policy
SERC
5, 6
7. Mike Garton
NERC Compliance Policy
NPCC
5, 6
Don Jones
Texas RE
ERCOT
10
2. David Penney
Texas RE
ERCOT
10
Group
5
6
7
8
9
10
X
X
X
X
X
X
X
5
1. Curtis Crews
9.
4
Dominion
1. Michael Gildea
8. Group
3
Tacoma Public Utilities
Jesus Sammy Alcaraz
1. Jose Landeros
2
Texas Reliability Entity
Southwest Power Pool Standards
Development Team
Jonathan Hayes
1. John Allen
City Utilities of Springfield
SPP 1, 4
2. Greg Froehling
Rayburn Electric
SPP
3. Louis Guidry
CLECO
SPP 1, 3, 5
4. Jonathan Hayes
Southwest Power Pool
SPP 2
5. Robert Rhodes
Southwest Power Pool
SPP 2
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
X
X
X
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6. Robert Hirchak
CLECO
SPP 1, 3, 5
7. Brandon Nugent
CLECO
SPP 1, 3, 5
8. Valerie Pinamonti
AEP
SPP 1, 3, 5
9. Mahmood Safi
OPPD
SPP 1, 3, 5
10 Group
Dave Davidson
Rusty Hardison
Transmission O&M
SERC
NA
2.
Pat Caldwell
Transmission O&M - Relay
SERC
NA
3.
Paul Barnett
Transmission O&M - Substation
SERC
NA
4.
Jerry Finley
Power Control Systems
SERC
NA
5.
Frank Cuzzort
Nuclear Engineering
SERC
NA
6.
Robert Brown
Nuclear Engineering
SERC
NA
7.
Robert Mares
Hydro Engineering
SERC
NA
8.
Annette Dudley
Hydro O&M
SERC
NA
9.
John Henry Sullivan
Fossil Engineering
SERC
NA
Compliance
SERC
NA
11 Group
Sam Ciccone
1. Jim Kinney
FE RFC 1
2. Brian Orians
FE RFC 5
3. Rusty Loy
FE RFC 5
4. Shawn Gehring
FE RFC 1
5. Doug Hohlbaugh
FE RFC 1, 3, 4, 5, 6
6. Bill Duge
FE RFC 5
7. Chris Lassak
FE RFC 5
8. Mike Ferncez
FE RFC 1
9. Tim Sheerer
FE RFC 1
12 Group
Ron Sporseen
3
4
5
6
7
8
Tennessee Valley Authority
1.
10. David Thompson
2
FirstEnergy
PNGC Comment Group
1.
Joe Jarvis
Blachly-Lane Electric Cooperative
WECC
3
2.
Dave Markham
Central Electric Cooperative
WECC
3
3.
Dave Hagen
Clearwater Power Cooperative
WECC
3
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
X
X
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4.
Roman Gillen
Consumer's Power Inc.
WECC
1, 3
5.
Roger Meader
Coos-Curry Electric Cooperative
WECC
3
6.
Dave Sabala
Douglas Electric Cooperative
WECC
3
7.
Bryan Case
Fall River Electric Cooperative
WECC
3
8.
Rick Crinklaw
Lane Electric Cooperative
WECC
3
9.
Ray Ellis
Lincoln Electric Cooperative
WECC
3
10. Annie Terracciano
Northern Lights Inc.
WECC
3
11. Aleka Scott
PNGC Power
WECC
4, 8
12. Heber Carpenter
Raft River Electric Cooperative
WECC
3
13. Steve Eldrige
Umatilla Electric Cooperative
WECC
1, 3
14. Marc Farmer
West Oregon Electric Cooperative
WECC
3
13 Group
Western Area Power Administration
14 Group
Nebraska Public Power District
Brandy A. Dunn
No additional members listed.
Cole Brodine
No additional members listed.
15 Group
Frank Gaffney
City of New Smyrna Beach
FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services
FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority
FRCC
4
7. Randy Hahn
Ocala Utility Services
FRCC
3
David Thorne
1. Carlton Bradshaw
17 Group
Delmarva Power & Light
Chris Higgins
1. Dean
Bender
WECC
1
2. Heather
Laslo
WECC
1
3. Brenda
Vasbinder WECC
1
3
Florida Municipal Power Agency
1. Timothy Beyrle
16 Group
2
4
5
6
7
8
X
Pepco Holdings Inc. & Affiliates
X
Bonneville Power Administration
X
X
RFC 1, 3
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
9
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Greg
Vassallo
WECC
1
5. Mason
Bibles
WECC
1
6. Jenifur
Rancourt
WECC
1, 3, 5, 6
7. Rebecca
Berdahl
WECC
3
8. Jason
Burt
WECC
1
18 Group
Sandra ShFaffer
No additional members listed.
19 Group
PPL Supply NERC Registered Organizations
1. Leland McMillan PPL Montana, LLC
WECC
5
2. Donald Lock
RFC
5
20 Group
WILL SMITH
1.
MAHMOOD SAFI
OPPD
MRO 1, 3, 5, 6
2.
CHUCK LAWRENCE
ATC
MRO 1
3.
TOM WEBB
WPS
MRO 3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO 1, 6
5.
KEN GOLDSMITH
ALTW
MRO 4
6.
ALICE IRELAND
XCEL(NSP)
MRO 1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO 1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO 1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO 3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO 4
11. TERRY HARBOUR
MEC
MRO 3, 5, 6, 1
12. MARIE KNOX
MISO
MRO 2
13. LEE KITTELSON
OTP
MRO 1, 3, 4, 5
14. SCOTT BOS
MPW
MRO 1, 3, 5, 6
15. TONY EDDLEMAN
NPPD
MRO 1, 3, 5
16. MIKE BRYTOWSKI
GRE
MRO 1, 3, 5, 6
17. THERESA ALLARD
MPC
MRO 1, 3, 5, 6
21 Group
Jason Marshall
3
4
5
6
7
PacifiCorp
Annette M. Bannon
PPL Generation, LLC
2
X
MRO NSRF
X
ACES Power Marketing Standards
X
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
X
X
X
10
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
Collaborators
1. Shari Heino
Brazos Electric Power Cooperative, Inc.
SERC
1
2. Mohan Sachdeva
Buckeye Power, Inc.
RFC
3, 4
3. Erin Woods
East Kentucky Power Cooperative
SERC
1, 3, 5
4. Scott Brame
North Carolina Electric Membership Corporation
RFC
1, 3, 4, 5
5. Mark Ringhausen
Old Dominion Electric Cooperative
SERC
3, 4
6. Lindsay Shepard
Sunflower Electric Power Corporation
SPP
1
7. Clem Cassmeyer
Western Farmers Electric Cooperative
ERCOT
1, 5
22 Group
Janet Smith
No additional members listed.
Arizona Public Service Company
23 Group
Antonio Grayson
No additional members listed.
24 Group
Todd Moore
1. Tim Hinken Kansas City Power & Light
Southern Company Generation
Kansas City Power & Light
X
X
X
X
X
SPP 1, 3, 5, 6
25 Individual
Brenda Frazer
Edison Mission Marketing & Trading
26 Individual
Richard Tressler
Alber Corporation
27 Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
28 Individual
Michael Falvo
Independent Electricity System Operator
29 Individual
Joe Tarantino
Sacramento Municipal Utility District
30 Individual
Michelle R D'Antuono
Ingleside Cogeneration LP
X
31 Individual
Daniel Duff
Liberty Electric Power LLC
X
32 Individual
Joe O'Brien
NIPSCO
33 Individual
Cristina Papuc
TransAlta Centralia Generation LLC
34 Individual
Edward Davis
Entergy Services
X
35 Individual
Glen Sutton
ATCO Electric Ltd
X
36 Individual
Thad Ness
American Electric Power
37 Individual
Joe Petaski
Manitoba Hydro
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
38 Individual
Bo Jones
Westar Energy
X
X
X
X
39 Individual
Kirit Shah
Steve Alexanderson
P.E.
Ameren
X
X
X
X
41 Individual
Chris Searles
BAE Batteries USA
42 Individual
Andrew Gallo
City of Austin dba Austin Energy
43 Individual
Chris Searles
BAE Batteries USA
44 Individual
Martin Bauer
US Bureau of Reclamation
45 Individual
Brian J. Murphy
NextEra Energy, Inc.
46 Individual
Patrick Brown
Essential Power, LLC
47 Individual
Andrew Z. Pusztai
American Transmission Company, LLC
X
48 Individual
Brad Harris
CenterPoint Energy
X
49 Individual
Anthony Jablonski
ReliabitliyFirst
50 Individual
Keira Kazmerski
Xcel Energy
X
X
X
X
51 Individual
Greg Rowland
Duke Energy
X
X
X
X
52 Individual
Martin Kaufman
ExxonMobil Research and Engineering
X
53 Individual
Laurie Williams
X
X
X
X
X
X
X
X
X
X
40
Individual
Central Lincoln
Mauricio Guardado
PNM Resources
Los Angeles Department of Water and
Power
55 Individual
Wayne E. Johnson
EPRI
56 Individual
Maggy Powell
Constellation/Exelon
54
Individual
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
X
X
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
12
1.
In response to comments, the PSMTSDT revised Requirement R1 to state that an entity’s Protection System Maintenance
Program (PSMP) shall include, for each Protection System component type, an identification of the maintenance method(s)
used, and the identification of the relevant monitoring attributes applied. Do you agree with this change? If you do not agree,
please provide specific suggestions for improvement.
Summary Consideration: Many commenters were in agreement with this change.
Comments were offered that the definition of PSMP is incongruous with its use in Requirement R1; the SDT disagreed, and noted
that the definition of a PSMP is linked to Requirement R1 in that the entity’s program shall include one or all of the parameters in the
definition. Requirement R1 requires that the entity establish their program, and is the foundation for the standard.
Other comments questioned why Requirement R1 includes the applicable level of monitoring for a Component when this is also
listed in the Component attributes within the tables; the SDT explained that the discussion in Requirement R1 is to assure that the
monitoring is present to support the intervals and activities used.
The SDT responded to concerns regarding the use, within Requirement R1, of “Component Type” by noting that this term allows
entities latitude in how they define their PSMP.
Other commenters noted that Requirement R1 does not require that entities maintain their Components; and is, therefore,
administrative and should have a lower VRF. The SDT responded that Requirement R1 is the foundation of the standard; and,
therefore, the VRF is appropriate.
The SDT accepted a suggestion to remove the imbedded parenthetical within Requirement R1.
Several comments were submitted that were unrelated to this question.
Organization
Yes or No
Pacific Gas and Electric Company
Negative
Question 1 Comment
PG&E thanks the drafting team for their efforts. PG&E agrees with overall changes to
the standard and sees the current draft as an improvement over the prior draft, on
which PG&E voted affirmative. PG&E however will vote negative on the current ballot
due to recent experience and trouble with trying to implement the intercell
connection resistance test for NiCad batteries as specified in Table 1-4c of PRC-005-2.
PG&E has experienced trouble trying to implement the "Battery intercell or unit-tounit connection resistance" maintenance activity for certain NiCad battery types. In
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
13
Organization
Yes or No
Question 1 Comment
these cases the battery post was not exposed and was entirely covered by the
intercell strap. The battery post protruded minimally from the battery and could not
be accessed with a probe. PG&E requests clarification on this requirement and that
provision be provided to accommodate existing battery systems without requiring
modification to the battery system. Modification of the battery system to access the
battery post places a hardship on the battery owner, may compromise the battery
design, and ultimately may require replacing the battery to allow fulfilling the
maintenance requirement. One solution may be to allow measuring intercell
connection resistance from the battery post bolt when the battery post is not
accessible. While this is not the optimal approach, it may still be effective since the
presence of corrosion would likely show up between both the battery post and bolt
and also between the bolt and intercell strap. Trending the resistance from bolt-tobolt may still be effective in determining an increasing resistance from post-to-post.
PG&E suggests the following language: Table 1-4c Verify - Battery intercell or unit-tounit connection resistance where battery post is accessible. Where battery post is not
accessible measure intercell or unit-to-unit connection resistance from bolt-to-bolt or
nearest connection to the battery post.
Response: Thank you for your comment. The SDT believes that the Maintenance Activities in Table 1-4c are explicit as to the required
activity and are necessary to ensure the integrity of the station battery. The SDT believes the activity you discuss is not an effective
method to satisfy the intent of the requirement in Table 1-4c; and the team suggests that you consult the manufacturer of your
battery system to investigate how to meet the requirement.
Seminole Electric Cooperative,
Negative
Seminole recommends the SDT re-consider an interval of 12 calendar years for the
Inc.
component in row 2, of Table 1-5. The maximum maintenance interval for
"Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil" should be consistent with the
"Unmonitored control circuit" interval which is 12 calendar years. In order to test the
lockout relays, it may be necessary to take a bus outage (due to lack of redundancy
and associated stability issues with delayed clearing). Increasing the frequency of bus
outages (with associated lines or transformers) will also increase the amount of time
that the BES is in a less stable system configuration. Increasing the time the BES is in
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
14
Organization
Yes or No
Question 1 Comment
a less stable system configuration also increases the probability of a low frequency,
high impact event occurring. We believe that, as written, the testing of "each" trip
coil and the proposed maintenance interval for lockout testing will result in the
increased amount of time that the BES is in a less intact system configuration.
Therefore, the Maximum Maintenance Interval should be 12 years for lockout relays.
It appears that the SDT is trying to address a specific type of lockout relay with the 6
year interval that consists of a longer operating rod lockout that is subject to binding
when called upon to operate. Why is it necessary to include all lockout relays when
only a very specific segment of all lockout relays is subject to this one problem?
Maybe a unique category of these specific types of lockouts, subject to operating rod
binding should be specified at 6 years, with other lockouts not subject to this
problem using a common interval like other protective components of 12 years. We
sincerely hope that the SDT will consider these positive changes.
Response: Thank you for your comment. The SDT believes that electromechanical lock-out relays (86) (used to convey the tripping
current to the trip coils), regardless of the manufacturer, need to be electrically operated to prove the capability of the device to
change state. The application of lockouts is typically associated with equipment limited having remote backup protection
(Generators/Transformers) or higher system consequences if remote backup is called upon to operate (Buses/Breakers). A failure of a
lockout to function results in decreased stability and has a higher outage impact. These tests need to be accomplished at least every six
years, unless PBM methodology is applied.
The contacts on the 86 that change state to pass on the trip current to a breaker trip coil need only be checked every 12 years with the
control circuitry.
Tampa Electric Co.
Negative
The requirement to periodically test Control circuits will negatively
impact reliability. The possibility of lifted wires being properly relanded or test links being left open following testing will cause more
misoperations than the finding of failed devices prevents. The outages
required to do the testing will limit available transmission capability
and therefore affect markets negatively for no reliability
enhancement.
Response: Thank you for your comment. The SDT believes that periodic testing of control circuits is a vital part of assuring proper
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
15
Organization
Yes or No
Question 1 Comment
operation of a protective relay system. There are several methods of accomplishing this testing. Where portions of the circuit are
isolated for testing, procedures should be in place to assure proper restoration of the circuit.
Tennessee Valley Authority
Negative
1. Regarding the functional test required every 3 months for “unmonitored
communication systems” in Table 1-2 of the PRC-005-2 Draft. TVA feels that a
Maximum Maintenance Interval for the Functional Test should be every 12 months
until auto-checkback has been fully implemented by the utility.
2. The Implementation Plan for PRC-005-2 Step 4 on Page 2 states: “The
Implementation Schedule set forth in this document requires that entities develop
their revised Protection System Maintenance Program within twelve (12) months
following applicable regulatory approvals, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twentyfour (24) months following NERC Board of Trustees adoption. This anticipates that it
will take approximately twelve (12) months to achieve regulatory approvals following
adoption by the NERC Board of Trustees.” TVA feels that this is not sufficient time to
implement full auto-checkback capability at some utilities. The time schedule of
twelve (12) months should be forty-eight (48) months following applicable regulatory
approvals
Response: Thank you for your comments.
1) The SDT believes the four-month interval is proper for unmonitored communications systems. The activity related to this interval is
to verify basic operating status.
2) The Implementation Plan is intended to facilitate implementation of the standard, not to facilitate modifications to meet the
requirements of the standard.
U.S. Bureau of Reclamation
Negative
1. The definition for PSMP is incongruous with the use of the PSMP in
Requirement R1. Requirement R1, including the Measure and VSL focus on the
identification of maintenance method of the Component types and not that the
PSMP is in fact being used for maintenance of the component.
2. The requirement R5 indicates the entity has to "demonstrate" efforts to correct
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
16
Organization
Yes or No
Question 1 Comment
identified unresolved maintenance issues. The measure M5 described
documentation of the efforts. The requirement language should be explicit.
Does the standard want a demonstration which implies active role of the entity
to prove what it is doing, or to provide documentation of the activities
underway to correct deficiencies? The language in the requirement should be
altered to "Each Transmission Owner, Generator Owner, and Distribution
Provider shall prepare a CAP for each identified Unresolved Maintenance
Issue." A second requirement is needed to require that "Each Transmission
Owner, Generator Owner, and Distribution Provider shall complete its CAP to
correct the identified Unresolved Maintenance Issues." The measures would
need to be adjusted accordingly to reflect the CAP and evidence that the entity
completed the CAP.
3. Re Terms defined for use only within PRC-005-2: The standard provides
definitions which will not be incorporated into the Glossary of Terms. This
would allow the definitions as used in this standard to conflict with the
definition used in other standards if this practice becomes more widespread
and would reduce the cohesiveness of the standard set.
4. Re The definition of Components: The standard defined what constitutes a
control circuit as a component type with "Control circuitry associated with
protective functions through the trip coil(s) of the circuit breakers or other
interrupting devices." The standard then modified the definition by allowing "a
control circuit Component is dependent upon how an entity performs and
tracks the testing of the control circuitry." The definition should not be
dependent upon practice. This makes the definition a fill in the blank definition.
Either eliminate the allowance or remove the definition of control circuit.
Response: Thank you for your comments.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
17
Organization
Yes or No
Question 1 Comment
1. The SDT believes that the definition of a PSMP is linked to Requirement R1 in that the entity’s program shall include one or all of
the parameters in the definition. Requirement R1 requires that the entity establish their program, and is the foundation for the
standard. Requirements R3-R4 address implementation of the entity’s PSMP.
2. Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope of this
standard. There can be any number of supply, process and management problems that make setting repair deadlines impossible.
The SDT specifically chose the phrase, “demonstrate efforts to correct” (with guidance from NERC Staff) because of the concern
that many more complex unresolved maintenance issues might require greater than the remaining maintenance interval to resolve
(and yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery during a six-month check.
In instances such as one that requires battery replacement as part of the long-term resolution, it is highly unlikely that the battery
could be replaced in time to meet the six-calendar-month requirement for this maintenance activity. The SDT does believe
corrective actions should be timely, but concludes it would be impossible to postulate all possible remediation projects; and,
therefore, impossible to specify bounding time frames for resolution of all possible unresolved maintenance issues, or what
documentation might be sufficient to provide proof that effective corrective action is being undertaken. The definition of
“Unresolved Maintenance Issue” has been modified to add a clarifying phrase that the deficiency, “…cannot be corrected during
the maintenance interval.”
3. The standard specifies that the terms used are intended for this document only; and, therefore, there should not be any conflict
with their use in any other PRC standard.
4. The intent of the different means of identifying control circuitry was to accommodate various entities’ philosophies on testing of
these circuits. Regardless of how an entity chooses to identify their control circuitry, the entity must meet the requirements of the
standard regarding maintenance of control circuitry.
DTE Energy
No
DECo does not agree. With the exception of station batteries, all components should
be tested as a scheme to assure that all components are working together as
designed, so the PSMP should not be required for each component type.
Response: Thank you for your comment. A PSMP allows for each component within a protective relay scheme to have a differing
maintenance interval allowing for unit or station outages. A company’s PSMP can perform maintenance on all the components within
a particular relay scheme, but that would require the shortest of the maintenance intervals.
PNGC Comment Group
No
Specifying “by component type” appears confusing. It seems possible that some
pieces of equipment from the same component type could end up in a different type
of maintenance program. We suggest changing to “by component or component
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 1 Comment
type” when entities determine the maintenance method in their PSMP.
Response: Thank you for your comment. The SDT believes that it is acceptable for an entity to subdivide components within a
component type, if desired. The SDT does not want to remove that latitude.
Nebraska Public Power District
No
1. Since auditors will be able to request documentation necessary to validate the
inclusion of the device within the appropriate level of monitoring, why does the
program document require listing level of monitoring and component
attributes? (Concerned about the burden of maintaining lists of components in
a program document that are alike but have different levels of monitoring. Ex:
Monitored and unmonitored microprocessor relays)
2. For identification of the relevant monitoring attributes applied can a single
specification document suffice for similar relay types such as one document for
SEL relays?
3. For trip circuit monitoring can a standard document be used for a group of
similar schemes?
Response: Thank you for your comments. See Section 6.1 of the Supplementary Reference and FAQ document for a discussion of this
topic.
1. The requirement to list component attributes is designed to support a company’s program for the maintenance intervals used.
2. The SDT concurs with using a single specification document for similar equipment.
3. The SDT concurs with a standard document for trip circuit monitoring when consistent practices are present.
Flathead Electric Cooperative, Inc.
No
1. Specifying “by component type” appears confusing. It seems possible that
some pieces of equipment from the same component type could end up in a
different type of maintenance program. We suggest changing to “by
component or component type” when entities determine the maintenance
method in their PSMP.
2. Generally, have concerns with all the new definitions except the NERC
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 1 Comment
definition of Protection System. The approach to creating new definitions of
plain language in a standard should be avoided.
Response: Thank you for your comments.
1. The SDT believes it is acceptable for an entity to subdivide components within a component type, if desired. The SDT does not
want to remove that latitude.
2. The standard specifies that the terms used are intended for this document only; and, therefore, there should not be any conflict
with their use in any other PRC standard.
American Electric Power
No
R1.1 binds you to the activities in the table, but our system is comprised of elements
(such as a Plant Control Systems), that are not included in the table. As a result, it is
not clear how an entity could develop an SPS that satisfies both the requirement and
our system.
Response: Thank you for your comment. IEEE defines a relay as: “An electric device designed to respond to input conditions in a
prescribed manner and after specified conditions are met to cause contact operation or similar abrupt change in associated electric
control circuits.” The SDT believes that protective relay functions that are embedded in control systems and/or SPSs are a part of this
standard and are, therefore, under the same requirements as dedicated, stand-alone protective relays. It is left to the entity to
determine how to align these requirements with operational concerns.
Manitoba Hydro
US Bureau of Reclamation
No
No
Please see comments provided in Question 4.
The requirement R1 states that the PSMP must identify how the component is to be
maintained, using time based or performance based or a combination. While R1
requires a PSMP, there is no measure that the PSMP is used for actually maintaining
the components, other than for documenting which maintenance method is being
used. The purpose of R1 is therefore administrative. Since there is no measure for
the use of the PSMP, why is the entity required to develop the PSMP as defined?
There is no VSL for R1 which requires that the entity establish a PSMP. Since there is
no severity level associated a PSMP that does not contain one of the required
activities it supports elimination of the definition of PSMP. PSMP definition is also
weak and does not match with the VSL that the PSMP identify the maintenance
method of the protection system component types. The definition is that PSMP
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 1 Comment
which must include: "A maintenance program for a specific component includes one
or more of the following activities: o Verify- Determine that the component is
functioning correctly. o Monitor - Observe the routine in-service operation of the
component. o Test - Apply signals to a component to observe functional
performance or output behavior, or to diagnose problems. o Inspect - Detect visible
signs of component failure, reduced performance and degradation. o CalibrateAdjust the operating threshold or measurement accuracy of a measuring element to
meet the intended performance requirement.” Since requirement 1 essentially only
requires identification of which maintenance method is to be used, there is no need
for the definition. It no longer matters how the device's functionality is determined
as long as it is performed on a time based or performance based method. This
approach may be lowering the reliability level associated with the protection system
maintenance. Since the definition of PSMP is that only one of the 5 activities is
needed, is seems that one could select to "Monitor" the in-service operation of the
component on a time base and no further action is needed. So that could mean
observe that the relay has power and was not misoperating every six years and
maintenance is performed. A PSMP is as defined does not help the reliability. It
would be better require the PSMP include as a minimum all five activities defined as
well as defining the maintenance method used (time based, performance based, or a
combination). There needs to be a requirement that the PSMP needs to be
developed. Then Requirement 1 would be to implement the PSMP.
Response: Thank you for your comments. Requirement R1 requires that the entity establishes a PSMP (with the specified attributes),
and is the foundation for the standard; thus, Requirement R1 is not administrative, as without a PSMP, there is nothing on which to
base the remainder of the standard. Requirements R3-R4 address implementation of the entity’s PSMP.
ExxonMobil Research and
Engineering
No
As written, the current draft of PRC-005-2 discriminates against smaller entities that
do not have a population size of 60 for each component type. Historical records
provide an accurate account of how specific components have performed in their
installed environment. For a set population size, increasing the number of historical
data points should improve the accuracy of an entity’s calculated mean time
between failures, so, if you increase the period over which the historical data must
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
21
Organization
Yes or No
Question 1 Comment
be evaluated, you can compensate for a smaller segment population size. The SDT’s
current draft prevents smaller entities from using a larger historical data set to make
up for a smaller population size when developing a performance based protective
system maintenance and testing program. The SDT should reconsider allowing
smaller entities to use historical records that extend for period longer than a single
year in the development of a performance based program .
Response: Thank you for your comment. Small entities are permitted to aggregate their components with similar components of
other entities to meet the component populations, as long as the programs are (and remain) similar – See Section 9 of the
Supplementary Reference and FAQ document and the associated footnote to Attachment A. Decreasing the component population
below the requirements of Attachment A will result in an unsound program due to component populations that are not statistically
significant. The Supplementary Reference and FAQ document states, “Any population segment must be comprised of at least 60
individual units; if any asset owner opts for PBM but does not own 60 units to comprise a population then that asset owner may
combine data from other asset owners until the needed 60 units is aggregated.”
EPRI
No
My comments are not to the point of dividing the requirements but the guidance in
the PSMP tables are not technically valid for maintaining stationary battery cells.
Internal ohmic measurements are related to the condition of an individual cell and
not a battery bank. Also, there is not a direct correlation to ohmic measurements and
battery or cell capacity. Ohmic measurements can provide an indication of a problem
cell and point to a cell that should be tested. There also seems to be a misconception
as to the type of capacity test that should be required. There are typically two types
of tests done on batteries: service tests and performance tests. Service test are done
to determine if a battery (group of cells) can meet its duty cycle whereas, a
performance test is intended to test a battery against the manufacturers curve to
make a determination of when the battery should be replaced. A battery could
technically still meet its duty cycle but have reduced capacity. This simply means that
the sizing was done properly, maintenance is timely, and there should be a timely
replacement of the cells.
Response: Thank you for your comment. The drafting team agrees with statements by you and others concerning the true capacity
of the station battery and relating it to internal ohmic measurements. Tables 1-4a, 1-4b and 1-4c have been modified for clarity, and
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
22
Organization
Yes or No
Question 1 Comment
the Supplemental Reference and FAQ document has been modified to further elaborate on these concerns.
Public Utility District No. 1 of
Okanogan County
Affirmative OCPD would like some clarification with regards to the Power Wave concept.
Currently in Table 1.1 and Table 3 it states, “Voltage and/or current waveform
sampling three or more times per power cycle, and conversion of samples to numeric
values for measurement calculations by microprocessor electronics." OCPD feels that
it might be better stated as simply 60 Hz.
Response: Thank you for your comment. The values for waveform sampling are intended to be verified by referencing a specific
manufacturer’s specifications.
ACES Power Marketing Standards
Collaborators
Yes
Is the use of parentheticals within another set of parentheticals in Part 1.1
intentional? It is unusual to do this and a little confusing.
Response: Thank you for your comment. The SDT agrees with your suggestion, and made the following change: “Identify which
maintenance method (time-based, performance-based per PRC-005 Attachment A, or a combination) is used to address each
Protection System component type.”
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration agrees that a Compliance Authority should be alerted to
those component types which have been assigned extended maintenance intervals
because they use some form of monitoring. We also agree that it is appropriate that
the PSMP list the relevant monitoring attributes in these cases, so they can be
confirmed to be consistent with the criteria in PRC-005-2’s interval tables.
Response: Thank you for your comments.
Northeast Power Coordinating
Council
MRO NSRF
Tacoma Public Utilities
Imperial Irrigation District (IID)
Dominion
Texas Reliability Entity
Southwest Power Pool Standards
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Development Team
Tennessee Valley Authority
FirstEnergy
Western Area Power
Administration
Pepco Holdings Inc. & Affiliates
Bonneville Power Administration
PacifiCorp
PPL Supply NERC Registered
Organizations
MRO NSRF
Arizona Public Service Company
Southern Company Generation
Kansas City Power & Light
Edison Mission Marketing &
Trading
Alber Corporation
Independent Electricity System
Operator
Liberty Electric Power LLC
TransAlta Centralia Generation
LLC
Entergy Services
ATCO Electric Ltd
Westar Energy
Ameren
Central Lincoln
BAE Batteries USA
City of Austin dba Austin Energy
Yes or No
Question 1 Comment
Yes
Yes
Yes
Yes
Yes
Yes
See comments under #4.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
24
Organization
Yes or No
BAE Batteries USA
Essential Power, LLC
American Transmission Company,
LLC
CenterPoint Energy
Xcel Energy
Duke Energy
PNM Resources
Los Angeles Department of Water
and Power
Yes
Yes
Question 1 Comment
Yes
Yes
Yes
Yes
Yes
Yes
Response: Thank you for your support.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
25
2.
As a result of the changes to Requirement R1, the previous Requirement R3 was separated into three requirements:
a. Requirement R3 now requires that an entity utilizing a time-based program maintain its Protection System components in
accordance with the maximum maintenance intervals listed in the tables. This change removes the compliance jeopardy
associated with an entity having more stringent intervals (in its PSMP) than those listed in the tables.
b. Requirement R4 (new) requires an entity utilizing a performance-based program maintain its Protection System components
in accordance with its performance-based Protection System Maintenance Program.
c. Requirement R5 (new) requires an entity to demonstrate efforts to correct identified unresolved maintenance issues. The
previous language in Requirement R3 directed that an entity initiate resolution.
Do you agree with this change? If you do not agree, please provide specific suggestions for improvement.
Summary Consideration: Many commenters were in agreement with this change.
Numerous comments were offered relative to subject and definition of “Unresolved Maintenance Issues,” per Requirement R5. As a
result of these comments, the definition of this term was modified to include the phrase, “… cannot be corrected during the
maintenance interval…” For those commenters objecting to the concept of Unresolved Maintenance Issues, the SDT explained the
rationale behind the concept.
Several comments were submitted that were unrelated to this question.
Organization
Beaches Energy Services
Yes or No
Negative
Question 2 Comment
The applicability of the standard should be modified to reflect the FERC approved
interpretation PRC-005-1b Appendix 1 that basically says that applicable
Protection Systems are those that protect a BES Element AND trip a BES Element.
The interpretation states: The applicability as currently stated will sweep in
distribution protection: “4.2.1 Protection Systems that are installed for the
purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)”
Many (most) network distribution systems that have more than one source into a
distribution network will have reverse power relays to detect faults on the BES
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 2 Comment
and trip the step-down transformer to prevent feedback from the distribution to
the fault on the BES. This is not a BES reliability issue, but more of a safety issue
and distribution voltage issue. These relays would be subject to the standard as
the applicability is currently written, but, should not be and they are currently not
within the scope of PRC-005-1b Appendix 1 because the step-down transformer
(non-BES) is tripped and not a BES Element (hence, the "and" condition of the
interpretation is not met). There are many other related examples of distribution
that might be networked or have distributed generation on a distribution circuit
where such reverse power relays, or overcurrent relays with low pick-ups, are
used for safety and distribution voltage control reasons and are not there for BES
Reliability. To make matters worse, for these Reverse Power relays, it is pretty
much impossible to meet PRC-023 because the intent of the relay is to make
current flow unidirectional (e.g., only towards the distribution system) without
regard for the rating of the elements feeding the distribution network. So, if these
relays are swept in, and if they are on elements > 200 kV, then the entity would
not be able to meet PRC-023 as that standard is currently written. So, the SDT
should adopt the FERC approved interpretation.
Response: Thank you for your comment. The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the
reliability of the BES. The SDT observes that the approved Interpretation addresses the term, “transmission Protection System,” and
notes that this term is not used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically
addresses Protection Systems that are installed for the purpose of detecting Faults on BES Elements.
To address your concern, the distribution protective devices and functions cited in this comment are not “installed for the purpose of
detecting Faults on BES Elements” and would, therefore, not be subject to PRC-005-2. A relay used primarily for “safety and
distribution voltage control reasons” is clearly not “installed for the purpose of detecting Faults on BES Elements.” The reverse
power relay application described is also not “installed for the purpose of detecting Faults on BES Elements,” (the relays react to
changes in power flow direction, which may or may not be due to a Fault) but for the purpose of preventing feedback from the
distribution system to the transmission system.
Please see the PRC-005-2 Supplementary Reference and FAQ, Section 2.3, for a more detailed discussion of this issue.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
27
Organization
Fort Pierce Utilities Authority
Yes or No
Negative
Question 2 Comment
1. The applicability of the standard should be modified to reflect the FERC
approved interpretation PRC-005-1b Appendix 1 that basically says that
applicable Protection Systems are those that protect a BES Element AND trip
a BES Element. The applicability as currently stated will sweep in distribution
protection: “4.2.1 Protection Systems that are installed for the purpose of
detecting Faults on BES Elements (lines, buses, transformers, etc.).” Most
network distribution systems that have more than one source into a
distribution network will have reverse power relays to detect faults on the
BES and trip the step-down transformer to prevent feedback from the
distribution to the fault on the BES. This is not a BES reliability issue, but
more of a safety and distribution voltage issue. These relays would be
subject to the standard as the applicability is currently written, but, should
not be and they are currently not within the scope of PRC-005-1b Appendix 1
because the step-down transformer (non-BES) is tripped and not a BES
Element (hence, the "and" condition of the interpretation is not met).
2. There are many other related examples of distribution that might be
networked or have distributed generation on a distribution circuit where
such reverse power relays, or overcurrent relays with low pick-ups, are used
for safety and distribution voltage control reasons and are not there for BES
Reliability.
To make matters worse, for these Reverse Power relays, it is pretty much
impossible to meet PRC-023 because the intent of the relay is to make
current flow unidirectional (e.g., only towards the distribution system)
without regard for the rating of the elements feeding the distribution
network. So, if these relays are swept in, and if they are on elements > 200
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
28
Organization
Yes or No
Question 2 Comment
kV, then the entity would not be able to meet PRC-023 as that standard is
currently written. FPUA recommends the SDT should adopt the FERC
approved interpretation.
3. Another concern is regarding the sudden pressure relays. These had been
out of the scope in all previous draft versions of PRC-005-2 because these do
not measure electrical quantities. However, the SDT just added a
requirement to test the trip path from the sudden pressure device, arguing
that it is captured by the definition of Protection Systems. This inconsistency
does not make sense and could create “grey areas” for other devices that
can trip for low oil level or high temperature, among others. By their nature,
sudden pressure devices are far less reliable than their associated control
circuitry. I know of at least one large entity that disables sudden pressure
relays on smaller transformers to cut down on nuisance alarms. If it is
expected that non-electrically initiated devices may become part of some
maintenance standard in the future, I think it would be premature for the
SDT to address sudden pressure relays in PRC-005-2.
4. And lastly, page 77 of the Supplementary Reference has some text clarifying
the requirement for establishing a baseline test: “For all new installations of
Valve-Regulated Lead-Acid (VRLA) batteries and Vented Lead-Acid (VLA)
batteries, where trending of the cells internal ohmic measurements to a
baseline are to be used to determine the ability of the station battery to
perform as designed, the establishment of the baseline as described above
should be followed at the time of installation to insure the most accurate
trending of the cell/unit.” This guidance does not recognize the fact that
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
29
Organization
Yes or No
Question 2 Comment
some battery manufacturers recommend the baseline tests to be performed
at some point in time after the install to allow the cell chemistry to stabilize
after the initial freshening charge. The manual from a battery manufacturer
(Enersys Powersafe) states that “The initial records are those readings taken
after the battery has been in regular float service for 3 months (90 days).
These should include the battery terminal float voltage and specific gravity
reading of each cell corrected to 77F (25C), all cell voltages, the electrolyte
level, temperature of one cell on each row of each rack, and cell-to-cell and
terminal connection detail resistance readings. It is important that these
readings be retained for future comparison”. If an entity follows the
manufacturer’s recommendation, the above statements would lead an
auditor to a finding of non-compliance because internal ohmic tests were not
performed prior to placing a new battery string in service. A simple
modification to the wording would eliminate the conflict.
Response: Thank you for your comments.
1. The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES. The SDT observes
that the approved Interpretation addresses the term, “transmission Protection System,” and notes that this term is not used
within PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses Protection Systems that
are installed for the purpose of detecting Faults on BES Elements.
2. To address your concern, the distribution protective devices and functions cited in this comment are not “installed for the
purpose of detecting Faults on BES Elements” and would, therefore, not be subject to PRC-005-2. A relay used primarily for
“safety and distribution voltage control reasons” is clearly not “installed for the purpose of detecting Faults on BES Elements.”
The reverse power relay application described is also not “installed for the purpose of detecting Faults on BES Elements,” (the
relays react to changes in power flow direction, which may or may not be due to a Fault) but for the purpose of preventing
feedback from the distribution system to the transmission system.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 2 Comment
Please see the PRC-005-2 Supplementary Reference and FAQ, Section 2.3, for a more detailed discussion of this issue.
3. DC trip circuit from a sudden pressure relay output to the trip coil of the interrupting device has always been included in the
“Control circuitry” portion of a Protection System, and is discussed in Section 15.3 of the PRC-005-2 Supplementary Reference
and FAQ document. In regards to including sudden pressure relays themselves, FERC, in Order 758, recently directed NERC to
submit an informational filing providing a schedule for addressing sudden pressure relays in PRC-005. The NERC System
Protection and Control Subcommittee (SPCS) worked with NERC staff to develop the informational filing, which was filed with
FERC on April 12, 2012. Activities associated with the schedule submitted in the filing will be included in a final SAR to further
develop PRC-005. A draft SAR for a second phase of this project is posted for information only at this time.
4. The drafting team revised the Supplemental Reference and FAQ document based on your recommendations.
Imperial Irrigation District (IID)
No
IID disagree with item c. and does not believe item c increases the reliability of the
BES. The maintenance issues will be resolved internally and should not be
required as per compliance of the standard.
Response: Thank you for your comment. The practice of returning Protection System devices to good working order exists currently
as a required element of a sound maintenance program as required by the existing Protection System maintenance and testing
standard, PRC-005-1b. For reference, NERC Compliance Application Notice CAN-0043 (Posted Final 12/30/2011) directs Compliance
Enforcement Authorities (CEAs) to “…look for relay test results or field records with annotations such as “as-found” readings or
pass/fail results; if failed, then adjustments made. The maintenance record for adjustments may be requested”.
Texas Reliability Entity
No
New requirement R5 states that an entity shall “demonstrate efforts” to correct
identified Unresolved Maintenance Issues. This falls short of requiring completion
of any corrective actions for the unresolved maintenance issue. We suggest
rewording to “Each Transmission Owner, Generator Owner, and Distribution
Provider shall develop a corrective action plan and work timetable to address
identified Unresolved Maintenance Issues. The Registered Entity shall complete
resolution of Unresolved Maintenance Issues within the time frame identified in
the Entity corrective action plan.” If R5 is modified, then M5 and the VSL should
also be modified accordingly.
Response: Thank you for your comment.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
31
Organization
Yes or No
Question 2 Comment
Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope of this
standard. There can be any number of supply, process and management problems that make setting repair deadlines impossible.
The SDT specifically chose the phrase, “demonstrate efforts to correct” (with guidance from NERC Staff) because of the concern that
many more complex unresolved maintenance issues might require greater than the remaining maintenance interval to resolve (and
yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery during a six-month check. In
instances such as one that requires battery replacement as part of the long term resolution, it is highly unlikely that the battery could
be replaced in time to meet the six-calendar-month requirement for this maintenance activity. The SDT believes corrective actions
should be timely, but concludes it would be impossible to postulate all possible remediation projects; and, therefore, impossible to
specify bounding time frames for resolution of all possible unresolved maintenance issues, or what documentation might be
sufficient to provide proof that effective corrective action is being undertaken. The definition of “unresolved maintenance issue” has
been modified to add a clarifying phrase that the deficiency “cannot be corrected during the maintenance interval.”
Nebraska Public Power District
No
The FAQ attempts to clarify the intent of “demonstrate efforts to correct”,
however, there is no explanation as to why this new term is preferable to the
more concise “initiate resolution” term that was developed and agreed upon over
the last year. In the Supplementary Reference and FAQ document there is a
request for clarification and it is reprinted below. Please clarify what is meant by
“...demonstrate efforts to correct an unresolved maintenance issue...”; why not
measure the completion of the corrective action? Management of completion of
the identified unresolved maintenance issue is a complex topic that falls outside of
the scope of this standard. There can be any number of supply, process and
management problems that make setting repair deadlines impossible. The SDT
specifically chose the phrase “demonstrate efforts to correct” (with guidance from
NERC Staff) because of the concern that many more complex unresolved
maintenance issues might require greater than the remaining maintenance
interval to resolve (and yet still be a “closed-end process”). For example, a
problem might be identified on a VRLA battery during a 6 month check. In
instances such as one that requiring battery replacement as part of the long term
resolution, it is highly unlikely that the battery could be replaced in time to meet
the 6 calendar month requirement for this maintenance activity. The SDT does not
believe entities should be found in violation of a maintenance program
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
32
Organization
Yes or No
Question 2 Comment
requirement because of the inability to complete a remediation program within
the original maintenance interval. The SDT does believe corrective actions should
be timely but concludes it would be impossible to postulate all possible
remediation projects and therefore, impossible to specify bounding time frames
for resolution of all possible unresolved maintenance issues or what
documentation might be sufficient to provide proof that effective corrective
action is being undertaken. I agree with this response and specifically the last
sentence. This indicates that R5 “demonstrating efforts to correct unresolved
issues” is too open ended and subjective and cannot be applied by enforcement in
a consistent way. R5 should be removed from the standard.
Response: Thank you for your comment.
Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope of this
standard. There can be any number of supply, process and management problems that make setting repair deadlines impossible.
The SDT specifically chose the phrase, “demonstrate efforts to correct” (with guidance from NERC Staff) because of the concern that
many more complex unresolved maintenance issues might require greater than the remaining maintenance interval to resolve (and
yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery during a six-month check. In
instances such as one that requires battery replacement as part of the long term resolution, it is highly unlikely that the battery could
be replaced in time to meet the six-calendar-month requirement for this maintenance activity. The SDT believes corrective actions
should be timely, but concludes it would be impossible to postulate all possible remediation projects; and, therefore, impossible to
specify bounding time frames for resolution of all possible unresolved maintenance issues, or what documentation might be sufficient
to provide proof that effective corrective action is being undertaken. The definition of “unresolved maintenance issue” has been
modified to add a clarifying phrase that the deficiency “cannot be corrected during the maintenance interval.”
Bonneville Power Administration
No
BPA believes that R5 is not worded in such a way that it can be easily or
consistently audited.
Response: Thank you for your comment.
Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope of this
standard. There can be any number of supply, process and management problems that make setting repair deadlines impossible.
The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of the concern that
many more complex unresolved maintenance issues might require greater than the remaining maintenance interval to resolve (and
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
33
Organization
Yes or No
Question 2 Comment
yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery during a six-month check. In
instances such as one that requires battery replacement as part of the long term resolution, it is highly unlikely that the battery could
be replaced in time to meet the six-calendar-month requirement for this maintenance activity. The SDT believes corrective actions
should be timely but concludes it would be impossible to postulate all possible remediation projects; and, therefore, impossible to
specify bounding time frames for resolution of all possible unresolved maintenance issues, or what documentation might be
sufficient to provide proof that effective corrective action is being undertaken. The definition of “Unresolved Maintenance Issue”
has been modified to add a clarifying phrase that the deficiency “cannot be corrected during the maintenance interval.” Each entity
must determine how to document the efforts to correct the Unresolved Maintenance Issue based on the specific issue and choice of
remediation.
PPL Supply NERC Registered
Organizations
No
1. The maximum maintenance intervals in PRC-005-2 of 4 calendar months and
18 calendar months are not compatible with computerized maintenanceplanning programs based on periodicity rather than elapsed time from the
previous check. This situation could be addressed in a conservative fashion
by performing work quarterly instead of at 4-month intervals, and annually
in place of 18-month periods, which also provides often-needed flexibility as
to scheduling the tasks. Inspections performed in April for Q2 and
September for Q3 would not meet NERC’s 4 calendar month criterion,
however, and a similar problem exists for annual checks. The more-stringent
compliance jeopardy cited above has therefore not been fully addressed.
We recommend changing the 4 calendar months and 18 calendar months
intervals to quarterly and annually respectively.
2. We consider addition of the expression, “causes the component to not meet
the intended performance,” to the previous draft’s definition of Unresolved
Maintenance Issues (UMIs) to constitute a step backwards, because of the
unavoidable subjectivity involved in deciding whether or not a battery or
other protection system device is unable to perform as intended. A battery
with some “sparkle” on the plates due to sulfation would still be able to
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
34
Organization
Yes or No
Question 2 Comment
perform adequately, for example, making this an issue to watch but not an
UMI. It is impractical to provide strict, quantitative, UMI-threshold
performance limits for every piece of equipment in a Protection System and
every situation that may arise, however. The concept of an UMI has some
appeal from a common-sense point of view; but as a regulation it is
impractical and, given the breadth of the topic at hand, is likely to remain so
regardless of alternative phrasing that might be attempted.
Response: Thank you for your comment.
1. The SDT believes that management issues associated with computerized maintenance management programs can be adapted to
provide maintenance triggers consistent with the intervals established in the tables. Many of these systems offer the ability for
the user to create custom algorithms to trigger the desired work order, reminder, or alarm, etc. The SDT also believes the four
calendar-month and 18-calendar-month intervals are appropriate for the relative Protection System components. An entity may
utilize the abbreviated intervals, such as you suggest, as long as they meet the explicit requirements and intervals established in
the standard.
2. The consideration of “meet the intended performance” is an issue for an entity to determine subjectively. This consideration
depends heavily upon the nature of observed anomaly and upon the actual intended performance.
Arizona Public Service Company
No
The standard does not provide basis for the enumerated “maximum allowable
interval that is appropriate to the type of the protection system and its impact on
the reliability of the Bulk-Power System.” An example of such an approach is the
Standard Technical Specifications in use by the nuclear power industry; e.g.,
NUREG 1432, volume 2. While we are supportive of the changes the SDT has
made, APS is concerned the draft Standard will not give entities the flexibility to
continue to improve reliability based on changing industry norms and best
practices. When technology changes for the better, industry will need the
flexibility to optimize use of the new technology while still maintaining an
appropriate level of reliability. Lack of defined bases for intervals will prevent
technically sound revision to maintenance practices.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
35
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. The SDT established the maximum maintenance intervals for each Protection System
component subject to the standard based upon research performed by the NERC System Protection and Control Subcommittee and
“best practice” input from industry. The base intervals are extended in consideration of modern monitoring capabilities and new
technologies. These extended intervals range from “12 calendar years” to “No periodic maintenance specified.” Consistent with the
FERC directive of intervals being “…appropriate to the type of protection system and its impact on the reliability of the Bulk Power
System,” the SDT did not provide a “No periodic maintenance specified” extended interval for high reliability impact devices, such as
protective relays; but rather stipulates a six-calendar-year interval for unmonitored electromechanical and unmonitored
microprocessor relays, and a 12-calendar-year verification of monitored microprocessor relays. Please see Section 8.3 of the
Supplementary Reference and FAQ document for a more detailed discussion of this issue.
Southern Company Generation
No
1. The change made to R3 was a good move. Entities should be allowed the
flexibility to build grace periods into their maintenance programs to assist
them in meeting common national standards for maintenance activities and
intervals.
2. If possible, elimination of all possible uncertainty in the auditability of
requirement R5 is desired. We prefer eliminating this requirement R5
altogether to the proposed draft that includes a requirement to demonstrate
efforts to correct identified unresolved maintenance issues.
Response:
1. Thank you for your comment and support.
2. Returning Protection System devices to good working order exists currently as a required element of a sound maintenance
program subject to the existing Protection System Maintenance and Testing Standard, PRC-005-1b. For reference, NERC
Compliance Application Notice CAN-0043 (Posted Final 12/30/2011) directs Compliance Enforcement Authorities (CEAs) to
“…look for relay test results or field records with annotations such as “as-found” readings or pass/fail results; if failed, then
adjustments made. The maintenance record for adjustments may be requested”.
Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope of
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
36
Organization
Yes or No
Question 2 Comment
this standard. There can be any number of supply, process and management problems that make setting repair deadlines
impossible. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex unresolved maintenance issues might require greater than the remaining maintenance
interval to resolve (and yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery during
a six-month check. In instances such as one that requires battery replacement as part of the long-term resolution, it is highly
unlikely that the battery could be replaced in time to meet the six-calendar-month requirement for this maintenance activity.
The SDT believes corrective actions should be timely, but concludes it would be impossible to postulate all possible remediation
projects; and, therefore, impossible to specify bounding time frames for resolution of all possible unresolved maintenance issues
or what documentation might be sufficient to provide proof that effective corrective action is being undertaken. The definition of
“unresolved maintenance issue” has been modified to add a clarifying phrase that the deficiency “cannot be corrected during the
maintenance interval.”
Ingleside Cogeneration LP
No
1. Ingleside Cogeneration LP strongly agrees with the change made to the
language in R1 and R3 specifying that compliance is measured against the
PRC-005-2’s interval tables wherever time-based methods are used. The
intervals were carefully designed to assure an acceptable level of BES
reliability, and the regulatory authorities must be prepared to stand by them.
Furthermore, a Registered Entity who may establish tighter intervals for their
own internal purposes should be encouraged to do so - and without a threat
of a violation hanging over their heads.
2. We also agree with the need to add a new requirement (R4) which applies to
those entities that choose to use a performance-based system to determine
some of their maintenance intervals. It logically maps back to requirement
R2 which states that the calculated intervals must be documented in the
PSMP.
3. We cannot agree with the language used in R5, which, in its previous form
under R3, had specified only that the Protection System owner “initiate
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
37
Organization
Yes or No
Question 2 Comment
resolution” to correct identified unresolved maintenance issues. We were
actually comfortable with this language as it was unambiguous that progress
did not need to be tracked start-to-finish. We would like to propose adding a
phrase that tracks the statement in M5; which we find acceptable. This
would result in the following: R5. Each Transmission Owner, Generator
Owner, and Distribution Provider shall demonstrate THAT IT HAS
UNDERTAKEN efforts to correct identified Unresolved
Maintenance Issues.
Response:
1. Thank you for your comment and support.
2. Thank you for your comment and support.
3. The SDT believes corrective actions should be timely, but concludes it would be impossible to postulate all possible remediation
projects; and, therefore, impossible to specify bounding time frames for resolution of all possible unresolved maintenance issues
or what documentation might be sufficient to provide proof that effective corrective action is being undertaken. For the
Compliance Monitoring Authority to be confident that the corrective action is being implemented, the entity should expect to
demonstrate progress toward correcting the Unresolved Maintenance Issue, such as the evidence suggested in Measure M5
(with additional suggested evidence added).
American Electric Power
No
1. R3: Table 1-5 notes a “mitigating device” as part of component attributes.
Such a phrase could be open to interpretation and needs to be clearly
defined.
2. Table 1-3, Maintenance Activities - there is nothing specifically regarding
accuracy. Suggest incorporating the definition of “verify” as used in the FAQ
or perhaps something similar to “verify values are as expected”.
3. R5: We understand the drafting team’s desire to deal with unresolved
maintenance issues, however it is not clear how the adequacy of resolving
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
38
Organization
Yes or No
Question 2 Comment
those issues would be determined by an auditor. If these kinds of efforts are
going to be scrutinized, there needs to be some sort of boundaries
established so that it is clear how unresolved maintenance issues would be
evaluated.
Response: Thank you for your comment.
1. The SDT intended that “mitigating devices” address actions of SPSs, which may include activities beyond tripping of interrupting
devices. For example, SPSs may perform actions like generation run-back or generation fast-valving.
2. ‘Verify” is a term expressed in the PSMP definition, and the use of the term in Table 1-3 indicates that the accuracy needs to be
‘whatever is necessary’ for proper functioning of the connected relays.
3. There can be any number of supply, process and management problems that make setting repair deadlines impossible. The SDT
believes corrective actions should be timely, but concludes it would be impossible to postulate all possible remediation projects;
and, therefore, impossible to specify bounding time frames for resolution of all possible unresolved maintenance issues.
Measure M5 suggests some examples of evidence.
US Bureau of Reclamation
No
The Requirement R5 indicates the entity has to "demonstrate" efforts to correct
identified unresolved maintenance issues. The measure M5 described
documentation of the efforts. The requirement language should be explicit. Does
the standard want a demonstration which implies active role of the entity to
prove what it is doing, or to provide documentation of the activities underway to
correct deficiencies? The language in the requirement should be altered to "Each
Transmission Owner, Generator Owner, and Distribution Provider shall prepare a
CAP for each identified Unresolved Maintenance Issue." A second requirement is
needed to require that "Each Transmission Owner, Generator Owner, and
Distribution Provider shall complete its CAP to correct the identified Unresolved
Maintenance Issues." The measures would need to be adjusted accordingly to
reflect the CAP and evidence that the entity completed the CAP.
Response: Thank you for your comment. The term within Requirement R5, “… demonstrate efforts …” is intended for both – that the
entities are acting to correct the deficiency and also (to prove compliance) maintaining documentation of the activities underway to
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
39
Organization
Yes or No
Question 2 Comment
correct the deficiency. The SDT elected to not require a “Corrective Action Plan” as defined in the NERC Glossary of Terms to avoid
much of the systemic, ongoing documentation attendant to that term. However, if an entity wishes to use a Corrective Action Plan
as defined, that would be an acceptable method of meeting Requirement R5.
Essential Power, LLC
No
The change to R3 is too restrictive, and removes the registered entity’s ability to
better define its own intervals based on its own experience and system
characteristics. The comments regarding a CEA’s enforcement of an RE’s more
stringent internal intervals is not indicative of an issue with the Requirement, but
with the way in which it is enforced.
Response: Thank you for your comment. Requirement R3 still allows entities flexibility within their own Protection System
Maintenance and Testing Program (PSMP), and only restricts an entity’s establishment of intervals that are greater than those
specified in the tables. For example, an entity may choose to establish, in its own PSMP, testing of a specific type or model of
electromechanical relay more frequently than the six-calendar-year interval specified in Table 1-1 of PRC-005-2. However, should
some issue come up that affects the entity’s ability to complete testing of those devices within their programs established interval,
but they are able complete the testing within the maximum maintenance interval provided by the standard, the standard explicitly
establishes that they will not be found non-compliant for missing their own, more stringent interval.
Xcel Energy
No
We agree with the changes to R3 and the new R4 requirement but disagree with
the wording change in the new R5 requirement. The difference between “initiate
resolution” and “demonstrate efforts to correct identified unresolved
maintenance issues” is very unclear. Please clarify the SDT’s intent with this
subtle wording change. In our opinion, it would be fairly obvious if an entity met a
requirement to “initiate resolution” and, thus, this would be easily measurable
requirement. It seems that the phrase “demonstrate efforts to correct identified
unresolved maintenance issues” will be open to more auditor judgment as to
what constitutes adequate efforts to correct a deficiency and thus makes the
measurement of meeting this requirement far more arbitrary. If this is not the
intent, then why bother with the wording change? Furthermore, CEAs should
realize that entities already have strong financial incentives in correcting identified
unresolved maintenance issues to minimize the risk of costly equipment damage
or equally costly outages of critical equipment. Delays in correcting identified
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
40
Organization
Yes or No
Question 2 Comment
unresolved maintenance issues are seldom driven by cost avoidance and are more
likely driven by the time it takes to develop, engineer and/or procure a better
solution to a problem. Prompt band-aid type fixes are not necessarily desirable
fixes and the wording of R5 should not promote the band-aid approach to the
correction of a problem.
Response: Thank you for your comment and your support on Requirements R3 and R4.
Requirement R5 is expressly focused on allowing entities to resolve deficiencies in an effective manner, rather than performing
“band-aid” fixes. Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside the
scope of this standard. There can be any number of supply, process and management problems that make setting repair deadlines
impossible. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of the
recognition that more complex unresolved maintenance issues could require more time to resolve effectively than there is time
remaining in the maintenance interval, yet the problems must eventually be resolved. The SDT believes that corrective actions
should be timely, but concludes it would be impossible to postulate all possible remediation projects; and, therefore, impossible to
specify bounding time frames for resolution of all possible unresolved maintenance issues, or what documentation might be
sufficient to provide proof that effective corrective action is being undertaken. The definition of “unresolved maintenance issue” has
been modified to add a clarifying phrase that the deficiency “cannot be corrected during the maintenance interval.”
ExxonMobil Research and
Engineering
No
As written, the current draft of PRC-005-2 discriminates against smaller entities
that do not have a population size of 60 for each component type. Historical
records provide an accurate account of how specific components have performed
in their installed environment. For a set population size, increasing the number of
historical data points should improve the accuracy of an entity’s calculated mean
time between failures, so, if you increase the period over which the historical data
must be evaluated, you can compensate for a smaller segment population size.
The SDT’s current draft prevents smaller entities from using a larger historical data
set to make up for a smaller population size when developing a performance
based protective system maintenance and testing program. The SDT should
reconsider allowing smaller entities to use historical records that extend for
period longer than a single year in the development of a performance based
program.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
41
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. Small entities are permitted to aggregate their components with similar components of
other entities to meet the component populations, as long as the programs are (and remain) similar – See Section 9 of the
Supplementary Reference and FAQ document and the associated footnote to Attachment A. Decreasing the component population
below the requirements of Attachment A will result in an unsound program due to component populations that are not statistically
significant. The Supplementary Reference and FAQ document states, “Any population segment must be comprised of at least 60
individual units; if any asset owner opts for PBM but does not own 60 units to comprise a population then that asset owner may
combine data from other asset owners until the needed 60 units is aggregated.” Historical data may be good for trending, but may
not be suitable for judging current maintenance program effectiveness.
EPRI
Constellation/Exelon
No
No
See comments in question 1
While we are fine with the structural change to separate the requirements out
further, we have concerns with the content of the requirements.
R5/M5
•
•
M5 needs further clarity to reflect the intended compliance obligation for
R5. In previous comments, Constellation expressed concern that
compliance obligation for R5 implied a greater level of completion in
attending to an identified “deficiency.” We pointed out that the severity
of the “deficiency” found will dictate the method and timing of a “follow
up correction action”. In response to the comment, the SDT stated that
“PRC-005-2 only requires the entity “... initiate resolution” of the issue
found.” The SDT revision of R5 and M5 is an improvement; however,
changes to M5 are needs to clarify that efforts to correct do not require
demonstration that those efforts have concluded.
A revision to the language will clarify the SDT intent. Please consider use
of the following language: R5. Each Transmission Owner, Generator
Owner, and Distribution Provider shall correct or initiate resolution of
identified Unresolved Maintenance Issues. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning] M5. Each Transmission
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
42
Organization
Yes or No
Question 2 Comment
Owner, Generator Owner, and Distribution Provider shall have evidence
that it has initiated resolution of, or corrected, identified Unresolved
Maintenance Issues in accordance with Requirement R5. The evidence for
initiated resolution may include but is not limited to work orders for
future resolution, project schedules for future resolution, or other
documentation of future plans. The evidence for corrected Unresolved
Maintenance Issues may include but is not limited to replacement
Component orders, invoices, return material authorizations (RMAs) or
purchase orders.
Response: Thank you for your comment. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from
NERC Staff) because of the recognition that more complex unresolved maintenance issues could require more time to resolve
effectively than there is time remaining in the maintenance interval, yet the problems must eventually be resolved. Measure M5 has
been modified to include “project schedules with completed milestones.”
Northeast Power Coordinating
Council
DTE Energy
MRO NSRF
Tacoma Public Utilities
Dominion
Yes
Yes
Yes
Yes
Yes
1. Dominion understands R3 to mean that the time-based maintenance interval
can be less that but not exceed the maximum maintenance intervals in the
tables. But that compliance will be based upon the maximum interval.
Please confirm that our understanding is correct.
2. Dominion believes the intent of the footnote in Table 1-1 is to ‘start the
interval’ on either the 1st day of a calendar year or calendar month. We also
believe this will require any entity whose current intervals are based on
annual or monthly will have to adjust their intervals to calendar as they
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
43
Organization
Yes or No
Question 2 Comment
transition to PRC-005-2. Please confirm our understanding is correct.
3. We also believe this transition could result in the compliance interval
measurement being shorter or longer than it would have been if PRC-005-2
had not been approved. If this is incorrect, please provide examples to
provide clarity.
Response: Thank you for your comment.
1. Yes, your understanding of Requirement R3 is correct.
2. No, your understanding of Footnote 1 at the bottom of the page where Table 1-1 appears in the standard is not correct. The
intent of Footnote 1 is to clarify, or define the terms “calendar year” and “calendar month” as they relate to the period in which
the next maintenance activity for a particular interval must occur. For example, if an entity performed electromechanical relay
testing at Substation A in April of 2010, in accordance with the maximum maintenance interval of six-calendar-years established
in Table 1-1, the entity must perform the next round of electromechanical relay testing at Substation A sometime during the
calendar-year period beginning January 1, 2016. Please see Section 7.1 of the Supplementary Reference and FAQ document for a
more detailed discussion of this issue.
3. If an entity’s maintenance program specifies a maintenance activity occur “30 days” from the previous activity’s performance, it
would be possible that a transition to a “calendar month” interval would allow the first performance of the activity after the
transition to occur sooner or later than the 30 days previously specified. However, many existing maintenance programs that
establish performance of an activity “annually” or “monthly” should not require more than adjusting the language in the
program. For instance, if an entity’s current program is to inspect substations “monthly,” they are likely performing those
inspections sometime during each calendar month. This practice would be no different with the interval redefined as: “once each
calendar month.”
PNGC Comment Group
Yes
The PNGC comment group agrees with this change. Removing the jeopardy
associated with more stringent intervals will make it less risky for entities to
tighten intervals in their PSMP.
Response: Thank you for your comment and support.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
44
Organization
ACES Power Marketing Standards
Collaborators
Yes or No
Yes
Question 2 Comment
1. We agree the changes will benefit reliability by allowing a registered entity to
have shorter maintenance cycles without the potential for compliance
violations associated with missing their shorter maintenance cycle.
2. Requirement R5 should be modified to focus on what is to be accomplished.
As it is written now, the requirement is essentially focused on compliance by
using “shall demonstrate efforts”. Compliance is about demonstrating or
presenting evidence that the requirement has been met. The purpose of the
requirement is to correct Unresolved Maintenance issues. We suggest
changing the wording to: “shall initiate resolution of Unresolved
Maintenance Issues.”
Response:
1. Thank you for your comment and support of this change.
2. Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside the scope of this
standard. There can be any number of supply, process and management problems that make setting repair deadlines impossible.
The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of the
recognition that more complex unresolved maintenance issues could require more time to resolve effectively than there is time
remaining in the maintenance interval, yet the problems must eventually be resolved. The SDT believes that corrective actions
should be timely, but concludes it would be impossible to postulate all possible remediation projects; and, therefore, impossible
to specify bounding time frames for resolution of all possible unresolved maintenance issues, or what documentation might be
sufficient to provide proof that effective corrective action is being undertaken. The definition of “unresolved maintenance issue”
has been modified to add a clarifying phrase that the deficiency “cannot be corrected during the maintenance interval.”
Liberty Electric Power LLC
Yes
Thank you for the change in Requirement 3. This standard now gives clear
direction to entities, removes the burden of "created paperwork" intended only
for the use of auditors, and removes the compliance jeopardy for holding a
program to a higher standard than required.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
45
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment and support.
TransAlta Centralia Generation LLC
Yes
More detail explanation or examples of Efforts on R5 is required
Response: Thank you for your comment. There can be any number of supply, process and management problems that make setting
repair deadlines impossible. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff)
because of the recognition that more complex unresolved maintenance issues could require more time to resolve effectively than
there is time remaining in the maintenance interval, yet the problems must eventually be resolved. The SDT believes that corrective
actions should be timely but concludes it would be impossible to postulate all possible remediation projects; and, therefore,
impossible to specify bounding time frames for resolution of all possible unresolved maintenance issues, or what documentation
might be sufficient to provide proof that effective corrective action is being undertaken. The definition of “unresolved maintenance
issue” has been modified to add a clarifying phrase that the deficiency “cannot be corrected during the maintenance interval.” See
the Supplementary Reference and FAQ document Section 4.1 for additional discussion.
Central Lincoln
1. We thank the SDT for removing the extra compliance jeopardy associated
with stringent intervals. The extra jeopardy never made sense to us, since it
could result in sanctions to one entity and no sanctions to another entity
when both followed the same interval with no BES risk presented by either.
2. We are concerned regarding the language of R5. We understand that
maintenance without resolution is worthless, but the language here is
subjective allowing different auditors to reach differing conclusions whether
a sufficiently documented effort has been made. We also note that entities
are expected to be continually in compliance with applicable standards, and
are expected to self report when they are not. Strictly interpreted, an entity
is out of compliance with R5 if there is any time lag between the moment the
problem is identified in the field and documentation is produced of an effort
taken to resolve it. We suggest the inclusion of a reasonable time limit.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 2 Comment
Response:
1. Thank you for your comment and support.
2. The definition of “Unresolved Maintenance Issue” has been modified to add a clarifying phrase that the deficiency “cannot be
corrected during the maintenance interval,” which allows the entity until the end of the maintenance interval to develop an
approach for correcting the problem. See the Supplementary Reference and FAQ document Section 4.1 for additional discussion.
Southwest Power Pool Standards
Development Team
Tennessee Valley Authority
FirstEnergy
Western Area Power
Administration
Pepco Holdings Inc. & Affiliates
PacifiCorp
MRO NSRF
Kansas City Power & Light
Edison Mission Marketing &
Trading
Alber Corporation
Flathead Electric Cooperative, Inc.
Independent Electricity System
Operator
Entergy Services
ATCO Electric Ltd
Manitoba Hydro
Westar Energy
Ameren
BAE Batteries USA
City of Austin dba Austin Energy
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
See comments under #4.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
BAE Batteries USA
American Transmission Company,
LLC
CenterPoint Energy
Duke Energy
PNM Resources
Los Angeles Department of Water
and Power
Yes or No
Question 2 Comment
Yes
Yes
Yes
Yes
Yes
Yes
Response: Thank you for your support.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
48
3.
The Supplemental Reference and FAQ document was revised to reflect changes made to the draft standard and to address
additional issues raised. Do you agree with the changes? If you do not agree, please provide specific suggestions for
improvement.
Summary Consideration: Several comments were submitted that were unrelated to this question.
Many commenters offered questions and suggestions related to the content of the Supplementary Reference and FAQ document,
which resulted in assorted changes throughout the document.
Organization
Fort Pierce Utilities Authority
Yes or No
Negative
Question 3 Comment
1. The applicability of the standard should be modified to reflect the FERC
approved interpretation PRC-005-1b Appendix 1 that basically says that
applicable Protection Systems are those that protect a BES Element AND trip
a BES Element. The applicability as currently stated will sweep in distribution
protection: “4.2.1 Protection Systems that are installed for the purpose of
detecting Faults on BES Elements (lines, buses, transformers, etc.).” Most
network distribution systems that have more than one source into a
distribution network will have reverse power relays to detect faults on the
BES and trip the step-down transformer to prevent feedback from the
distribution to the fault on the BES. This is not a BES reliability issue, but more
of a safety and distribution voltage issue. These relays would be subject to the
standard as the applicability is currently written, but, should not be and they
are currently not within the scope of PRC-005-1b Appendix 1 because the
step-down transformer (non-BES) is tripped and not a BES Element (hence,
the "and" condition of the interpretation is not met). There are many other
related examples of distribution that might be networked or have distributed
generation on a distribution circuit where such reverse power relays, or
overcurrent relays with low pick-ups, are used for safety and distribution
voltage control reasons and are not there for BES Reliability. To make matters
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
worse, for these Reverse Power relays, it is pretty much impossible to meet
PRC-023 because the intent of the relay is to make current flow unidirectional
(e.g., only towards the distribution system) without regard for the rating of
the elements feeding the distribution network. So, if these relays are swept
in, and if they are on elements > 200 kV, then the entity would not be able to
meet PRC-023 as that standard is currently written. FPUA recommends the
SDT should adopt the FERC approved interpretation.
2. Another concern is regarding the sudden pressure relays. These had been out
of the scope in all previous draft versions of PRC-005-2 because these do not
measure electrical quantities. However, the SDT just added a requirement to
test the trip path from the sudden pressure device, arguing that it is captured
by the definition of Protection Systems. This inconsistency does not make
sense and could create “grey areas” for other devices that can trip for low oil
level or high temperature, among others. By their nature, sudden pressure
devices are far less reliable than their associated control circuitry. I know of at
least one large entity that disables sudden pressure relays on smaller
transformers to cut down on nuisance alarms. If it is expected that nonelectrically initiated devices may become part of some maintenance standard
in the future, I think it would be premature for the SDT to address sudden
pressure relays in PRC-005-2.
3. And lastly, page 77 of the Supplementary Reference has some text clarifying
the requirement for establishing a baseline test: “For all new installations of
Valve-Regulated Lead-Acid (VRLA) batteries and Vented Lead-Acid (VLA)
batteries, where trending of the cells internal ohmic measurements to a
baseline are to be used to determine the ability of the station battery to
perform as designed, the establishment of the baseline as described above
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
should be followed at the time of installation to insure the most accurate
trending of the cell/unit.” This guidance does not recognize the fact that some
battery manufacturers recommend the baseline tests to be performed at
some point in time after the install to allow the cell chemistry to stabilize
after the initial freshening charge. The manual from a battery manufacturer
(Enersys Powersafe) states that “The initial records are those readings taken
after the battery has been in regular float service for 3 months (90 days).
These should include the battery terminal float voltage and specific gravity
reading of each cell corrected to 77F (25C), all cell voltages, the electrolyte
level, temperature of one cell on each row of each rack, and cell-to-cell and
terminal connection detail resistance readings. It is important that these
readings be retained for future comparison”. If an entity follows the
manufacturer’s recommendation, the above statements would lead an
auditor to a finding of non-compliance because internal ohmic tests were not
performed prior to placing a new battery string in service. A simple
modification to the wording would eliminate the conflict.
Response: Thank you for your comments.
1. The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term, “transmission Protection System,” and notes that this term is
not used within PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses
Protection Systems that are installed for the purpose of detecting Faults on BES Elements.
To address your concern, the distribution protective devices and functions provided as examples in this comment, as pointed
out by the commenter, are not “installed for the purpose of detecting Faults on BES Elements,” and would, therefore, not be
subject to PRC-005-2. A relay used primarily for “safety and distribution voltage control reasons” is clearly not “installed for
the purpose of detecting Faults on BES Elements.” The reverse power relay application described is also not “installed for
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
51
Organization
Yes or No
Question 3 Comment
the purpose of detecting Faults on BES Elements” (the relays react to changes in power flow direction, which may or may not
be due to a Fault), but for the purpose of preventing feedback from the distribution system to the transmission system.
Please see the PRC-005-2 Supplementary Reference and FAQ, Section 2.3, for a more detailed discussion of this issue.
2. DC trip circuit from a sudden pressure relay output to the trip coil of the interrupting device has always been included in the
“Control circuitry” portion of a Protection System, and is discussed in Section 15.3 of the PRC-005-2 Supplementary
Reference and FAQ document. In regards to including sudden pressure relays themselves, FERC, in Order 758, recently
directed NERC to submit an informational filing providing a schedule for addressing sudden pressure relays in PRC-005. The
NERC System Protection and Control Subcommittee (SPCS) worked with NERC staff to develop the informational filing, which
was filed with FERC on April 12, 2012. Activities associated with the schedule submitted in the filing will be included in a
final SAR to further develop PRC-005. A draft SAR has been posted on the project page for information only.
3. The Drafting Team has revised the Supplemental Reference and FAQ document based on your recommendations.
DTE Energy
MRO NSRF
No
No
1. Section 5.1 (second paragraph, under the first bullet) states: “TBM can include
review of recent power system events near the particular terminal. Operating
records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme
components have demonstrated correct performance within specifications,
the maintenance test time clock can be reset for those components.” If this
“actual event” can be used as proof that the Protection System operated
correctly, then this should be added to M3 in the Measures section of PRC005-2.
2. Section 2.4.1 - Sudden Pressure Relays - This question should be clarified that
circuits from only EHV transformers should be considered in scope. As
highlighted by the NERC GMD reports EHV transformers (345, 500 & 765 kV)
are critical.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
3. In addition, circuits that do not actually trip a breaker (panel lights, alarms,
etc.) should not be included in the scope of components included in the
maintenance and testing program.
Response: Thank you for your comments.
1. Measure M3 lists possible types of evidence, and states, “is not limited to.” Therefore, in-service operations can be provided
as evidence.
2. This standard applies to the BES and certain transformers less than 345kV are, therefore, included.
3. Table 5 Component Type states, “Control Circuitry associated with protective functions…” and, therefore, the circuits you
reference are not included.
FirstEnergy
No
Western Area Power
Administration
No
Please see our comments and suggested changes to the Supplemental Reference
and FAQ document in Question 4.
Western Area Power Administration does not agree that the trip path from a
sudden pressure device is a part of the protection system control circuitry as
stated in the revised Supplementary document. FAQ should be used as guidance
and not for compliance.
Response: Thank you for your comment.
The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted from
PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing elements. The
SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the currentlyapproved PRC-005-1B, consistent with the SAR for Project 2007-17, and understands this to be consistent with the position of FERC
staff. The Supplementary Reference and FAQ document provides supporting discussion, but is not part of the Standard. The SDT
intends that it be posted as a Reference Document, accompanying the standard. As established in SDT Guidelines, the standard is to
be a terse statement of requirements, etc., and is not to include explanatory information like that included in the Supplementary
Reference and FAQ document.
Nebraska Public Power District
No
1. Section D 1.3 Evidence Retention - Do not agree with requirement to keep the
two most recent performances of each distinct maintenance activity. Should
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
not require records previous to last audit. What is the point of keeping
records up to twenty years?
2. FAQ page 7 and 77 now include discussion about how sudden pressure relays
are “presently” excluded because they do not meet the definition of a
protection system and a method of component verification does not exist.
This part I agree with. The problem is that they go on to explain that the DC
control circuitry from the Sudden Pressure relay is part of a protection
system. This I disagree with. It’s clear that the Standards Drafting Team is
attempting a compromise to address direction from FERC Docket No. RM105-000. This approach however, sets a bad precedence. A trip path from a
non-protection system component should not be classified as a protection
system trip path.
3. The removal of grace periods and the comments in the FAQ that it will be up
to the Auditor to determine if a test was not done due to extraordinary
circumstances (example: Communications can’t be tested due to the line out
from a storm and under repair) is not acceptable. The SDT needs to come up
with guidelines for these situations and not leave it up to each auditor to
determine what is acceptable.
Response: Thank you for your comments.
1. For a Compliance Monitor to be assured of compliance, the SDT believes the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding maintenance to validate that entities have been in
compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT specified the data retention
in the posted standard to establish this level of documentation. This seems to be consistent with the current practices of several
Regional Entities.
2. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
elements. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent
with the currently-approved PRC-005-1b, consistent with the SAR for Project 2007-17, and understands this to be consistent with
the position of FERC staff.
3. FERC Order 693 directs NERC to establish maximum allowable intervals. Grace periods would not satisfy this directive.
PPL Supply NERC Registered
Organizations
No
We recommend that the final sentence of M3 and M4 be changed to, “Any of the
following constitutes sufficient evidence: dated maintenance records, dated
maintenance summaries, dated check-off lists, dated inspection records, dated
work orders, or other equivalent documentation,” and that the slightly different
final sentence of M5 be similarly changed.
Response: Thank you for your comment.
The SDT believes the measures should not mandate evidence, but provide examples of evidence.
MRO NSRF
No
1. Section 5.1 (second paragraph, under the first bullet) states: “TBM can include
review of recent power system events near the particular terminal. Operating
records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme
components have demonstrated correct performance within specifications,
the maintenance test time clock can be reset for those components.” If this
“actual event” can be used as proof that the Protection System operated
correctly, then this should be added to M3 in the Measures section of PRC005-2.
2. Section 2.4.1 - Sudden Pressure Relays - This question should be clarified that
circuits from only EHV transformers should be considered in scope.
3. As highlighted by the NERC GMD reports EHV transformers (345, 500 & 765
kV) are critical. In addition, circuits that do not actually trip a breaker (panel
lights, alarms, etc.) should not be included in the scope of components
included in the maintenance and testing program.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
Response: Thank you for your comments.
1. Measure M3 lists possible types of evidence and states “is not limited to.” Therefore, ‘in-service’ operations can be provided
as evidence.
2. This standard applies to the BES and certain transformers less than 345kV are, therefore, included.
3. Table 5 Component Type states, “Control Circuitry associated with protective functions…” and, therefore, the circuits you
reference are not included.
Arizona Public Service Company
No
Either the FAQ or the Standard should define the bases for each interval
mandated. See the response to question 2 for further details.
Response: Please see the Technical Justification document associated with Project 2007-17. Please also see Section 8.3 of the
Supplementary Reference and FAQ document.
Ingleside Cogeneration LP
No
We do not agree with the assertion in the reference and FAQs that the DC supply
and control circuitry for mechanical components are part of a BES Protection
System. This is not an accepted norm in the existing Standard as the Project Team
claims - only an expansion in scope that was not properly vetted by the industry.
If the Compliance Authorities believe that electrical components which support
mechanical systems are rightfully part of the BES or BPS, then this has implications
far beyond Protection System maintenance. The appropriate place to begin this
determination is with Project 2010-17 Definition of the BES - where it can be fully
reviewed by all affected industry stakeholders.
Response: Thank you for your comment.
The trip path from a sudden pressure device is a part of the Protection System control circuitry. Sudden pressure relays, as opposed
to other types of mechanical components, are installed to detect an electrical fault condition inside a transformer. The sensing
element is omitted from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the
sensing elements. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently-approved PRC-005-1b, consistent with the SAR for Project 2007-17, and understands this to be
consistent with the position of FERC staff.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
American Electric Power
Yes or No
No
Question 3 Comment
Though the guidance provided in these documents may appear to be beneficial,
we are troubled that despite the time spent on them by the drafting team, and
the voluminous nature of the references, that the information contained in them
essentially fades away upon approval of the standard. Rather than voluminous
supplementary references, we suggest adding this information, as necessary, to
the standard itself. Not only would this prove beneficial by having less information
housed outside of the standard, it might help prevent the need for future CANs
and interpretation requests.
Response: Thank you for your comments.
The Supplementary Reference and FAQ document provides supporting discussion, but is not part of the standard. The SDT intends
that it be posted as a Reference Document accompanying the standard. As established in SDT Guidelines, the standard is to be a
terse statement of requirements, etc., and is not to include explanatory information like that included in the Supplementary
Reference and FAQ document. The Supplementary Reference will be revised in the course of the revision process of the standard.
Westar Energy
No
1. We believe all of the 4 month intervals can be changed to 6 month
intervals and still ensure reliability. It is unclear which equipment Table 14(d) applies to.
2. In the heading it says “Excluding distributed UFLS and distributed UVLS”,
then the line below that says “non-distributed UFLS system, or nondistributed UVLS systems is excluded”.
Response: Thank you for your comments.
1. The activity related to this interval is to verify various basic operating parameters. The SDT believes that extension of verification
of these parameters beyond the interval within the standard is inappropriate.
2. These are addressing two different items; the first addresses distributed UFLS/UVLS, whether tripping at BES levels or not, and
the second addresses non-distributed UFLS/UFLS/SPS that trips only non-BES interrupting devices.
Ameren
No
We agree with the intent of the Supplement changes but believe that they are
either incomplete or need clarification. Therefore, we provide the specifics as
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
follow :
(a) Page 93, Revise Section 15.7 Distributed UFLS (i) Change Table 1-2 to 1-3.(ii)
Include ‘Verify operation...and/or auxiliary tripping device’ to agree with Table 3.
(b) Please identify BES Elements in Supplementary Reference Figure 2.
(c) Remove ‘Reverse power relays’ from the bulleted list on the top section of
page 33. They provide thermal of the steam turbine, and they may protect CTG
speed reduction gear teeth, but neither of these are electrical protection of the
generator.
(d) Please add Interval FAQ to address a component minimum maintenance
activity that is not in the present PRC-005-1 program. (i) : “How is interval proven
for a component minimum maintenance activity that is not in the present PRC005-1 program? For example, suppose the present program continuously
monitors a communication system, say audio tones, and personnel respond to
alarms; this approach presently have basis that is sufficient. (ii) Table 1-2
requires two maintenance activities every 12 calendar years: 1) verify channel
meets performance criteria; and 2) verify essential I/O. The entity is required to
perform these minimum maintenance activities one time in the first 13 years after
regulatory approval. The 12 year interval is proven by the date of the PRC-005-2
maintenance activity and the date of your PRC-005-1 program applicable for the
previous maintenance. After the second time the PRC-005-2 maintenance activity
is performed, appropriately sometime in year 14 to 25 after regulatory approval,
then interval will be proven by the dates of the two PRC-005-2 maintenance
activities.”
(e) Page 17 We disagree with retention of maintenance records for replaced
equipment as this can cause confusion. At most the last maintenance date could
be retained to prove interval between it and the test date of the replacement
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
equipment that provides like-kind protection.
(f)Page 36, FAQ ‘initial date for maintenance’ answer is inconsistent with CAN0011. Though the CAN applies to PRC-005-1, it should be consistent with NERC’s
position on this.
(g) Page 71, Please remove ‘The trip path from a sudden pressure device is a part
of the Protection System control circuitry...’ because the actuating relay does not
respond to electrical quantities. This is just one example of the many gotcha’s
that will no doubt arise in enforcement. (
h) If a capacitor trip device is an example of a non-battery based station DC
supply, then please provide a FAQ to convey it.
Response: Thank you for your comments.
a. The SDT modified the Supplementary Reference and FAQ document, as suggested.
b. The applicable facilities for a generator are listed in Section 4.2.5 of the standard. Figure 2 is a visual representation of this.
c. Reverse power relays, as discussed in your comment, do not detect Faults; but if they can trip the generator, they must be
maintained per 4.2.5.
d. This issue is addressed in the Implementation Plan for Project 2007-17.
e. The records for removed/replaced equipment need to be retained to provide documentation that you were in compliance for the
entire compliance monitoring period.
f. The SDT has provided guidance as it relates to PRC-005-2.
g. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the sensing elements.
The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the
currently-approved PRC-005-1b, consistent with the SAR for Project 2007-17, and understands this to be consistent with the
position of FERC staff.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
h. If the “capacitor trip device” you reference is the stored energy device for the breaker, it would not be included in Table 1-4(d).
Central Lincoln
No
The Supplemental Reference and FAQ apparently has not kept up with definition
changes and uses uncapitalized “component” “Protection System components”.
Please use capitals if defined terms are intended.
Response: Thank you for your comment. The SDT modified the Supplementary Reference and FAQ document as suggested.
BAE Batteries USA
No
Page 20 states that every 18 months "battery ohmic values to station battery
baseline (if performance tests are not opted)" should be changed to add comment
that ohmic values, while permissible as a tool, should not be taken to validate the
actual capacity, thus the reliability of the battery. If capacity is an issue due to
questionable ohmic values shown, a decision must be made to [1] perform a
capacity test following one of the three methodologies recorded in IEEE 450 or
IEEE 1188; [2] make a decision to replace the battery string depending upon the
number of cells with questionable ohmic values shown, the age of the battery
string, and the critical nature of the station in question; or [3] accept the risk that
the battery may or may not perform as intended due to the lack of a true
knowledge of the battery capacity (See IEEE Letter to Al McMeekin). Every 18
calendar months verify/inspect the following: "Cell Condition of all individual
battery cells (where visible) should add "or as frequently as recommended in the
battery manufacturer's operating instructions."Every 6 years: perform or verify
the following:"Battery Performance Test (if internal ohmic tests are not opted)"
should be changed to read "Battery Performance Test (if ohmic tests are not
conducted or if ohmic test values show that a degraded situation with the cells call
into question whether the battery will perform to "design requirements."this
should be repeated where referenced in additional examples (VLA, VRLA, Ni-Cd)
Response: Thank you for your comment. The drafting team agrees with your statement, and those of others concerning the true
capacity of the station battery and relating it to internal ohmic measurements. Tables 1-4a, 1-4b and 1-4c have been modified for
clarity, and the Supplemental Reference and FAQ document has been modified to further elaborate on these concerns.
ExxonMobil Research and
No
: As written, the current draft of PRC-005-2 discriminates against smaller entities
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
60
Organization
Yes or No
Engineering
Question 3 Comment
that do not have a population size of 60 for each component type. Historical
records provide an accurate account of how specific components have performed
in their installed environment. For a set population size, increasing the number of
historical data points should improve the accuracy of an entity’s calculated mean
time between failures, so, if you increase the period over which the historical data
must be evaluated, you can compensate for a smaller segment population size.
The SDT’s current draft prevents smaller entities from using a larger historical data
set to make up for a smaller population size when developing a performance
based protective system maintenance and testing program. The SDT should
reconsider allowing smaller entities to use historical records that extend for
period longer than a single year in the development of a performance based
program.
Response: Thank you for your comment. Small entities are permitted to aggregate their components with similar components of
other entities to meet the component populations, as long as the programs are (and remain) similar – See Section 9 of the
Supplementary Reference and FAQ document and the associated footnote to Attachment A. Decreasing the component population
below the requirements of Attachment A will result in an unsound program due to component populations that are not statistically
significant. The Supplementary Reference and FAQ document states, “Any population segment must be comprised of at least 60
individual units; if any asset owner opts for PBM but does not own 60 units to comprise a population then that asset owner may
combine data from other asset owners until the needed 60 units is aggregated.” Historical data may be good for trending, but may
not be suitable for judging current maintenance program effectiveness.
TransAlta Centralia Generation LLC
Yes
More detail explanation on Segment is required; the reason of sixty (60) individual
components is required for one Segment. More detail explanation on Countable
Event is required.
Response: Thank you for your comments.
The SDT believes that Segment and Countable Events are clearly stated in the standard. Decreasing the component population
below the requirements of Attachment A will result in an unsound program due to component populations that are not statistically
significant.
City of Austin dba Austin Energy
Yes
The effort expended by the SDT in creating and revising the content of the
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 3 Comment
Supplemental Reference and FAQ is admirable and most appreciated. The guide is
a useful reference.
Response: Thank you for your comment and support.
Los Angeles Department of Water
and Power
Yes
LADWP notices that the terms "Unresolved Maintenance Issue" and
"maintenance-correctable issue" are used in several places. We recognize that
"Unresolved Maintenance Issue" is defined as a deficiency identified during a
maintenance activity that causes the component to not meet the intended
performance and requires follow-up corrective action. Please define
"maintenance-correctable issue" and clarify the differences between the two
terms.
Response: Thank you for your comments.
“Unresolved Maintenance Issue” replaced the term “maintenance-correctable issue,” and the SDT corrected the Supplementary
Reference and FAQ document to reflect the change.
Progress Energy
1. Table 3, Row 7: The requirement to “Verify electrical operation of
electromechanical lockout and/or tripping auxiliary devices” contradicts Section
15.7, bullet 2 of the Supplementary Reference and FAQ document. In the
supplementary reference, the phrase “and/or auxiliary tripping device(s)” has
been struck out.
Response: Thank you for your comments.
The Supplementary Reference and FAQ document has been modified per your suggestion.
EPRI
Northeast Power Coordinating
Council
Tacoma Public Utilities
Imperial Irrigation District (IID)
Southwest Power Pool Standards
Development Team
No
Yes
see comments in question 1
Yes
Yes
Yes
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Tennessee Valley Authority
PNGC Comment Group
Bonneville Power Administration
ACES Power Marketing Standards
Collaborators
Southern Company Generation
Kansas City Power & Light
Edison Mission Marketing &
Trading
Alber Corporation
Independent Electricity System
Operator
Liberty Electric Power LLC
Entergy Services
ATCO Electric Ltd
Manitoba Hydro
US Bureau of Reclamation
American Transmission Company,
LLC
CenterPoint Energy
Xcel Energy
Duke Energy
PNM Resources
Yes or No
Question 3 Comment
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Response: Thank you for your support.
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
63
4.
If you have any other comments on this Standard that you have not already provided in response to the prior questions, please
provide them here.
Summary Consideration: Several comments were repeated from Questions 1, 2, or 3, and the summary consideration responses are
not repeated here.
Numerous commenters suggested minor changes to the definition of the terms “inspect” and “Countable Event.” In response, the
SDT modified the description of the term, “inspect” within the definition of PSMP. Previously “inspect” was “Examine for signs of
component failure, reduced performance or degradation.” now “inspect” is “Examine for signs of component failure, reduced
performance or degradation.” The SDT also modified the definition of Countable Event from “A Component which has failed and
requires repair or replacement…” to “A failure of a Component requiring repair or replacement …”
The SDT continued to receive comments regarding the Applicability of the standard. The SDT modified the Applicability Clause
4.2.5.4 to read: “Protection Systems for station service or excitation transformers connected to the generator bus of generators
which are part of the BES, that act to trip the generator either directly or via lockout or tripping auxiliary relays.”
Some commenters questioned the last line in Table 1-2 for Communications Systems. The SDT realized they had several errors in the
table – one omitted element and one incorrect interval. The table was corrected.
Several comments were offered regarding the station battery activities in Tables 1-4 (a-f). Representatives of the IEEE Stationary
Battery Committee assisted the SDT in making revisions to these tables to address concerns related to ohmic testing of the cell/units.
Several commenters questioned elements of the criteria in Attachment A for performance-based maintenance; the SDT explained the
rationale for these criteria, including, where appropriate, the related statistical basis.
Several comments pointed out inconsistencies between the Standard and Supplementary Reference and FAQ. The SDT modified the
Standard and Supplementary Reference and FAQ to address these inconsistencies.
A few commenters questioned portions of the standard, or suggested changes that the SDT chose not to adopt. The SDT responded
with their rationale. These comments included:
•
NERC should provide a format for test reports, etc.
•
Include batteries within a performance-based PSMP
•
Objections to the inclusion of distribution devices that are installed for the benefit of the BES
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
64
•
VSLs permitting entities to experience some small level of non-performance relative to the standard without incurring a
violation
•
VSLs set at inappropriate levels
•
The inclusion of the control circuitry related to sudden pressure relays, even though sudden pressure relays themselves are
not included
•
Various facets of control circuitry maintenance
•
Specific intervals or activities within the tables
•
Evidence retention language
•
Intervals for lockout relays
•
Voltage and current sensing devices
Organization
Northern Indiana Public
Service Co.
Yes or No
Negative
Question 4 Comment
A format for maintenance reports and specific test requirements for relays are
missing.
Response: Thank you for your comments.
The SDT does not believe it is necessary or appropriate to prescribe a specific format for maintenance results or test requirements.
James A Maenner
Negative
As written, the standard may require DPs to include distribution protection devices
designed to isolate and protect distribution facilities from faults on monitored
transmission or other BES facilities. Qualifying language should be added differentiate
protective systems which control BES and distribution facilities for faults on the BES.
Response: Thank you for your comments.
PRC-005-2 specifically addresses Protection Systems that are installed for the purpose of detecting Faults on BES Elements, even if
they are installed on distribution facilities. UFLS and UVLS devices which are commonly installed on distribution facilities for the
purposes of addressing related NERC Standards are included. Protection Systems installed on distribution facilities for the purposes
of detecting Faults on distribution facilities are not included.
SERC Reliability Corporation
Negative
FERC Order 758 includes directives that affect this project. I understand that the
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
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Organization
Yes or No
Question 4 Comment
SPCS/SAMS group is looking at the technical documents to support additional
standards activity but as this project is presented, it does not meet the FERC
directives. Otherwise, I could vote affirmatively, but I do have some concerns about
how clearly and unambiguously the standards requirements are written. This standard
should be a candidate for the RSAW initiative being developed by the Standards
Committee.
Response: Thank you for your comments. The Standards Committee has directed the PSMTSDT to finalize PRC-005-2 and present it to
the NERC Board of Trustees for adoption, and concurrent with this posting of PRC-005-2 to post for information a draft SAR for a
second phase of Project 2007-17 addressing further modifications to PRC-005-2.
FERC Order 758 includes directives associated with Maintenance and Testing of Auxiliary and Non-Electrical Sensing Relays, Reclosing
Relays, and DC Control Circuitry. Regarding these directives in relation to PRC-005-2:
1. Testing of Auxiliary and Non-Electrical Sensing Relays – The NERC System Protection and Control Subcommittee (SPCS) recently
worked with NERC staff to develop an informational filing in response to Order 758. Activities associated with the schedule
submitted in the filing will be included in a final SAR to establish a future phase of Project 2007-17 for future development of
PRC-005. A draft SAR is posted on the project page for information only.
2. Reclosing relays will be addressed in a second phase of this project, which will produce PRC-005-3. Development of that
revision will begin after PRC-005-2 is completed and the NERC SPCS completes the technical documentation regarding reclosing
relays.
3. DC Control Circuitry and Components – This draft standard PRC-005-2 includes extensive, specific maintenance activities (with
maximum maintenance intervals) related to the DC control circuits.
Southwest Transmission
Cooperative, Inc.
Negative
1. For the Requirement R1’s High VSL, “entities’” should be “entity’s” to be
consistent with the other VSLs.
2. It is not clear why missing three component types jumps to a Severe VSL. Missing
two is a Moderate VSL. Missing three should be a High VSL.
Response: Thank you for your comments.
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Question 4 Comment
1. The SDT has corrected the Requirement R1 VSL, as you suggest.
2. The SDT believes that missing three components is considered a “significant percentage,” and is in accordance with the VSL
guidelines.
Midwest ISO, Inc.
Negative
In the VSL for Table 4 it seems that the phrase “5% or less” should be “not more than
5%”. With the original language it seems like an entity could be found to have an R4
lower VSL violation for “failure” of zero meaning they had done no testing. This VSL is
written in the negative and should be rewritten in the positive.
Response: Thank you for your comments.
The VSL Guidelines, developed in accordance with FERC’s VSL Order, establish the Lower VSL for stepped VSLs as “5% or less,” the
Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the
Severe VSL as “more than 15%.”
Lincoln Electric System
Negative
Western Area Power
Administration
Minnkota Power
Cooperative, Inc.
Lakeland Electric
Kissimmee Utility Authority
Baltimore Gas & Electric
Company
Occidental Chemical
Dairyland Power Coop.
U.S. Army Corps of Engineers
Dairyland Power Coop.
Beaches Energy Services
Negative
Please refer to comments submitted by the MRO NERC Standards Review Forum for
LES’ concerns related to PRC-005-2.
Please see comments provided on Official Comment Form
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Please see FMPA comments
Please see separately submitted FMPA comments.
Please see the issues raised in the Comment Form submitted on behalf of
Constellation.
See comments submitted by Ingleside Cogeneration LP
See MRO NSRF comments.
See MRO/NSRF comments
See NSRF comments.
The applicability of the standard should be modified to reflect the FERC approved
interpretation PRC-005-1b Appendix 1 that basically says that applicable Protection
Systems are those that protect a BES Element AND trip a BES Element. The
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Question 4 Comment
interpretation states: The applicability as currently stated will sweep in distribution
protection: “4.2.1 Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.)” Many (most) network
distribution systems that have more than one source into a distribution network will
have reverse power relays to detect faults on the BES and trip the step-down
transformer to prevent feedback from the distribution to the fault on the BES. This is
not a BES reliability issue, but more of a safety issue and distribution voltage issue.
These relays would be subject to the standard as the applicability is currently written,
but, should not be and they are currently not within the scope of PRC-005-1b
Appendix 1 because the step-down transformer (non-BES) is tripped and not a BES
Element (hence, the "and" condition of the interpretation is not met). There are many
other related examples of distribution that might be networked or have distributed
generation on a distribution circuit where such reverse power relays, or overcurrent
relays with low pick-ups, are used for safety and distribution voltage control reasons
and are not there for BES Reliability. To make matters worse, for these Reverse Power
relays, it is pretty much impossible to meet PRC-023 because the intent of the relay is
to make current flow unidirectional (e.g., only towards the distribution system)
without regard for the rating of the elements feeding the distribution network. So, if
these relays are swept in, and if they are on elements > 200 kV, then the entity would
not be able to meet PRC-023 as that standard is currently written. So, the SDT should
adopt the FERC approved interpretation.
Response: Thank you for your comments.
The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES. The SDT observes
that the approved Interpretation addresses the term, “transmission Protection System,” and notes that this term is not used within
PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses Protection Systems that are
installed for the purpose of detecting Faults on BES Elements.
To address your concern, the distribution protective devices and functions cited in this comment are not “installed for the purpose of
detecting Faults on BES Elements,” and would, therefore, not be subject to PRC-005-2. A relay used primarily for “safety and
distribution voltage control reasons” is clearly not “installed for the purpose of detecting Faults on BES Elements.” The reverse
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Question 4 Comment
power relay application described is also not “installed for the purpose of detecting Faults on BES Elements” (the relays react to
changes in power flow direction, which may or may not be due to a Fault) but for the purpose of preventing feedback from the
distribution system to the transmission system.
Please see the PRC-005-2 Supplementary Reference and FAQ, Section 2.3, for a more detailed discussion of this issue.
U.S. Bureau of Reclamation
Negative
1. The definition for PSMP is incongruous with the use of the PSMP in Requirement
R1. Requirement R1, including the Measure and VSL focus on the identification of
maintenance method of the Component types and not that the PSMP is in fact
being used for maintenance of the component.
2. The requirement R5 indicates the entity has to "demonstrate" efforts to correct
identified unresolved maintenance issues. The measure M5 described
documentation of the efforts. The requirement language should be explicit. Does
the standard want a demonstration which implies active role of the entity to
prove what it is doing, or to provide documentation of the activities underway to
correct deficiencies? The language in the requirement should be altered to "Each
Transmission Owner, Generator Owner, and Distribution Provider shall prepare a
CAP for each identified Unresolved Maintenance Issue." A second requirement is
needed to require that "Each Transmission Owner, Generator Owner, and
Distribution Provider shall complete its CAP to correct the identified Unresolved
Maintenance Issues." The measures would need to be adjusted accordingly to
reflect the CAP and evidence that the entity completed the CAP.
3. Re Terms defined for use only within PRC-005-2: The standard provides
definitions which will not be incorporated into the Glossary of Terms. This would
allow the definitions as used in this standard to conflict with the definition used in
other standards if this practice becomes more widespread and would reduce the
cohesiveness of the standard set.
4. Re The definition of Components: The standard defined what constitutes a
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Question 4 Comment
control circuit as a component type with "Control circuitry associated with
protective functions through the trip coil(s) of the circuit breakers or other
interrupting devices." The standard then modified the definition by allowing "a
control circuit Component is dependent upon how an entity performs and tracks
the testing of the control circuitry." The definition should not be dependent upon
practice. This makes the definition a fill in the blank definition. Either eliminate
the allowance or remove the definition of control circuit.
Response: Thank you for your comments.
1. The SDT believes that the definition of a PSMP is linked to Requirement R1 in that the entity’s program shall include one or all
of the parameters in the definition. Requirement R1 requires that the entity establish their program and is the foundation for
the standard. Requirements R3-R4 address implementation of the entity’s PSMP.
2. The term within Requirement R5, “… demonstrate efforts …” is intended for both – that the entities are acting to correct the
deficiency and also (to prove compliance) maintaining documentation of the activities underway to correct the deficiency. The
SDT elected to not require a “Corrective Action Plan,” as defined in the NERC Glossary of Terms, to avoid much of the systemic,
ongoing documentation attendant to that term. However, if an entity wishes to use a Corrective Action Plan as defined, that
would be an acceptable method of meeting Requirement R5.
3. The standard specifies that the terms used are intended for this document only; and, therefore, there should not be any
conflict with their use in any other PRC standard.
4. The intent of the different means of identifying control circuitry was to accommodate various entities’ philosophies on testing
of these circuits. Regardless of how an entity chooses to identify their control circuitry, the entity must meet the requirements
of the standard regarding maintenance of control circuitry.
Independent Electricity
System Operator
Negative
The IESO continues to disagree with the VRF assigned to the new Requirements R3
and R4. R3 and R4 ask for implementing the maintenance plan (and initiate corrective
measures) whose development and content requirements (R1 and R2) themselves
have a Medium VRF. Failure to develop a maintenance program with the attributes
specified in R1, and stipulation of the maintenance intervals or performance criteria
as required in R2, will render R3/R4 not executable. Hence, we reiterate our position
that the VRF for R3 be changed to Medium.
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Question 4 Comment
Response: Thank you for your comments.
The SDT team disagrees and believes the failure to implement a PSMP should be assigned a VRF of High.
Illinois Municipal Electric
Agency
Negative
The inconsistency between the proposed Protection System language in the
Applicability section of PRC-005-2 and the transmission Protection System
interpretation recently approved by FERC (PRC-005-1b Appendix 1) needs to be
resolved.
Response: The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term “transmission Protection System,” and notes that this term is not used
within PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems that
are installed for the purpose of detecting Faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference
Document for additional discussion.
Central Lincoln PUD
Negative
The percentage based VSL unreasonably penalizes smaller entities, since one
Component can cause them to hit the 10% cutoff for a High VSL while a large entity
may miss 100s of components without exceeding the Lower VSL.
Response: Thank you for your comments.
A smaller entity will have less to maintain in accordance with the standard; and, thus, the percentages are still appropriate.
JEA
Negative
This standard greatly expands the scope of work that will be required of JEA without
providing a corresponding incremental increase in reliability and may in fact cause
reliability issues. Specific concerns are that JEA believes that we do continuous
monitoring of a vast majority of our components and our approach has demonstrated
its effectiveness but the revised standard will most likely require JEA to have to adopt
a new approach with significant increases in manpower hours. Additionally, testing
lockouts is of great concern because of its ability to cause reliability issues.
Response: Thank you for your comments.
The SDT believes that performing these maintenance activities will benefit the reliability of the BES. If your components are
monitored according to the attributes specified in Table 1-1 through 1-5, you may be able to utilize the extended intervals/minimized
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Question 4 Comment
activities associated with those monitoring attributes within the tables. The SDT believes that electromechanical lockout relays need
periodic operation. As such, these devices are required to be exercised at the same six-year interval required for electromechanical
relays. The SDT recognizes the risk of ‘human error’ trips when testing lockout devices, but believes these risks can be managed.
Performance-based maintenance is an option if you want to extend your intervals beyond six years.
City and County of San
Francisco
Negative
VSL's are based upon Failure to Maintain Percentages for "a specific Protection
System component type". VSL's should be based upon Failure to Maintain
Percentages for total number of Protection System components, and not give greater
weight in the VSL determination, to component types with few elements, like station
batteries.
Response: Thank you for your comments.
The SDT believes that these VSLs should address failures to maintain percentages of each Component Type. Failure to maintain
quantities of low-population Component Types, such as station batteries, may have serious consequences for BES reliability, and the
SDT believes that these must not be masked by larger populations of other Component Types, such as protective relays.
Gainesville Regional Utilities
Negative
We support FMPA's position on this matter.
Response: Thank you for your comments. Please see our response to FMPA’s comments.
Blachly-Lane Electric Co-op
Georgia Power Company
Georgia Transmission Corp.
Western Electricity
Coordinating Council
SMUD
Western Farmers Electric
Cooperative
Central Electric Cooperative,
Inc. (Redmond, Oregon)
Clearwater Power Co.
Consumers Power Inc.
Affirmative
Affirmative
Affirmative
Affirmative
Please see "PNGC Comment Group" for our comments.
Refer to Comments submitted by Antonio Grayson.
Affirmative
Affirmative
Affirmative
Please see "PNGC Comment Group" for our comments.
Affirmative
Affirmative
Please see "PNGC Comment Group" for our comments.
Please see "PNGC Comment Group" for our comments.
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Organization
Coos-Curry Electric
Cooperative, Inc
Fall River Rural Electric
Cooperative
Lane Electric Cooperative,
Inc.
Northern Lights Inc.
Pacific Northwest
Generating Cooperative
Raft River Rural Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative, Inc.
Ohio Edison Company
MidAmerican Energy Co.
Madison Gas and Electric Co.
Great River Energy
Omaha Public Power District
Muscatine Power & Water
North Carolina Electric
Membership Corp.
Midwest ISO, Inc.
MidAmerican Energy Co.
Southwest Transmission
Cooperative, Inc.
Yes or No
Question 4 Comment
Affirmative
Please see "PNGC Comment Group" for our comments.
Affirmative
Please see "PNGC Comment Group" for our comments.
Affirmative
Please see "PNGC Comment Group" for our comments.
Affirmative
Affirmative
Please see "PNGC Comment Group" for our comments.
Please see "PNGC Comment Group" for our comments.
Affirmative
Please see "PNGC Comment Group" for our comments.
Affirmative
Affirmative
Please see "PNGC Comment Group" for our comments.
Please see "PNGC Comment Group" for our comments.
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Please see FirstEnergy's comments submitted through the formal comment period.
Please see MidAmerican and MRO NSRF Comments.
Please see MRO NSRF comments
Please see MRO NSRF comments.
Please see MRO NSRF Comments.
Please see the comments submitted by MRO NSRF
Please see the formal comments submitted by ACES Power Marketing.
Affirmative
Affirmative
Affirmative
See Comments submitted by the MRO NSRF.
See MidAmerican and NSRF comments
1. The first part of definition of a Countable Event should be modified as follows:
“The failure of a Component such that it requires repair or replacement...”. As it is
currently word, it is technically counting the Component as the Countable Event
and not the failure of the component. Considering that the other two items that
are Countable Events are conditions and misoperations, it seems appropriate to
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Question 4 Comment
make failure the Countable Event.
2. Application of this standard to UFLS is problematic as worded in Section 4.2.2.
The UFLS are only applicable if “installed per ERO underfrequency load-shedding
requirements”. Technically, no UFLS fits this description because there are no
ERO requirements to have a UFLS. PRC-006-0 was never approved by the
Commission and is not enforceable. The Commission considered it a “fill-in-theblank” standard. While PRC-006-1 corrects the “fill-in-the-blank” issues and was
approved by the NERC BOT November 4, 2010, the Commission has yet to act on
it.
3. The data retention requirement for the Protection System Maintenance Program
documentation seems excessive. The Data Retention section states that all
versions since the last compliance audit must be maintained. Since TOs, GOs, and
DPs are all on six year audit cycles, this would require maintaining this
documentation for six years. Is this really necessary? The length could become
even greater once NERC implements registered entity assessments that could
shorten or lengthen the periods between compliance audits. The data retention
requirements for Requirements R2, R3, R4, and R5 are not consistent with NERC
Rules of Procedure. Section 3.1.4.2 of Appendix 4C - Compliance Monitoring and
Enforcement Program states that the compliance audit will cover the period from
the day after the last compliance audit to the end date of the current compliance
audit. The data retention requirements compel the registered entity to retain
documentation for the longer of “the two most recent performances of each
distinct maintenance activity for Protection System Components, or all
performances of each distinct maintenance activity for the Protection System
Component since the previous scheduled audit date”. While it may have been
intended to apply to both clauses, the “since the previous schedule audit date”
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Question 4 Comment
only applies to the second clause. Since some of the maintenance activities have
intervals of 12 years, this would require the registered entity to retain
documentation for 24 years which cannot be audited since it is outside the audit
window per the Rules of Procedures. At a minimum, we suggest clarifying that the
documentation must not be maintained past the day after the last audit
completion date.
4. In the fourth paragraph of the Data Retention section, Component is not used
consistently. It is used in both singular and plural form. It seems like it should be
one or the other.
5. Requirement R1 VSLs: For the High VSL, “entities’” should be “entity’s” to be
consistent with the other VSLs.
6. It is not clear why missing three component types jumps to a Severe VSL. Missing
two is a Moderate VSL. Missing three should be a High VSL.
Response: Thank you for your comments.
1. The SDT agrees with your comments on Countable Event, and has modified the definition of Countable Event to: “A failure of a
Component requiring …”
2. Applicability Clause 4.2.2 applies to whatever ERO-required UFLS that may exist, either today or in the future. NERC Reliability
Standard PRC-006-1 has now been approved by FERC.
3. The SDT believes that all versions of the entity’s PSMP should be retained for audit purposes. For a Compliance Monitor to be
assured of compliance, the SDT believes the Compliance Monitor will need the data of the most recent performance of the
maintenance, as well as the data of the preceding maintenance to validate that entities have been in compliance since the last
audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data retention in the posted
standard to establish this level of documentation.
4. The SDT has corrected the fourth paragraph of the Evidence Retention section as you suggested.
5. The SDT has corrected the Requirement R1- High VSL, as you suggested.
6. The SDT believes that missing three components is considered a “significant percentage,” and is in accordance with the VSL
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Question 4 Comment
Guidelines.
Oncor Electric Delivery
Affirmative
The proposed consolidation of these standards (PRC-005-1, PRC-008-0, PRC-11-0 and
PRC-017-0) provides more clarity and less room for varying interpretations for relay
maintenance and testing.
Response: The SDT thanks you for your comment and affirmative vote.
Southern Company
Generation
For the 18 month / 6 year activities, it is technically incorrect to allow equivalency
between internal ohmic measurements and performance testing. This view is not
substantiated by industry experience, documentation, or standards. Additionally, it
should be specified to the auditor that the intervals for the battery maintenance are
relevant to the component, not the application. This means that if a battery is
replaced just before a required 6 year performance test, the 6 year interval for the
performance test is reset.
Response: Thank you for your comment. The drafting team agrees with your statement, and those of others concerning the true
capacity of the station battery and relating it to internal ohmic measurements. Tables 1-4a, 1-4b and 1-4c have been modified for
clarity, and the Supplemental Reference and FAQ document will be modified to further elaborate on these concerns.
The SDT agrees with your assessment that the maintenance activity is relevant to the component, not the application. Guidance to
the auditors of this nature is beyond the ability of the SDT. See Section 4.1 of the Supplementary Reference and FAQ document for
additional discussion on this topic.
Ameren
(a) R3 & R4: Change VRF to “Medium” for the following reasons:
(i) Consistency
with existing standards that PRC-005-2 replaces. Per the
VRF_Standards_Applicability_Matrix_2012-03-01, PRC-005-1b R2 VRF is Lower, PRC008-0 R2 VRF is Medium, PRC-011-0 R2 VRF is Lower, and PRC-017-0 R2 VRF is Lower.
(ii) We are not aware that lack of Protection System maintenance alone has directly
caused or contributed to bulk electric system instability, separation, or a cascading
sequence of failures. (iii) Many entities do not presently perform several of the
proposed minimum maintenance activities, and/or perform maintenance activities at
greater than the PRC-005-2 maximum interval. Yet BES system instability, separation,
or cascading sequence of failure events are extremely rare. (iv) Either change VRF to
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Question 4 Comment
Medium, or double the percentage ranges applied to each component type across
VSLs. We strongly believe that the SDT needs to retune these to match the
experienced risk, which has been extremely low.
(b) Measure M3 on page 6 should only apply to 99.5% of the components. Please
revise to state: “Each ... shall have evidence that it has implemented the Protection
System Maintenance Program for 99.5% of its components and initiated....” We
believe that PRC-005-2 unrealistically mandates perfection without providing
technical justification. A basic premise of engineering is to allow for reasonable
tolerances, even Six Sigma allows for defects. Requiring perfection may well harm
reliability by distracting valuable resources from higher priority duties concerning the
Protection System. We are not asking for the VSL to be changed. The consequence of
a very small number of components having a missed or late maintenance activity is
insignificant to BES reliability. Our proposed reasonable tolerance sets an appropriate
level of performance expectation. We disagree with the notion that this is “nonperformance”.
(c) Measure M5 - add ‘internal inventory / parts request, trouble investigation
assignment, trouble repair report’ as examples of an entity undertaking efforts with
internal parts and/or labor resources.
(d) Augment R3 and R4 VSL with a ‘number based limit for populations up to 100
components’ for comparable treatment of small entities. For example, for Lower VSL
restate as ‘...the responsible entity failed to maintain from one to five Components if
total Components is less than 100; or 5% or less of the total Components if total
exceeds 99 included within a specific Protection System Component Type...’.
Otherwise a small entity could unfairly incur a Severe violation for the same number
of Components that a larger entity would incur a Lower VSL. (i) Similarly, Moderate
numbers should be 6 to 10; High 11 to 15; and Severe 16 or more if the total
Components of a certain Component Type that is less than 100.
(e) Augment R5 VSL with percentage based limits for comparable treatment of larger
entities. For example, for Lower VSL restate as ‘The responsible entity failed to
undertake efforts to correct 5 or less Unresolved Maintenance Issues if total of such
issues in the audit period is less than 100; or 5% or less if total of such issues in the
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Question 4 Comment
audit period exceeds 99.’ (i) Similarly, Moderate numbers should be >5% to 10%; High
>10% to 15%; and Severe more than 15% if the total Unresolved Maintenance Issues
in the audit period exceeds 99.
(f) Please number all pages of the standard. They are missing from pages with tables.
(g) Please add a title to the table following Table 3. Is it a continuation of Table 3?
Response: Thank you for your comments.
a) The SDT disagrees, and believes a VRF of High is appropriate for Requirements R3 and R4.
b) NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation.
c) The SDT agrees that the examples listed would constitute evidence of undertaking efforts to correct Unresolved Maintenance
Issues; however, Measure M5, as written, includes the phrase, “… includes but is not limited to …” to emphasize that entities may
use other evidence.
d) The SDT disagrees and believes a smaller entity will have less to maintain in accordance with the standard; and, thus, the
percentages are still appropriate.
e) The SDT disagrees and believes the VSL’s for Unresolved Maintenance Issues should be a numeric quantity and not a percentage.
In response to each of the comments ‘a’ through ‘e’, the SDT recommends reviewing the “VRF/VSL Justification” that is posted with
the standard. This document provides the SDT’s analysis of how the VRFs and VSLs meet FERC and NERC guidelines, as required for
the standard to achieve regulatory approval.
f) The SDT numbered all the pages.
g) The SDT corrected the Table 3 header issue.
Sacramento Municipal Utility
District
1) SMUD wishes to comment on the requirement to test the trip paths from relays
that do not respond to electrical quantities. In two separate sections of the FAQ, the
SDT included this new guidance on the trip paths. In section 2.4.1 of the FAQ, the SDT
plainly asserts that the trip path from Sudden Pressure Relays (SPR) will now be
covered and implies that the trip paths from non-electrically initiated devices might
also be covered. In section 2.4.1, the SDT does not provide any guidance on how to
determine which trip paths are included, but does provide guidance on how one
might test the trip path. In section 15.3, the SDT finally provides the guidance -
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Question 4 Comment
control circuits (trip paths) are included if the relay is installed to detect faults on BES
Elements. In reviewing the definition of Protection System, SMUD feels the “Control
circuitry associated with protective functions...” to be in reference to the “Protective
relays which respond to electrical quantities”. The SDT is now applying a new
interpretation in which each of the five bullets is considered separately. Furthermore,
the SDT appears to be defining “...associated with protective functions...” to mean
detecting faults on the BES. What basis can the SDT offer for defining this phrase to
mean detecting faults on the BES? Since this same wording is not used in defining the
relay, can a relay be covered under the standard, but not its control circuitry? For
instance, Out of Step Tripping? Over Excitation? Frequency or Voltage Protection on a
generator? These relays respond to electrical quantities, but are not applied to detect
faults on BES Elements. SMUD believes this interpretation takes us down a very
confusing path. SMUD respectively requests the SDT strike the new wording (as seen
on the redlined version) in 2.4.1 and 15.3.
Response: Thank you for your comments.
1. DC trip circuit from a sudden pressure relay output to the trip coil of the interrupting device has always been included in the
“Control circuitry” portion of a Protection System, and is discussed in Section 15.3 of the PRC-005-2 Supplementary Reference
and FAQ document. In regards to including sudden pressure relays themselves, FERC, in Order 758, recently directed NERC to
submit an informational filing providing a schedule for addressing sudden pressure relays in PRC-005. The NERC System
Protection and Control Subcommittee (SPCS) worked with NERC staff to develop the informational filing, which was filed with
FERC on April 12, 2012. The Standards Committee has directed the PSMTSDT to finalize PRC-005-2 and present it to the NERC
Board of Trustees for adoption, and concurrent with this posting of PRC_005-2, to post for information a draft SAR for a second
phase of Project 2007-17 addressing further modifications to PRC-005-2.
Activities associated with the schedule submitted in the filing will be included in the final SAR to further develop PRC-005. The
SDT believes that Protection Systems that trip (or can trip) BES Elements due to a Fault should be included (in the case of a Sudden
Pressure Scheme, the control circuitry and DC supply components would apply). The relays mentioned are already covered by the
standard, in that they are “Protection Systems that act to trip the generator either directly or via lockout or auxiliary tripping
relays.”
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Organization
Tennessee Valley Authority
Yes or No
Question 4 Comment
1. Regarding the functional test required every 3 months for “unmonitored
communication systems” in Table 1-2 of the PRC-005-2 Draft. TVA feels that a
Maximum Maintenance Interval for the Functional Test should be every 12 months
until auto-checkback has been fully implemented by the utility.
2. The Implementation Plan for PRC-005-2 Step 4 on Page 2 states: “The
Implementation Schedule set forth in this document requires that entities develop
their revised Protection System Maintenance Program within twelve (12) months
following applicable regulatory approvals, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twentyfour (24) months following NERC Board of Trustees adoption. This anticipates that it
will take approximately twelve (12) months to achieve regulatory approvals following
adoption by the NERC Board of Trustees.” TVA feels that this is not sufficient time to
implement full auto-checkback capability at some utilities. The time schedule of
twelve (12) months should be forty-eight (48) months following applicable regulatory
approvals.
3. TVA has many excitation transformers directly connected to the generator bus,
configured such that a fault on the excitation transformer will cause a generator trip.
Is the intent that the revised standard will include these transformers in the
applicability? Would they be included by section 4.2.5.1?
4. TVA (Rusty Hardison) has forwarded a slide presentation with six questions to the
PRC-005-2 Draft Team requesting consideration as input to the Frequently Asked
Questions document accompanying the standard. Thank you for considering.
Response: Thank you for your comments.
1) The SDT believes the four month interval is proper for unmonitored communications systems. The activity related to this interval
is to verify basic operating status.
2) The Implementation Plan is intended to facilitate implementation of the standard, not to facilitate modifications to meet the
requirements of the standard.
3) The SDT revised Applicability Clause 4.2.5.4 to include excitation transformers connected to the generator bus.
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4) The SDT modified the Supplementary Reference and FAQ document to address these questions.
Tacoma Public Utilities
1. For components that are part of a time-based PSMP, if correction of Unresolved
Maintenance Issues takes place before the maximum maintenance interval expires, is
it mandatory to demonstrate (document) these efforts to correct identified
Unresolved Maintenance Issues? Is the purpose of Requirement R5 only to avoid
compliance jeopardy when an entity discovers a problem during maintenance but
cannot correct the problem until after the maximum maintenance interval has expired
(as discussed in the Supplemental Reference and FAQ document)? Or, is the purpose
also to ensure that all Unresolved Maintenance Issues are documented even if they
corrected very quickly and within the maximum maintenance intervals and just
considered part of routine maintenance (i.e., Unresolved Maintenance Issues not
explicitly documented) in a manner similar to recalibrating a relay?
2. Assume that a component under a time-based PSMP is not considered “monitored”
per the PSMP, but in actuality it is. If an alarm comes in, indicating a component
problem, would the entity have any additional documentation obligations under PRC005-2 associated with this alarm, provided that all minimum maintenance activities
and maximum maintenance intervals associated with the unmonitored component
are satisfied? The concern is that, if there are additional documentation obligations;
then many entities may disable monitoring in some cases in order to avoid compliance
jeopardy.
3. Assume that an entity treats batteries at certain remote communication sites as if
they were applicable to PRC-005-2. These sites are not substations or generating
facilities but support the broad communication system, including teleprotection
functions. Furthermore, these sites have limited access during some times of the year
because of heavy snow or ice. It is conceivable that it may not be possible to meet all
minimum maintenance activities or all maximum maintenance intervals (4 and 6
calendar months) unless the site is extensively monitored and/or field personnel
expose themselves to hazard. Would any allowances be made in these cases? Would
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these sites even be applicable to PRC-005-2, since they are not part of a “station” DC
supply?
4. It is still unclear whether Section 15.3 permits periodically verifying DC voltage at
the actuating device trip terminals as an acceptable method of accomplishing the
maintenance activity identified in Table 1-5 for unmonitored control circuitry
associated with protective functions. It is recommended that this approach be
considered acceptable, provided that auxiliary relays are operated within the
maximum maintenance interval.
5. In the Implementation Plan for Requirements R1, R2, and R5, why there is a
requirement to “be 100% compliant [with R5] on the first day of the first calendar
quarter twelve (12) months following applicable regulatory approvals”? The emphasis
of this question is on Requirement R5, which pertains to Unresolved Maintenance
Issues.
6. In the Implementation Plan for R3 and R4, to be considered “100% compliant with
PRC-005-2,” is it only necessary to have completed the applicable minimum
maintenance activities one time for the applicable component (which is our
assumption)? Or, does being considered 100% compliant under this Implementation
Plan imply that two instances of the applicable minimum maintenance activities must
have been completed for the applicable component?
Response: Thank you for your comments.
1. The definition of Unresolved Maintenance issue has been revised to specify that it applies to deficiencies that “…cannot be
corrected during the maintenance interval...”
2. The SDT believes that as long as all minimum maintenance activities and maximum maintenance intervals associated with a
component are completed and documented, no additional documentation obligations are necessary.
3. The SDT does not believe that the scope of the standard refers to communication sites. The SDT believes that a loss of power
to the communications systems at a remote site would cause the communications systems associated with protective relays
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to alarm at the substation. At this point, the corrective actions can be initiated.
4. The SDT believes that every trip path from relay to trip coil must be verified. If a trip coil has multiple trip paths, verifying DC
voltage at the actuating device would not accomplish the maintenance activity identified in Table 1-5 for unmonitored control
circuitry.
5. The SDT believes that the entity be 100% compliant with Requirement R5 on the first day of the first calendar quarter because
an Unresolved Maintenance Issue could arise during the first calendar quarter.
6. The Implementation Plan addresses the initial performance of the required activity within the required intervals. The entity
should expect to comply with PRC-005-1B until they fully implement PRC-005-2.
Texas Reliability Entity
1. The Implementation Plan is still overly long and complicated. Registered Entities
and Regional Entities will have to track and apply multiple versions of this standard for
up to 14 years. It would be preferable to have a much shorter implementation plan,
so that only one version of the standard will be applicable at any given time,
recognizing that for some Components no action will be required under the standard
for a number of years.
2. Referring to R3, R4 and M1 (and other places), it is redundant to add “Protection
System” to describe “Components “or “Component Types” based on the “local
definitions” provided. Alternatively, the defined term could be changed to
“Protection System Component” and used consistently.
3. In Table 1-3, the activity should include verifying that the current and voltage signal
values are within tolerances, not just that signal values are present. The minimum
activity should include a ratio check and/or burden check of current transformers.
Suggest revising to state “Verify that current and/or voltage signal values provided to
the protective relays are within the accuracy tolerance of the voltage and current
sensing device”.
4. In the VSL for R2, we are assuming that the “4% within three years” is a 4% failure
rate based on Attachment A, but that is unclear. We suggest clarifying this language
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to match Attachment A language.
5. What is the basis for the 4% failure rate limit in Attachment A? It would appear
that a 4% failure rate is high for protective relays. Does the SDT have a technical
justification supporting the selection of 4% as the applicable limit?
6. In Attachment A, item 4 in the “maintain the technical justification” section needs
clarification. It can be assumed that the phrase “for the greater of either the last 30
Components maintained or all Components maintained in the previous year” is
referring to Components within a specific Segment, but more specific language may
be needed. Also, are the references to “prior year” and “previous year” intended to
refer to calendar years or 365 days preceding the analysis?
7. In Attachment A, item 5 in the “maintain the technical justification” section needs
clarification. We suggest adding a timeframe for the “experience 4% or more
Countable Events” phrase. Does this refer to any 12-month period? Additionally, the
determination of a timeframe for “4% of the Segment population” is needed.
Example- If there are 100 Components in a performance-based Segment in Year 1 and
I add an additional 100 Components in Year 2, is the 4% based on 100 or 200?
Response: Thank you for your comments.
1. The SDT disagrees, and believes that having a shorter implementation plan would not allow entities to complete the
requirements. The Implementation Plan is designed to allow an entity to systematically implement PRC-005-2 such that an
ongoing program may be facilitated.
2. Strictly speaking, you are correct. However, the SDT has elected to include the emphasis, “Protection System” in these
locations to help clarify that such components are only in-scope where they are part of the “Protection System.”
3. The SDT disagrees. Verify is defined as, “Determining that the component is functioning correctly.” If the signals to the relay
are beyond tolerance, the component is not functioning correctly.
4. The SDT agrees and has corrected the Requirement R2 VSL to indicate “…no more than…”
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5. The SDT chose 4% because an entity with a small population (30 units) would have to adjust its time intervals between
maintenance if more than one countable event was found to have occurred during the last analysis period. A smaller
percentage would require that entity to adjust the time interval between maintenance activities if even one unit is found out
of tolerance or causes a Misoperation (see Supplemental Reference and FAQ Section 9.1).
6. The SDT affirms that all references to “prior year“and “previous year” refer to “calendar year.”
7. The time frame refers to a calendar year. The 4% failure rate is determined from those Component segments tested in the
previous calendar year.
TransAlta Centralia
Generation LLC
1.3 Evidence Retention. The standard said: For Requirement R2, R3, R4 and R5, the
Transmission Owner, Generator Owner and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance.
How to count” the most recent performance “. Is this Standard going forward basis?
For some of the protection system component, the maximum maintenance interval is
12 years (such as CT, PT or microprocessor relay) on the standard, how to count the
two most recent performance?
Response: Thank you for your comments.
For a Compliance Monitor to be assured of compliance, the SDT believes the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding maintenance to validate that entities have been in
compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data
retention in the posted standard to establish this level of documentation, which is consistent with the current practices of several
regional entities.
PacifiCorp
1: The definition of “Protection System” in this version of PRC-005-2 includes “station
dc supply associated with protective functions...” as a Protection System component.
Page 83 of the FAQ document accompanying the draft standard provides further
clarification that the batteries covered under PRC-005-2 are those that “supply the
trip current to the trip coils of the interrupting devices that are a part of the
Protection System.” This statement in the FAQ is much more limiting than the
definition of Protection System and may create confusion concerning registered
entities’ compliance obligations. For example, a registered entity may have one
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battery / charger system in a station that supplies DC voltage to communication
equipment, including that utilized in transfer trip communication, while a separate
battery (typically operating at a different DC voltage) is utilized for relay / trip coil
operation. In this case, it is unclear whether the battery / charger system utilized for
transfer trip communication is subject to the requirements of the standard.
PacifiCorp recommends that NERC or the SDT reconcile this apparent inconsistency in
the FAQ document.
2: In Tables 1-4(a) thru 1-4(d), the maximum maintenance interval of four calendar
months includes inspection “for unintentional grounds.” PacifiCorp seeks clarification
on whether this maintenance activity is intended to target the detection of
unintentional grounds on the battery bank / rack itself, or a ground located anywhere
on the entire DC wiring system.
3: The Violation Severity Level (“VSL”) for R5 - which ranges from a failure to correct 5
or less (“Lower” VSL) to greater than 15 (“Severe” VSL) Unresolved Maintenance
Issues - fails to adequately account for the cumulative amount of equipment a
registered entity is required to maintain pursuant to PRC-005-2. A better alternative
approach may be to base the VSL on the cumulative percentage of Unresolved
Maintenance Issues that an entity fails to address and correct. Such an approach
would be more consistent with the VSLs for R3 and R4, which are based on a
percentage of the total scheduled maintenance. This approach more fairly and
reasonably addresses the covered maintenance activities relative to the approach in
the VSLs for R5, which are based on a strict count and therefore independent of the
cumulative amount of maintenance activities performed by a registered entity.
PacifiCorp recommends that the SDT develop an alternative method for determining
VSLs for R5 that reflects the scope of an entity’s maintenance activities and the
resulting Unresolved Maintenance Issues managed by an entity.
Response: Thank you for your comments.
1. The SDT believes the term “Station dc supply” is clearly defined within the standard, and that the definition should be
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considered when applying the term. Your reference to Page 83 of the Supplemental Reference and FAQ Document clarifies
that Table 1-4 of the standard refers to Station Batteries only, and not Communications Site Batteries.
2. The SDT believes the inspection for unintentional grounds applies to the entire DC wiring system.
3. The SDT disagrees and believes the VSL’s for Unresolved Maintenance Issues should be a numeric quantity, and not a
percentage.
Essential Power, LLC
1. This DRAFT Standard is written as a prescriptive ‘procedure’ and not as a
‘Standard’. The SDT should revise the Standard to address the goal, or intent,
rather prescribing how entities should meet the Standard.
2. Inclusion of non-BES elements within the Standard falls outside of NERC’s
jurisdiction, as defined in the EPA 2005. The SDT should remove these elements
from the Standard.
3. The inclusion of dc circuitry for equipment that is itself not covered under the
Standard is not logical and does not contribute to reliability. The SDT should
remove this from the Standard.
Response: Thank you for your comments.
1. The SDT believes the standard describes the desired outcomes and is not a ‘prescriptive procedure’. The entity is free to
determine what maintenance methods are best suited for its program.
2. FPA Section 215(a) Definitions section defines “bulk-power system as … facilities and control systems necessary for operating
an interconnected electric energy transmission network (or any portion thereof).” That definition then is limited by a later
statement which adds the term bulk-power system “does not include facilities used in the local distribution of electric
energy.”
Facilities such as those to which you refer are not solely “used in the local distribution of electric energy,” despite their
location on local distribution networks. Further, if these facilities were not covered by the reliability standards, reliability gaps
would exist.
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3. The SDT believes that Protection Systems that trip (or can trip) for Faults on the BES should be included. This position is
consistent with the SAR for Project 2007-17, and with the position of FERC staff.
MRO NSRF
1. Article 4.2.1 - The NSRF believes that this article should be revised to say
“Protection Systems installed for the purpose of protecting BES Elements only and
detecting Faults on BES Elements. Protection Systems designed to protect nonBES elements that incidentally open 100 kV and greater breakers are excluded
from the scope of PRC-005-2”. This makes it very clear what is included in the
scope of the Testing and Maintenance program and what is not.
2. Change the text of “Standard PRC-005-2 - Protection System Maintenance” Table
1-5 on page 21, Row 1, Column 3 to:”Verify that a trip coil is able to operate the
circuit breaker, interrupting device, or mitigating device.” Or alternately,
“Electrically operate each interrupting device every 6 years “Trip coils are
designed to be energized no longer than the breaker opening time (3-5 cycles).
They are robust devices that will successfully operate the breaker for 5,00010,000 electrical operations. The most likely source of trip coil failure is the
breaker operating mechanism binding, thereby preventing the breaker auxiliary
stack from opening and keeping the trip coil energized for too long of a time
period. Therefore, trip coil failure is a function of the breaker mechanism failure.
Exercising the breakers and circuit switchers is an excellent practice. Exercising
the interrupting devices would help eliminate mechanism binding, reducing the
chance that the trip coils are energized too long. The language as currently
written in Table 1-5 row 1, will also have the unintentional effect of changing an
entities existing interrupting device maintenance interval (essentially driving
interrupting device testing to a less than 6 year cycle).The NSRF believes that as
written the testing of “each” trip coil will result in the increased amount of time
that the BES is in a less reliable system configuration. The NSRF hopes that the
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SDT will consider these changes.
3. The NSRF recommends the statement “Excluding distributed UFLS and distributed
UVLS (see Table 3)” be added to the top of Table 1-4(f).
4. Table 3. There will be many DP’s that have distributed UFLS (or UVLS) solely on
the distribution system (less than 100 kV). The only item these DP’s will have to
verify under Table 3 “Protection System dc supply” is the Protection System dc
supply voltage. Yet, the definition of Protection System, as it relates to dc supply
is “Station dc supply associated with protective functions (including batteries,
battery chargers, and non-battery-based dc supply)”. Our interpretation of Table
3 and Section 15.7 of the Supplementary Reference & FAQ document is that a DP
need only check the dc supply voltage at the terminals of the relays. If that is the
SDT interpretation as well, we recommend revising Table 3 of the standard to
reflect that. Table 3 contains issues that need to be addressed in a similar fashion
as discussed for non-UFLS and non-UVLS systems, i.e. Table 1-1. Comparison to
independent sources is only one way to check for a reliable AC measuring device.
It also appears that monitoring capabilities are not being given any credit in
regards to the AC sensing devices, DC supply, or control circuitry themselves.
There should be no difference in the way these systems are treated compared to
BES Protection Systems.
5. In Section D Compliance, Article 1.3, paragraph 4 the standard requires
documentation be kept for the “. . . two most recent performances of each
distinct maintenance activity. . .”. This needs to clarify that it cannot go back
before 06/18/07, as evidenced by the suspension of CAN-0008. Also with some of
the testing intervals being 12 years that would dictate a Registered Entity
maintain 24 years of records, which is unreasonable. This article should be
revised to have documentation for the most current testing interval, if after
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06/18/07.
6. It is understood that lockout relay testing is important as unexercised lockouts
can stick and cause regional outages as experienced at Westwing. However,
lockout testing by itself is risky and can lead to local outages. If Registered
Entities are required to take on the additional risk of testing lockout relays,
dispensation must be granted for outages caused by those tests. The following
statement should be included in the standard “No enforcement actions or
penalties will result from outages caused by relay testing unless a Registered
Entity shows a history of 3 or more test related outages per year for 5 years.”
7. In the VSL for Table 4 it seems that the phrase “5% or less” should be “not more
than 5%”. With the original language it seems like an entity could be found to
have an R4 lower VSL violation for “failure” of zero meaning they had done no
testing. This VSL is written in the negative and should be rewritten in the positive.
8. The drafting team needs to clarify “maintenance summaries” as stated in
Measure M3. This is an ambiguous term that could be interpreted differently
amongst entities. If a term such as ‘summary’ is to be utilized within the
standard, a clear definition of what the term is, what it pertains to, where it is
located, etc. needs to be included. The NSRF recommends that “maintenance
summaries” be defined and included in the “Definition of Terms used in
Standard” section.
9. Footnote 1 in the Table sections would be much improved by inserting an
example similar to what was provided in Section 8.4 of the Supplemental
Reference and FAQ document
10. Additional methods of verification should be allowed for AC measurement
monitoring other than simply performing comparison to an independent source.
For example, a sudden rate of change in calculated relay MW analog value and/or
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3Io calculation would give way towards a bad CT and/or path. Loss of potential
logic is available in most microprocessor relays today, which is very reliable logic
for determining PT/CCVT issues. Consideration should be given to utilities that
are capable of performing this type of monitoring in order to allow them to reach
that next level of attributes.
11. Please clarify why input/output verification is excluded from the highest level of
monitoring related to communications systems (Table 1-2). The way the
monitoring attribute is listed does not provide that these will operate when
needed. Recommend language be added similar to the monitoring of inputs and
outputs described in the relay section (Table 1-1).
Table 1-3 should take into account the same concepts mentioned above in
regards to AC measurement verification in Table 1-1. There are alternative ways
to verify these quantities while still ensuring reliable operation. As such,
companies should be given the opportunity to implement them. Additionally,
credit should be given to circuit monitoring and alarming in AC circuits with
electromechanical relays. If a transducer/alarming relay is placed in the circuit
and monitoring is alarmed appropriately, the health of the AC sensing device can
be determined. This would essentially provide the same level assurance as
mentioned with the microprocessor relays.
12. Clarification is needed on the last row of Table 1-5. Does integrity entail
monitoring and alarming of every individual path, if necessary, or is overall
integrity sufficient? This statement is once again open to interpretation and
leaves the entity at the mercy of the auditor.
Response: Thank you for your comments.
1. The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES. Please see
Section 2.3 of the Supplementary Reference and FAQ document for additional discussion.
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2. The SDT sees no appreciable change or improvement in the standard with your proposed change, and respectfully declines to
modify the draft.
3. The SDT believes that the suggested change would be redundant to the current text of the Table 1-4(f) header.
4. This is an intentional difference between distributed UFLS/UVLS and the remainder of the Protection Systems addressed
within the standard because of the distributed nature of distributed UFLS/UVLS and because these devices are usually
tripping distribution System Elements. If an entity were to install monitoring equipment for verification of Station DC supply
voltage, or other facets of the reduced maintenance activities regarding distributed UFLS/UFLS, Table 1-3 describes the
adjusted activities permitted relative to that monitoring.
5. The SDT believes the Implementation Plan is descriptive in that an entity will be 100% compliant with PRC-005-2 when one
maintenance period has elapsed. On a continuing basis, in order that a Compliance Monitor can be assured of compliance,
the SDT believes that the Compliance Monitor will need the data of the most recent performance of the maintenance, as well
as the data of the preceding one to validate that entities have been in compliance since the last audit. The SDT has specified
the data retention in the posted standard to establish this level of documentation, which is consistent with the current
practices of several regional entities.
6. The SDT believes it is left to the entity to determine how to align the requirements of the standard with requirements of
other regulations and with operational concerns.
7. The VSL Guidelines, developed in accordance with the FERC VSL Order establish the Lower VSL for stepped VSLs as “5% or
less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and
including) 15%,” and the Severe VSL as “more than 15%.”
8. The SDT believes defining “Maintenance Summaries” is unnecessary. The measure simply lists some types of evidence to
demonstrate that an entity has maintained its Protection System in accordance with the standard.
9. The SDT believes that the footnote is adequate, but recognizes that some entities may desire the additional details that are
included in Section 8.4 of the Supplementary Reference and FAQ document.
10. The SDT believes that the methods that you suggest would be useful for meeting the 12-calendar-year interval for
unmonitored Components. However, for monitored systems with no physical maintenance activities, the SDT is concerned
about the quality of some of the methods suggested.
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11. The SDT has modified the last row of Table 1-2 to be similar to the corresponding row of Table 1-1.
12. Section 15.3 of the Supplemental Reference and FAQ provides the following guidance: “Monitoring of integrity means to
monitor for continuity and/or presence of voltage on each trip path.”
Duke Energy
1. Duke Energy votes “Negative” because we strongly object to the wording in the
Applicability section 4.2.1. We believe that the wording change to PRC-005-2 draft
4 after the Successive Ballot but prior to the Recirculation Ballot expanded the
reach of the standard to relaying schemes that detect faults on the BES but are
not intended to provide protection for the BES. FERC’s September 26, 2011 Order
in Docket No. RD11-5 approved NERC’s interpretation of PRC-005-1 R1 and R2,
stating: “The interpretation clarifies that the Requirements are “applicable to any
Protection System that is installed for the purpose of detecting faults on
transmission elements (lines, buses, transformers, etc.) identified as being
included in the [BES] and trips an interrupting device that interrupts current
supplied directly from the BES.” This interpretation is consistent with the
Commission’s understanding that a “transmission Protection System” is installed
for the purpose of detecting and isolating faults affecting the reliability of the bulk
electric system through the use of current interrupting devices.” The SDT’s
response to our comment directed us to Section 2.3 of the Supplementary
Reference and FAQ document which states “There should be no ambiguity: if the
element is a BES element then the Protection System protecting that element
should be included within this Standard.” We agree with that statement, but
question why the SDT insists on changing Section 4.2.1 to include devices that
detect Faults on the BES but which do not provide protection for the BES? Duke
Energy’s standard protection scheme for dispersed generation at retail stations
would become subject to the standard due to the changes in section 4.2.1. These
protection schemes are designed to detect faults on the BES, but do not operate
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BES elements nor do they interrupt network current flow from the BES. In the
most recent draft, the relays, current transformers, potential transformers, trip
paths, auxiliary relays, batteries, and communication equipment associated with
the dispersed generation protection scheme would be subject to the
requirements in PRC-005-2. Previous drafts of the standard would not have
required Duke Energy to maintain the protection system components associated
with dispersed generation schemes at retail stations in accordance to the
requirements in PRC-005-2. The new wording in section 4.2.1 would add
significant O&M costs and resource constraints due to the inclusion of protection
system devices at retail stations without increasing the reliability of the BES. Duke
Energy does not believe it was the intent of the standard to include elements that
did not have an impact on the reliability of the BES. Duke Energy would prefer the
following definition: Protection Systems that are installed for the purpose of
protecting BES Elements (lines, buses, transformers, etc.)”.
2. We also note that the Lower VSLs for R3 and R4 include violations for “5% or
less,” and R5 for “5 or less” which mandates perfection. We believe that the
consequence of a very small number of components having a missed or late
maintenance activity is insignificant to BES reliability.” We suggest that a range of
0.5% to 5% would be more reasonable.
Response: Thank you for your comments.
1. The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES. The SDT
observes that the approved Interpretation addresses the term “transmission Protection System,” and notes that this term is
not used within PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses
“Protection Systems that are installed for the purpose of detecting Faults on BES Elements.” Please see Section 2.3 of the
Supplementary Reference and FAQ document for additional discussion.
2. NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation. Much
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of this comment appears to be related to the technical content of the standard, not on the VRFs or VSLs.
PPL Supply NERC Registered
Organizations
Although we have provided some suggested changes in these comments, PPL
Generation entities voted in favor of this version. We thank the SDT for the effort on
this project and believe that the SDT has developed a revision that improves on many
aspects of the existing version of PRC-005.
Response: The SDT thanks you for your affirmative vote.
ExxonMobil Research and
Engineering
As written, the current draft of PRC-005-2 discriminates against smaller entities that
do not have a population size of 60 for each component type. Historical records
provide an accurate account of how specific components have performed in their
installed environment. For a set population size, increasing the number of historical
data points should improve the accuracy of an entity’s calculated mean time between
failures, so, if you increase the period over which the historical data must be
evaluated, you can compensate for a smaller segment population size. The SDT’s
current draft prevents smaller entities from using a larger historical data set to make
up for a smaller population size when developing a performance based protective
system maintenance and testing program. The SDT should reconsider allowing
smaller entities to use historical records that extend for period longer than a single
year in the development of a performance based program.
Response: Thank you for your comment. Small entities are permitted to aggregate their components with similar components of
other entities to meet the component populations, as long as the programs are (and remain) similar – See Section 9 of the
Supplementary Reference and FAQ document and the associated footnote to Attachment A. Decreasing the Component population
below the requirements of Attachment A will result in an unsound program due to Component populations that are not statistically
significant. The Supplementary Reference and FAQ document states, “Any population segment must be comprised of at least 60
individual units; if any asset owner opts for PBM but does not own 60 units to comprise a population then that asset owner may
combine data from other asset owners until the needed 60 units is aggregated.” Historical data may be good for trending, but may
not be suitable for judging current maintenance program effectiveness.
American Transmission
Company, LLC
ATC recommends that the SDT change the text of “Standard PRC-005-2 - Protection
System Maintenance” Table 1-5 on page 21, Row 1, Column 3 to:”Verify that a trip coil
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is able to operate the circuit breaker, interrupting device, or mitigating device.” Or
alternately, “Electrically operate each interrupting device every 6 years “Basis for the
change: Trip coils are designed to be energized no longer than the breaker opening
time (3-5 cycles). They are robust devices that will successfully operate the breaker
for 5,000-10,000 electrical operations. The most likely source of trip coil failure is the
breaker operating mechanism binding, thereby preventing the breaker auxiliary stack
from opening and keeping the trip coil energized for too long of a time period.
Therefore, trip coil failure is a function of the breaker mechanism failure. Exercising
the breakers and circuit switchers is an excellent practice. ATC would encourage
language that would suggest this task be done every 2 years, not to exceed 3 years.
Exercising the interrupting devices would help eliminate mechanism binding, reducing
the chance that the trip coils are energized too long. The language, as currently
written in Table 1-5 row 1, will also have the unintentional effect of changing an
entities existing interrupting device maintenance interval (essentially driving
interrupting device testing to a less than 6 year cycle).ATC continues to recommend a
negative ballot since we believe that the testing of “each” trip coil will result in the
increased amount of time the BES is in a less intact system configuration. ATC hopes
that the SDT will consider these changes.
Response: Thank you for your comment. The SDT sees no appreciable change or improvement in the standard with your proposed
change, and respectfully declines to modify the draft.
Bonneville Power
Administration
BPA believes that PRC-005-2 achieves the goal of reducing redundancy and overlap
within the PRC standards by consolidating four existing standards into one. BPA's
comments are focused on improving the clarity and audit-ability of the proposed
standard.
1. Regarding Section D1.3 “Evidence Retention”, BPA suggests that the entire first
paragraph be removed because for all the instances that follow the first
paragraph there is a requirement to keep evidence obtained since the last audit.
Therefore, there are no instances where the evidence retention period is shorter
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than the time since the last audit, and the first paragraph is not necessary.
Furthermore, the first paragraph introduces the idea of “other evidence” for
which there is no explanation. It is unclear what could be used for evidence
other than the items described in the
2. Measures. The idea of “other evidence” should not be introduced without an
explanation of what that evidence might be, so this is another reason for
removing the first paragraph.
3. Regarding requirements R2 and R4, BPA believes that these two requirements
should be combined into a single requirement with two parts. Since both of
these requirements deal with performance-based maintenance, it would simplify
the standard and improve the flow if they were to be combined.
4. Regarding Table 1-4(f), it is unclear if all of the conditions on the left side need to
be met before any of the reduced maintenance activities on the right side are
allowed, or if there is a one-on-one relationship between an item on the left and
the adjacent item on the right. BPA suggests that the table be reconfigured to
clarify the relationship between the conditions on the left and the activities on
the right.
Response: Thank you for your comments and support.
1. The SDT has been advised to include this paragraph as the first paragraph in the evidence retention.
2. The list of possible evidence with the measures is not intended to provide a comprehensive list of all type of evidence that may
be useful. The entity is provided the flexibility to use other evidence that they deem relevant.
3. Requirements R2 and R4 are separate, as they address two specific requirements; one to establish a performance-based PSMP
according to criteria, and the other to implement that PSMP.
4. There is a one-to-one correspondence between the right and left columns, and the SDT believes that further clarification is
unnecessary.
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CenterPoint Energy
Yes or No
Question 4 Comment
1. CenterPoint Energy recommends retaining an option to utilize technology for
monitoring trip coil continuity as an alternative to the maintenance activity in
Table 1-5. The Table 1-5 requirement to "Verify that each trip coil is able to
operate the circuit breaker, interrupting device, or mitigating devices (regardless
of any monitoring of the control circuitry)" appears to address breaker
maintenance, instead of Protection System Controls. In the Supplementary
Reference and FAQ, monitoring is described as greatly reducing the time between
a component failure and discovery of that failure.
2. For the “Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (Excludes non-BES trip coils)”, the Table
3 requirement is to “Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic)” every 12 calendar years.
CenterPoint Energy recommends this requirement be revised to “No periodic
maintenance specified”. CenterPoint Energy believes this to be a commissioning
task, not a preventive maintenance task. A preventive maintenance task, such as
the above, is unnecessary for distributed UFLS and UVLS system components.
The overriding performance, or “risk-based”, NERC Reliability Standards for UFLS
are PRC-006 and PRC-007 where an entity is required to shed their obligated firm
load amount.
3. For the “Unmonitored control circuitry associated with protective functions
inclusive of all auxiliary relays”, the Table 1-5 requirement is to “Verify all paths of
the trip circuits inclusive of all auxiliary relays through the trip coil(s) of the circuit
breakers or other interrupting devices” every 12 calendar years. CenterPoint
Energy recommends this requirement be revised to “No periodic maintenance
specified”. CenterPoint Energy believes that verifying all tripping paths is a
commissioning task, not a preventive maintenance task. Alternatively,
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CenterPoint Energy recommends specifically excluding panel wiring and requiring
only cabling between panels and interrupting devices be verified. Requiring trip
path verification to include panel wiring complicates maintenance while focusing
on a component that is not subject to age-related degradation in addition to,
historically, not being a source of protection system failures. This type of testing
can negatively impact BES system reliability with the outages that are required
and by exposing the electric system to incorrect tripping.
Response: Thank you for your comments.
1. While trip coil monitors may demonstrate continuity, they do not fully demonstrate operability.
2. The SDT disagrees regarding UFLS and UFLS-related control circuitry maintenance, and believes that the maintenance specified is
appropriate.
3. The SDT disagrees with your proposal regarding Table 1-5 for dc control circuits and auxiliary relays which may be a critical part of
a tripping scheme.
Central Lincoln
Central Lincoln appreciates the good work the SDT has done. We believe this
particular team has actually listened to our comments and made changes where
needed. Thanks.
Response: The SDT thanks you for your affirmative vote.
Constellation/Exelon
Constellation/Exelon thanks the drafting team for the hard work on the PRC-005
standard. The standard language made significant progress; however, below are
outstanding issues of concern:
Table 1-3
1. Table 1-3 should not include current transformers (CTs). The tests mandated by
this draft seeks to measure that a signal is “provided to the protective relay”
however, for CT’s this test merely confirms that a signal is sent, not that it
reached the correct protective relay.
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2. The maintenance activity in Table 1-3 for PTs and CTs as they relate to electro
mechanical relays should be left to the discretion of the Generator Owner. In
order to meet the required activity specified in PRC-005-2 draft 2 Table 1-3, the
generating unit would be required to take readings with meters while the unit is
operating. This practice introduces a risk of tripping the unit inadvertently. The
risk of tripping the unit while performing this maintenance activity is contrary to
the intended purpose of PRC-005 and introduces a potentially adverse affect on
the reliability of the BES. Such testing is not recommended by suppliers.
Battery Testing
3. The Tables describing battery testing could be consolidated into less granular
breakdown and thus alleviate some of the associated compliance burden and
avoid potential confusion.
4. Further to battery testing, given the quantity of batteries and the shorter interval
cycles, the four calendar month requirement for batteries is too rigid as a firm
four months. Similar to how a definition of annual can have a boundary such as
within 9 to 16 months; battery testing intervals should allow a boundary such as
“three times per year and not more than 6 months between each and average
intervals not exceeding four months.”
5. Please confirm that references throughout Standard to battery/batteries relate to
the entire battery bank and not to the individual battery cells unless specifically
mentioned. Similarly, battery charger maintenance activity should relate to the
battery charger in its entirety and not to individual parts or components.
Auto Synchronizing Systems and Relays
6. The drafting team should clarify in the language that testing of auto synchronizing
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systems and relays is excluded.
Applicability
7. To make 4.2.5.4 under Facilities more clear, please remove the term “generatorconnected”.
8. When the SDT changed the original PRC-005 applicability language from
“...affecting the reliability of the BES...” to the new 4.2.1 language “...that are
installed for the purpose of detecting faults on BES elements (lines, buses,
transformers, etc.)”, they opted to exclude the second half of this sentence taken
from the PRC-005-1a Interpretation, which read “...and trips an interrupting
device that interrupts current supplied directly from the BES.” By doing so, the
SDT failed to recognize that some Protection Systems can be responsive to faults
on the BES, but still have no effect on the reliability of the BES. The change in
4.2.1 may unintentionally expand the scope of PRC-005.Depending on how
Section 4.2.1 is interpreted, it could create a perverse incentive to disable, or not
apply, reverse directional protection on the secondary (at voltages less than
100kV) of radially connected load-serving transformers. Such relaying typically
uses available units in a multifunction device, and while not critically necessary
for fault clearing, it is applied because it adds a benefit at no incremental cost
with minimal security risk, and it will not interrupt a BES element if it operates
insecurely. It also improves reliability to connected distribution load, in the event
a BES transmission line faults during abnormal switching, by coordinating with
non-directional overcurrent relays that would otherwise interrupt the entire load.
Furthermore such directional relaying would only operate after the faulted BES
line is already removed from any connection at BES voltages via its high voltage
(>100kV) circuit breakers. Viewed in an expansive way, the proposed 4.2.1
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language could bring into scope these relays as well as tripping circuits of
distribution voltage circuit breakers that are normally operated in a radial
configuration. It would be reasonable for a TO to disable this relaying, rather than
accept these consequences. In the previous comment period (Sept 2011),
industry raised similar concerns and to most of the commenters, the SDT
responded with the following statement:”The SDT believes that the Applicability
as stated in PRC-005-2 is correct and that it supports the reliability of the BES. The
SDT observes that the approved Interpretation addresses the term, “transmission
Protection System”, and notes that this term is not used within PRC-005-2; thus
the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses
“Protection Systems that are installed for the purpose of detecting faults on BES
Elements.” Please see Section 2.3 of the Supplementary Reference and FAQ
document for additional discussion.” Unfortunately, this response fails to address
the concerns raised above. Entergy previously suggested the following language
for 4.2.1:”Protection Systems that are installed for the purpose of detecting faults
on BES Elements (lines, buses, transformers, etc.) and trips an interrupting device
that interrupts current supplied directly from the BES Elements.”This language is
appropriate and addresses industry concerns. We ask that the SDT adopt this
language as Section 4.2.1.
Evidence Retention
9. It is not necessary and is undesirable to reiterate the language from the NERC
Rules of Procedure (Appendix 4C 3.1.4.2) in the standard. Stating such language
in two places is redundant and future changes to this section of the Rules of
Procedure language will create compliance conflict. While this language may be
recommended for inclusion as new boilerplate-type language for NERC standards
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and may be used in other recently revised standards, the potential conflict should
be taken into account and avoided for PRC-005. The first paragraph in section 1.3
should be removed.
10. Further, the standard language should dictate data retention relevant to the
standard activities and not merely default to the time period in between audits.
The Rules of Procedure language enables CEAs to confirm compliance for the full
audit period, but the Standard retention language allow for a more reasoned
obligation for evidence retention. Specific to this standard, two or three years of
evidence for certain components, such as battery tests, is sufficient to
demonstrate an entity’s PSMP program. On a positive note, standardizing the
requested evidence information is helpful.
Response: Thank you for your comments.
1. Regarding current transformers, the SDT disagrees, and notes that the table specifies that the entity verify that the signal is
provided to the relay.
2. Regarding testing for currents or potentials behind a Generator Operator’s electromechanical relay panel, the SDT believes that it
is possible during a 12-year interval to find a reasonably low-risk opportunity to perform the required test. Please refer to
Section 15.2.1 of the Supplementary Reference and FAQ document for a discussion of this topic.
3. The existing battery tables have evolved such that entities may easily locate the specific table that applies to the technology
being used in order to improve clarity and avoid confusion.
4. Regarding battery testing, the SDT believes that sufficient industry expertise supports a four-month interval requirement.
5. The SDT confirms that most of the battery requirements apply to the entire battery bank, and not necessarily to each battery jar
or cell; the same is true for battery chargers. Those requirements specific to individual cells are clearly indicated.
6. Automatic synchronizing relays (which generally close circuit breakers, rather than trip them) are not covered by the Applicability.
7. The generator-connected station service transformers are often connected to the generator bus directly without an interposing
breaker; thus, the Protection Systems on these transformers will trip the generator, as stated in Applicability 4.2.5.1.
8. The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES. The SDT observes
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that the approved Interpretation addresses the term, “transmission Protection System,” and notes that this term is not used
within PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems
that are installed for the purpose of detecting Faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference
Document for additional discussion.
9. The SDT has been advised to include this paragraph as the first paragraph in the Evidence Retention section.
10. For the Compliance Monitoring Authority to be confident that the corrective action is being implemented, the entity should
expect to demonstrate progress toward correcting the Unresolved Maintenance Issue, such as the evidence suggested in
Measure M5 (with additional suggested evidence added). The SDT has specified the data retention in the posted standard to
establish this level of documentation, which is consistent with the current practices of several regional entities.
DTE Energy
1. DECo does not agree with the 6 year interval for the majority of the Protection
System components. There are not sufficient problems found on routine
maintenance based on a 10 year interval that would justify that significant of a
reduction in the maintenance interval.
2. Also, with respect the station batteries specifically, station batteries, DECo
recommends the elimination of the 4 month inspection as annual inspections
have been sufficient for early diagnosis of potential issues. Advanced monitoring
is not practical at this time as it does not appear that the technology required to
forgo the 4 month inspection is readily available.
Response: Thank you for your comments.
1. The SDT believes the intervals and activities specified are technically effective, in a fashion that may be consistently monitored for
compliance. It is left to the entity to determine how to align these requirements with requirements of other regulations and with
operational concerns. If the relevant components are monitored, more lengthy intervals may be utilized. Performance-based
maintenance is an option to increase the intervals, if the performance of these devices supports those intervals.
2. Regarding battery testing, the SDT believes that sufficient industry expertise supports a four-month interval requirement.
FirstEnergy
FE asks that the team clarify the intent of certain aspects of the applicability section:
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1. Sec. 4.2.5.4 - For transformers supplying unit auxiliaries, protective functions that
provide for transferring of auxiliaries without tripping the generating unit should
not be included. Also, we believe that the term "station service transformer" is
being used inaccurately. As currently written, the section includes all the
protection systems for station service transformers for generators that are a part
of the BES. It states, “Protection Systems for generator-connected station service
transformers for generators that are part of the BES.” Generating facilities may
have transfer schemes on the auxiliary transformer to transfer equipment to a
reserve transformer instead of tripping the unit. These protection systems should
not be included in the Facilities for PRC-005-2, since the BES is not affected. But
since a station service transformer, by definition (IEEE Std. 505), is "a transformer
that supplies power from a station high voltage bus to the station auxiliaries and
also to the unit auxiliaries during unit startup or shutdown or when the unit
auxiliaries transformer is not available, or both." [Ed. note: a.k.a. Start-Up
Transformer or Cranker], the terminology "generator-connected station service
transformer" is confusing and easily subject to misinterpretation.
2. Also, there needs to be consistency of use of terms between the standard and its
Supplementary Reference document. On pages 32 and 33 of the FAQ, the
following questions and their respective answers should be consistent with use of
terms and replace “station service” with “auxiliary” as follows: FAQ Question Please provide a sample list of devices or systems that must be verified in a
generator, generator step-up transformer, and generator connected auxiliary
transformer to meet the requirements of this Maintenance Standard.FAQ
Question - In the case where a plant does not have a generator connected
auxiliary transformer such that it is normally fed from a system connected
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auxiliary transformer, is it still the drafting team’s intent to exclude the protection
systems for these system connected auxiliary transformers from scope even
when the loss of the normal (system connected) auxiliary transformer will result
in a trip of a BES generating facility? Therefore, for consistency between the
reference FAQ document and the standard, we suggest that “station service” be
replaced with “auxiliary” in 4.2.5.4 and read as follows: “Protection Systems for
generator-connected auxiliary transformers used on generators which are part of
the BES, that act to trip the generator either directly or via lockout or tripping
auxiliary relays.”
Response: Thank you for your comments.
1. Applicability Section 4.2.5.4 specifically addresses the Protection Systems that act to trip the generator, and the “station service
transformer” term seems to be the most consistently-used term for this application.
2. The SDT modified the Supplementary Reference and FAQ document for consistency with the standard.
Kansas City Power & Light
1. For clarity, change the text of “Standard PRC-005-2 - Protection System
Maintenance” Table 1-5 on page 21, Row 1, Column 3 to: “Verify that each a trip
coil is able to operate the circuit breaker, interrupting device, or mitigating
device.”. Or alternately, “Electrically operate each interrupting device every 6
years”.
2. Countable Event as proposed is somewhat unclear. Recommend the following
language: Countable Event - A Component which has failed and requires repair or
replacement, any condition discovered during the maintenance activities in
Tables 1-1 through 1-5 and Table 3 which requires corrective action, or a
Misoperation attributed to hardware failure or calibration failure. Misoperations
due to any other reason are not included in Countable Events.
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Response: Thank you for your comments.
1. The SDT believes it is important that each individual trip coil be verified.
2. The SDT does not believe that the changes you suggest improve the standard.
BAE Batteries USA
Manitoba Hydro
Major comments have been addressed in Question 3.
Manitoba Hydro is voting negative for the following reasons:
1 - Battery inspection and verification interval - Manitoba Hydro maintains that the
battery inspection interval should be extended to 6 months. The 4 month interval is
too frequent based on our experience and while IEEE std 450 (which seems to be the
basis for table 1-4) does recommend intervals, it also states that users should evaluate
these recommendations against their own operating experience. Manitoba Hydro has
more than ten years of experience using its existing battery inspection intervals and
Manitoba Hydro’s reliability data has proven that the 6 month inspection interval is
suitable for Manitoba Hydro. Manitoba Hydro’s battery maintenance tasks were
derived from a reliability study of Manitoba Hydro stationary batteries, and the tasks
and intervals are suitable given Manitoba Hydro’s installed plant, design criteria,
climate, and reliability performance. A more frequent inspection interval might be
more suitable to specific utilities with material differences in climate, design, installed
apparatus, and performance, but it is not suitable for Manitoba Hydro and may be
more than is required for many other utilities. To use a more frequent inspection
interval would penalize Manitoba Hydro which has been diligently performing battery
inspections for many years, with no resulting increase in reliability. It would also
potentially adversely affect reliability by diverting resources away from projects that
are critical to reliability to meet this maintenance interval. In addition, the 4 month
time period proposed for basic battery verification and inspection interval is not
aligned with the more detailed 18 month battery verification and inspection interval
which will result in additional and unnecessary site visits and maintenance activities.
As well, Manitoba Hydro does not feel that the SDT has provided sufficient technical
basis to support a 4 month battery inspection and verification interval and requests
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that further justification and external reference be provided.
2 - PBM not permitted for batteries - Manitoba Hydro disagrees with the SDT’s basis
for not permitting the use of PBM for batteries. The reasons provided by the SDT for
disallowing them are that batteries are perishable and involve chemical reactions.
However, it is our understanding that many other industries rely on performance
based maintenance programs when dealing with similar equipment. We would
appreciate an external reference or source which supports the claim that equipment
with these characteristics cannot have a performance based maintenance system
applied to them.
3 - Phased Implementation Plan - Manitoba Hydro maintains its position that
prescribing how an entity must reach full compliance with PRC-005-2 will provide a
negligible improvement in reliability while significantly increasing the compliance
burden. PRC-005-2 affects a large number of assets and proving compliance for the
prescribed percentages of assets during the transition period creates unnecessary
overhead with no added value. We suggest that the requirement to demonstrate the
percentage of assets currently under PRC-005-1 vs. PRC-005-2 be removed, that
entities should be given a single compliance date for each of the maintenance
intervals and be allowed the flexibility to schedule and complete their maintenance as
required while transitioning to the defined time intervals in PRC-005-2, and that NERC
measures progress on reaching PRC-005-2 intervals using means other than
Compliance measures such as industry surveys.
4 - Data Retention Requirements - The data retention requirements are too uncertain
for two reasons. First, the requirement to “provide other evidence” if the evidence
retention period specified is shorter than the time since the last audit introduces
uncertainty because a responsible entity has no means of knowing if or when an audit
may occur of the relevant standard. Secondly, it is unclear what ‘other evidence’,
besides the specified evidence in the Measures, an entity may be asked to provide to
demonstrate it was compliant for the full time period since their last audit.
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Response: The SDT thanks you for your comments.
1. The SDT believes that sufficient industry expertise supports a four-month interval.
2. The SDT believes that batteries cannot be a unique population segment of a Performance-based Maintenance (PBM) Program
because there are too many variables in the electrochemical process to completely isolate all of the performance-changing
criteria necessary for using PBM on battery systems.
3. The SDT disagrees with your proposal for a phased implementation plan.
4. The SDT has been advised to include this paragraph as the first paragraph in the evidence retention section.
Alber Corporation
My comment is in regard to the proposed maintenance tasks associated with ohmic
testing and capacity testing of lead-acid batteries affected by PRC-005-2.The option is
given to the battery use to perform either inter cell/unit ohmic tests OR battery
capacity tests whichever suits the user. The two tests, while related, are not directly
interchangeable with one another. Ohmic tests are intended to be used as a tool
during battery maintenance inspections to determine the general state of health
(condition) of the battery as a whole. Capacity tests are intended to demonstrate the
actual capacity of a battery. Ohmic tests cannot be substituted for capacity tests.
Alber has pioneered the development of portable and fixed internal resistance test
equipment for stationary lead-acid batteries since 1972. Through years of research,
testing in real-world applications and development, Alber has conclusively determined
that there is a direct relationship between internal cell resistance and capacity.
However, because this correlation is not linear, ohmic measurements should not be
used to calculate capacity or remaining life. Ohmic measurements should be used as a
supplement to capacity testing and not as a replacement. These measurements are
very valuable in identifying developing problems between the capacity testing
intervals and for determining whether a battery string is going to perform its intended
mission. IEEE 1188-2005 for VRLA batteries agrees with this and recommends
measurement of this parameter once every three months. While not specifically
recommended in IEEE 450-2010 for vented lead-acid batteries, ohmic measurements
can provide early warning of potential failure and should be performed at least
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annually. Again, if readings result in doubt that a battery will perform as intended,
follow up capacity testing is recommended. A battery discharge test completely
simulates the operating environment and therefore conclusively proves that a battery
can perform during an emergency. The results of these tests will help set the priority
for capacity testing as the user becomes more familiar with their batteries and may
assist in extending capacity test intervals. The intention of the proposed NECR PRC005-2 standard as it relates to the DC supply, and, in particular, the station battery is
to increase reliability of the bulk electric system (BES) in north America. In its current
draft form, PRC-005-2 proposes the utility may perform internal ohmic measurements
or perform capacity, but both tests are not required. It would appear therefore; that
the Standards Drafting Team (SDT) has made the assumption that test results
obtained from measuring cell internal ohmic values is the same as performing a
capacity test. It is not, and to provide the option to perform one test or the other runs
counter to industry recommended practices. Such maintenance practices will, in
effect, ultimately reduce the reliability of the BES rather than improve it. Periodic
capacity testing on a 5 year interval for VLA batteries, and a 2 year interval for VRLA
batteries is consistent with IEEE 450-2010 and IEEE 1188-2005 recommended
practices respectively. It should be part of a complete maintenance program designed
to maximize the DC supply's availability when needed. Respectfully submitted, Richard
Tressler Alber Corp.
Response: Thank you for your comment. The SDT agrees with your statement, and those of others, concerning the true capacity of
the station battery and relating it to internal ohmic measurements. Tables 1-4a, 1-4b and 1-4c have been modified for clarity, and
the Supplemental Reference and FAQ Document has been modified to further elaborate on these concerns.
NIPSCO
Per NIPSCO Tech Service Dept : There is a need for NERC to provide a format for
maintenance reports. Also, it would help if specific test requirements for relays were
provided.
Response: Thank you for your comments. The SDT do not believe it is necessary or appropriate to prescribe a specific format for test
results or test requirements.
PNM Resources
PNM Resources appreciate the outstanding work of the SDT! We offer two comments
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for consideration by the SDT.
1) We believe that the 6 Calendar Month battery cell/unit internal ohmic value
measurement for VRLA Batteries may be more frequent than we believe is necessary
to maintain reliability. PNM has witnessed no significant failure patterns with VRLA
batteries in our system and we currently do impedance testing of all Transmission
Station Batteries on a 2-year basis.
2) We also believe that system constraints could arise that will make it difficult to
“verify all paths of the trip circuits inclusive of all auxiliary relays through the trip
coil(s) of the circuit breakers or other interrupting devices” as specified in Table 1-5
for “unmonitored control circuitry associated with protective functions inclusive of all
auxiliary relays”. Thank you for your consideration.
Response: Thank you for your comments.
1. The SDT believes that it is necessary to verify that the station battery can perform as manufactured by evaluating the cell/unit
parameters to station battery baseline if a performance or modified performance test is not conducted. Please see Section 15.4
of the Supplementary Reference and FAQ Document for a discussion of this topic.
2. The SDT believes the intervals and activities specified are technically effective, in a fashion that may be consistently monitored for
compliance. It is left to the entity to determine how to align these requirements with requirements of other regulations and with
operational concerns.
American Electric Power
PRC-005-2 is intended to supersede the existing standard PRC-017-0 "Special
Protection System Maintenance and Testing". As it is currently written, an Entity with
a Special Protection System will be required by R1 to select either a time-based,
performance-based or combination maintenance method for the Entity's SPS. Since
Special Protection Systems are not frequently installed, it is unlikely that an Entity will
be able to meet the requirement of R2 and Attachment A that the Segment
population contain 60 components for all components of the SPS. This will require
the Entity to utilize the time-based maintenance method for at least some
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components in the SPS. Under the time-based maintenance method and R3, the
Entity will be required to utilize the minimum maintenance activities and maximum
maintenance intervals prescribed within Tables 1-1 through 1-5, Table 2, and Table 3.
Special Protection Systems by their nature may physically include components that
are not listed in the NERC definition of Protection System and therefore are not
included in the tables of PRC-005-2. The standard, as currently drafted, does not
clearly provide a means for an Entity with a Special Protection System to establish
minimum maintenance activities and maximum maintenance intervals for
components that have been declared by their Region as part of a Special Protection
System but that are not included in the NERC definition of Protection System.
Response: The SDT thanks you for your comments. The SDT does not perceive the gap in maintenance requirements that you
describe for SPSs.
US Bureau of Reclamation
1. Re Terms defined for use only within PRC-005-2: The standard provides
definitions which will not be incorporated into the Glossary of Terms. This would
allow the definitions as used in this standard to conflict with the definition used
in other standards if this practice becomes more widespread and would reduce
the cohesiveness of the standard set.
2. Re The definition of Components: The standard defined what constitutes a
control circuit as a component type with "Control circuitry associated with
protective functions through the trip coil(s) of the circuit breakers or other
interrupting devices." The standard then modified the definition by allowing "a
control circuit Component is dependent upon how an entity performs and tracks
the testing of the control circuitry." The definition should not be dependent
upon practice. This makes the definition a fill in the blank definition. Either
eliminate the allowance or remove the definition of control circuit.
Response: The SDT thanks you for your comments.
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1. The standard specifies that the terms used are intended for this standard only; therefore, there should no conflict with their use
in any other PRC standard.
2. The intent of the different means of identifying control circuitry was to accommodate various entities’ philosophies on testing
these circuits. Regardless of how an entity chooses to identify their control circuitry, the entity must meet the requirements of
the standard regarding maintenance of control circuitry.
ReliabilityFirst
1. ReliabilityFirst votes in the negative for this standard primarily due to the
language in Requirement R5. The language in Requirement R5 is subjective and
non-measurable in its present state. ReliabilityFirst offers the following
comments for consideration.
2. Definition of “Component”
a. The language stating “discrete piece of equipment” within the first sentence is
unclear and open ended. ReliabilityFirst suggests the following modified
language for the first sentence in the definition of “Component”: “A Component
is a piece of equipment that is one of the five specific element included in a
Protection System, including but not limited to a protective relay or current
sensing device.”
3. Definition of “Unresolved Maintenance Issue”
a. There may be instances when a deficiency is identified and corrected during
the maintenance itself. For further clarity and to address this circumstance,
ReliabilityFirst recommends the following modification for consideration: “A
deficiency identified during a maintenance activity that could not be corrected
and causes the component to not meet the intended performance and requires
follow-up corrective action.”
4. Facilities Section 4.2.1
a. This is too limited or selective in only including Protection Systems that are
installed on BES Elements to strictly detect Faults. There are a number of relays
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that are installed to detect non-Fault but abnormal conditions such as power
swings/out of step and overvoltage that should not be excluded from a
maintenance program. ReliabilityFirst recommends the following language for
consideration: “Protection Systems that are installed for the purpose of
protecting BES Elements (lines, buses, transformers, etc.)”
5. Facilitates Section 4.2.2
a. It is unclear what requirements the phrase “installed per ERO underfrequency
load-shedding requirements.” is referring to. Is it NERC UFLS Requirements,
Regional UFLS Requirements, etc.? To be consistent with section 4.2.3,
ReliabilityFirst recommends the following for consideration: “Protection Systems
used for underfrequency load-shedding systems installed to arrest declining
frequency, for BES reliability.
6. Requirement R3
a. For time-based maintenance program(s), there is no safeguard if more than
4% Countable Events are experienced during a maintenance interval.
ReliabilityFirst recommends adding an new Subpart 3.1 (similar to the language
for performance-based in Attachment A): “3.1 If the Components in a Protection
System Segment maintained through a time-based PSMP experience 4% or more
Countable Events, develop, document, and implement a Corrective Action Plan
to reduce the Countable Events to less than 4% of the Segment population
within 3 years.”
7. Requirement R5
a. Requirement R5 has language which states “...shall demonstrate efforts to
correct...”. ReliabilityFirst believes this language is subjective and nonmeasurable. It will be difficult in determining what amount of demonstration an
entity will need to provide in order to be compliant. There is also no timeframe in
which the correction needs to be completed (is it 30 days or 30 years?).
ReliabilityFirst believes measurable language such as “shall correct” or “shall
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have and implement a Corrective Action Plan” should be incorporated within the
requirement.
8. Table 1-2
a. For “Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function” ReliabilityFirst believes the maintenance interval is too short.
Carrier communication failures are a major cause of Misoperations. Many have
automatic checkback and are monitored but continue to fail during Fault
conditions. ReliabilityFirst recommends a maintenance interval of 6 years.
b. For “Any communications system with continuous monitoring or periodic
automated testing for the performance of the channel using criteria pertinent to
the communications technology applied” ReliabilityFirst believes a maintenance
interval should be required. ReliabilityFirst recommends a maintenance interval
of 12 years.
9. Table 1-3
a. For “Any voltage and current sensing devices not having monitoring attributes
of the category below.” ReliabilityFirst recommends a maintenance interval of 6
years.
b. For “Voltage and Current Sensing devices connected to microprocessor relays
with AC measurements are continuously verified by comparison of sensing input
value...” ReliabilityFirst believes the concept of never having to do any testing
just because you have continuous monitoring is fundamentally flawed in this
table as well as 1-5 and 2. Continuous monitoring and measurement comparison
cannot test everything, such as loss of ground, multiple grounds and turn-to-turn
failures, and monitoring itself can fail. ReliabilityFirst recommends a
maintenance interval of 12 years.
10. Table 1-5
a. ReliabilityFirst recommends adding “auxiliary tripping devices” to
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Electromechanical lockout devices in row 2 of Table 1-5. If lockout relays are
maintained every six years auxiliary tripping devices should be as well.
ReliabilityFirst recommends the following language for considerations:
“Electromechanical lockout devices and auxiliary tripping devices which are
directly in a trip path from the protective relay to the interrupting device trip coil
(regardless of any monitoring of the control circuitry).”
Response: The SDT thanks you for your comments.
1. Requirement R5 is expressly focused on allowing entities to resolve deficiencies in an effective manner, rather than performing
“band-aid” fixes. Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside
the scope of this standard. There can be any number of supply, process and management problems that make setting repair
deadlines impossible. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff)
because of the recognition that more complex unresolved maintenance issues could require more time to resolve effectively than
there is time remaining in the maintenance interval, yet the problems must eventually be resolved. The SDT believes that
corrective actions should be timely, but concludes it would be impossible to postulate all possible remediation projects; and,
therefore, impossible to specify bounding time frames for resolution of all possible unresolved maintenance issues or what
documentation might be sufficient to provide proof that effective corrective action is being undertaken. The definition of
“Unresolved Maintenance Issue” has been modified to add a clarifying phrase that the deficiency “cannot be corrected during the
maintenance interval.”
2. The SDT believes it important to distinguish between component “types” (of which there are 5) and individual components (of
which there are numerous examples), and believes that you are confusing the two concepts.
3. The definition of “Unresolved Maintenance Issue” has been modified to add a clarifying phrase that the deficiency “cannot be
corrected during the maintenance interval.”
4. The SDT believes your proposed language for Applicability Section 4.2.1 is overly broad and could lead to unintentional
application of PRC-005-2 to other as-of-yet unidentified systems.
5. The SDT intends that this refers to either NERC UFLS requirements or regional UFLS requirements.
6. Countable Events apply only to entities that utilize a performance-based PSMP (Requirements R2 and R4). For entities that use a
time-based program, the establishment of maximum intervals within the standard relieves the entity from having to have any
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basis, etc., that the intervals used are appropriate, as long as those intervals conform to the tables.
7. Management of completion of the identified Unresolved Maintenance Issue is a complex topic that falls outside of the scope of
this standard. There can be any number of supply, process and management problems that make setting repair deadlines
impossible. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex unresolved maintenance issues might require greater than the remaining maintenance
interval to resolve (and yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery during
a six-month check. In instances such as one that requires battery replacement as part of the long-term resolution, it is highly
unlikely that the battery could be replaced in time to meet the six-calendar-month requirement for this maintenance activity.
The SDT does believe corrective actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution of all possible Unresolved
Maintenance Issues, or what documentation might be sufficient to provide proof that effective corrective action is being
undertaken. The definition of “Unresolved Maintenance Issue” has been modified to add a clarifying phrase that the deficiency
“cannot be corrected during the maintenance interval.”
8. a) The SDT believes that sufficient emphasis is placed on communication system checks and maintenance. The SDT also believes
that more frequent hands-on testing will be no more effective in finding problems than the automated monitoring of these
functions. b). The SDT believes that continuous monitoring requirements, as already drafted, will drastically reduce risk to the
BES.
9. a) The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Entities are empowered to develop PSMPs that exceed these requirements, if they determine such a
PSMP to be necessary. b). The SDT believes that continuous monitoring is equivalent to actually conducting the maintenance
activities otherwise specified at a far more frequent interval than would be possible with physical hands-on maintenance; and,
therefore, improves reliability. The SDT has also identified throughout the tables specific activities that they believe to not be
effectively conducted via monitoring.
10. The SDT believes the intervals and activities specified for auxiliary relays are technically effective, and believes sufficient emphasis
is placed on auxiliary tripping relay maintenance.
ATCO Electric Ltd
1. Table 1-4(a) Vented Lead-Acid (VLA) Batteries: ATCO Electric has a number of
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remote substations that are difficult to access frequently. The requirement for a
4 calendar month inspection for electrolyte level is too frequent.
(i)
(ii)
Does alarm/monitor technology exist for electrolyte level in battery design
today? For in-service battery systems, if battery alarm/monitor technology
exists, a capital project is required to retrofit each battery system and this
kind of retrofit work could be detrimental to both the battery design life as
well as the battery reliability.
The electrolyte level requirement would become achievable if electrolyte
level inspection was moved to the 18 calendar months category, or if the 4
calendar months frequency was increased to 8 calendar months.
2. Table 1-4(b) Valve Regulated Lead Acid (VRLA) Batteries: ATCO Electric has a
number of remote substations that are difficult to access frequently. The
requirement of a 6 calendar month inspection of individual battery cell/unit
internal ohmic values is too frequent. The requirement would become
achievable if battery cell/unit internal ohmic value inspections were moved to
the 18 calendar months category.
3. Table 1-5 Control Circuitry When a breaker is opened, there is no indication on
which trip coil is actually operated. How do market participants demonstrate
compliance for "verify that each trip coil is able to operate..."? The verification of
trip coil health is done during breaker maintenance with various maintenance
durations that maybe longer than 6 years depending on breaker types.
4. The requirement of "verify electrical operation of electromechanical lockout
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devices" introduces high risk of human error outages to the BES system and
diminishes the reliability gain from performing this activity. The drafting team
should consider lockout relay failure rates, onerous tasks of blocking each trip
contacts in many BES elements' tripping circuits, imposed risk, required
resources in the overall reliability benefit gained by performing the lockout relay
maintenance.
Response: The SDT thanks you for your comments.
1. Devices to monitor electrolyte levels are available. The SDT believes that the four-month interval for checking electrolyte level
(absent monitoring) is appropriate, as low electrolyte level may impair the ability of the battery to function properly.
2. The SDT believes that the six-month interval for evaluation of cell/unit ohmic parameters to baseline is appropriate, as
degradation of these parameters may impair the ability of the battery to function properly.
3. Breaker control circuitry is typically designed with facilities, such that individual trip coils can be isolated for observation. Also, it
may be possible to distinguish operation of individual trip coils by determining what devices initiate those trip coils.
4. The SDT believes that electromechanical lockout relays need periodic operation. As such, these devices are required to be
exercised at the same six- year interval required for electromechanical relays. The SDT recognizes the risk of human error trips
when working with testing of lockout devices, but believes these risks can be managed. Performance-based maintenance is an
option if you want to extend your intervals beyond six years.
Florida Municipal Power
Agency
The applicability of the standard should be modified to reflect the FERC approved
interpretation PRC-005-1b Appendix 1 that basically says that applicable Protection
Systems are those that protect a BES Element AND trip a BES Element. The
interpretation states: The applicability as currently stated will sweep in distribution
protection: “4.2.1 Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.)”Many (most) network
distribution systems that have more than one source into a distribution network will
have reverse power relays to detect faults on the BES and trip the step-down
transformer to prevent feedback from the distribution to the fault on the BES. This is
not a BES reliability issue, but more of a safety issue and distribution voltage issue.
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These relays would be subject to the standard as the applicability is currently written,
but, should not be and they are currently not within the scope of PRC-005-1b
Appendix 1 because the step-down transformer (non-BES) is tripped and not a BES
Element (hence, the "and" condition of the interpretation is not met). There are many
other related examples of distribution that might be networked or have distributed
generation on a distribution circuit where such reverse power relays, or overcurrent
relays with low pick-ups, are used for safety and distribution voltage control reasons
and are not there for BES Reliability. To make matters worse, for these Reverse Power
relays, it is pretty much impossible to meet PRC-023 because the intent of the relay is
to make current flow unidirectional (e.g., only towards the distribution system)
without regard for the rating of the elements feeding the distribution network. So, if
these relays are swept in, and if they are on elements > 200 kV, then the entity would
not be able to meet PRC-023 as that standard is currently written. So, the SDT should
adopt the FERC approved interpretation.
Response: Thank you for your comments.
The SDT believes that the Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES. The SDT observes
that the approved Interpretation addresses the term, “transmission Protection System,” and notes that this term is not used within
PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems that are
installed for the purpose of detecting Faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and FAQ
Document for additional discussion.
Reverse power relays and low-set overcurrent relays, as discussed in your comment, are not installed for detecting Faults on BES
elements. The SDT does not understand your concerns regarding PRC-023, but we suggest you provide those concerns to the team
working on that standard.
Ingleside Cogeneration LP
The derivation of the implementation plan apparently incorporates the
“requirements” of NERC’s Compliance organization, which has released several CANs
on the topic. This is exactly backwards, and has led to at least one CAN which has
been withdrawn due to legal overreach. However, the plan as written is very
complex. We believe that diagrams of acceptable time frames should be included in
the implementation plan so that industry stakeholders can better assess the impact
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on their maintenance operations.
Response: The SDT thanks you for your comments. The SDT has developed the Implementation Plan such that it is clear, both to
entities and to Compliance Enforcement Authorities, as to when the various requirements must be fully implemented. The
Implementation Plan has been crafted to allow entities to systematically implement the standard in a manner that facilitates
effective ongoing performance of a PSMP. The SDT does not believe it necessary to “diagram” the PSMP.
EPRI
The drafting time should see the opinion of the IEEE Stationary Battery Committee
before this standard is rolled out for implementation.
Response: The SDT thanks you for your comments. Several members of the NERC Task Force of the IEEE Stationary Battery
Committee participated in developing modifications to the sections of Table 1-4 to be more effective and technically accurate.
ACES Power Marketing
Standards Collaborators
1. The first part of definition of a Countable Event should be modified as follows:
“The failure of a Component such that it requires repair or replacement...”. As it
is currently worded, it is technically counting the Component as the Countable
Event and not the failure of the component. Considering that the other two
items that are Countable Events are conditions and misoperations, it seems
appropriate to make failure the Countable Event.
2. Application of this standard to UFLS is problematic as worded in Section 4.2.2.
The UFLS are only applicable if “installed per ERO underfrequency load-shedding
requirements”. Technically, no UFLS fits this description because there are no
ERO requirements to have a UFLS. PRC-006-0 was never approved by the
Commission and is not enforceable. The Commission considered it a “fill-in-theblank” standard. While PRC-006-1 corrects the “fill-in-the-blank” issues and was
approved by the NERC BOT November 4, 2010, the Commission has yet to act on
it.
3. The data retention requirement for the Protection System Maintenance Program
documentation seems excessive. The Data Retention section states that all
versions since the last compliance audit must be maintained. Since TOs, GOs,
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and DPs are all on six year audit cycles, this would require maintaining this
documentation for six years. Is this really necessary? The length could become
even greater once NERC implements registered entity assessments that could
shorten or lengthen the periods between compliance audits. The data retention
requirements for Requirements R2, R3, R4, and R5 are not consistent with NERC
Rules of Procedure. Section 3.1.4.2 of Appendix 4C - Compliance Monitoring and
Enforcement Program states that the compliance audit will cover the period
from the day after the last compliance audit to the end date of the current
compliance audit. The data retention requirements compel the registered entity
to retain documentation for the longer of “the two most recent performances of
each distinct maintenance activity for Protection System Components, or all
performances of each distinct maintenance activity for the Protection System
Component since the previous scheduled audit date”. While it may have been
intended to apply to both clauses, the “since the previous scheduled audit date”
only applies to the second clause. Since some of the maintenance activities have
intervals of 12 years, this would require the registered entity to retain
documentation for 24 years which cannot be audited since it is outside the audit
window per the Rules of Procedures. At a minimum, we suggest clarifying that
the documentation must not be maintained past the day after the last audit
completion date. In the fourth paragraph of the Data Retention section,
Component is not used consistently. It is used in both singular and plural form.
It seems like it should be one or the other.
4. Requirement R1 VSLs: For the High VSL, “entities’” should be “entity’s” to be
consistent with the other VSLs.
5. It is not clear why missing three component types jumps to a Severe VSL.
Missing two is a Moderate VSL. Missing three should be a High VSL.
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Response: Thank you for your comments.
1. The SDT agrees with your comments on Countable Event, and has modified the definition of Countable Event to: “A failure of a
Component requiring …”
2. Applicability Clause 4.2.2 applies to whatever ERO-required UFLS that may exist, either today or in the future. NERC Reliability
Standard PRC-006-1 has now been approved by FERC.
3. The SDT believes that all versions of the entity’s PSMP should be retained for audit purposes. For a Compliance Monitor to be
assured of compliance, the SDT believes the Compliance Monitor will need the data of the most recent performance of the
maintenance, as well as the data of the preceding maintenance to validate that entities have been in compliance since the last
audit (or currently, since the beginning of mandatory compliance). The SDT specified the data retention in the posted standard to
establish this level of documentation, which is consistent with the current practices of several regional entities.
4. The SDT corrected the Requirement R1- High VSL, as you suggested.
5. The SDT believes that missing three components is a “significant percentage,” and is in accordance with the VSL Guidelines.
Independent Electricity
System Operator
The IESO continues to disagree with the VRF assigned to the new R3 and R4. R3 and
R4 ask for implementing the maintenance plan (and initiate corrective measures)
whose development and content requirements (R1 and R2) themselves have a
Medium VRF. Failure to develop a maintenance program with the attributes specified
in R1, and stipulation of the maintenance intervals or performance criteria as required
in R2, will render R3/R4 not executable. Hence, we reiterate our position that the VRF
for R3 be changed to Medium.
Response: Thank you for your comments.
The SDT disagrees, and believes the failure to implement a PSMP should be assigned a VRF of High.
BAE Batteries USA
The NERC Standard should incorporate suggestions made in a letter provided to the
NERC Drafting Team along w/ a specific Task Force Report commissioned by the IEEE
Stationary Battery Committee.
Response: The SDT thanks you for your comments. Several members of the NERC Task Force of the IEEE Stationary Battery
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Committee participated in developing modifications to the sections of Table 1-4 to be more effective and technically accurate.
Nebraska Public Power
District
The SDT believes that it is possible to manage the risks that you describe and that
performance of these trip path verifications will be an overall benefit to the reliability
of the BES
1. Please provide the basis for the requirement of functional trip checks?
2. Are there recorded instances that an “event” would have been avoided if
functional trip checks had been performed?
3. Suggest for monitored microprocessor relays in Table 1-1 and 3 to verify
“settings are as specified that are essential to the proper functioning of the
protection system”. Many settings are not essential.
4. A key concern is will the reliability of the bulk electric system be affected
negatively due to increased risk from human element initiated events as a result
of the more frequent functional trip checks that will be required. All functional
tests should be moved to the minimum frequency of 12 years to minimize this
unknown but present risk.
Response: The SDT thanks you for your comments.
1. Please see Section 15.3 of the Supplementary Reference and FAQ document.
2. While the SDT cannot comment on any specific events that would have been avoided explicitly by performing functional trip
checks, there is no doubt that the number of Misoperations will be reduced if more comprehensive maintenance is performed. It
is also likely that mal-performance of control circuitry has been a factor in a number of disturbances.
3. In many microprocessor relays, various settings impact other settings, making it difficult to explicitly determine which are
essential to proper functioning of the Protection System. Additionally, the SDT anticipates that this activity, for microprocessor
relays, may very well be easily performed by downloading the settings from the relay and comparing them to the file of desired
settings.
4. The maintenance of the overall control circuitry is already specified for a 12-year interval. Only trip coil verification and lockout
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relay verification are specified for six years.
Southwest Power Pool
Standards Development
Team
Under section 1.3 Evidence Retention we feel like documentation of the last two
performances of each distinct maintenance activity should be limited to the last one.
This is due to the amount of documentation being recorded as well as for certain a
component there is a 12 year maximum interval. Would you have to store this
information for 24 years? This could also violate the NERC ruling that was just made
on a CAN 008 that stated you do not have to show intervals earlier than June 18th
2007. Suggested alternate language “For Requirement R2, Requirement R3,
Requirement R4, and Requirement R5, the Transmission Owner, Generator Owner,
and Distribution Provider shall each keep documentation of the most recent
performance of each distinct maintenance activity for the Protection System
Components, or all performances of each distinct maintenance activity for the
Protection System Component since the previous audit date, whichever is longer, but
not prior to June 18th 2007.”
Response: The SDT thanks you for your comments. For a Compliance Monitor to be assured of compliance, the SDT believes the
Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
maintenance to validate that entities have been in compliance since the last audit (or currently, since the beginning of mandatory
compliance). The SDT specified the data retention in the posted standard to establish this level of documentation, which is
consistent with the current practices of several regional entities.
NextEra Energy, Inc.
1. Verifying electrolyte levels of vented lead acid (VLA) batteries every four (4)
calendar months is excessive and will not promote the reliability of the bulk
electric system (BES). The maximum maintenance interval should be twelve (12)
calendar months. Today’s lead-calcium and lead-selenium-low antimony
batteries do not experience rapid water loss as compared to the legacy leadantimony batteries and if battery cells should crack from positive plate growth,
twelve (12) calendar months is more than adequate to detect electrolyte leakage
before cell failure.
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2. Verifying that unmonitored communication systems are functional every four (4)
calendar months is excessive and will not promote the reliability of the BES. The
maximum maintenance interval should be twelve (12) calendar months. Based
on our operating experience, twelve (12) calendar months is sufficient to detect
communication failures without affecting the reliability of the BES.
Response: The SDT thanks you for your comments.
1. The SDT believes that the four-month interval for checking electrolyte level (absent monitoring) is appropriate, as low electrolyte
level may impair the ability of the battery to function properly.
2. The SDT believes that the four-month interval is proper for unmonitored communications systems. The activity related to this
interval is to verify basic operating status.
Flathead Electric
Cooperative, Inc.
1. We appreciate the work of the drafting team to fulfill the SAR objectives. Flathead
generally does not like some of the new definitions proposed by the revised
standard, especially R5, “Unresolved Maintenance Issues” is too vague and will be
left up to individual auditors to determine compliance.
2. In addition, it appears the drafting team is creating new definitions for plain
English in the definition of Protection System Maintenance Program (PSMP).
Surely "test, monitor, inspect, calibrate" don't need NERC definitions. Let's leave
the definition as "An ongoing program by which Protection System components
are kept in working order and proper operation of malfunctioning components is
restored." Suggest deleting "A maintenance program for a specific component
includes one or more of the following activities: o Verify- Determine that the
component is functioning correctly. o Monitor - Observe the routine in-service
operation of the component. o Test - Apply signals to a component to observe
functional performance or output behavior, or to diagnose problems. o Inspect Detect visible signs of component failure, reduced performance and degradation.
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o Calibrate-Adjust the operating threshold or measurement accuracy of a
measuring element to meet the intended performance requirement."
3. In addition, it appears the component and component type definitions alter the
meaning of the NERC approved definition of a protection system. I would suggest
the drafting team not try to redefine the NERC-approved definition of Protection
system.
4. "Countable Event" definition seems to conflict with standards related to
Misoperation of protection system.
Response: The SDT thanks you for your comments.
1. Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope of
this standard. There can be any number of supply, process and management problems that make setting repair deadlines
impossible. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex unresolved maintenance issues might require greater than the remaining maintenance
interval to resolve (and yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery during
a six-month check. In instances, such as one that requires battery replacement as part of the long term resolution, it is highly
unlikely that the battery could be replaced in time to meet the six-calendar-month requirement for this maintenance activity.
The SDT does believe corrective actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects and therefore, impossible to specify bounding time frames for resolution of all possible unresolved
maintenance issues or what documentation might be sufficient to provide proof that effective corrective action is being
undertaken. The definition of “Unresolved Maintenance Issue” has been modified to add a clarifying phrase that the deficiency
“cannot be corrected during the maintenance interval.” The SDT believes the definition is sufficiently clear, while also allowing
some flexibility for both TOs and auditors.
2. The SDT believes that the descriptions within the PSMP definition are necessary so that the definition will be clearly understood
and so that entities consistently apply those terms as they implement the activities within the tables.
3. The definitions, for use within this standard, do not alter the approved definition of “Protection System,” but instead provide
consistent terms for use within the standard.
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4. The definition, within this standard, of Countable Event has no relationship to the approved definition of Misoperation. It is used
solely to describe and evaluate Protection System performance for the purpose of developing and perpetuating a performancebased PSMP.
Entergy Services
1. We recommend the word “Protection” be deleted from the definition of
Component to make the defined term Component be a generic term. If that
word is not deleted then we recommend the term used in the standard
“Protection System Component” be changed to “Component” since as defined a
Component is a Protection System piece of equipment. Component - A
Component is any individual discrete piece of equipment included in a System,
including but not limited to a protective relay or current sensing device.
2. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some
entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed
Response: The SDT thanks you for your comments.
1. The SDT intends that the term not be generic, and that term explicitly apply within this standard.
2. The intent of the different means of identifying control circuitry was to accommodate various entities’ philosophies on testing
these circuits. Regardless of how an entity chooses to identify their control circuitry, the entity must meet the requirements of
the standard regarding maintenance of control circuitry.
PNGC Comment Group
We thank the SDT for their hard work and will be voting "yes" on this project.
However, we have 5 specific comments independent of the questions above and
we've listed them in order of priority:
1. The PNGC Comment Group takes issue with the associated VSLs for R3. For a small
entity using a time based maintenance program, even one missed interval could be
enough to elevate them to a high VSL despite the limited impact on the Bulk Electric
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
128
Organization
Yes or No
Question 4 Comment
System. Consider an entity with 9 total components within a specific Protection
System Component Type. One violation would mean an 11% violation rate, enough to
catapult them into a High VSL. Given the “NERC Guidance (Below), this seems to be a
contradiction given the language of “...more than one”. a. NERC Guidance on VSL
assignment: i. LOWER: Missing a minor element (or a small percentage) of the
required performance ii. Moderate: Missing at least one significant element (or a
moderate percentage) of the required performance. iii. High: Missing more than one
significant element (or is missing a high percentage) of the required performance or is
missing a single vital component. iv. Severe: Missing most or all of the significant
elements (or a significant percentage) of the required performance. We suggest
changing the language for “Lower VSL” for R3 to: For Responsible Entities with more
than a total of 20 Components within a specific Protection System Component Type in
Requirement R3, 5% or fewer have not been maintained... OrFor Responsible Entities
with a total of 20 or fewer Components within a specific Protection System
Component Type, 2 or fewer Components in Requirement R3 have not been
maintained...
2. The PNGC comment group disagrees with the “Evidence Retention” requirements
for the standard. In the current version for R2-R5, entities are required to: “...keep
documentation of the two most recent performances of each distinct maintenance
activity for the Protection System Components, or all performances of each distinct
maintenance activity for the Protection System Component since the previous
scheduled audit date, whichever is longer.” The PNGC comment group believes that
keeping documentation for one previous maintenance activity or since the last audit,
whichever is longer, should be sufficient. Keeping the two most recent instances of an
activity with a maximum maintenance interval of 12 years could mean planning for up
to 35 years or so of evidence retention. With the longer of “since the last audit” or “at
least one maintenance interval” as the minimum retention requirement the CEA
should have sufficient basis to determine compliance.
3. The PNGC comment group believes R5, “Unresolved Maintenance Issues” is too
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
129
Organization
Yes or No
Question 4 Comment
vague and will be left up to individual auditors to determine compliance. This
requirement appears ripe for misapplication and future CANs on the topic. Good
utility practice will ensure that maintenance issues are corrected as a primary function
of our members is to provide the most reliable service possible. The SDT lists several
possible examples of evidence in M5 but we believe that more specificity is needed
for evidence requirements or the requirement should be removed. We understand
the importance of “maintenance” of protection systems and that when maintenance
issues cannot be immediately addressed there needs to be follow up. We believe
notation of the maintenance issue during the inspection should be sufficient for
compliance. By including the examples in the associated measure for the
requirement, we believe the SDT has confused the issue. In our opinion M5 should
indicate that evidence of notation of the issue is all that is required (meaning
acknowledging of the issue on the inspection form). Further, in your response to
entity comments during the last comment period on this topic, you stated, “The SDT
believes that an effective PSMP must include correction of deficiencies...”. This
statement implies that the standard must cover the correction of deficiencies to
completion. There could be very long time frames associated with maintenance
including management budget decisions, equipment purchase lead times and
personnel scheduling for follow up work. Some issues could potentially require years
of tracking within this standard creating an unnecessary compliance risk for the entity.
We believe the SDT has met the intent of order 693 if a maintenance activity is
initiated. The completion of the initiated maintenance activity should be outside the
bounds of the standard and the standard should clearly state this.
4. We also find issues with the “Definitions of Terms Used in Standard “Specifically,
the definition of “Component” seems to confuse the subject unnecessarily. We
suggest simplifying the definition by breaking out the control circuitry and voltage and
current sensing device examples. That is a lot of material to cover in what should be a
simple definition of “Component”.
5. Also we believe the definitions of the 5 behaviors under the PSMP definition are
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
130
Organization
Yes or No
Question 4 Comment
unnecessary. We believe that indicating that the PSMP involves some or all of the 5
activities without trying to define them is fine. For example, your definition of
“Inspect” states: Detect visible signs of component failure, reduced performance and
degradation. But what if you find no failure, reduced performance or degradation?
Have you not inspected the component? Or what about “verify”? If you determine
the component is not functioning correctly, have you not verified anything?
Response: The SDT thanks you for your comments.
1. A smaller entity will have less to maintain in accordance with the standard; and, thus, the percentages are still appropriate.
2. For a Compliance Monitor to be assured of compliance, the SDT believes the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding maintenance to validate that entities have been in
compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT specified the data retention
in the posted standard to establish this level of documentation, which is consistent with the current practices of several regional
entities.
3. Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope of
this standard. There can be any number of supply, process and management problems that make setting repair deadlines
impossible. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex unresolved maintenance issues might require greater than the remaining maintenance
interval to resolve (and yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery during
a six-month check. In instances such as one that requires battery replacement as part of the long term resolution, it is highly
unlikely that the battery could be replaced in time to meet the six-calendar-month requirement for this maintenance activity.
The SDT does believe corrective actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution of all possible unresolved
maintenance issues or what documentation might be sufficient to provide proof that effective corrective action is being
undertaken. The definition of “Unresolved Maintenance Issue” has been modified to add a clarifying phrase that the deficiency
“cannot be corrected during the maintenance interval.” The evidence listed in the Measure is intended to be illustrative of the
types potentially effective evidence, but is not all-inclusive, as demonstrated by the term, “… not limited to…”
4. The definitions of terms that are specified for use only within this standard are intended to support consistent application of the
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
131
Organization
Yes or No
Question 4 Comment
standard.
5. The SDT believes that the descriptions within the PSMP definition are necessary so that the definition will be clearly understood
and so that entities consistently apply those terms as they implement the activities within the tables. The term “inspect” was
modified to “Examine for …” in consideration of your comment.
Western Area Power
Administration
Western Area Power Administration - Rocky Mountain Region does not agree with
changing lockout devices to 6 year intervals for testing.
Response: The SDT thanks you for your comments. The interval for lockout relays has been at six years for several drafts; this is not
a change. The SDT believes that electromechanical lockout relays need periodic operation, and that six years is the appropriate
interval. Performance-based maintenance is an option, if you want to extend your intervals beyond six years.
END OF REPORT
Consideration of Comments: Project 2007-17 Protection System Maintenance and Testing
132
Consideration of Comments
Protection System Maintenance and Testing - Project 2007-17
The Protection System Maintenance and Testing Drafting team thanks all commenters who submitted
comments on the 3rd draft of the standard for Protection System Maintenance. These standards were
posted for a 30-day public comment period from June 18, 2012 through June 27, 2012. Stakeholders
were asked to provide feedback on the standards and associated documents through a special
electronic comment form. There were 51 sets of comments, including comments from approximately
170 different people from approximately 110 companies representing all 10 Industry Segments as
shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary Consideration of all Comments Received:
Definitions:
No changes were made to the Definitions.
Applicability:
No changes were made to the Applicability.
Requirements:
No changes were made to the Requirements.
Tables
In Table 1-2, the interval for the second portion of the first row of the table was changed from 12 years
to 6 years. Also, in Table 1-2, “channels” was modified to “communications systems” in two locations,
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
and the Component Attributes in the last row were modified to clarify that all attributes must be
present to use the associated intervals and activities.
Editorial changes were made to Tables 1-4c, 1-4d., and 1-4e. The words “Protection System” were
added to the headers of Tables 1-4c and 1-4d; in Table 1-4e, a redundant “only” was removed.
No additional changes were made to the Tables.
Measures
No changes were made to the Measures.
VRFs and VSLs
No changes were made to the VRFs and VSLs.
Version History
The Version History was updated to reflect the latest approved version of PRC-005.
Implementation Plan
The Implementation Plan was revised to retire the four legacy standards upon full implementation of
PRC-005-2 rather than upon the Effective Date. Clarifying language was added to address this change.
Supplementary Reference and FAQ Document
Numerous changes, both technical and editorial, were made throughout the Supplementary Reference
and FAQ.
Mapping Document
Minor clarifying changes were made to the Mapping Document.
Consideration of Comments: Project 2007-17
2
Index to Questions, Comments, and Responses
1.
In response to stakeholder input, the SDT made several changes to the standard and associated
definitions as detailed below: ............................................................................................... 11
2.
The SDT made complementary changes in the “Supplementary Reference and FAQ Document” to
provide supporting discussion for the Requirements within the standard. Do you have any specific
suggestions for further improvements? ............................................................................... 24
3.
If you have any other comments that you have NOT provided in response to the above questions,
please provide them here. (Please do not repeat comments that you provided elsewhere.)41
Consideration of Comments: Project 2007-17
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
6.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
7.
Kathleen Goodman
ISO - New England
NPCC 2
8.
Michael Jones
National Grid
NPCC 1
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
10. Michael R. Lombardi Northeast Utilities
NPCC 1
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
12. Bruce Metruck
New York Power Authority
NPCC 6
13. Silvia Parada Mitchell NextEra Energy, LLC.
NPCC 5
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC 1
16. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
18. Brian Robinson
Utility Services
NPCC 8
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Doanld Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Chris Higgins
Group
Bonneville Power Administration
2
3
4
5
X
X
X
X
X
X
X
X
X
X
X
6
7
X
Additional Member Additional Organization Region Segment Selection
1. Fred
Bryant
WECC 1
2. Jason
Burt
WECC 1
3. Brenda
Vasbinder
WECC 1
4. Heather
Laslo
WECC 1
3.
Group
Nick Wehner
Additional Member
ACES Power Marketing Standards
Collaborators
Additional Organization
Region Segment Selection
1. Ashley Gonyer
East Kentucky Power Cooperative
SERC
2. John Shaver
Arizona Electric Power Cooperative
WECC 1, 4, 5
3. John Shaver
Southwest Transmission Cooperative, Inc.
WECC 1, 4, 5
4. Mark Ringhausen
Old Dominion Electric Cooperative
SERC
3, 4
5. Mohan Sachdeva
Buckeye Power, Inc.
RFC
3, 4
6. Scott Brame
North Carolina Electric Membership Corporation RFC
4.
Group
Jesus Sammy Alcaraz
1, 3, 5
1, 3, 4, 5
Imperial Irrigation District (IID)
X
Additional Member Additional Organization Region Segment Selection
Consideration of Comments: Project 2007-17
5
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1. Epifanio Martinez
IID
WECC 1, 3, 4, 5, 6
2. Nando Gutierrez
IID
WECC 1, 3, 4, 5, 6
3. Tony Allegranza
IID
WECC 1, 3, 4, 5, 6
4. Jose Landeros
IID
WECC 1, 3, 4, 5, 6
5.
Group
Greg Rowland
Duke Energy
2
X
3
4
X
5
6
X
X
7
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
Duke Energy
RFC
1
2. Ed Ernst
Duke Energy
SERC
3
3. Dale Goodwine
Duke Energy
SERC
5
4. Greg Cecil
Duke Energy
RFC
6
6.
Group
Will Smith
MRO NSRF
X
X
X
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
MAHMOOD SAFI
MRO
1, 3, 5, 6
2.
CHUCK LAWRENCE ATC
MRO
1
3.
TOM WEBB
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
1, 6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
XCEL
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
3, 5, 6, 1
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTELSON
OTP
MRO
1, 3, 4, 5
14. SCOTT BOS
MPW
MRO
1, 3, 5, 6
15. TONY EDDLEMAN
NPPD
MRO
1, 3, 4
16. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
17. DAN INMAN
MPC
MRO
1, 3, 5, 6
7.
Group
OPPD
Jonathan Hayes
Southwest Power Pool NERC Reliability
Standards Development Team
Consideration of Comments: Project 2007-17
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Additional Member
Additional Organization
Jonathan Hayes
Southwest Power Pool
SPP
NA
2.
Robert Rhodes
Southwest Power Pool
SPP
NA
3.
Paul Abel
Oklahoma gas and electric
SPP
1, 3, 5
4.
John Allen
City Utilities of springfield
SPP
1, 4
5.
Bud Averill
Grand River Dam Authority
SPP
1, 3, 5
6.
Clem Cassmeyer
Western Farmers Electric Cooperative
SPP
1, 3, 5
7.
Paul Cox
GDS Associates
SPP
NA
8.
Willy Haffecke
City Utilities of springfield
SPP
1, 4
9.
Julie Lux
Westar Energy inc.
SPP
1, 3, 5, 6
10. Mahmood Safi
OPPD
MRO
1, 3, 5
11. Sean Simpson
Board of public utilities of kansas city, kansas SPP
NA
12. Louis Guidry
CLECO
SPP
1, 3, 5
13. Lindsay Sheppard
Sunflower Electric Corporation
SPP
1
14. Steve McGie
Coffeyville
SPP
NA
8.
Sam Ciccone
FirstEnergy
Additional Member Additional Organization Region
M. Ferncez
FE
RFC
2.
T. Sheerer
FE
RFC
3.
D. Hohlbaugh
FE
RFC
4.
B. Orians
FE
RFC
5.
J. Chmura
FE
RFC
6.
L. Lee
FE
RFC
7.
R. Loy
FE
RFC
8.
B. Duge
FE
RFC
Group
Mike Garton
Additional Member
Additional Organization
4
5
6
7
X
X
X
X
X
X
X
X
X
Segment
Selection
1.
9.
3
Region Segment Selection
1.
Group
2
Dominion
Region Segment Selection
1. Louis Slade
Dominion Resources Services, Inc. RFC
5, 6
2. Randi Heise
Dominion Resources Services, Inc. MRO
5, 6
3. Connie Lowe
Dominion Resources Services, Inc. NPCC
5, 6
Consideration of Comments: Project 2007-17
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Michael Crowley
10.
Dominion Virginia Power
Group
SERC
Pawel Krupa
2
3
4
5
6
7
8
1, 3, 5, 6
Seattle City Light Operations
Additional Member Additional Organization Region Segment Selection
1. Pawel Krupa
Seattle City Light
WECC 1
2. Dana Wheelock
Seattle City Light
WECC 3
3. Hao Li
SCL
WECC 4
11.
Group
Ron Sporseen
Additional Member
PNGC Small Entity Comment Group
Additional Organization
1.
Joe Jarvis
Blachly-Lane Electric Cooperative WECC 3
2.
Dave Markham
Central Electric Cooperative
WECC 3
3.
Dave Hagen
Clearwater Power Company
WECC 3
4.
Roman Gillen
Consumer's Power Inc.
WECC 1, 3
5.
Roger Meader
Coos-Curry Electric Cooperative
WECC 3
6.
Bryan Case
Fall River Electric Cooperative
WECC 3
7.
Rick Crinklaw
Lane Electric Cooperative
WECC 3
8.
Annie Terracciano
Northern Lights Inc.
WECC 3
9.
Aleka Scott
PNGC Power
WECC 4
10. Heber Carpenter
Raft River Electric Cooperative
WECC 3
11. Steve Eldrige
Umatilla Electric Cooperative
WECC 1, 3
12. Marc Farmer
West Oregon Electric Cooperative WECC 4
13. Margaret Ryan
PNGC Power
12.
Dave Davidson
Group
X
X
X
Region Segment Selection
WECC 8
Tennessee Valley Authority
X
Additional Member Additional Organization Region Segment Selection
1. Rusty Hardison
TOM Support
SERC
1
2. Pat Caldwell
TOM Support
SERC
1
3. David Thompson
TVA Compliance
SERC
5
4. Jerry Finley
Rel&Eng Engeering Stdrs SERC
1
5. Robert Brown
TVA Generation - Nuclear SERC
5
6. Tom Vandervort
TVA Generation - Fossil
SERC
5
7. Annette Dudley
TVA Generation - Hydro
SERC
5
13.
Group
Brenda Hampton
Luminant
Consideration of Comments: Project 2007-17
X
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Additional Member
1. Mike Laney
14.
Additional Organization
2
3
4
5
6
7
Region Segment Selection
Luminant Generation Company LLC ERCOT 5
Group
Frank Gaffney
Florida Municipal Power Agency
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
15.
Group
Jennifer Eckels
FRCC
Colorado Springs Utilities
Additional Member Additional Organization Region Segment Selection
1. Charles Morgan
Colorado Springs Utilities WECC 3
2. Lisa Rosintoski
Colorado Springs Utilities WECC 6
3. Paul Morland
Colorado Springs Utilities WECC 1
16.
Individual
Jim Eckelkamp
Progress Energy
X
X
X
X
17.
Individual
Cole Brodine
Nebraska Public Power District
18.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
X
X
X
19.
Individual
Antonio Grayson
Southern Company
X
X
X
X
20.
Individual
Brandy A. Dunn
Western Area Power Administration
X
21.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
22.
Individual
Michael Falvo
Independent Electricity System Operator
23.
Individual
Jennifer Wright
X
X
Individual
Dale Dunckel
San Diego Gas & Electric
Public Utility District No. 1 of Okanogan
County
25.
Individual
Joe Petaski
Manitoba Hydro
26.
Individual
Kenneth A Goldsmith
Alliant Energy
27.
Individual
Thad Ness
American Electric Power
24.
Consideration of Comments: Project 2007-17
X
X
X
X
X
X
X
X
X
X
X
X
X
X
9
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
28.
Individual
X
2
3
X
Ed Davis
Entergy Services
Individual
30. Individual
Anthony Jablonski
Maggy Powell
ReliabilityFirst
Exelon Corporation and its affiliates
31.
Individual
Eric Salsbury
Consumers Energy
32.
Individual
Chris Searles
BAE Batteries USA
33.
Individual
Kevin Luke
Georgia Transmission Corporation
34.
Individual
Brad Harris
CenterPoint Energy
35.
Individual
Steven Wallace
Seminole Electric Cooperative, Inc
X
36.
Individual
Kirit Shah
Ameren
X
37.
Individual
Public Service Company of New Mexico
X
Individual
Laurie Williams
Steve Alexanderson
P.E.
39.
Individual
Wayne E. Johnson
EPRI
40.
Individual
Bob Thomas
Illinois Municipal Electric Agency
41.
Individual
Travis Metcalfe
Tacoma Power
X
X
42.
Individual
Jonathan Meyer
X
X
Individual
Stephen J. Berger
Idaho Power Company
PPL Generation, LLC on behalf of its Supply
NERC Registered Entities
44.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
X
45.
Individual
Martin Bauer
US Bureau of Reclamation
46.
Individual
Darryl Curtis
Oncor Electric Delivery
X
Individual
48. Individual
d mason
Tony Kroskey
HHWP
Brazos Electric Power Cooperative
X
49.
Individual
Alice Ireland
Xcel Energy
50.
Individual
Brett Holland
Kansas City Power & Light
X
X
51.
Individual
William Cantor
TPI
29.
38.
43.
47.
4
5
X
6
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Central Lincoln
Consideration of Comments: Project 2007-17
7
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10
1.
In response to stakeholder input, the SDT made several changes to the standard and associated definitions as detailed below:
• Revised the “Inspect” element of the definition of Protection System Maintenance Program (PSMP), the definition of
the term Unresolved Maintenance Issues, and the definition of the term Countable Event.
• Revised Clause 4.2.5.4 of the Applicability section of the standard.
• Revised Table 1-2 “Component Type - Communications Systems.”
• Revised Tables 1-4a, 1-4b, 1-4c, 1-4d, and 1-4f “Component Type - Protection System Station dc Supply….”
Do you agree with these changes? If not, please indicate which changes you do not agree with and provide specific
suggestions in the comment area for improvements that would allow you to support the standard.
Summary Consideration:
Some commenters continued to object to various activities and/or intervals within the tables. The drafting team made several
changes detailed below in response to these comments.
1. One interval was changed – the interval for the activity in Table 1-2 for unmonitored communications systems was changed from
12 years back to 6 years as it had been in all previous postings. This change promotes consistency with similar activities within
Table 1-1 (Protective Relays).
2. The language in two activities in Table 1-2 was changed from “channels” to “communications systems”.
3. The language in the Component Attributes in the last row of Table 1-2 was modified to read: “Any communications system with
all of the following:” to clarify that all must be present to use the related intervals and activities.
4. In Table 1-4e, a redundant “only” was removed from the Component Attributes in the last row.
A few commenters continued to contrast the Applicability (4.2.1) with the Interpretation represented in PRC-005-1b. The drafting
team responded, but no changes were made.
Several comments were offered on the informational posting of the draft SAR to revise PRC-005-2 to add reclosing relays. The
drafting team responded, but no changes were made.
Organization
Yes or No
Consideration of Comments: Project 2007-17
Question 1 Comment
11
Organization
Yes or No
Question 1 Comment
No
1. BPA believes the term communications system and channel needs to be
clarified as to whether the intent is the communications system, a
channel on the telecommunication channel, the teleprotection channel,
or the teleprotection function.
2. A. Minimum battery maintenance interval is to assure that the battery
plant will perform as needed, and obtain a reasonable confidence that it
will continue acceptable performance until the next maintenance
evaluation. Typically, any utility VLA battery application, steady state
float charge/long duration discharge, a Monthly or Quarterly
maintenance is excessive given a proper design/maintenance program
(IEEE 450, 484, 485). There is a 60 year proven history of this. BPA
recognizes that there will be specific VLA battery installations that will be
required beyond this minimum. BPA recommends rolling the 4 month
maintenance into the 18 month maintenance schedule.
B. The scientific vetted method of determining a VLA batteries current
performance, and projected performance, is a capacity test. This has
been scientifically verified at least 10 times since 1919, with consistent
results. This approach is consistent with the IEEE 450, as well as many
other standards, and is supported by the industry. If an alternate
approach using measured parameters to predict current and future
battery performance is to be allowed, then it must assure the same
result.
C. Battery monitoring does enable measurements to be made
automatically with greater frequency. Additionally it provides the ability
to collect, store, report, and analyze data from the battery even during
an outage. It does not mitigate the necessity to perform battery
maintenance. If battery monitoring is performed mandatory
maintenance should also be required on the monitor.
Bonneville Power Administration
Response: Thank you for your comments.
Consideration of Comments: Project 2007-17
12
Organization
Yes or No
Question 1 Comment
1. The SDT has modified “channel” to “communications system” in Table 1-2 in response to your comment. Discussion was also
added to Section 15.5.1 of the Supplementary Reference and FAQ Document to explain “channel”.
2. See below:
A.
The drafting team disagrees with your assertion that the 4 month interval should be extended to the 18 month maintenance
schedule for performance of maintenance activities. The 18 month maximum maintenance interval for the unmonitored VLA
battery used in a Protection System station dc supply is too long for verification that there is any voltage on the dc supply, that
each cell of the unmonitored station battery is inspected to see that it has electrolyte in it, or that the unmonitored dc supply is
inspected for unintentional dc grounds.
B.
The drafting team agrees with you that the performance capacity test is a well proven method to determine the capacity of a
station battery and provides an indication of the health of the battery. However, there are other measurements that are indicative
of battery health and performance that when trended to the station battery baseline and examined along with the other
maintenance activities required in Table 1-4 of the standard can indicate that station battery can perform as manufactured. By
trending periodically measured properties indicative of battery performance while serving its Protection System, the Transmission
Owner, Generator Owner or Distribution Provider can develop a condition based method to determine (1) when a station battery
requires a capacity test (instead of performing a capacity test on a predetermined, prescribed interval), (2) when an individual cell
or battery unit should be replaced, or (3) if the station battery should be replaced without performing a capacity test, based on the
analysis of the trended data.
C.
The drafting team agrees that, “battery monitoring does enable measurements to be made automatically with greater
frequency. Additionally it provides the ability to collect, store, report, and analyze data from the battery even during an outage.”
Besides these positive qualities it alleviates the necessity to physically perform - in the station - most of the battery maintenance
activities listed in Table 1-4 (see Table1-4 (f)). However, the inspection of the battery, its cells and the physical condition of the
battery rack are mandatory maintenance activities that must be performed by the maintenance workforce at the station or via
remote control. Concerning the maintenance of the monitoring system, please refer to Table 2 (Alarming Paths and Monitoring) of
the standard for the mandatory maintenance that is required on the monitor.
Imperial Irrigation District (IID)
No
IID does not agree with the proposed changes to the definition of Inspect
using the word Examine and suggests using Visual Examination instead.
Response: Thank you for your comments. The SDT believes the word ‘Examine’ is correct.
Consideration of Comments: Project 2007-17
13
Organization
Western Area Power Administration
Yes or No
No
Question 1 Comment
The Standard Drafting team has made changes to the battery maintenance
tables 1-4 (a-f) that does not reflect the extensive re-wording of the
Supplemental Reference/FAQ document or address the posted
recommendations of IEEE Battery Task Force. The industry needs clear,
concise maintenance tasks, intervals and standards for their maintenance
programs that are developed and tested by industry experts such as IEEE
and EPRI.
Response: Thank you for your comments.
The changes to maintenance tables 1-4 (a-f) were made as a result of conversations with members of the IEEE Battery Task Force
and their recommendations to the drafting team. The drafting team disagrees with the assertion that the changes to the tables do
“not reflect the extensive re-wording of the Supplementary Reference and FAQ document.” The drafting team considered the IEEE
Battery Task Force Recommendations and revised the Standard with the assistance of several of their members (see the drafting
team response posted on the NERC site).
The drafting team believes that the Component Attributes, Maximum Maintenance Intervals and Maintenance Activities of Table
1-4 are clear and concise. If an owner has a question concerning how to perform any maintenance activity listed in the table, the
Supplementary reference and FAQ document along with IEEE and EPRI documents provide unambiguous and succinct examples of
how to perform the activity. This standard is not intended to instruct the Transmission Owners, Generator Owners or Distribution
Providers on how to perform the minimum maintenance activates listed in the tables. PRC-005-2 must plainly and tersely tell the
owners what they must do - not how to do it.
American Electric Power
No
The first column, third row of Table 1-2 should be clarified to indicate
whether the bulleted items are related by an “or” clause or an “and” clause.
For example, must the communication system have either or both of those
attributes for it to be considered?
Response: Thank you for your comment. We are requiring both bullets to be applicable and have changed the wording to better
reflect our intention.
ReliabilityFirst
No
Consideration of Comments: Project 2007-17
ReliabilityFirst offers the following comments related to the bullet points in
Question 1:
14
Organization
Yes or No
Question 1 Comment
a. Bullet 1 - Agree with definition revisions
b. Bullet 2 - Agree with clause 4.2.5.4
c. Bullet 3 - Disagree with revised Table 1-2 “Component Type Communications Systems.” The revision increased the maximum time for
unmonitored systems to 12 years. However, communication failures
correspond to one of the top three causes of Misoperations. The revised last
row of the Table 1-2 still permits continuous monitoring to be substituted
for testing. It is not clear that the available monitoring can actually identify
the health of many of the components that can fail in a power line carrier
communication system. RFC believes more research is needed to
substantiate the 12 calendar year maintenance interval for unmonitored
communications systems.
d. Bullet 4 - Disagree with revised tables 1-4a, 1-4b, 1-4c, 1-4d, and 1-4f
“Component Type - Protection System Station dc Supply....” The changes
appear to largely ignore the recommendations of the IEEE Stationary Battery
Committee.
Response: Thank you for your comments.
A. Thank you.
B. Thank you.
C. The SDT agrees with your comment and has changed the maximum interval for this activity back to 6 calendar years.
D. The changes to maintenance tables 1-4 (a-f) were made as a result of conversations with members of the IEEE Battery Task
Force and their recommendations to the drafting team. The drafting team considered the IEEE Battery Task Force
Recommendations and revised the standard with the assistance of several of their members (see the drafting team response
posted on the NERC site).
BAE Batteries USA
No
Consideration of Comments: Project 2007-17
I agree with the basic changes, but recommend that a slight modification be
made to Tables 1-4(a) and 1-4(b). In the box defining the 18 calendar
Months or 6 Calendar Years, the portion in parentheses (e.g. internal ohmic
values or float current) should be changed to (e.g. internal ohmic values or
15
Organization
Yes or No
Question 1 Comment
float current in concert with other accepted measurements).
Response: Thank you for your comments.
The drafting team disagrees and believes that examination of other accepted measurements and inspection results (indicative of
battery performance) are a part of trending to the station battery baseline. This same inference applies to the interpretation of the
results of a performance or modified performance capacity test for determining whether a station battery should be replaced or
cells removed. Please see section 15.4 of the Supplementary Reference and FAQ document for a further discussion of this topic.
Central Lincoln
No
Central Lincoln agrees with most of the changes except for the change from
“as designed” to “as manufactured” in the Station DC supply table. The
concern is not high enough to warrant a negative ballot, and we appreciate
the difficulty the SDT has had on this issue with IEEE. The “as manufactured”
performance may be interpreted as the battery’s capacity when new and
fully charged. Of course a properly engineered system will be based on a
future aged battery capacity, reduced from the brand new capacity. We
prefer “as designed,” but this might lead a CEA to ask for design
documentation an entity may have not retained. In the end, it is not the
manufactured or design capacity that matters, it is the battery’s ability to
power the protection systems and trip the breakers. We suggest “as
manufactured” be changed to “as needed.”
Response: Thank you for your comment.
One of the reasons that “as designed” was changed to “as manufactured” is as you discussed. If “as designed” is used it will be
difficult for the owner to determine the original design for the dc system, making it difficult for an owner during an audit. Just like
the term “as designed” is difficult to document, “as needed” will also be harder for the owner to document than “as manufactured.”
See question “Why is it necessary to verify the battery string can perform as manufactured?” in Section 15.4 of the Supplementary
Reference and FAQ document for a further explanation of this change.
EPRI
No
Consideration of Comments: Project 2007-17
1. Table 1-4a - Verify that the station battery can perform as manufactured
by evaluating the measured cell/unit internal ohmic values against the
baseline values of each cell.-and-Verify that the station battery can
perform as manufactured by conducting a performance capacity test of
16
Organization
Yes or No
Question 1 Comment
the entire battery bank.
2. Table 1-4b - Verify that the station battery can perform as manufactured
by evaluating the measured cell/unit internal ohmic values against the
baseline values of each cell.-or-Verify that the station battery can
perform as manufactured by conducting a performance capacity test of
the entire battery bank.
3. Table 1-4c - Verify that the station battery can perform as manufactured
by evaluating the measured cell/unit internal ohmic values against the
baseline values of each cell.-and-Verify that the station battery can
perform as manufactured by conducting a performance capacity test of
the entire battery bank.
Response: Thank you for your comments:
1. The standard drafting team believes the “or” of table 1-4(a) should not be replaced with the “- and -” as stated in your
comment. The station battery owner of a VLA battery should be allowed to perform either of the two maintenance activities
listed in table 1-4(a) to be compliant with the standard, and that “cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current)” should remain in the standard.
2. The standard drafting team agrees that the “-or-”should remain as you suggested in your comment. This will allow the owner
of a VLRA battery to choose compliance by performing either of the two maintenance activities at their maximum
maintenance intervals listed in table 1-4(b).
3. Because of the marked difference in the aging process of lead acid and nickel-cadmium station batteries the drafting team
does not believe that trending ohmic values against the baseline values of each cell, and conducting a performance capacity
test of the entire battery bank is the appropriate maintenance activity for NiCad Batteries to ‘Verify’ that the station battery
can perform as manufactured. The only appropriate maintenance activity in Table 1-4(c) at the maximum maintenance
interval of 6 calendar years is to “Verify that the station battery can perform as manufactured by conducting a performance or
modified performance capacity test of the entire battery bank.”
Illinois Municipal Electric Agency
No
Consideration of Comments: Project 2007-17
Illinois Municipal Electric Agency supports comments submitted by Florida
Municipal Power Agency. IMEA appreciates SDT efforts, and supports the
overall refinements in PRC-005-2; however, the inconsistency between 4.2.1
and the FERC-approved interpretation of PRC-005-1b needs to be resolved
17
Organization
Yes or No
Question 1 Comment
to avoid confusion. This issue has implications for smaller entities in
particular.
Response: Thank you for your comments.
The SDT believes that the Applicability 4.2.1 as stated in PRC-005-2 is correct and supports the reliability of the BES. The SDT
believes all Protection Systems installed for the purpose of detecting faults on the BES need to be maintained per the
requirements of PRC-005-2. The SDT observes that the approved Interpretation addresses the term, “transmission Protection
System”, and notes that this term is not used within PRC-005-2; thus the Interpretation does not apply to PRC-005-2. Please see
Section 2.3 of the Supplementary Reference and FAQ document for additional discussion.
PPL Generation, LLC on behalf of its
Supply NERC Registered Entities
No
See Question 3 Comments
Response: Thank you for your comments. Please see the response to your Question 3 comments.
TPI
No
See IEEE Stationary Battery Committee Letter dated 23 March 2012
Response: Thank you for your comments.
The drafting team considered the IEEE Battery Task Force Recommendations and revised the standard with the assistance of
several of their members (see the drafting team response posted on this project’s page of the NERC website).
Tennessee Valley Authority
No
MRO NSRF
Yes
While we agree with the changes made, we believe that table 1-4 should
include in the 18 calendar month maintenance activities: 1) Setting the
battery charger to equalize, and 2) Inspect battery charger components for
leakage and or damage. These additional steps would verify the ability of the
battery charger to operate as needed.
Response: Thank you for your comments.
Because all battery chargers used in Protection Systems do not have equalize settings or have components that leak, the drafting
Consideration of Comments: Project 2007-17
18
Organization
Yes or No
Question 1 Comment
team does not believe your recommendation is appropriate for this standard.
Southern Company
Yes
Related to the changes identified in the Battery Tables:
1. We do not see that the change from “as designed” to “as
manufactured” really changed the meaning of the battery capability to
delivery its rated capacity. We would like the SDT to consider the
following language: “verify that the station battery can provide adequate
power to the Protection System by conducting.....”
2. For Generating Plant Batteries, we feel as though that the only way to
prove that a generation battery can deliver what it is supposed to be
able to deliver for “All” of its functions is by conducting a capacity test”.
We would like the SDT to consider adding such a Note to the battery
tables and/or make the statement in the FAQ document.
Response: Thank you for your comments:
1.
2.
To “verify that the station battery can provide adequate power” for a battery serving a generating station dc supply or a
station dc supply that has dc loads considerably greater than the Protection System requirements may appear to be a good
choice; however, the use of “adequate power” makes it difficult for the Generator Owner to determine the original design of
the dc system and show an auditor that “adequate power” can be delivered to the dc system by the battery. For this reason
and others explained in the Supplementary Reference and FAQ document under the question “why is it necessary to verify
the battery string can perform as manufactured?” The drafting team believes that perform as “manufactured” is the best
wording for the standard.
Your concerns about large amp-hour batteries used in generating stations and transmission stations with large auxiliary loads
was addressed in the drafting team’s response to the Chair of the IEEE Stationary Battery Committee, which stated:
“In contrast to the Transmission Owner battery design function, a Generator Owner's battery likely feeds other critical
loads such as DC powered oil pumps, seal oil pumps, and other DC control power loads necessary to safely shutdown a
power plant following a loss of AC power. In the case of nuclear plants, these DC loads could include motor operated
valves and other loads related to nuclear safety. For the Generator Owner, the design load profile for the battery is a
long duration, deep discharge of the battery. While a cell ohmic value trending program might be adequate to prove
that the Generator Owners battery could fulfill its Protection System function, the Generator Owner might want to
Consideration of Comments: Project 2007-17
19
Organization
Yes or No
Question 1 Comment
validate the deep discharge capability of the battery by routine periodic capacity testing to prove the battery's
adequacy at providing power to those long duration loads critical for plant shutdown. The PSMTSDT believes that this
deep discharge battery capacity test approach will prove the battery can meet its function relative to the plant
Protection System without also having a trending program for cell ohmic values.”
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration LP agrees that the changes described above make
PRC-005-2 clearer and less ambiguous. We believe that this will result in far
fewer violations related to administrative or documentation errors - and
focus on those cases which actually may impair BES reliability.
Yes
TABLE 1-5: Similar to the distributed under-frequency load-shedding relays,
SPS control circuitry should only be regulated to verify the integrity of the
control circuits from the relay to the lockout or auxiliary relay that is used to
trip the circuit breakers, but not to the circuit breakers themselves. Owners
of SPS control circuitry should have the option of testing these schemes
using test procedures that will confirm the control circuitry through the
completed trip circuit is continuous and that the circuit breaker will operate
when required. Often times the operation of the circuit breaker is
confirmed by operation through other protection systems and the SPS
function is a parallel path that can be verified without operating the circuit
breaker. This change would allow the Transmission Owner to eliminate
equipment outages required to test this scheme or the risk caused by
removing the SPS for energized testing.
Response: Thanks for your support.
San Diego Gas & Electric
Response: Thank you for your comments.
The table only requires that the SPS control circuit path including the trip coil of the breaker be verified with a 12 year maximum
interval. The testing does not have to be done all at once; the maintenance activities in the table can be performed in segments
and are complete as long as the entire circuit is tested within the interval. Section 10 of the Supplementary Reference and FAQ
document provides additional discussion on this.
Alliant Energy
Yes
Consideration of Comments: Project 2007-17
While we agree with the changes made, we believe that Table 1-4 should
20
Organization
Yes or No
Question 1 Comment
include in the 18 month maintenance activities more checks on Battery
Chargers. Based on EPRI data and vendor recommendation we believe that
1) Setting the Battery Charger to equalize, and 2) Inspect battery charger
components for leakage and/or damage should be added. These additional
steps would better verify the ability of the battery charger to operate as
needed.
Response: Thank you for your comments.
Because all battery chargers used in Protection Systems do not have equalize settings or have components that leak, the drafting
team does not believe your recommendation is appropriate for this standard.
Ameren
Yes
We believe that the SDT has improved the definitions with these changes
and we fully support them. In addition, we also support the Table 1-2
Communication Systems changes based on our experience, and the Station
dc Supply changes in the five Tables 1-4a, 1-4b, 1-4c, 1-4d, and 1-4f because
they are realistic and consistent with our experience.
Yes
1. PNM seeks clarification on the revised Clause 4.2.5.4 of the Applicability
section of the standard. - “Protection Systems for station service or
excitation transformers connected to the generator bus of generators which
are part of the BES, that act to trip the generator either directly or via
lockout or tripping auxiliary relays.” Will Auxiliary Transformers that are
directly connected to the generator bus of generators which are part of the
BES and that step down to distribution level voltage & perform similar
functions as that of station service transformer fall under this clause?
Response: Thank you for your support.
Public Service Company of New
Mexico
Response: Thank you for your comments.
If the cited Protection Systems trip the generator, they are applicable to the requirements of PRC-005-2 and maintained
accordingly.
Brazos Electric Power Cooperative
Yes
Consideration of Comments: Project 2007-17
Please see the formal comments submitted by ACES Power Marketing.
21
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. Please see the response to ACES Power Marketing.
Northeast Power Coordinating
Council
Yes
ACES Power Marketing Standards
Collaborators
Yes
Duke Energy
Yes
Southwest Power Pool NERC
Reliability Standards Development
Team
Yes
FirstEnergy
Yes
Dominion
Yes
PNGC Small Entity Comment Group
Yes
Luminant
Yes
Colorado Springs Utilities
Yes
Nebraska Public Power District
Yes
PacifiCorp
Yes
Independent Electricity System
Operator
Yes
Public Utility District No. 1 of
Yes
Consideration of Comments: Project 2007-17
22
Organization
Yes or No
Question 1 Comment
Okanogan County
Manitoba Hydro
Yes
Consumers Energy
Yes
Georgia Transmission Corporation
Yes
CenterPoint Energy
Yes
Seminole Electric Cooperative, Inc
Yes
Tacoma Power
Yes
Idaho Power Company
Yes
American Transmission Company,
LLC
Yes
US Bureau of Reclamation
Yes
Oncor Electric Delivery
Yes
Xcel Energy
Yes
Kansas City Power & Light
Yes
HHWP
no comment
Consideration of Comments: Project 2007-17
23
2.
The SDT made complementary changes in the “Supplementary Reference and FAQ Document” to provide supporting discussion
for the Requirements within the standard. Do you have any specific suggestions for further improvements?
Summary Consideration:
Commenters suggested a variety changes to the Supplementary Reference and FAQ document. The SDT appreciated the feedback and
made numerous modifications to the document ranging from correcting typographical errors to including some additional FAQ and
corresponding answers, as well as presenting new and revised technical content.
Organization
San Diego Gas & Electric
Yes or No
Question 2 Comment
No
R5/M5: M5 should add “The evidence may include but is not limited to...tracking of
the unresolved maintenance issue in accordance with the TO’s corrective
maintenance process.” This alleviates the Transmission Owner from setting up a
separate corrective maintenance tracking process intended solely for this regulation.
Response: Thank you for your comments.
This comment is related to the standard itself and not to the Supplementary Reference and FAQ document. The Measures are
intended to provide examples of evidence, and are not meant to be all-inclusive.
Illinois Municipal Electric
Agency
No
Illinois Municipal Electric Agency supports comments submitted by Florida Municipal
Power Agency.
Response: Thank you for your comments. Please see the responses to Florida Municipal Power Agency’s comments.
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
No
See Question 3 Comments
Response: Thank you for your comment. Please see the responses to your Question 3 comments.
Northeast Power Coordinating
Council
No
Imperial Irrigation District (IID)
No
Consideration of Comments: Project 2007-17
24
Organization
Yes or No
Duke Energy
No
Southwest Power Pool NERC
Reliability Standards
Development Team
No
Tennessee Valley Authority
No
Colorado Springs Utilities
No
Nebraska Public Power District
No
PacifiCorp
No
Ingleside Cogeneration LP
No
Independent Electricity
System Operator
No
Public Utility District No. 1 of
Okanogan County
No
Manitoba Hydro
No
CenterPoint Energy
No
Seminole Electric Cooperative,
Inc
No
Tacoma Power
No
Consideration of Comments: Project 2007-17
Question 2 Comment
25
Organization
Yes or No
Idaho Power Company
No
Kansas City Power & Light
No
Bonneville Power
Administration
Yes
Question 2 Comment
BPA requests the drafting team to provide more detailed examples of the following
for both monitoring and testing:
1. That addresses the multiple routes, and automated switching between the
routes, in a typical large Telecommunications Network Cloud. This applies only if
testing of the ‘cloud’, or a teleprotection channel through the ‘cloud’, is the intent
of the standard.
2. That addresses the fact that many older teleprotection technologies, not only
used separate test inputs/outputs, but the internal path through the equipment is
unverified until the particular function is activated. I.E.: In certain technologies, a
functioning ‘guard’ signal does not have any correlation to a functioning ‘trip’
signal.
Response: Thank you for your comments.
1. The intent of the standard is to verify the teleprotection channel is functional, regardless of what constitutes the channel.
2. The SDT believes that the maintenance activity in Table 1-2, “Verify operation of communication system inputs and outputs that
are essential to proper functioning of the Protection System” allows the entity flexibility to maintain the various technologies that
they may own. The Supplementary Reference and FAQ document addresses some of the options available, but obviously cannot
provide detail on all types of equipment.
ACES Power Marketing
Standards Collaborators
Yes
Several capitalized terms in the supplementary reference document are used
inconsistently with their definition or the reference to their definition is not clear.
For example, “communications Systems” in the second bullet in section 2.2 uses
“Systems” inconsistently with its definition. The use of “sensing Element” on page 6
is another example. We believe this is inconsistent with the definition of Element
which could be a generator, transformer, circuit breaker, bus section, etc. but does
not appear to be a Protection System Component.
The “localized” definition of Component that is contained in the standard should also
Consideration of Comments: Project 2007-17
26
Organization
Yes or No
Question 2 Comment
be included in the reference document since it is not in the NERC Glossary. Use of
“dc Load” on page 82 is not consistent with the definition of Load. Load is an end use
customer. There are many other places in the document where there are
inconsistencies with these definitions. Thus, the document needs to be further
reviewed to ensure the use of the terms is consistent with their definitions.
Response: Thank you for your comments. The SDT modified the Supplementary Reference and FAQ document as you suggested.
Dominion
Yes
The term ‘Underfrequency' is capitalized in the Supplementary Reference document
yet it is not included in NERC’s Glossary of terms. We suggest a return to lower case.
In fact, given this document is meant to be used for reference only, we question the
need to capitalize any term.
Response: Thank you for your comments.
The SDT modified the Supplementary Reference and FAQ document as you suggested. For consistency with the standard, the SDT will
continue to capitalize terms when they are used in the context defined in the NERC Glossary of Terms.
Luminant
Yes
The testing of non-BES breakers for plants should be discussed in the FAQ using the
similar application for Distribution Providers. Luminant recommends a section for
Generation Owners that describes what Elements (circuit breakers) should be tested.
Luminant strongly believes that there is no additional benefit to the BES by requiring
the GO to test the non-BES breakers (UAT low side and generator field breakers).
These circuits are radial fed.
Response: Thank you for your comments.
The FAQ discussion on testing of non-BES breakers for Distribution Providers pertains to those devices used as part of UFLS or UVLS
schemes. Section 15.3.1 of the Supplementary Reference and FAQ document has been augmented to address this topic for
Generator Owners.
Southern Company
Yes
See comment on Generating Plant Batteries in Question #1.
Response: Thank you for your comments. Please see the response to your comments in Question 1.
Western Area Power
Yes
Western Area Power Administration is appreciative of the hard work done by the SDT
Consideration of Comments: Project 2007-17
27
Organization
Yes or No
Administration
Question 2 Comment
and NERC. We respectfully submit that the Supplementary Reference and FAQ
Document should:
1. Offer guidance on establishing baselines for older battery banks
2. Be in agreement with IEEE standards for battery maintenance
3. Replace the existing CANS
Response: Thank you for your comments.
1. Please see Section 15.4.1 of the Supplementary Reference and FAQ document, specifically the question, “How is baseline
established for cell/unit internal ohmic measurements?” which offers guidance on establishing baselines for older battery banks.
2. The IEEE documents to which you refer are “Recommended Practices” as explicitly stated in their titles and not mandatory
standards. The SDT considered the IEEE Recommended Practices, as well as other documents, in developing the minimum
requirements and maximum intervals within PRC-005-2.
3. The CANs are developed by NERC Compliance Staff to address specific currently-approved NERC Standards, and will be retired
when the related standards are retired. The SDT has no control or influence regarding CANs.
Alliant Energy
Yes
Section 15.4 of the FAQ document does an excellent job of describing the details of
battery maintenance and testing, but there is essentially no description of battery
charger maintenance and testing activities. We believe this section needs to be
expanded to include a good description of battery charger maintenance activities as
well.
Response: Thank you for your comments.
While manufacturers’ recommendations for maintenance of their equipment are quite diverse, the required maintenance activities
within PRC-005-2 for battery chargers are: verification of the station dc supply voltage (maximum unmonitored maintenance interval
4 calendar months); and, verification of the battery charger float voltage (maximum unmonitored maintenance interval of 18
calendar months). If anomalies regarding the battery charger are found by performing these activities, relevant corrective actions
should be taken.
American Electric Power
Yes
Rather than voluminous supplementary references, we suggest adding this
information, as necessary, to the standard itself. Not only would this prove beneficial
by having less information housed outside of the standard, it might also help prevent
Consideration of Comments: Project 2007-17
28
Organization
Yes or No
Question 2 Comment
the need for future CANs and interpretation requests. Though the guidance provided
in these documents may appear to be beneficial, we are troubled that the SDT feels it
is necessary to provide such a volume of material outside the standard itself, and yet
still consider such “references” as enforceable.
Response: Thank you for your comments.
This document provides supporting discussion, but is not part of the standard and not enforceable. The SDT intends that it be posted
as a reference document accompanying the standard. As established in the SDT Guidelines, the standard is to be a terse statement
of requirements, and is not to include explanatory information like that included in the Supplementary Reference and FAQ
document. The Supplementary Reference and FAQ document will be revised in conjunction with any revisions of PRC-005.
BAE Batteries USA
Yes
1. On page 21 of 97,Question 7.1, "Please provide an example of the unmonitored
versus other levels of monitoring available," "Every six calendar years, perform/verify
the following: Battery performance test (if ohmic tests are not opted)" - add after
ohmic tests "or other accepted battery measurement parameters."
2. pg 22 of 97, Example 2 "Every 18 calendar months": Add the same verbiage so that
the first bullet reads: "Battery ohmic values or other accepted battery measurement
parameters to station battery baseline . . ."
3. pg 23 of 97, Example 3 "Every 18 calendar months": Add the same verbiage so that
the first bullet reads: "Battery ohmic values or other accepted battery measurement
parameters to station battery baseline . . ."
4. pg 23 of 97, Example 3 "Every six calendar years": Add the same verbiage so that
the first bullet reads: "(if internal ohmic test or other accepted battery measurement
parameters to station battery baseline are not opted)"
5. pg 27 of 97, Question 8.1.2, item #4: Change the last sentence to read: "However,
the methods prescribed in these recommendations cannot be specifically required
because they are offered as best practice guidelines and not set as standards."
6. pg 71 of 97, Question 15.4.1, Frequently asked Questions: "How is a baseline
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Yes or No
Question 2 Comment
established for cell/unit internal ohmic measurements?" 2nd paragraph - 1st
sentence, replace the word "consistent test equipment" with "the same type of test
equipment." In addition, should add a final sentence at the end of this paragraph
that states, "Also, in many cases, one manufacturer's 'conductance' test may not
produce the same measurement results as another 'conductance' test
manufacturer’s equipment. Therefore, for meaningful results to an established
baseline, the same instrument should always be used."
7. Page 73 of 97, Question 15.4.1, Frequently asked questions: "What conditions
should be inspected for visible battery cells?" Approximately in the 7th line modify
the sentence to read . . .abnormal color(which is an indicator of sulfation or possible
copper contamination) . . .
8. Page 75 of 97, Question 15.4.1, Frequently asked questions: "How do I verify the
battery string can perform as manufactured?" 2nd paragraph that reads "Whichever
parameter is evaluated . . ." should be revised to say "Whatever parameters are used
to evaluate the battery (ohmic measurements, float current, float voltages, specific
gravity, performance test, or combination thereof), the goal is to determine . . .
9. Page 75 of 97, Question 15.4.1, Frequently asked questions: "How do I verify the
battery string can perform as manufactured?" 5th paragraph starts, "A detailed
understanding of the characteristic of a battery is also attempting to use float current
as a measure of the ability of a battery . . . and ends with "to see if a trending process
is recommended for determining aging of these products." The Stationary Battery
Task Force recommends deleting this whole paragraph due to inaccuracies or
statements that are not relevant. If a paragraph that alludes to float current is
considered critically essential, then a short paragraph could be substituted which
might say," Float current along with other measureable parameters can be used in
lieu of or in concert with ohmic measurement testing to measure the ability of a
battery to perform as manufactured. The key to using any of these measurement
devices is to establish a trending line against baseline so that a documented process
establishes the validity of the judgment used to determine that the battery may
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Question 2 Comment
perform or not perform as manufactured."
10. Page 81 of 97, Question 15.4.1, Frequently asked questions: "Why does it appear
that there are two maintenance activities in Table 1-4(b) for VRLA batteries . . . .?"
3rd paragraph: "A comparison and trending against the baseline new battery ohmic
reading can be used in lieu of capacity tests to determine remaining battery life.
Remaining battery life is analogous to stating that the battery is still able to 'perform
as manufactured.'" This might better be restated as follows: "Trending against the
baseline of VRLA cells in a battery string is essential to determine approximate state
of health of the battery. For example, using ohmic measurement testing as the
mechanism for measuring the battery cells, then, if all the cells in the string show to
be in a consistent trend line and that trend line has not risen above say a 25-30%
deviation over baseline, then a judgment can be made that the battery is still in a
reasonably good state of health. This judgment can assume that the battery is still
able to 'perform as manufactured.' It would be wise to confirm the accepted
deviation range with the manufacturer of the battery in question to assure good
judgment in deciding on the state of health to perform as manufactured.' This is the
intent of the "perform as manufactured six-month test' at Row 4 on Table 1-4(b)."
11. Page 81 of 97, Question 15.4.1, Frequently asked questions: [same as Item #10
above], following paragraph: Recommend using a range of 25-30% with the
statement that "It would be wise to confirm the accepted deviation range with the
manufacturer of the battery in question to assure good judgment' in deciding on the
state of health to perform as manufactured.
Response: Thank you for your comments.
1. The SDT modified the Supplementary Reference and FAQ document on page 21 as you suggested.
2. The SDT modified the Supplementary Reference and FAQ document on page 22 as you suggested.
3. The SDT modified the Supplementary Reference and FAQ document on page 23 as you suggested.
4. The SDT modified the Supplementary Reference and FAQ document on page 23 as you suggested.
5. The drafting team agrees with your comment concerning all of the best practices of the IEEE guidelines not being requirements of
the standard and incorporated your comments into the Supplementary Reference and FAQ document on page 27.
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6.
7.
8.
9.
10.
11.
Yes or No
Question 2 Comment
The drafting team incorporated your comments concerning same type test equipment replacing consistent type test equipment
on pages 71 & 72 of the Supplementary Reference and FAQ document.
The drafting team added a comment regarding color observation on page 74 of the Supplementary Reference and FAQ
document.
The SDT modified the Supplementary Reference and FAQ document on page 75 as you suggested.
The SDT modified the paragraph on float current on page 75 of the Supplementary Reference and FAQ document as you
suggested.
The SDT modified the Supplementary Reference and FAQ document based on your comment.
The SDT revised the Supplementary Reference and FAQ document as you suggested.
Georgia Transmission
Corporation
Yes
Recommend adding further comments on data retention. We prefer the
interpretation for the maintenance cycles equaling 12 calendar years, example
microprocessor protective relays. This proves the extreme of data retention. We
interpret the retention period to be 24 years. Previous test record to current test
record equals 12 years, and 12 more years (next maintenance cycle) before removing
previous records from storage (24 years).
Response: Thank you for your comments.
To be assured of compliance, the SDT believes the Compliance Monitor will need the data for the most recent performance of the
maintenance, as well as the data for the preceding maintenance period. This seems to be consistent with what auditors are expecting
(per the SDT’s experience), and is also consistent with Compliance Process Bulletins 2011-001 and 2009-05.
Ameren
Yes
(1) Capitalizing in some cases is inappropriate (e.g., Systems; Glossary defines System
as ‘A combination of generation, transmission, and distribution components.’ So
‘communication System’ incorrectly capitalizes ‘system').
(2) Page 15, we disagree with retention of maintenance records for replaced
equipment as this can cause confusion. We believe that at the most the last
maintenance date could be retained to prove interval between it and the test date of
the replacement equipment that provides like-kind protection.
(3) We request the SDT to provide a few examples of ‘non-battery-based dc supply’.
The SDT has previously responded that this does not include ‘capacitor trip devices’.
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Yes or No
Question 2 Comment
Does the SDT mean to include M-G sets, flywheels, and / or rectifiers? Also, Emerging
Technologies on page 73 is vague please clarify.
Response: Thank you for your comments.
1. The SDT revised the Supplementary Reference and FAQ document to address your comment.
2. The records for removed/replaced equipment need to be retained to provide documented evidence that the entity was in
compliance for the entire compliance monitoring period. This documentation includes maintenance activities as well as
maintenance intervals.
3. As noted, the drafting team previously stated that the “capacitor trip devices” on circuit breakers and reclosers are not examples
of station dc supply devices using emerging technology. Some of the non-battery based energy storage devices with
demonstrated prototypes for use in Protection System dc supplies are the flywheel and the fuel cell. One non-battery based dc
supply commercially available in the United States and Canada uses compressed air and a capacitor to replace the electrochemical
process of a station battery for supplying the dc power required for operating Protection System elements and for supplying
normal dc power to the station in the event of loss of ac power.
Public Service Company of
New Mexico
Yes
The Supplementary Reference and FAQ Document has served as a valuable resource
and PNM commends the drafting team’s efforts in writing a comprehensive
document.
Section 13. Self Monitoring Capabilities and Limitations - Last but one bullet on Page
59 of the Supplementary Reference and FAQ Document is confusing and needs
possible rewording and clarification. “With this information in hand, the user can
document monitoring for some or all sections by extending the monitoring to
include...” appears confusing.
Response: Thank you for your comments. The SDT modified the Supplementary Reference and FAQ document to address your
comment.
EPRI
Yes
Why consider the ability of the station battery to perform as manufactured? The
reason the term “perform as manufactured” was used is because there is not much
data available to verify actual sizing of the cells for their application. The only battery
values for typical Protection systems that have a verifiable basis are the battery
manufacturer’s data. The only way to know when a battery needs to be replaced is to
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Question 2 Comment
compare measured values against manufacturer’s data or other established values.
To verify that the station battery can perform as manufactured is the process of
determining when the station battery must be replaced or when an individual cell or
battery unit must be removed or replaced. Inspections alone do not provide trending
information that indicates the state of aging of a station battery. The maintenance
activities listed in Table 1-4 to “verify that a station battery can perform as
manufactured” are intended to provide information about the aging process of a
station battery. A Transmission Owner, Generator Owner or Distribution Provider
can then use the information provided by the maintenance activity to determine if
testing of a station battery is required or if timely replacement or removal of the
station battery or its components (cell/unit) should be accomplished. Capacity
discharge testing is the only industry approved method of determining the true
capacity of lead acid and nickel-cadmium station batteries. The performance capacity
test of the entire battery bank listed as maintenance activities of table 1-4 provides a
mechanism for trending battery discharge characteristics based on manufacturers
published data. Trending discharge test results is the basis for determining the aging
of a station battery serving a Protection System. Based on these results, decisions
concerning replacement of a battery serving a Protection System and its components
can be made by the Transmission Owner, Generator Owner or Distribution Provider.
There is a marked difference in the aging process of lead acid and nickel-cadmium
station batteries. The difference in the aging process of the two types of batteries is
chiefly due to the electrochemical process of the battery type. Aging and eventual
failure of lead acid batteries is due to expansion and corrosion of the positive grid
structure, loss of positive plate active material, and loss of capacity caused by
physical changes in the active material of the positive plates. However, the primary
failure of nickel - cadmium batteries is because of the gradual linear aging of the
active materials in the plates. The electrolyte of a nickel - cadmium battery only
facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued
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corrosion of the positive plate and grid structure throughout its operational life while
a nickel - cadmium battery does not. Changes to the periodic measured properties of
a lead acid battery when trended to a baseline can provide an indication of aging of
the grid structure, positive plate deterioration, or changes in the active materials in
the plate. Since aging in nickel-cadmium cells is linear, periodic measured properties
of nickel-cadmium cells when trended to a baseline can provide an indication of aging
of the active material in the positive plates. By trending periodic measured properties
of a station battery serving its Protection System the Transmission Owner, Generator
Owner or Distribution Provider can develop a condition based method to determine
(1) when a station battery requires a capacity test (instead of performing a capacity
test on a predetermined, prescribed interval), (2) when an individual cell or battery
unit should be replaced, or (3) based on the analysis of the trended data, if the
station battery should be replaced without performing a capacity test. There is a
clear difference in the aging process of lead acid and nickel-cadmium batteries. The
measurable properties of a nickel - cadmium battery will change more gradually than
VRLA cells; therefore, periodic interval and trending to determine aging has very little
industry experience, but the user should work with the battery manufacturer to
determine if internal ohmic measurements can be applied to their product. While it
has been proven that there is a relationship between internal ohmic measurements
and cell capacity of lead acid batteries, an accurate determination of a battery’s exact
capacity cannot be attained by measuring its cell’s internal ohmic values. However,
trending internal ohmic measurement of VRLA battery cells to establish a base line is
a method of trending measured properties by Transmission Owners, Generator
Owners and Distribution Providers to evaluate their station battery cells for health
and aging. Evaluating internal ohmic cell/unit measurements against the battery cell
baseline values is an acceptable Maintenance Activity listed in tables 4-1(a) and 41(b) 4-1(c) to verify that the station battery can perform as manufactured as long as it
is measured and trended to the baseline values at an interval less than or equal to
the published Maximum Maintenance Interval of tables. Why was the term
“manufactured” used instead of “designed” in the maintenance activities of tables 1-
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4(a), 1-4(b), 1-4(c), 1-4(d) and 1-4(f)?The phrase “as designed” always raises the
question of “who made the design requirements that are being tested to or
evaluated, the manufacturer of the battery or the engineer sizing the battery? The
use of the term designed when discussing a battery’s ability to perform was incorrect
because we did not differentiate between a performance test and a service test. The
phrase “meets the design requirements” is used when discussing a service test which
is a discharge test that measures a battery’s capability to meet a duty cycle which
was designed by the person sizing the battery. However, when talking about a
performance capacity test, the test is a measure of the currents or amp-hour
discharge rates based on the battery manufacturer data for the station battery being
tested. The term “manufactured” used in the tables avoids the confusion caused by
the term “designed” and its application to service testing. Also, when discussing
internal ohmic measurement trending, “manufactured” applies to establishing a set
of base line values when compared to a battery of known capacity based on the
manufacturer’s published data. When trending other measurable properties that
assist in establishing aging, the battery manufacturer’s data are used as a basis for
establishment of baseline values and therefore the use of “manufactured” avoids any
ambiguity that might be caused by use of the term “designed”.
Response: Thank you for your comments.
The drafting team recognizes that the majority of your comments support and amplify the information contained in the
Supplementary Reference and FAQ document. However, the drafting team does not agree with some of the information contained in
your comments.
1. While the drafting team agrees that part of the process of determining when to replace a battery should be “to compare
measured values against manufacturer’s data or other established values,” we disagree with the statement “the only way to
know when a battery needs to be replaced is by using this maintenance activity” because it does not give credit to the role visual
inspections play in the replacement process.
2. The drafting team has a broader interpretation of the term “manufactured” than that implied in your comment concerning
ohmic measurement trending (“manufacturer’s published data”). We believe the term “manufactured” as used in the
maintenance activities of the standard also includes as you stated earlier in your comment “other established values.” Just as
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3.
Yes or No
Question 2 Comment
battery manufacturers establish tolerances that when exceeded constitute further examination of the battery for replacement,
test equipment manufacturers, battery owners and others have established tolerances for specific batteries that are considered
valid to determine if the particular battery can perform as “manufactured.”
As implied in your comment and by over a decade of industry experience, it has been proven that there is a relationship between
internal ohmic measurements and the aging process of lead-acid batteries. No such relationship has been established for nickelcadmium batteries. Also at this time - with the exception of the results of a capacity test - the drafting team is unaware of any
published data for nickel-cadmium battery properties that can be measured and trended against the station battery baseline.
The drafting team believes that either of the two maintenance activities listed in table 1-4(a) and 1-4(b) for lead-acid batteries
are acceptable to verify that the station battery can perform as manufactured when conducted at the maximum maintenance
intervals of the tables. However, the drafting team disagrees with your inference that table 1-4(c) for Nickel Cadmium batteries
should have any other maintenance activity besides the performance or modified performance capacity test of the entire bank
to verify that the station battery can perform as manufactured.
US Bureau of Reclamation
Yes
The FAQ should clarify why the requirement for a "Summary of maintenance and
testing procedures" developed by an entity is considered prescribing a methodology
to meet those requirements. The entity is developing the methodology for meeting
the requirements that the elements be maintained.
Response: Thank you for your comment.
“Summary of maintenance and testing procedures” is terminology used in Requirement R1.2 of the existing standard PRC-005-1.1b
and is not applicable to version PRC-005-2.
Oncor Electric Delivery
Yes
On Page 81 of the Supplementary reference and FAQ Draft it appears that the
drafting team changed the term “designed” to “manufactured” and then used the
quotation from the previous standard’s Table 1-4(b). Oncor recommends that the
two statements on page 81 of the Supplementary Reference and FAQ - Draft be
changed from the present version “...verify that the station battery can perform as
manufactured by evaluating the measured cell/unit internal ohmic values to station
battery baseline.” ”Verify that the station battery can perform as manufactured by
conducting a performance, service, or modified performance capacity test of the
entire battery bank.” to a new version of the quotes based on the new version of
Table 1-4(b). The new quotes should be stated as follows:”...verify that the station
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Yes or No
Question 2 Comment
battery can perform as manufactured by evaluating cell/unit measurements
indicative of battery performance (e.g. internal ohmic values or float current) against
the station battery baseline.” ”Verify that the station battery can perform as
manufactured by conducting a performance or modified performance capacity test of
the entire battery bank.”
Response: Thank you for your comments.
The SDT modified the Supplementary Reference and FAQ document based on your comments.
Brazos Electric Power
Cooperative
Yes
Please see the formal comments submitted by ACES Power Marketing.
Response: Thank you for your comment. Please see the responses to the ACES Power Marketing comments.
Xcel Energy
Yes
The following paragraph from the top of page 71 in the FAQ should be retained.
When internal ohmic measurements are taken, consistent test equipment should be
used to establish the baseline and used for the future trending of the cells internal
ohmic measurements because of variances in test equipment and the type of ohmic
measurement used by different manufacturer’s equipment. Keep in mind that one
manufacturer’s “Conductance” test equipment does not produce similar results as
another manufacturer’s “Impedance” test equipment, even though both
manufacturers have produced “Ohmic” test equipment. This paragraph from page 78
(second full paragraph) should be stricken or re written. Consistency is the key when
measuring and evaluating ohmic readings. Consistent testing methods by trained
personnel are essential. Moreover, it is absolutely critical that personnel use the
same make/model of test instrument every time readings are taken if the values are
going to be compared. The type of probe, the location of the reading (post,
connector, etc.) and the room temperature during the test needs to be carefully
recorded when the readings are taken. For every subsequent time the readings are
taken, the same make/model of the test instrument must be used, the same type of
probes must be used, and the location of the reading must be the same. The first
paragraph explain the consistency issue and the second then removes the ability to
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Yes or No
Question 2 Comment
use consistent equipment and rather demands that identical equipment be used.
This is not a feasible position as manufacturers can and do leave the testing space
and therefore the entity should be cognizant of using the appropriate compatible test
equipment but to spell out that particular make/models be maintained is not
acceptable and brushes against anti-trust complications by inhibiting new players in
this testing space.
Response: Thank you for your comments.
The SDT revised the Supplementary Reference and FAQ document to address your concerns.
TPI
Yes
Page 81...this statement is incorrect and should be changed: "A comparison and
trending against the baseline new battery ohmic reading can be used in lieu of
capacity tests to determine remaining battery life." "can be used" has to be changed
to "may be used". This should refer to the other FAQ to fully explain how to use
ohmic measurements.
Page 81...25% is not a universally accepted value. This value has to be determined by
experience for a particular type/model of battery. This part of the FAQ contradicts
other FAQs.
Response: Thank you for your comments.
1. The SDT revised the Supplementary Reference and FAQ document based on your comment.
2. The SDT used 25% as an example, and revised the Supplementary Reference and FAQ document for clarity. Since there are no
universally accepted repositories of this information, the Protection System owner will have to determine the value/percentage
where the battery cannot perform as manufactured. This is the most difficult and important part of the entire process. The
paragraph on page 81 of the Supplementary Reference and FAQ document has been modified based on your comments.
HHWP
MRO NSRF
no comment
Yes
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Yes or No
FirstEnergy
Yes
PNGC Small Entity Comment
Group
Yes
Central Lincoln
Yes
American Transmission
Company, LLC
Yes
Consideration of Comments: Project 2007-17
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40
3.
If you have any other comments that you have NOT provided in response to the above questions, please provide them here.
(Please do not repeat comments that you provided elsewhere.)
Summary Consideration:
Some commenters continued to object to various activities and/or intervals within the tables. The drafting team made several changes
detailed below in response to these comments.
1. One interval was changed – the interval for the activity in Table 1-2 for unmonitored communications systems was changed from 12
years back to 6 years as it had been in all previous postings. This change promotes consistency with similar activities within Table 1-1
(Protective Relays).
2. The language in two activities in Table 1-2 was changed from “channels” to “communications systems”.
3. The language in the Component Attributes in the last row of Table 1-2 was modified to read: “Any communications system with all
of the following:” to clarify that all must be present to use the related intervals and activities.
4. In Table 1-4e, a redundant “only” was removed from the Component Attributes in the last row.
A few commenters objected to the prescribed VRFs and/or VSLs. The SDT responded that these VRFs and VSLs are in accordance with
guidance from FERC and NERC.
A few comments were offered regarding Data Retention, generally objecting to retaining the maintenance records for two complete
maintenance intervals. The SDT responded that the data retention specifications are consistent with auditors’ expectations and with
Compliance Process Bulletins 2011-001 and 2009-05.
Several comments were made (some expressed as the reason for a Negative Ballot) in response to the informational posting of the draft
SAR to modify PRC-005-2 to add reclosing relays. No changes were made as a result of these comments.
Organization
Ameren
Yes or No
Question 3 Comment
(1) Remove Table 1-4 batteries from the Countable Event definition.
(2) Please change Table 1-4(d) title to “Component Type - Protection System Non
Battery Based Station dc Supply” [delete: Using Non Battery Based Energy Storage] to
be consistent with the definition.
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Question 3 Comment
(3) R3 & R4: Change VRF to “Medium” for the following reasons:
(a) Guideline (3) - Consistency among Reliability Standards is not satisfied. The
VRF_Standards_Applicability_Matrix_2012-03-01 clearly shows that comparable
requirements in the standards that PRC-005-2 replaces are Medium or Lower,
specifically PRC-005-1b R2 VRF is Lower, PRC-008-0 R2 VRF is Medium, PRC-011-0 R2
VRF is Lower, and PRC-017-0 R2 VRF is Lower.
(b) The High Risk Requirement is not met. We are not aware that lack of Protection
System maintenance alone has directly caused or contributed to bulk electric system
instability, separation, or a cascading sequence of failures.
(c) Guideline (4) Consistency with NERC’s Definition of the Violation Risk Factor Level
is not met. Many entities do not presently perform several of the proposed minimum
maintenance activities, and/or perform maintenance activities at greater than the
PRC-005-2 maximum interval. Yet BES system instability, separation, or cascading
sequence of failure events continues to be extremely rare.
(4) Measure M3 on page 6 should only apply to 99.5% of the components. We
strongly advocate the SDT to revise and state: “Each ... shall have evidence that it has
implemented the Protection System Maintenance Program for 99.5% of its
components and initiated....” We believe l that PRC-005-2 unrealistically mandates
perfection without providing technical justification. A basic premise of engineering is
to allow for reasonable tolerances, even Six Sigma allows for defects. Requiring
perfection may well harm reliability by distracting valuable resources from higher
priority duties concerning the Protection System. Note that we are not suggesting for
the VSL to be changed. Our proposed reasonable tolerance sets an appropriate level
of performance expectation. We disagree with the notion that this is “nonperformance”.
Response: Thank you for your comments.
1. The SDT believes that R1.1 is very explicit (All batteries associated with the station dc supply Component Type of a Protection
System shall be included in a time-based program) and has precedence over the Countable Event definition. However, the
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Question 3 Comment
drafting team does not agree that Table 1-4 should be removed from the Countable Event definition; Table 1-4(d) addresses
non-battery-based energy storage devices, which can use a performance based program.
2. The SDT sees no appreciable improvement in the standard with your proposed change and respectfully declines to modify the
standard. The drafting team believes the words “Energy Storage” in the title of Table 1-4(d) better conveys the role or
circumstance of not having a battery in the dc supply, more so than using the wording from the latest version of the definition
of Protection System (non-battery-based dc supply).
3. The SDT believes that the assigned VRFs are correct, as explained below:
a. The SDT believes the requirements of PRC-005-2 do not map, one-to-one, with the requirements of the legacy
standards, each of which comingle various attributes addressed within the new standard; thus, a requirement – to –
requirement comparison of VRFs is irrelevant.
b. The SDT believes that failure to implement and follow its PSMP could cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures.
c. The SDT believes that failure to implement and follow its PSMP could cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures.
4. VSLs define the degree to which compliance with a requirement was not achieved. Anything less than 100% constitutes a
violation.
-1- The data retention requirements for Requirements R2, R3, R4, and R5 are not
ACES Power Marketing
consistent with NERC Rules of Procedure. Section 3.1.4.2 of Appendix 4C – Compliance
Standards Collaborators
Monitoring and Enforcement Program states that the compliance audit will cover the
period from the day after the last compliance audit to the end date of the current
compliance audit. The data retention requirements compel the registered entity to
retain documentation for the longer of “the two most recent performances of each
distinct maintenance activity for Protection System Components, or all performances
of each distinct maintenance activity for the Protection System Component since the
previous scheduled audit date”. Given that many of the maximum maintenance
intervals exceed audit periods for responsible entities, an entity could be required to
retain data previous to its last audit, which is not consistent with the Rules of
Procedure. We suggest changing this such that the data only needs to be maintained
since the last audit.
-2- Under the “Definitions” section, for the definition of “Protection System” it is
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Yes or No
Question 3 Comment
unclear whether the bullets constitute items that are considered to be Protection
Systems, elements that may be included within a Protection System, or elements
which all must be included to constitute a Protection System. A statement preceding
the bullets that explains their relationship to the term “Protection System” would be
helpful. This clarification should at least be made within the supplementary reference
document, if it cannot be made to the actual definition.
-3- Requirement R1 VSLs: It is not clear why missing three component types jumps to
a Severe VSL. Missing two is a Moderate VSL. Missing three should be a High VSL.
Response: Thank you for your comments.
1. To be assured of compliance, the SDT believes the Compliance Monitor will need the data for the most recent performance of
the maintenance, as well as the data for the preceding maintenance period. This seems to be consistent with what auditors are
expecting (per the SDT’s experience), and is also consistent with Compliance Process Bulletins 2011-001 and 2009-05.
2. The definition of Protection System is expressed in the manner that FERC approved on February 3, 2012.
3. The SDT believes that missing three component types is a “significant percentage” and is in accordance with the VSL Guidelines.
Exelon Corporation and its
affiliates
1. In the response to Exelon’s previous comment regarding current transformers, the
SDT disagreed that test mandated by the current Standard draft seeks to measure a
signal is “provided to the protective relay”; however, the test referenced in Table 1-3
merely confirms that the signal is sent and not that it reached the correct protective
relay. Generation sites are built in phases, and these requirements do not ensure
that the wiring of the protection system matches the prints and the intent of the
engineers who designed it. Please provide a technical explanation of how this type of
test for a CT will verify that the signal reaches the relay.
2. In the response to Exelon’s previous comment related to the maintenance activity
in Table 1-3 for PTs and CTs as they relate to electro mechanical relays the SDT
disagreed that the maintenance program should be left to the discretion of the
Generator Owner. Exelon further explained that In order to meet the required
activity specified in PRC-005-2 draft 2 Table 1-3, the generating unit would be
required to take readings with meters while the unit is operating. This practice
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introduces a risk of tripping the unit inadvertently. The risk of tripping the unit while
performing this maintenance activity is contrary to the intended purpose of PRC-005
and introduces a potentially adverse effect on the reliability of the BES. In its
response the SDT has not provided the justification as to why performing such a high
risk activity increases the reliability of the BES and justification for testing that refutes
existing manufacturers recommendations.
3. In the last round of comments, the SDT did not specifically address Exelon’s
comments regarding the omission of “...and trips an interrupting device that
interrupts current supplied directly from the BES” from the revised applicability
language in Section 4.2.1. We are concerned that the SDT may not fully appreciate
our concern. Without the qualification that comes from the “and...” phrase above,
Exelon feels that section 4.2.1 will bring reverse-looking relays on radial transformers
into scope, which are not interpreted as BES Protection Systems. By doing so, it
creates a perverse incentive to disable these protection functions, even though they
provide a reliability benefit, for the sake of limiting compliance exposure. Please offer
a direct response to why the phrase, “...and trips an interrupting device that
interrupts current supplied directly from the BES” is no longer included in 4.2.1 and
clarify that non-BES relays are not considered within scope. Comments and SDT
Response from last comment period (for reference):Exelon Comment: When the SDT
changed the original PRC-005 applicability language from “...affecting the reliability of
the BES...” to the new 4.2.1 language “...that are installed for the purpose of
detecting faults on BES elements (lines, buses, transformers, etc.)”, they opted to
exclude the second half of this sentence taken from the PRC-005-1a Interpretation,
which read “...and trips an interrupting device that interrupts current supplied
directly from the BES.” By doing so, the SDT failed to recognize that some Protection
Systems can be responsive to faults on the BES, but still have no effect on the
reliability of the BES. The change in 4.2.1 may unintentionally expand the scope of
PRC-005.Depending on how Section 4.2.1 is interpreted, it could create a perverse
incentive to disable, or not apply, reverse directional protection on the secondary (at
voltages less than 100kV) of radially connected load-serving transformers. Such
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relaying typically uses available units in a multifunction device, and while not critically
necessary for fault clearing, it is applied because it adds a benefit at no incremental
cost with minimal security risk, and it will not interrupt a BES element if it operates
insecurely. It also improves reliability to connected distribution load, in the event a
BES transmission line faults during abnormal switching, by coordinating with nondirectional overcurrent relays that would otherwise interrupt the entire load.
Furthermore such directional relaying would only operate after the faulted BES line is
already removed from any connection at BES voltages via its high voltage (>100kV)
circuit breakers. Viewed in an expansive way, the proposed 4.2.1 language could
bring into scope these relays as well as tripping circuits of distribution voltage circuit
breakers that are normally operated in a radial configuration. It would be reasonable
for a TO to disable this relaying, rather than accept these consequences. In the
previous comment period (Sept 2011), industry raised similar concerns and to most
of the commenters, the SDT responded with the following statement: ” The SDT
believes that the Applicability as stated in PRC-005-2 is correct and that it supports
the reliability of the BES. The SDT observes that the approved Interpretation
addresses the term, “transmission Protection System”, and notes that this term is not
used within PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC005-2 specifically addresses “Protection Systems that are installed for the purpose of
detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary
Reference and FAQ document for additional discussion.” Unfortunately, this response
fails to address the concerns raised above. Entergy previously suggested the
following language for 4.2.1:”Protection Systems that are installed for the purpose of
detecting faults on BES Elements (lines, buses, transformers, etc.) and trips an
interrupting device that interrupts current supplied directly from the BES Elements.”
This language is appropriate and addresses industry concerns. We ask that the SDT
adopt this language as Section 4.2.1. SDT Response: The SDT believes that the
Applicability, as stated in PRC-005-2, is correct and supports the reliability of the BES.
The SDT observes that the approved Interpretation addresses the term, “transmission
Protection System,” and notes that this term is not used within PRC-005-2; thus, the
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interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses
“Protection Systems that are installed for the purpose of detecting Faults on BES
Elements.” Please see Section 2.3 of the Supplementary Reference Document for
additional discussion. Thank you for the opportunity to comment.
Response: Thank you for your comments.
1. Section 15.2 of the Supplementary Reference and FAQ document provides a technical explanation of how this type of test for
a CT will verify the signal reaches the relay.
2. The SDT believes it is possible during a 12-year interval to find a reasonably low-risk opportunity to perform the required test
and that performing the test satisfies FERC Order 693 “…that maintenance and testing of a protection system must be carried
out within a maximum allowable interval that is appropriate to the type of the protection system and its impact on the
reliability of the Bulk Power System.” Please see Section 15.2.1 of the Supplementary Reference and FAQ document for
examples of off-line tests that can minimize the risk you describe.
3. Reverse-looking relays (in the cited application) are not installed for the purpose of detecting faults on the BES and would not
be subject to this standard. The SDT believes that the Applicability as stated in PRC-005-2 is correct and that it supports the
reliability of the BES.
Southern Company
1. We would like the SDT to consider rewording M5 as follows: The evidence may
include any form of evidence indicating an entity is demonstrating efforts to
correct identified Unresolved Maintenance Issues. Additionally: All of the
examples of evidence should be moved to the Supp Ref doc and be there only for
reference.
2. Page numbers should be visible on all pages.
Response: Thank you for your comments.
1. The SDT does not believe that the changes you suggest improve the standard. Regarding “demonstrate efforts to correct…,”
the SDT’s intent is to allow an entity to furnish a way of addressing Unresolved Maintenance Issues without the formality and
burden of a full-fledged Corrective Action Plan.
2. The SDT agrees and has referred the concern to NERC Staff for their consideration when preparing the documents for posting.
Ingleside Cogeneration LP
Although Ingleside Cogeneration LP does not want to derail the improvements that
the SDT has obviously made to PRC-005-1, we remain concerned that expansions in
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scope of a BES Protection System will automatically roll over to other standards. For
example, if the loss of a low voltage auxiliary transformer can trip a generator, its
Protection System will be in-scope for PRC-005-2. It is not a big leap in logic to
assume that the auxiliary transformer itself should be a BES Element - and subject to
the whole body of CIP, MOD, IRO, and TOP standards. Our experience has been that
Compliance authorities will make these assumptions, even if that was never the
intent of the SDT. The effort to develop and maintain procedures, test results, and
communications concerning every BES Element is not trivial - and a single instance of
a missed requirement may lead to fines in the thousands of dollars. Ingleside
Cogeneration is committed to take any action required to assure BES reliability, but
NERC and the project teams must have evidence of its own that it is worth the cost.
Response: Thank you for your comments. The SDT believes that performing these maintenance activities will benefit the reliability
of the BES.
American Electric Power
1. As stated in our previous comments for R3, Table 1-5 notes a “mitigating device”
as part of component attributes. The meaning of this phrase is open to
interpretation and needs to be clearly defined. Is it a discrete device? A
protection scheme? Either? The team’s response, by stating its intentions
regarding this phrase, actually illustrates the need to provide clarity for this term
within the standard.
2. As stated previously, under the time-based maintenance method and R3, the
Entity will be required to utilize the minimum maintenance activities and
maximum maintenance intervals prescribed within Tables 1-1 through 1-5, Table
2, and Table 3. Special Protection Systems, by their nature, may physically include
components that are not listed in the NERC definition of Protection System and
therefore are not included in the tables of PRC-005-2. The standard, as currently
drafted, does not clearly provide a means for an Entity with a Special Protection
System to establish both minimum maintenance activities and maximum
maintenance intervals for components that have been declared by their Region as
part of a Special Protection System but that are *not* included in the NERC
definition of Protection System. For example, consider a Special Protection
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System that is comprised of the following elements: Generating Unit Distributed
Control System (DCS) - Qty 1Protective Relays - Qty 4 - Provide digital inputs to
DCS Boiler Pressure Transmitters - Qty 2 - Provide analog inputs to DCS For a
predetermined set of system events, the protective relays operate, indicating to
the DCS that the event has occurred. If the pressure transmitters indicate that
the boiler pressure exceeds a predefined threshold, the DCS responds by
adjusting the analog output signals to the turbine valves. For compliance with the
existing version of PRC-017-0, the owner of the above system has written a
Maintenance and Testing Program that thoroughly tests the protective relays,
DCS logic and analog inputs and outputs. However, under PRC-005-2, the owner
of the system would not be able to use the proposed performance based method
because the system does not have the required Segment population of 60
components. This leaves the owner no other option than the time based method.
However, only the protective relays meet the NERC definition of Protection
System and they are the only elements of this hypothetical SPS described in
Tables 1-1 through 1-5. The existing PRC-005-2 draft does not contain time based
activities that would be applicable to the DCS logic, analog inputs and analog
outputs. Therefore, whereas the existing NERC standards demand the testing of
these devices, NERC standards would no longer require their testing upon the
implementation of PRC-005-2.
Response: Thank you for your comments.
1. A mitigating device is one that acts to respond as directed by a Special Protection System (SPS). It may be a breaker, valve,
distributed control system, or any variety of other devices.
2. The SDT notes that the definition of a Special Protection System states “An automatic protection system designed to detect
abnormal or predetermined system conditions, and take corrective actions other than and/or in addition to the isolation of
faulted components to maintain system reliability.” If the SPS you described meets this definition and contains Protection System
components, then PRC-005-2 applies to those Protection System components.
American Transmission
Company, LLC
ATC recommends that the SDT change the text of “Standard PRC-005-2 - Protection
System Maintenance” Table 1-5 on page 24, Row 1, Column 3” to: “Verify that a trip
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coil is able to operate the circuit breaker, interrupting device, or mitigating device.”
Or alternately, “Electrically operate each interrupting device every 6 years.”
Basis for the change: Trip coils are designed to be energized no longer than the
breaker opening time (3-5 cycles). They are robust devices that will successfully
operate the breaker for 5,000-10,000 electrical operations. In addition, many utilities
purchase breakers with dual redundant trip coils to mitigate the possibility of a
failure. It is well recognized that the most likely source of trip coil failure is the
breaker operating mechanism binding, thereby preventing the breaker auxiliary stack
from opening and keeping the trip coil energized for too long of a time period.
Therefore, trip coil failure is a function of the breaker mechanism failure. Exercising
the breakers and circuit switchers is an excellent practice to mitigate the most
prevalent cause of breaker failure. ATC would encourage language that would
suggest this task be done every 2 years, not to exceed 3 years. Exercising the
interrupting devices would help eliminate mechanism binding, reducing the chance
that the trip coils are energized too long. The language, as currently written in Table
1-5 row 1, will also have the unintentional effect of changing an entities existing
interrupting device maintenance interval (essentially driving interrupting device
testing to a less than 6 year cycle).ATC continues to recommend a negative ballot
since we believe that the testing of “each” trip coil will result in the increased amount
of time the BES is in a less intact system configuration. ATC hopes that the SDT will
consider these changes.
Response: Thank you for your comments. The SDT sees no appreciable improvement in the standard with your proposed change and
respectfully declines to make the modification.
Colorado Springs Utilities
Colorado Springs Utilities votes "negative" based on the document "Draft SAR for
Phase 2 of Project 2007-17" under the section titled Brief Description of Proposed
Standard Modifications/Actions, which states " The Standard Drafting team shall
modify NERC Standard PRC-005-2 to add reclosing relays to the standard. In order to
do so, the definition of Protection System shall be revised to include reclosing relays,
the Facilities portion of the Applicability of the Standard shall be revised to describe
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those reclosing relays that are included within the standard, and appropriate
minimum maintenance intervals (with maximum allowable intervals) shall be added
to the standard. The Standard Drafting team shall also make any other changes that
are necessary to explicitly address reclosing relays, but shall not make general
revisions to the standard, either in content or arrangement." Colorado Springs
Utilities position is reclosing relays are used as part of the system restoration process,
and should not be associated with the protection or reliability of the system.
Reclosing relays should be grouped with SCADA controls of breakers and manual
controls of breakers, and should be tested with the same frequency. Breaker
reclosing is not used on many lines, and is disabled on many lines. Automatic Breaker
Reclosing is a system enhancement, not a system requirement.
Response: Thank you for your comments.
The SDT notes that the draft SAR for Phase 2 of Project 2007-17 is not applicable to the current successive ballot and was posted for
informational purposes only. In Order 758, FERC directed NERC to include reclosing relays in a future version of PRC-005; the SDT
developed this draft SAR to address FERC’s directive.
Duke Energy
Duke Energy votes “Negative” because we strongly object to the wording in the
Applicability section 4.2.1. We believe that the wording change to PRC-005-2 draft 4
after the previous Successive Ballot but prior to the associated Recirculation Ballot
expanded the reach of the standard to relaying schemes that detect faults on the BES
but which are not intended to provide protection for the BES. The SDT’s response to
our comment directs us to Section 2.3 of the Supplementary Reference And FAQ
Document which states “There should be no ambiguity: if the element is a BES
element then the Protection System protecting that element should be included
within this Standard.” We agree with that statement, but point out that Section 4.2.1
is inconsistent with that statement, and has a much broader reach because it includes
devices that detect Faults on the BES but which do NOT provide protection for the
BES. Compliance audits will be driven by the words in the standard, not the
explanations in the Supplementary Reference And FAQ Document. We would
appreciate a response to our concern that explains the reliability benefit associated
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with this expansion of scope, and which specifically addresses the following Duke
Energy situation: Duke Energy’s standard protection scheme for dispersed generation
at retail stations would become subject to the standard due to the changes in section
4.2.1. These protection schemes are designed to detect faults on the BES, but do not
operate BES elements nor do they interrupt network current flow from the BES. In
the most recent draft, the relays, current transformers, potential transformers, trip
paths, auxiliary relays, batteries, and communication equipment associated with the
dispersed generation protection scheme would be subject to the requirements in
PRC-005-2. Previous drafts of the standard would not have required Duke Energy to
maintain the protection system components associated with dispersed generation
schemes at retail stations in accordance to the requirements in PRC-005-2. The new
wording in section 4.2.1 would add significant O&M costs and resource constraints
due to the inclusion of protection system devices at retail stations without increasing
the reliability of the BES. Duke Energy does not believe it was the intent of the
standard to include elements that did not have an impact on the reliability of the BES.
Duke Energy would prefer the following wording for Section 4.2.1: Protection
Systems that are installed for the purpose of protecting BES Elements (lines, buses,
transformers, etc.)”.FERC’s September 26, 2011 Order in Docket No. RD11-5
approved NERC’s interpretation of PRC-005-1 R1 and R2, stating: “The interpretation
clarifies that the Requirements are “applicable to any Protection System that is
installed for the purpose of detecting faults on transmission elements (lines, buses,
transformers, etc.) identified as being included in the [BES] and trips an interrupting
device that interrupts current supplied directly from the BES.” This interpretation is
consistent with the Commission’s understanding that a “transmission Protection
System” is installed for the purpose of detecting and isolating faults affecting the
reliability of the bulk electric system through the use of current interrupting devices.”
Response: Thank you for your comments.
The SDT believes the Applicability as stated in PRC-005-2 is correct and supports the reliability of the BES. All Protection Systems
installed for the purpose of detecting faults on the BES need to be maintained per the requirements of PRC-005-2. The SDT observes
that the approved Interpretation addresses the term, “transmission Protection System”, and notes that this term is not used within
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PRC-005-2; thus the Interpretation does not apply to PRC-005-2. Please see Section 2.3 of the Supplementary Reference and FAQ
document for additional discussion.
Entergy Services
Entergy provides the following comments to achieve consistency in the written
standards:
•
•
•
•
Numbers indicating measurable quantities should be numbers: 95%, 5%, etc. and
not spelled out.
Words indicating a specific document or entity should be capitalized: this
Standard
Words indicating generic devices should not be capitalized: components, faults,
monitors, misoperation
4. If two words go together with a singular meaning they should both be either
capitalized or not: Communication Systems
Response: Thank you for your comments. The SDT followed NERC’s style guide for the various issues you point out.
FirstEnergy
FirstEnergy supports the standard and thanks the drafting team for all their hard
work.
Response: Thank you for your comments.
Luminant
In addition to the revised Supplemental Reference and FAQ guide revision requested
in question 2, Luminant recommends that Table 1-5; Line 1 and 4 be revised to
specifically state that only BES elements (circuit breakers/interrupting devices) are to
be tested. There is no benefit to the BES system for testing the non-BES breakers and
some locations, trip testing of the breakers would cause a unit black-out due to unit
design. Some units do not have start-up transformers. By performing these tests,
there is a risk of causing unit damage while the unit is off-line. Therefore Luminant
recommends that Table 1-5 be revised to only require BES breakers be tested for
compliance purposes. This would be consistent with the requirements covered in
Table 3 for UFLS Systems.
Response: Thank you for your comments.
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The SDT revised Section 15.3.1 of the Supplementary Reference and FAQ document to address this concern, and does not believe
that further revision of the standard is necessary.
Public Utility District No. 1 of
Okanogan County
In tables 1-4 with regards to station batteries.
1. DC Supply voltage. Is this reading taken off the batteries or out of the charger?
Which read needs to be documented?
2. Unintentional grounds. If the charger has the ability to detect and alarm on
unintentional grounds, do we need to manually check this as well?
3. In the 18 month section there is a reference to Float voltage of charger. How do
we document in our procedure? Can we use SCADA?
4. In the NICAD battery section. Why can't we do impedance testing? Why only load
testing?
5. In table 1-5 there is mention of "Lockout Devices" does this mean that 86 relays
are being brought into scope?
6. In table 2 there is discussion with regard to Alarm paths and alarm path
monitoring. Table 1-5 item 4 discusses Auxiliary Relays in the control circuit path.
Typically, Auxiliary relays in this scenario are closed contacts and open when in an
alarmed state. For example, a low SF6 alarm contacts on a breaker interrupts the trip
circuit and prevents the breaker from operating. Does this type of auxiliary relay
need to be tested every 12 years?
7. For monitoring transmission PTs- Can we measure low side voltage (13kv) PTs
multiplied by the power transformer ratio to verify transmission PT accuracy?
8. Table 1-3 describes independent "measurements continuously verified by
comparison" Does separate AC measurement need to be connected to same relay?
or can it be connected to separate relay with comparison done in SCADA?
Response: Thank you for your comments.
1. The verification of dc voltage is simply an observation of battery voltage to prove that the charger has not been lost or is not
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2.
3.
4.
5.
6.
7.
8.
Yes or No
Question 3 Comment
malfunctioning, and the standard is indifferent as to where the voltage is actually measured. However, Section 15.4.1 of the
Supplementary Reference and FAQ document suggests that this voltage be optimally measured at the battery’s main
terminals.
Per Table 1-4(f) and Table 2, if your charger has the ability to detect and alarm on unintentional grounds and meets the Table
2 requirements, no periodic inspection of unintentional dc grounds is required.
As explained in Section 15.4.1 of the Supplementary Reference and FAQ document, the maintenance activity of verifying the
float voltage of the battery charger is not to prove that a charger is lost or producing high voltage on the station dc supply, but
rather to prove that the charger is properly floating the battery within the proper voltage limits. Per Table 1-4(f) and Table 2,
if your charger has the ability to monitor and alarm to ensure correct float voltage is being applied on the station dc supply
and meets the Table 2 requirements, no periodic verification of float voltage of battery charger is required. The standard is
proscribed from describing “how”. It is left to the entity to determine what methods best address their program.
At this time - with the exception of the results of a capacity test - the drafting team is unaware of any published data for
nickel-cadmium battery properties that can be measured and trended against the station battery baseline.
As explained in Section 15.3 of the Supplementary Reference and FAQ document, if the lock-out relays (86) are
electromechanical type components, then they must be trip tested per Table 1-5.
As explained in Section 15.3 of the Supplementary Reference and FAQ document, contacts of the 86 or 94 that pass the trip
current on to the circuit interrupting device trip coils will have to be checked as part of the 6 or 12 year requirement.
Normally-open contacts that are not used to pass a trip signal and normally-closed contacts do not have to be verified.
There are multiple methods to verify the current and voltage signal values as explained in Section 15.2 of the Supplementary
Reference and FAQ document.
It is left to the entity to determine what methods best address their program. Section 15.2 of the Supplementary Reference
and FAQ document discusses various methods of conducting this comparison.
Manitoba Hydro
Manitoba Hydro is maintaining our negative vote based on our previously submitted
comments (see comments submitted in the comment period ending on March 28th,
2012).
Response: Thank you for your comment. The SDT has also not changed its position from that expressed in response to the earlier
comments.
Oncor Electric Delivery
On Page 89 of the Supplementary reference and FAQ Draft document on the
References page (reference #12) the correct number of the standard should read “Std
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450-2010” instead of “Std 45-2010.”
Response: Thank you for comment. The Supplementary Reference and FAQ document has been corrected.
Dominion
On the Redline version of the standard, page 11 Version History; Version 2 Action,
should PRC-005-1a be listed as PRC-005-1b and PRC-017 listed as PRC-017-0.
Additionally, it does not appear that the Version History has captured a complete
record of all revisions to this standard.
Response: Thank you for your comments. The references to the approved standards and the Version History have been corrected.
Brazos Electric Power
Cooperative
Please see the formal comments submitted by ACES Power Marketing.
Response: Thank you for your comment. Please see our responses to the comments submitted by ACES Power Marketing.
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
PPL Generation, LLC thanks the SDT for their effort on this latest version of the
standard and has voted affirmatively. We offer the following comments/suggestions:
1.) PPL Generation, LLC would like more direction on how the Tables 1-3 are to be
interpreted. Under the left column “Component Attributes,” it is not completely
clear as to which situation is applicable in order to know what “Maintenance Activity”
applies. Either the table's "Component attributes" or the statement “Include the
applicable monitored Component attributes applied to each Protection System
Component Type consistent with the maintenance intervals specified in Tables 1-1
through 1-5, Table 2, and Table 3 where monitoring is used to extend the
maintenance intervals beyond those specified for unmonitored Protection System
Components” could be more prescriptive on the specific component attributes to
provide entities direction as to when exactly each table is to be followed.
2.) In regards to Unresolved Maintenance Issues, PPL Generation, LLC is concerned
with the use of the word “efforts” in regards to the use in “shall demonstrate efforts”
in Requirement 5. We suggest that either a formal definition of “effort” is provided
or more clarity is added in the Requirement 5, shown below, that gives a quantitative
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scale of what constitutes an effort. “Each Transmission Owner, Generator Owner, and
Distribution Provider shall demonstrate efforts to correct identified Unresolved
Maintenance Issues.” In its current form, “efforts” can be broadly interpreted by
auditors as any number of different required actions of an entity and could
potentially lead to inconsistencies in applying the term throughout the regions.
Response: Thank you for your comments.
1. The left column of the Tables describes the monitoring attributes (if any) that are available on the particular components. The
center and right columns describe the related maximum maintenance intervals and minimum maintenance activities.
2. The SDT believes there is sufficient understanding in the industry for the term “efforts” and the risk of compliance jeopardy is
minimal.
Progress Energy
1. R3 and the VSL for R3 seem to imply that an entity would not be in violation of this
standard if they exceed their PSMP intervals (including any program grace) as long as
the maintenance is performed within the maximum intervals prescribed within the
tables. This interpretation was further supported in the previous draft of the
Supplemental Reference (Section 8.2.1, page 35), which stated: “According to R3, a
strictly time-based maintenance program would only be in violation if the maximum
time interval of the Tables is exceeded.” However, this statement has been removed
from the supplemental document under the latest draft revision. Would the entity
be noncompliant if they exceed their PSMP interval but not the maximum table
interval?
2. Table 1-4(e): Typo. “Any Protection System dc supply used only for tripping only....”
3. Page 51, 4th paragraph, 5th line: Typo “thre” should be “three.”
Response: Thank you for your comments.
1. The standard is defining maximum allowable intervals and minimum acceptable activities for a PSMP. Requirement R3 was
revised recently to establish that entities must maintain their Protection System components, at a minimum, in accordance with
the relevant tables. Entities are empowered to develop PSMPs that exceed these requirements if they determine such a PSMP is
necessary; however, according to Requirement R3, the entity will not be held to their more-aggressive (than the tables) PSMP for
compliance monitoring purposes.
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2. The SDT made the suggested editorial change to Table 1-4(e).
3. The Supplementary Reference and FAQ document has been corrected as suggested.
ReliabilityFirst
ReliabilityFirst offers the following comments for considerations:
1. General Comment
a. ReliabilityFirst believes not only should there be testing required for individual
components (as required Protection System Maintenance Program), ReliabilityFirst
believes that the entire Protection System (consisting of all Protective relays,
communications systems, Voltage and current sensing devices, etc.) should be tested
as a whole. Individually each component may test successfully but while tested as a
complete Protection System (through interaction between all the interdependent
components), deficiencies in settings along with logic and wiring errors could be
discovered.
2. Requirement R5
a. ReliabilityFirst believes the language in Requirement R5 (“...shall demonstrate
efforts to correct...”) is subjective and non-measurable. It will be difficult in
determining what amount of “demonstration” an entity will need to provide in order
to be compliant along with lack of timeframe in which the correction needs to be
completed. While RFC understands it is hard to prescribe a specific
timeframe/deadline (it can depend on various number of supply, process and
management problems), RFC believes at a minimum, the applicable entity should be
required to develop a Corrective Action Plan to address the Unresolved Maintenance
Issue. ReliabilityFirst offers the following modification for consideration: “Each
Transmission Owner, Generator Owner, and Distribution Provider shall put in place a
corrective action plan to remedy all identified Unresolved Maintenance Issues.”
Response: Thank you for your comments.
1. The SDT does not believe it feasible to craft requirements for testing an entire Protection System as a whole that would
simultaneously prove performance of every component and believes such invasive testing would jeopardize BES reliability.
2. The SDT’s intent is to furnish a way for an entity to address Unresolved Maintenance Issues without the formality and burden of a
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full-fledged Corrective Action Plan.
Seattle City Light Operations
SCL supports the position of WECC PNGC with regard to the position paper VRF/VSL
recommendation. Specifically, it is the contention of PMGC and members that small
entities with maybe 2 or 3 components within a Component Type that sustain a
violation will unnecessarily be subjected to a “severe” or “high” VSL assignment due
to the % based parameter.
We feel the SDT did not adequately address our concerns during the last
ballot/comment period. While this is a non-issue for larger entities with hundreds or
thousands of individual components, we believe this exposes smaller entities to
unnecessary compliance risk.
1. The PNGC Comment Group takes issue with the associated VSLs for R3. For a small
entity using a time based maintenance program, even one missed interval could be
enough to elevate them to a high VSL despite the limited impact on the Bulk Electric
System. Consider an entity with 9 total components within a specific Protection
System Component Type. One violation would mean an 11% violation rate, enough to
catapult them into a High VSL. Given NERC Guidance (following), this seems to be a
contradiction given the language of “...more than one” [NERC Guidance on VSL
assignment: i. LOWER: Missing a minor element (or a small percentage) of the required
performance. ii. MODERATE: Missing at least one significant element (or a moderate
percentage) of the required performance. iii. HIGH: Missing more than one significant
element (or is missing a high percentage) of the required performance or is missing a
single vital component. iv. SEVERE: Missing most or all of the significant elements (or a
significant percentage) of the required performance.] Thus we support the WECC
PNGC suggestion to change the language for “Lower VSL” for R3 to: 'For Responsible
Entities with more than a total of 20 Components within a specific Protection System
Component Type in Requirement R3, 5% or fewer have not been maintained...' OR
'For Responsible Entities with a total of 20 or fewer Components within a specific
Protection System Component Type, 2 or fewer Components in Requirement R3 have
not been maintained...'
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Response: Thank you for your comments.
The SDT respectfully disagrees and believes that the Standard appropriately incorporates and accounts for the system risks and
burdens of maintenance for both large and small entities. The VSLs were developed in accordance with the “FERC VSL Order” and
the NERC criteria; for stepped VSLs - Lower VSL is “5% or less”, Medium VSL is “more than 5% up to
(and including) 10%”, High VSL is “more than 10% up to (and including) 15%”, and Severe VSL is “more than 15%”.
Public Service Company of
New Mexico
Table 1-1 Component Type - Protective Relay and Table 1-2 Component Type Communications Systems refer to Table 2 Alarm Paths and Monitoring for monitoring
related attributes. However, the maximum maintenance interval in rows referring to
Table 2 in both Tables 1-1 and 1-2 is 12 calendar years whereas there is a row in Table
2 that if there is an Alarm Path with monitoring (row 2 of Table 2), no periodic
maintenance is required. Does this mean that even if there is an Alarm Path with
monitoring for which no periodic maintenance is required, the component type Protective Relay or Communications Systems will still be required to be maintained
within the maximum 12 calendar years interval? This appears to be contradictory
especially since rows in Tables 1-3, 1-4(f), and 1-5 that refer to Table 2 have “no
periodic maintenance specified” under maximum maintenance interval. This also
appears to be contradictory to the text provided under bullet 1 of Section 5.2
Extending Time-Based Maintenance which states that - If continuous indication of the
functional condition of the Component is available (from relays or chargers or any
self-monitoring device), then the intervals may be extended, or manual testing may
be eliminated.” Rows referring to Table 2 in Tables 1-1 and 1-2 do not suggest that
manual testing will be eliminated as it is requiring a 12 calendar year maintenance
time interval even if it meets the requirements under table 2 for alarm path with
monitoring. PNM recommends adding the following under Maximum Maintenance
Interval to be consistent with other tables 1-3, 1-4(f), and 1-5 - “12 calendar years OR
no periodic maintenance specified”.
Response: Thank you for your comments.
For protective relays and communications systems, the only maintenance activity in the last line of the related table is to verify those
unmonitored inputs and outputs that are essential to the proper functioning of the Protection System. The SDT sees no appreciable
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improvement in the standard with your proposed change and respectfully declines to modify the standard.
Bonneville Power
Administration
1. Table 1-2: Communication Systems: BPA believes that the entire section of Table
1-2 needs clarity. A channel, channel performance criteria, & communication
system all have very precise definitions in the communications world. (Please
refer to Supplemental Frequency AQ - Figure 1 - Typical Transmission System
Diagram, Telecommunications Network Cloud)When referring to the terms in
Table 1-2, if the drafting team is referring to the ‘telecommunications cloud’, this
section is unclear. BPA believes it is clearer if the drafting team is referring to the
two telecommunications equipment panels and requests documented
clarification. The traditional term for this would be teleprotection channel or
teleprotection function. BPA assumes the intention was teleprotection channel.
BPA recognizes that the teleprotection equipment panels, in many modern cases,
are built into the relay. For background information, the Telecommunications
Network is composed of multiple Communication Systems (40 to 50 is not
uncommon) that contain multiple thousand (5-6K) pieces of equipment. These
systems and equipment are tied together with hundreds of thousands of
Communication Channels and Tributaries. Most of the Channels and Tributaires
have, at least a primary and backup (WECC Guideline: Design of Critical
Communications Circuits), and some have multiple primary’s and backups. All of
these are needed to create the circuit connections, as indicated on the diagram
from one teleprotection panel to another teleprotection panel. Given the above
scenario - the confusion is possible. As an example, for the component attribute:
‘Any unmonitored communication system necessary for the correct operation of
the protective functions, and not having all the monitoring attributes of a
category below.’ The 4 calendar month maintenance activity is to: ‘Verify that the
communications system is functional.’ The questions that arise are which
systems, the drop system or the transport system? The whole system or just the
part carrying the protective signals? What about the channels interconnecting the
various systems and so on? BPA suggests clarifying: Any unmonitored
teleprotection function necessary for the correct operation of the protective
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functions, and not having all the monitoring attributes of a category below. The 4
calendar month maintenance activity is to: ‘Verify that the teleprotection
function is functional’ BPA believes this is a much better approach as it identifies
only that the teleprotection panels must get inputs and outputs to the relays
between them. BPA believes more clarity is still needed. A simple example of an
old tone based FSK transfer Trip System over a single point to point analog MW
radio channel; the teleprotection panel will normally transmit a guard tone in a
particular spectrum over a single radio channel to the teleprotection panel at the
far end. BPA understands that one way to verify that the teleprotection function
is serviceable in a 4 month maintenance activity is if the guard signal arrives at
the opposing end, correct? BPA infers that this is efficient as entities can now
monitor loss of guard and have a continuously monitored system which will result
in performing just a12 year maintenance. Is this correct? This raises the question
of the trip function. Until the trip function is energized from the relay, the
circuitry sending the trip by initiating a FSK in not functioning. Does this function
needs to be check in addition to the guard function? This raises the question of
the MW radio channel. BPA recognizes that the FSK trip signal travels over
different spectrum in the analog MW radio. Even if the radio will transmit a
Guard FSK signal to the far end, it will not necessarily transmit a Trip FSK signal to
the far end (a common hidden failure mode in many MW systems). Do entities
need to check for guard at the far end and test that a FSK Trip signal propagates
through the radio system and is received at the teleprotection panel? BPA
requests clarification in the followings scenario: Using testing inputs as opposed
to operating inputs that trips and guards may be initiated from a different set of
inputs of the teleprotection panel, and monitored from a different set of outputs
on the teleprotection panel ( very common on teleprotection equipment ). The
test might work, but an actual Trip signal would not work (a common hidden
failure mode on current available equipment). If one were to say ‘good enough’
for a 4 month test (and hope any auditors agree if there is ever a false operation).
How about the 12 calendar year test? For a point to point analog MW radio,
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there is only a single channel that can be tested for passage of guard and trip
tones. If the radio is redundant, which it most likely is (WECC Guideline: Design of
Critical Communications Circuits) then this has to be done twice, once for each
path. Can the drafting team clarify this scenario? In a more typical real-world
case, the circuit connection, between the two teleprotection panels, will
transverse multiple redundant communications systems. If it crosses 4 redundant
systems in the communications cloud, then there are a total of 4^2 or 16 possible
communication channels, each with different test criteria, that need to be tested.
Additionally, the channels are rerouted manually and automatically much faster
than a 12 year cycle (daily is not uncommon). Do all these combinations need to
be tested? This discussion illustrates the confusion of the current wording. BPA
recommends that: If the intention is to test in the ‘cloud’ or the performance of
the ‘cloud’, BPA believes there needs to be a new standard, or set of standards
created to deal with the intricacies of the telecommunication cloud. If the
intention was to test the teleprotection channel, BPA believes additional clarity
needs to be provided to address the dynamic redundancies and rerouting of the
communications system. If the intention was to test the teleprotection function
BPA believes additional clarity needs to be provided to test/monitor the functions
(inputs and outputs) between the teleprotection panels.
2. Table 1-4(a):VLA Battery: 4 Months/Inspect/Electrolyte Level BPA believes that
for a properly designed and installed steady state float charge/long duration
discharge type battery plant this is not needed. The inspection at 4 Month
intervals will unearth catastrophic failures (Split cells, severe overcharging, etc...).
These types of failures can happen anytime, and need to be designed around.
Unless the battery plant is under high cyclic load, water usage can be handled in a
12/18 month maintenance cycle. Severe overcharging needs to be dealt with by
design/maintenance practices (for example: an Appropriate high voltage alarmed
with an immediate call out) since 4 months is too long to wait to detect the
condition. Minor overcharging will not be detectable in a 4 month interval (and
one wants to very slightly overcharge a battery verse any individual cell being
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undercharged, but that is a whole different technical discussion). IEEE484
specifies ventilation should be provided for the worst-case hydrogen generation
due to overcharging. Other than an inherent manufactures defect that can
happen anytime 24/7, splitting cells due to sulfation build up is a slow know
process that can be handled in a 12/18 month maintenance cycle with a good
visual inspection. Although this is in line with IEEE450, given the specific type of
battery configuration in the utility world, this is excessive. Should there be a
unique battery plant design, then it is incumbent on that utility to have
appropriate shorter intervals. BPA is in support of “For unintentional grounds”
and recognizes that it does not apply to intentionally grounded battery systems
(teleprotection systems run off of communication batteries in sites where there is
no station battery {i.e.: Grand Coulee/Lower Snake}).In general there are two
types of batteries used by utilities, outside of their control centers, which will be
supplying protective systems. The vast majority is the station battery, which is
described very well in the IEEE standards: Switchgear control battery applications
typically require output current levels that vary over a relatively long period of
time. The battery operates on a float charge during steady state conditions. The
battery charger powers relays, indicating lights, and peripheral devices during
normal conditions. Instantaneous operation of the circuit breaker and switches
require battery output current. Initially, this current may be relatively high for a
short duration and then reduce for an extended period of time, followed by
another high operating current demand. If the charger output is lost, these lowlevel currents are supplied by the battery for a specified period. The second is a
telecommunications battery supplying the teleprotection equipment (excluding
the telecommunications batteries supplying only the communication cloud),
which are described very well in the IEEE standards: Telecommunication systems
are typically of high reliability, with a minimum uptime of 99.99% is often
required. Although the batteries are sized for long duration discharge, short
duration discharges are usually the case. Excess charging capacity is often
available because of redundant charger configurations and engineered
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overcapacity. The reserve battery time is usually of long duration.
Response: Thank you for your comments.
1. The SDT does not necessarily agree that the term “teleprotection” is universally used or interpreted consistently in the utility
protection industry and believes its use in the standard would not improve the standard. Your comments in the complexity and
intricacy of the telecommunications “cloud” are well-taken; however, it was the SDT’s intent to require an overall functional test
of the “cloud”-based path, but not an exhaustive test of each and every individual channel that could be involved. Yes, there is
some risk in a FSK-based guard/trip scheme that the trip function may not perform even if the guard function does, but the SDT
sees this risk as manageable and in line with other risks inherent in interval-based maintenance.
2. This standard is applicable to station batteries. Please see Section 15.4.1 of the Supplementary Reference and FAQ document for
more discussion. The scope of this standard does not include communication site batteries. The SDT believes that PRC-005-2
strikes an appropriate balance between maintenance burden, failure modes, manufacturer recommendations and IEEE battery
guidelines.
Independent Electricity
System Operator
The IESO continues to disagree with the VRF assigned to the new Requirements R3
and R4. R3 and R4 ask for implementing the maintenance plan (and initiate corrective
measures) whose development and content requirements (R1 and R2) themselves
have a Medium VRF. Failure to develop a maintenance program with the attributes
specified in R1, and stipulation of the maintenance intervals or performance criteria
as required in R2, will render R3/R4 not executable. Hence, we reiterate our request
to change R3’s VRF to Medium.
Response: Thank you for your comments.
The SDT respectfully disagrees and contends that the consequences of failing to maintain Protection Systems in the required time
frames merit a High VRF.
PNGC Small Entity Comment
Group
The PNGC Small Entity Comment Group appreciates the hard work of the Standards
Development Team on this difficult and complex project. However we are
disappointed with the response to our concerns over the VSL matrix and although we
believe on balance this should not be the sole reason for voting "no", we find it
difficult to re-cast a "yes" vote and will therefore vote "abstain" to maintain the
integrity of the quorum and reflect our position. Your response to our comment;"1.
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A smaller entity will have less to maintain in accordance with the standard; and, thus,
the percentages are still appropriate." reflects a position that indicates are cursory
and dismissive review of our concern. We would counter that because a smaller
entity has less to maintain, a solely percentage violation measure is therefore
inappropriate. We've appended our original comment below in addition to the SDT
response. PNGC Comment:1. The PNGC Comment Group takes issue with the
associated VSLs for R3. For a small entity using a time based maintenance program,
even one missed interval could be enough to elevate them to a high VSL despite the
limited impact on the Bulk Electric System. Consider an entity with 9 total
components within a specific Protection System Component Type. One violation
would mean an 11% violation rate, enough to catapult them into a High VSL. Given
the “NERC Guidance (Below), this seems to be a contradiction given the language of
“...more than one”. a. NERC Guidance on VSL assignment: i. LOWER: Missing a minor
element (or a small percentage) of the required performance ii. Moderate: Missing at
least one significant element (or a moderate percentage) of the required
performance. iii. High: Missing more than one significant element (or is missing a high
percentage) of the required performance or is missing a single vital component. iv.
Severe: Missing most or all of the significant elements (or a significant percentage) of
the required performance. We suggest changing the language for “Lower VSL” for R3
to: For Responsible Entities with more than a total of 20 Components within a
specific Protection System Component Type in Requirement R3, 5% or fewer have not
been maintained... Or for Responsible Entities with a total of 20 or fewer
Components within a specific Protection System Component Type, 2 or fewer
Components in Requirement R3 have not been maintained... SDT response: 1. A
smaller entity will have less to maintain in accordance with the standard; and, thus,
the percentages are still appropriate.
Response: Thank you for your comments.
The SDT respectfully disagrees and believes that the Standard appropriately incorporates and accounts for the system risks and
burdens of maintenance for both large and small entities. The VSLs were developed in accordance with the “FERC VSL Order” and
the NERC criteria; for stepped VSLs - Lower VSL is “5% or less”, Medium VSL is “more than 5% up to (and including) 10%”, High VSL is
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“more than 10% up to (and including) 15%”, and Severe VSL is “more than 15%”.
US Bureau of Reclamation
The reliability level for protection systems has been lowered by eliminating the
requirement for entity defined maintenance and testing procedures. Currently the
draft only prescribes that the elements are identified as to when they will be
maintained. The FAQ suggested that the PRC-005 did not have sufficient specificity
with regard to the PSMP requirement. The entity no longer must be able to
document that they were maintained in accordance with any prescribed method, jus
that they were maintained in accordance within an acceptable interval. Second, the
measure for R1 does not specific what evidence is considered acceptable. This makes
the standard hard to enforce.
Response: Thank you for your comments.
The standard is defining maximum allowable intervals and minimum acceptable activities for a PSMP. Entities are empowered to
develop PSMPs that exceed these requirements if they determine such a PSMP to be necessary. Measure M1 offers examples of
documentation that should ease compliance and enforcement.
Seminole Electric Cooperative,
Inc
1. The SDT has provided ONE Protection System Component with two differing
maintenance periods, the lockout (86) device. Six years is used for the lockout
operation and twelve years is used for contact testing of the lockouts. Earlier the
SDT had a similar arrangement with microprocessor relays, the microprocessor
relay would be tested on a twelve year cycle but the microprocessor's electromechanical trip outputs were to be tested on a six year cycle. The SDT then made
a decision that the single microprocessor asset would have a common testing
cycle of twelve years, reasonably considering it a single asset with a single
maintenance cycle of 12 years. To eliminate confusion with lockout relays, it is
recommended that a similar decision be made by the SDT to make a single
lockout relay asset have a common maintenance cycle of twelve years. The
lockout relay twelve year cycle would include both the lockout operational test
and the lockout relay tripping contact tests. This twelve year cycle would also be
in direct maintenance alignment with other microprocessor relays and auxiliary
relay testing cycles.
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2. In addition, the sudden pressure relays and their integral control circuit should
either be included or excluded. This is a compliance trap and will lead to many
findings of non-compliance, based on sudden pressure relays not being included
in many prior versions and currently not included in this version, except for their
DC control circuit.
Response: Thank you for your comments.
1. The SDT believes that electromechanical lockout relays need periodic operation. As such, these devices are required to be
exercised at the same 6 year interval required for electromechanical relays. The SDT recognizes the risk of human error trips
when working with testing of lockout devices but believes these risks can be managed. Performance based maintenance is an
option if you want to extend the intervals beyond 6 years. However, the SDT modified Table 1-5 to remove other auxiliary
relays, etc, from this activity, and clarified that the verification of such devices is included within the 12-year unmonitored
control circuitry verification.
2. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is
omitted from PRC-005-2 testing requirements because the SDT is unaware of industry recognized testing protocol for the
sensing elements. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently approved PRC-005-1 and with the SAR for Project 2007-17.
Florida Municipal Power
Agency
1. The SDT is still not agreeing with the applicability as interpreted and approved by
FERC PRC-005-1b Appendix 1 that basically says that applicable Protection
Systems are those that protect a BES Element AND trip a BES Element. The
interpretation states: In these two standards, use of the phrase transmission
Protection System indicates that the requirements using this phrase are
applicable to any Protection System that is installed for the purpose of detecting
faults on transmission elements (lines, buses, transformers, etc.) identified as
being included in the Bulk Electric System (BES) and trips an interrupting device
that interrupts current supplied directly from the BES. The SDT continues to
ignore this FERC approved interpretation, and this omission causes us to vote
Negative again. The basic issue is that some distribution protection will be swept
in with the applicability of the standard, which states: 4.2.1 Protection Systems
that are installed for the purpose of detecting Faults on BES Elements (lines,
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buses, transformers, etc.)
2. Many (most) network distribution systems that have more than one source into a
distribution network will have reverse power relays to detect faults on the BES
and trip the step-down transformer to prevent feedback from the distribution to
the fault on the BES. This is not a BES reliability issue, but more of a safety issue
and distribution voltage issue. These relays would be subject to the standard as
the applicability is currently written, but, should not be and they are currently not
within the scope of PRC-005-1b Appendix 1 because the step-down transformer
(non-BES) is tripped and not a BES Element (hence, the "and" condition of the
interpretation is not met). There are many other related examples of distribution
that might be networked or have distributed generation on a distribution circuit
where such reverse power relays, or overcurrent relays with low pick-ups, are
used for safety and distribution voltage control reasons and are not there for BES
Reliability. To make matters worse, for these Reverse Power relays, it is pretty
much impossible to meet PRC-023 because the intent of the relay is to make
current flow unidirectional (e.g., only towards the distribution system) without
regard for the rating of the elements feeding the distribution network. So, if these
relays are swept in, and if they are on elements > 200 kV, then the entity would
not be able to meet PRC-023 as that standard is currently written. So, the SDT
should have adopted the FERC approved interpretation. We have made this
recommendation several times before.
Response: Thank you for your comments.
1. The SDT believes the Applicability as stated in PRC-005-2 is correct and supports the reliability of the BES. The SDT observes that
the approved interpretation addresses the term, “transmission Protection System”, and notes that this term is not used within
PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems that are
installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and FAQ
document for additional discussion.
2. In the case you cite, the transformer is likely not a BES element; thus reverse power relays, even if installed to detect a fault in
the transformer rather than actually to detect transformer energizing current, would not be included (as they are not installed
for the purpose of detecting a fault on the BES). Please note that reverse power relays respond to real power (watts) instead of
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reactive power, and fault current is highly reactive.
Tennessee Valley Authority
This comment is regarding the Implementation Plan for Requirements R3 and R4, 1.
(Page 3 of 5) of The Implementation Plan for Project 2007-17 Protection Systems
Maintenance and Testing PRC-005-02. Number 1. states: For Protection System
component maintenance activities with maximum allowable intervals of less than
one (1) calendar year, as established in Tables 1-1 through 1-5: o The entity shall
be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
eighteen (18) months following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter thirty (30) months following NERC Board of Trustees adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities. TVA Comment: Even though TVA has already started a plan to address
this issue, it will take several years to implement automatic checkback on 541 carrier
blocking sets on the TVA system. TVA performed quarterly testing from 2000
through 2007, then after data showed failures not attributed to signal margin, the
test was changed to twice a year in 2008. TVA carrier failure rate has not increased
since the frequency was changed in January 2008 from 4 tests/year to 2 tests/year.
We suggest a graduated implementation plan for this effort similar to number 3
(being compliant 30% in 24 months, 60% in 36 months, and 100% in 48 months) on
Pages 3 and 4 of 5.
Response: Thank you for your comments.
If an entity’s experience is that these components require less-frequent maintenance, a performance-based program in accordance
with Requirement R2 and Attachment A is an option. Your comments on your failure rates seems to indicate that you are performing
a failure rate analysis similar to what is required under Attachment A for performance maintenance. While it is unfortunate that you
feel you cannot meet the implementation requirements, the SDT believes that the existing plan is judicious in its time frame relative
to the maximum intervals required by the standard.
Tacoma Power
1. This is a follow-up question/comment from the previous round of balloting;
please see the part in all capitals. It is still unclear whether Section 15.3 permits
periodically verifying DC voltage at the actuating device trip terminals as an
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acceptable method of accomplishing the maintenance activity identified in Table
1-5 for unmonitored control circuitry associated with protective functions IF DC
VOLTAGE IS VERIFIED AT EACH APPLICABLE SET OF ACTUATING DEVICE TRIP
TERMINALS SO THAT EVERY TRIP PATH IS ADDRESSED. It is recommended that
this approach be considered acceptable, provided that auxiliary relays are
operated within the maximum maintenance interval.
2. In Table 1-2, does the ‘channel’ include the communication interface/driver that
is part of the end device?
Response: Thank you for your comments.
1. The method chosen for verification is left to the entity. The second to last paragraph of Section 15.3 of the Supplementary
Reference and FAQ document states: “Monitoring of the control circuit integrity allows for no maintenance activity on the
control circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or tripping auxiliary relays).
Monitoring of integrity means to monitor for continuity and/or presence of voltage on each trip path. For Ethernet or fiber-optic
control Systems, monitoring of integrity means to monitor communication ability between the relay and the circuit breaker.” If
your suggested activity verifies each and every individual path to the trip coil, it may be an effective method of addressing this
requirement; simply checking for voltage at the trip coil may not verify all individual paths.
2. Please see Section 15.5.1 of the Supplementary Reference and FAQ document. The maintenance activities in Table 1-2 related
to “channel” have been revised to “communications systems”
BAE Batteries USA
This revision is a major improvement over the previous draft. Hopefully, the
comments above are seen in the light of ensuring basic accuracy of the revised
statements. They are not intended to materially change the intent of the position
agreed upon at the last drafting team meeting.
Response: Thank you for your comments.
HHWP
VSL should not be a function of "specific Protection System Component Type". VSL
should look at percentage of TOTAL Protection System Components that were not
tested within scheduled test date. Consider the entity with 400 Protection System
Components, including 2 station battery systems. If that entity completed 399 of 400
tests within schedule and missed 1 battery test, the VSL would be high or severe.
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Alternatively, if the entity completed 399 of 400 tests, but the missed test was one of
200 protective relays, the VSL would be low. There is no assurance though that the
missed battery test resulted in higher risk for the BES than the missed protective
relay test. As a result the relationship between VSL and the degree of violation
severity lacks predictability.
Response: Thank you for your comments.
The SDT disagrees because a battery supplies control power to numerous protective schemes, failure to ensure that the battery is fit
for duty is more egregious than missing one component of numerous schemes.
Consumers Energy
1. We agree with the purpose in section 3 of the Standard. However, section 4.2.1
expands the scope from "affecting the reliability of the Bulk Electric System" to
"detecting Faults on BES Elements". In our opinion, the Applicability should be
limited to the stated Purpose. Expanding the scope as is done in 4.2.1 greatly
increases the number of Protection Systems covered without an increase in
reliability of the BES. We prefer the applicability as expressed in Appendix 1 of
PRC-005-1b.
2. We suggest changing "Component Type" in R1.2 to something similar to
"Segment" as defined within the Standard. A "Component Type" limits to one of
five categories, whereas a "Segment" must share similar attributes.
3. In item 2 of the second section of Attachment A, it is only necessary to use 5%, as
5% of a Segment (minimum of 60) is always 3 or more.
Response: Thank you for your comments.
1. The SDT believes the Applicability as stated in PRC-005-2 is correct and supports the reliability of the BES. The SDT observes that
the approved interpretation addresses the term, “transmission Protection System”, and notes that this term is not used within
PRC-005-2; thus the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses “Protection Systems that are
installed for the purpose of detecting faults on BES Elements.” Please see Section 2.3 of the Supplementary Reference and FAQ
document for additional discussion.
2. In the documentation to support Requirement R1.2, an entity can list different technologies within a Component Type along
with their respective monitoring attributes. The SDT sees no appreciable improvement in the standard with your proposed
change and respectfully declines to modify the standard.
Consideration of Comments: Project 2007-17
72
Organization
Yes or No
Question 3 Comment
3. The SDT agrees with your observation but sees no appreciable improvement in the standard with your proposed change and
respectfully declines to modify the standard.
Alliant Energy
We appreciate the work done by the SDT and believe it is an excellent product.
Response: Thank you for your comments.
Georgia Transmission
Corporation
We cast our ballot as an affirmative vote and agree with the nature of the standard.
We raise concerns on the measures that are very prescriptive on documentation. We
prefer a standard based on the program and measures that track the application and
performance of the groups program. Maintaining the documentation for individual
elements becomes a group’s prime directive along with maintaining the equipment;
this develops a process more controlled by documentation than results. This also
adds a level of complexity for data retention, the drafting team tried to resolve by
reducing the load of data. We contend the retention levels to be extreme
considering some of the 12 calendar year cycles, interpret the data for compliance to
be 24 years. One cannot remove previous documents until new maintenance
performed 12 years after the current recorded date. We recommend reducing the
data retention to list or check sheets and not the extreme of each individual
component. Another important factor in managing the data is the capability of
retrieval after 12 or 24 years. Some systems and formats are not available for 12 or
24 years and add a burden on companies to maintain legacy systems or convert
massive amounts of data.
Response: Thank you for your comments.
To be assured of compliance, the SDT believes the Compliance Monitor will need the data for the most recent performance of the
maintenance, as well as the data for the preceding maintenance period. This seems to be consistent with what auditors are
expecting (per the SDT’s experience), and is also consistent with Compliance Process Bulletins 2011-001 and 2009-05. This seems to
be consistent with what auditors are expecting (per the SDT’s experience), and is also consistent with Compliance Process Bulletins
2011-001 and 2009-05. The SDT has specified the data retention in the posted standard to establish this level of documentation. The
entity is urged to assure that data is retained as specified within the standard.
Nebraska Public Power District
1. We recommend removing requirement 5. This is adding the requirement for a
Consideration of Comments: Project 2007-17
73
Organization
Yes or No
Question 3 Comment
2.
3.
4.
5.
6.
corrective action program to the standard. Performance metrics should be
utilized to measure if a registered entity is correcting maintenance deficiencies in
a timely manner. Examples of performance metrics include: o A Countable event
has already been defined in the definition of terms, which would cover the need
to replace equipment. o The quantity and causes of Misoperations are a direct
correlation to good or poor maintenance practices and corrective actions by a
utility. o TADS records events which are initiated by failed protection system
equipment and would identify utilities with poor corrective action processes.
Can you show us a study or references justifying why records need to be kept for
longer than the end of the current audit period. We are concerned that the
complexities and costs of tracking and maintaining records, along with the
corresponding maintenance program and PRC-005 revision that old tests would
fall under will be an undue cost to small utilities. We suggest requiring entities to
retain the last maintenance record or any records created during the current
audit period.
The comment from the previous consideration of comments, “The SDT believes
that Protection Systems that trip (or can trip) the BES should be included” seems
to include any device that can affect the BES. This sets a precedence to include
any device that can trigger trip coils into the maintenance system. These devices
are meant to protect equipment and not the BES.
Based on the IEEE device numbers, please indicate which devices are part of the
BES protection system and should be included in a maintenance program.
Why do functional trip checks need to be done on any interval if checks are done
upon commissioning, maintenance and modification? We suggest eliminating any
interval and making the requirement to check upon commissioning, maintenance
and modification.
Comments on SAR for 2007-17 Very few reclosing relays protect the BES. Most
reclosing relays actually would have a negative impact on the reliability of the
bulk electric system. It is imperative that the SDT clearly define what types of
reclosing relays are referred to here, and if it pertains to ANY reclosing relay that
Consideration of Comments: Project 2007-17
74
Organization
Yes or No
Question 3 Comment
can affect the BES.
7. There is a difference between components designed to protect the BES and
components which can affect the BES.
8. For R5 if the maintenance interval is 6 years does the maintenance issue become
an “unresolved” item immediately or does the next maintenance interval 6 years
later need to be reached before it takes on an unresolved status to be auditable
under R5?
9. Comments: Suggest for monitored microprocessor relays in Table 1-1 and 3 to
change wording to verify “settings are as specified that are essential to the proper
functioning of the protection system”. Many settings are not essential.
10. A key concern is will the reliability of the bulk electric system be affected
negatively due to increased risk from human element initiated events as a result
of the more frequent functional trip checks that will be required. I suggest there
be consideration that the interval for functional tests be moved to the minimum
frequency of 12 years to minimize this unknown but present risk.
Response: Thank you for your comments.
1. The SDT disagrees:
NERC has demonstrated its belief that returning Protection System devices to good working order exists currently as a required
element of a sound maintenance program subject to the existing Protection System maintenance and testing standard, PRC005-1. For reference, NERC Compliance Application Notice CAN-0043 (Posted Final 12/30/2011) directs Compliance
Enforcement Authorities (CEAs) to “…look for relay test results or field records with annotations such as “as-found” readings or
pass/fail results; if failed, then adjustments made. The maintenance record for adjustments may be requested”.
Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope of
this standard. There can be any number of supply, process and management problems that make setting repair deadlines
impossible. The SDT specifically chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex unresolved maintenance issues might require greater than the remaining maintenance
interval to resolve (and yet still be a “closed-end process”). For example, a problem might be identified on a VRLA battery
during a 6 month check. In instances such as one that requires battery replacement as part of the long term resolution, it is
highly unlikely that the battery could be replaced in time to meet the 6 calendar month requirement for this maintenance
activity. The SDT does believe corrective actions should be timely but concludes it would be impossible to postulate all possible
Consideration of Comments: Project 2007-17
75
Organization
Yes or No
Question 3 Comment
remediation projects and therefore impossible to specify bounding time frames for resolution of all possible unresolved
maintenance issues, or what documentation might be sufficient to provide proof that effective corrective actions are being
undertaken.
2. To be assured of compliance, the SDT believes the Compliance Monitor will need the data for the most recent performance of
the maintenance, as well as the data for the preceding maintenance period. This seems to be consistent with what auditors are
expecting (per the SDT’s experience), and is also consistent with Compliance Process Bulletins 2011-001 and 2009-05. This
seems to be consistent with what auditors are expecting (per the SDT’s experience), and is also consistent with Compliance
Process Bulletins 2011-001 and 2009-05. The SDT has specified the data retention in the posted standard to establish this level
of documentation. The entity is urged to assure that data is retained as specified within the standard.
3. The response cited from a previous consideration of comments was specifically related to sudden pressure relays. The
Applicability 4.2.1 of the standard, specifically states, “…installed for the purpose of detecting Faults on BES Elements”.
4. It is left to the entity to determine which devices and their complementary IEEE device numbers are installed for the purpose of
detecting Faults on BES Elements.
5. The standard does not specify “functional trip tests”, but instead requires that various elements of the dc control circuit be
verified at various intervals. Also, FERC Order 693 directs NERC to establish maximum allowable maintenance intervals for
Protection System components. Please see Section 15.3 of the Supplementary Reference and FAQ Document.
6. Reclosing relays are not covered in PRC-005-2. In Order 758, FERC directed NERC to include reclosing relays in a future version
of PRC-005; the SDT developed the draft SAR to address FERC’s directive
7. The SDT agrees; the standard explicitly covers “Protection Systems that are installed for the purpose of detecting Faults on BES
elements (lines, buses, transformers, etc.)”.
8. The item does not become an “Unresolved Maintenance Issue” unless it is not corrected before the current maintenance
interval expires.
9. The SDT sees no appreciable improvement in the standard with your proposed change and respectfully declines to modify the
standard.
10. The SDT believes that performing these maintenance activities at the specified intervals will benefit the reliability of the BES.
The standard does not specify “functional trip tests”, but instead requires that various elements of the dc control circuit be
verified at various intervals.
Western Area Power
Administration
Western Area Power Administration is appreciative of the hard work done by the
SDT and NERC.
1. We respectfully submit our professional opinion that the increased relay testing
Consideration of Comments: Project 2007-17
76
Organization
Yes or No
Question 3 Comment
2.
3.
4.
5.
required by the PRC-005-2 will result in a net degradation to the reliability of the
BES due to human hands disturbing working systems.
We propose that auxiliary relays be tested at commissioning and anytime the
circuits are rewired or redesigned. If there is evidence that the relay has
functioned properly in its current configuration then the best practice for insuring
reliability is to leave it alone.
The maintenance interval of 6 years for lock-out relay testing is not consistent
with 12 year interval of auxiliary relay testing or control circuit testing. No
justification is provided for this increased testing interval of lock-out relays versus
other electro-mechanical devices. These inconsistent testing intervals, within the
same protection control schemes and protective devices, will complicate the
industry's Protection System Maintenance Program and cause an increase in
maintenance costs.
Condition Based Monitoring or Performance Based Monitoring are not allowed on
trip coil circuits or lock-out relays. This is inconsistent with current or future
technology. Deviation from the 6 year testing interval should be allowed, using
CBM or PBM. The Standard should not present a barrier to technology
advancements or industry initiatives. The continuous, frequent testing of these
devices is detrimental to system reliability.
Disagree with testing of the dc control portion of the sudden pressure device as
defined by the FAQ. We feel that this device and its wiring were deemed out of
scope previously.
Response: Thank you for your comments.
1. The SDT believes that performing these maintenance activities at the specified intervals will benefit the reliability of the BES.
2. The SDT believes that performing these maintenance activities at the specified intervals will benefit the reliability of the BES.
Also, FERC Order 693 directs NERC to establish maximum allowable maintenance intervals for Protection System components.
3. The SDT believes that electromechanical lockout relays need periodic operation to remain reliable. As such, these devices are
required to be exercised at the same 6 year interval required for electromechanical relays. Performance based maintenance is
an option if you want to extend the intervals beyond 6 years.
4. Performance-based maintenance per Attachment A of the standard may be applied to both trip coil circuits and lockout relays.
Consideration of Comments: Project 2007-17
77
Organization
Yes or No
Question 3 Comment
5. The trip path from a sudden pressure device is a part of the Protection System control circuitry. The sensing element is omitted
from the definition of Protection System because the SDT is unaware of industry recognized testing protocol for the sensing
elements. This position is consistent with the currently-approved PRC-005-1 and the SAR for Project 2007-17.
Southwest Power Pool NERC
Reliability Standards
Development Team
N/A
Idaho Power Company
No additional comments.
Kansas City Power & Light
No other comments.
END OF REPORT
Consideration of Comments: Project 2007-17
78
Consideration of Comments
Project 2007-17 Protection System Maintenance and Testing
The Protection System Maintenance and Testing Drafting Team would like to thank all commenters
who submitted comments on the 4th draft of the standard for Protection System Maintenance. These
standards were posted for a 30-day public comment period from July 27, 2012 through August 27,
2012. Stakeholders were asked to provide feedback on the standards and associated documents
through a special electronic comment form. There were 36 sets of comments, including comments
from approximately 102 different people and from approximately 65 companies representing 9 of the
10 Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary Consideration of all Comments Received:
The only edit to the standard was to add an “s” to “communication” in several locations within Table 1-2
for consistency. The term is now “communications system” throughout the table.
Definitions: No changes made.
Applicability: No changes made.
Requirements: No changes made.
Tables: In Table 1-2, added an “s” to “communication” in several locations for consistency. The term is
now “communications system” throughout the table.
Measures: No changes made.
VSLs: In the VSLs for Requirement R5, the word “identify” was added to each VSL to be consistent with
the requirement.
Supplementary Reference and FAQ Document: Various spelling and punctuation errors were corrected,
and additional content was added to improve the reference document.
Implementation Plan: No changes made.
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
Unresolved Minority Views:
A few commenters questioned the inclusion of breaker trip coil verification, auxiliary relay
verification, and/or lockout relay verification. The drafting team responded that each of these
devices needs to be maintained at the prescribed intervals to assure reliability.
Several commenters were concerned that an entity has to be “perfect” in order to be compliant;
the SDT responded that NERC Standards currently allow no provision for any degree of nonperformance relative to the requirements.
Several commenters continued to object to inclusion of UFLS and UVLS relays, in that they may
not be installed on BES equipment. The drafting team responded that these devices, while not
on BES equipment, are installed for the reliability of the BES, and are therefore included. The
drafting team further noted that these devices are currently addressed in PRC-008-0 and PRC011-0.
A few commenters questioned the inclusion of the dc control circuitry for sudden pressure relays
even though the relays themselves are excluded from the definition of “Protection System”; the
SDT reiterated its position that this dc control circuitry is included because the dc control
circuitry is associated with protective functions.
Several commenters expressed concerns regarding Requirement R5 and Unresolved
Maintenance Issues. The SDT explained its rationale for the requirement as drafted.
Consideration of Comments: Project 2007-17
2
Index to Questions, Comments, and Responses
1. In response to stakeholder input, the SDT made several changes to Table 1-2 of the standard, as
detailed below: .................................................................................................................................. 12
2. The SDT modified the Implementation Plan as follows: .................................................................... 16
3. The SDT made complementary changes in the “Supplementary Reference and FAQ Document” to
provide supporting discussion for the Requirements within the standard. Do you have any specific
suggestions for further improvements?............................................................................................ 21
4. If you have any other comments that you have NOT provided in response to the above questions,
please provide them here. (Please do not repeat comments that you provided elsewhere.) ......... 28
Consideration of Comments: Project 2007-17
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Carmen Agavriloai
Independent Electricity System Operator
NPCC 2
3.
Greg Campoli
New York Independent System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC 2
9.
Michael Jones
National Grid
NPCC 1
Hydro One Networks Inc.
NPCC 1
10. David Kiguel
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Michael R. Lombardi Northeast Utilities
NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Silvia Parada Mitchell NextEra Energy, LLC
NPCC 5
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
16. Robert Pellegrini
The United Illuminating Company
NPCC 1
17. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
19. Brian Robinson
Utility Services
NPCC 8
20. Michael Schiavone
National Grid
NPCC 1
21. Wayne Sipperly
New York Power Authority
NPCC 5
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Group
Southwest Power Pool Reliability Standards
Development Team
Jonathan Hayes
Additional Member
Additional Organization
Southwest Power Pool
SPP
NA
2. Robert Rhodes
Southwest Power Pool
SPP
NA
3. John Allen
City Utilities of Springfield
SPP
1, 4
4. Clem Cassmeyer
Western Farmers Electric Cooperative SPP
1, 3, 5
5. Terri Pyle
Oklahoma Gas and Electric
SPP
1, 3, 5
6. Sandra Sanscrainte ITC holdings
SPP
NA
7. Katie Shea
Westar Energy
SPP
1, 3, 5, 6
8. Tim Bobb
Westar Energy
SPP
1, 3, 5, 6
Group
Greg Rowland
3
4
5
6
7
X
Region Segment Selection
1. Jonathan Hayes
3.
2
Duke Energy
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
Duke Energy
RFC
1
2. Lee Schuster
Duke Energy
FRCC
3
3. Dale Goodwine
Duke Energy
SERC
5
4. Greg Cecil
Duke Energy
SERC
6
Consideration of Comments: Project 2007-17
5
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4.
Group
Connie Lowe
Dominion
2
3
X
X
X
X
4
5
6
X
X
X
X
7
Additional Member Additional Organization Region Segment Selection
1. Mike Garton
NPCC
5, 6
2. Louis Slade
RFC
5, 6
3. Randi Heise
SERC
5, 6
4. Mike Crowley
SERC
1, 3
5.
Group
Frank Gaffney
Florida Municipal Power Agency
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority FRCC
3
3. Jim Howard
Lakeland Electric
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
6.
Group
Brenda Hampton
Additional Member
1. Mike Laney
7.
FRCC
Luminant
Additional Organization
X
Region Segment Selection
Luminant Generation Company LLC ERCOT 5
Group
Jason Marshall
Additional Member
ACES Standards Collaborators
Additional Organization
Region Segment Selection
1. Shari Heino
Brazos Electric Power Cooperative
2. Scott Brame
North Carolina Electric Membership Corporation RFC
1, 3, 4, 5
3. Clem Cassmeyer
Western Farmers Electric Cooperative
SPP
1, 5
4. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
5. Ashley Gonyer
East Kentucky Power Cooperative
SERC
1, 3, 5
8.
Group
Dennis Chastain
X
ERCOT 1, 5
Tennessee Valley Authority
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Rusty Hardison
SERC
1
2. Pat Caldwell
SERC
1
3. David Thompson
SERC
5
Consideration of Comments: Project 2007-17
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Jerry Finley
SERC
1
5. Robert Brown
SERC
5
6. Tom Vandervort
SERC
5
7. Annette Dudley
SERC
5
9.
Group
Chris Higgins
Bonneville Power Administration
X
2
3
4
X
5
X
6
7
8
9
X
Additional Member Additional Organization Region Segment Selection
1. Jason
Burt
WECC 1
2. Heather
Laslo
WECC 1
3. Fred
Bryant
WECC 1
4. Rita
Coppernoll
WECC 1
5. Mason
Bibles
WECC 1
6. Brenda
Vasbinder
WECC 1
10.
Individual
Joe Uchiyama
O&M Group
11.
Individual
Antonio Grayson
Southern Company
X
12.
Individual
Brandy A. Dunn
Western Area Power Administration
X
13.
Individual
Cole Brodine
Nebraska Public Power District
X
14.
Individual
Tom Finch
CYPL
15.
Individual
Eric Scott
City of Palo Alto
16.
Individual
Cleyton Tewksbury
Bridgeport Energy
17.
Individual
Joe O'Brien
NIPSCO
X
18.
Individual
Thad Ness
American Electric Power
X
19.
Individual
J. S. Stonecipher, PE
Beaches Energy Services
X
20.
Individual
Chris McVicker
Puget Sound Energy
X
21.
Individual
Nazra Gladu
Manitoba Hydro
X
X
22.
Individual
Keith Morisette
Tacoma Power
X
X
23.
Individual
Steven Wallace
Seminole Electric Cooperative, Inc.
X
24.
Individual
Kirit Shah
Ameren
X
25.
Individual
Scott Bos
Muscatine Power and Water
X
Consideration of Comments: Project 2007-17
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
26.
Individual
Michelle R D'Antuono
Ingelside Cogeneration LP
27.
Individual
Andrew Z. Pusztai
American Transmission Company
28.
Individual
Anthony Jablonski
ReliabitliyFirst
29.
Individual
Yves Lavoie
Primax Technologies Inc.
30.
Individual
Bob Thomas
Illinois Municipal Electric Agency
31.
Individual
Eric Salsbury
Consumers Energy
32.
Individual
Jonathan Meyer
Idaho Power Company
X
33.
Individual
Brad Harris
CenterPoint Energy
X
34.
Individual
Brett Holland
KCP&L/ KCPL-GMO
X
35.
Individual
Edward Amato
Individual
Chris Searles
Midtronics Inc
IEEE Stationary Battery Committee Task
Force
36.
Consideration of Comments: Project 2007-17
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
X
8
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
It is not necessary to answer the remainder of the questions unless you have additional comments that have not already been
provided by the entity whose comments you are supporting. Each entity that indicates support for another entity’s comments will be
counted as having provided comments, regardless of whether they provide any additional comments.
Summary Consideration:
Organization
Agree
Support Comments Submitted by Another Entity
Northeast Power Coordinating
Council
Southwest Power Pool Reliability
Standards Development Team
Duke Energy
Dominion
Florida Municipal Power Agency
Luminant
ACES Standards Collaborators
Tennessee Valley Authority
Consideration of Comments: Project 2007-17
9
Organization
Agree
Support Comments Submitted by Another Entity
Bonneville Power Administration
O&M Group
Southern Company
Western Area Power Administration
Nebraska Public Power District
CYPL
City of Palo Alto Utilities
City of Palo Alto
Bridgeport Energy
NIPSCO
American Electric Power
Beaches Energy Services
Puget Sound Energy
Manitoba Hydro
Tacoma Power
Seminole Electric Cooperative, Inc.
Consideration of Comments: Project 2007-17
Florida Municipal Power Agency and the Illinois Municipal Power Agency,
Duke Energy and WAPA
10
Organization
Agree
Support Comments Submitted by Another Entity
Ameren
Muscatine Power and Water
MIdwest Reliability Organization NERC Standards Review Forum (MRO NSRF)
Ingelside Cogeneration LP
American Transmission Company
ReliabitliyFirst
Primax Technologies Inc.
Illinois Municipal Electric Agency
Consumers Energy
Idaho Power Company
CenterPoint Energy
KCP&L/ KCPL-GMO
Midtronics Inc
Consideration of Comments: Project 2007-17
11
1. In response to stakeholder input, the SDT made several changes to Table 1-2 of the standard, as detailed below:
The interval for the second portion of the first row of the table was changed from 12 years to 6 years.
The term “channels” was modified to “communications system” in two locations.
The Component Attributes in the last row were modified to clarify that all attributes must be present to use the
associated intervals and activities.
Do you agree with these changes? If not, please provide specific suggestions for changes to Table 1-2 in the comment area.
Summary Consideration: In general, the industry was supportive of the changes to the table. More clarification on the scope of
the “communications systems” was provided in Section 15.5.1 of the Supplementary Reference and FAQ document, and the term,
“communication system” was corrected to “communications system.”
Organization
Bonneville Power Administration
Yes or No
Question 1 Comment
No
BPA believes that changing the language from "channels" to
"communications systems" does not clarify the intent since
"communications systems" is not defined in the standard. The term
“communications systems” which is referenced in the Supplementary
Reference and FAQ document remains ambiguous. BPA recommends one of
these two definitions be included in the standard:1) If the intent is to cover
only the Communications Equipment and “channel” as defined
above:”Communications System” - The Communications System as defined
for the purposes of PRC-005-02 consists of a Component’s signaling inputs
and outputs and the communications channel that these signals traverse.
The intervening carrier communications devices that transport this channel
are explicitly excluded from the definition of Communications System.2) If
the intent is to cover the Communications Equipment, “channel” and the
cloud functionally:”Communications System” - The Communications System
as defined for the purposes of PRC-005-02 consists of a Component’s
Consideration of Comments: Project 2007-17
12
Organization
Yes or No
Question 1 Comment
signaling inputs and outputs and the communications channel that these
signals traverse. The Communications System includes the simple end-toend functionality of the intervening carrier communications devices that
transport this channel but explicitly excludes intermediate switching,
redundant paths, packet routing, digital cross-connections and other “cloud”
carrier elements from the definition of Communications System.
Response: Thank you for your comments. It is the drafting team’s intent to require the entity to perform maintenance on the
protective system communications part of the scheme to verify that it is performing as required. Both the communications
equipment and the channel are part of that. If that channel is a third-party leased circuit, then the entity can only verify
performance of the channel and not maintain any of its equipment. If the channel is a power line carrier and owned by the
entity, the performance can be verified and the equipment can be maintained, if necessary. This standard is proscribed from
describing “how” to perform an overall functional test of a communications system; it is left to the entity to determine what
methods best address their program.
Also, Section 15.5.1 of the Supplementary Reference and FAQ document was revised to further discuss communications
systems.
Southern Company
No
Suggestion - Change the interval back to 12 years instead of 6 years. The 12
year interval is reasonable considering that un-monitored communications
systems will be functionally tested every 4 months
Response: Thank you for your comments. The drafting team respectfully disagrees. Although an entity functionally tests an
unmonitored communications system every four months, there is no requirement to have the pertinent performance criteria
verified as part of this functional test. Testing the communications system's performance criteria involves additional tests, such
as those described in Section 15.5.1 of the Supplementary Reference and FAQ document. Of course, an entity can always
perform both types of tests on a four-month interval, but at this time we see no reason to have the performance criteria
verification at a four-month interval. An entity has the latitude to perform maintenance more frequently than specified, if it
feels that such maintenance is needed.
Tacoma Power
Yes
Consideration of Comments: Project 2007-17
In Table 1-2, for unmonitored communications systems, under Maintenance
Activities, ‘communication system’ is used, but in the next row,
13
Organization
Yes or No
Question 1 Comment
‘communications system’ is used. These terms should be consistent.
Response: Thank you for your comment. The drafting team has revised the Table 1-2 to consistently use “communications
systems.”
Ameren
Yes
Ameren supports these changes in the interest of BES reliability.
Yes
Ingleside Cogeneration LP was prepared to support a six year maintenance
interval - which was specified in all other drafts of PRC-005-2. We agree that
the project team’s modification is necessary to correct a mistake that crept
into the last version.
Response: Thank you for your support.
Ingelside Cogeneration LP
Response: Thank you for your support.
Northeast Power Coordinating
Council
Yes
Southwest Power Pool Reliability
Standards Development Team
Yes
Duke Energy
Yes
Dominion
Yes
Chris Searles
Yes
Florida Municipal Power Agency
Yes
Luminant
Yes
Consideration of Comments: Project 2007-17
14
Organization
Yes or No
ACES Standards Collaborators
Yes
Tennessee Valley Authority
Yes
O&M Group
Yes
Western Area Power Administration
Yes
Nebraska Public Power District
Yes
City of Palo Alto
Yes
Bridgeport Energy
Yes
American Electric Power
Yes
Beaches Energy Services
Yes
Puget Sound Energy
Yes
American Transmission Company
Yes
ReliabitliyFirst
Yes
Idaho Power Company
Yes
CenterPoint Energy
Yes
KCP&L/ KCPL-GMO
Yes
Midtronics Inc
Yes
Consideration of Comments: Project 2007-17
Question 1 Comment
15
2. The SDT modified the Implementation Plan as follows:
Within “Retirement of Existing Standards,” the legacy standards will be retired upon full implementation of PRC-005-2,
rather than upon PRC-005-2 becoming effective.
Within “General Considerations,” each entity shall be responsible for maintaining each of their Protection System
components according to their maintenance program already in place for the legacy standards (PRC-005-1b, PRC-008-0,
PRC-011-0, and PRC-017-0) or according to their maintenance program for PRC-005-2, but not both.
Do you agree with these changes? If not, please provide specific suggestions for changes to the Implementation Plan in the
comment area.
Summary Consideration: The commenters largely supported the Implementation Plan, including the changes made at this revision.
Several commenters questioned whether the added text within “General Considerations” is necessary, in that it essentially duplicates
statements made elsewhere in the Implementation Plan; the drafting team believes that the additional emphasis is useful. No
changes were made to the Implementation Plan in response to comments.
Organization
Yes or No
Southern Company
No
Question 2 Comment
The "General Consideration" sentence in question above is superfluous and
therefore unnecessary. The instruction provided in the sentence is (repeated and)
more clearly stated in the first sentence of the "Retirement of Existing Standards:"
section.
Response: Thank you for your comment. The drafting team believes that the modification to the “General Considerations” section
of the Implementation Plan adds clarity.
Western Area Power
Administration
No
The logistics of these statements are confusing and need further clarification as to
intent and implementation.
Response: Thank you for your comment. The drafting team believes that the implementation plan is clear. The entity should
follow the previous maintenance intervals for any specific components until that component is addressed by PRC-005-2. As the
Consideration of Comments: Project 2007-17
16
Organization
Yes or No
Question 2 Comment
transition is occurring, the entity should adjust its maintenance and testing schedule so that they are able to demonstrate that the
required percentage of components meet the maintenance intervals given in the PRC-005-2 tables at each of the percent
compliant milestones given in this Implementation Plan.
Tennessee Valley Authority
The intent of this modification is not clear. It could be interpreted as allowing an
entity, for any given Protection System component identified in Table 1-1 through
Table 1-5, to choose to maintain those components under an existing maintenance
program that is compliant with the legacy standards until PRC-005-2 completely
retires PRC-005-1b, PRC-008-0, PRC-011-0 and PRC-017-0 (first calendar quarter one
hundred fifty-six (156) months following regulatory approval of PRC-005-2). For
example, if an entity elects to maintain unmonitored communications system
components described in Table 1-2 using its program that is compliant with the
legacy standards, when would it have to meet the intervals defined in Table 1-2? The
use of “or” under “General Considerations” indicates that compliance with the legacy
standards is acceptable until such time that all of the legacy standards are retired.
Response: Thank you for your comment. The drafting team believes that the Implementation Plan is clear.
The entity should follow the previous maintenance intervals for any specific components until that component is addressed by
PRC-005-2. As the transition is occurring, the entity should adjust its maintenance and testing schedule so that they are able to
demonstrate that the required percentage of components meet the maintenance intervals given in the PRC-005-2 tables at each of
the percent compliant milestones given in this Implementation Plan.
If an entity elects to maintain unmonitored communications system components described in Table 1-2 using its program that is
compliant with the legacy standards, it would have to meet the intervals defined in Table 1-2 according to the Implementation
Plan for Requirements R3 and R4.
ACES Standards Collaborators
Yes
We thank the drafting team for this consideration that will allow early compliance
with the new version of the standard. This plan should avoid many of the transitional
issues that have occurred with other new versions of standards.
Response: Thank you for your comment.
Consideration of Comments: Project 2007-17
17
Organization
Yes or No
American Electric Power
Yes
Question 2 Comment
We believe the text “Once an entity has designated PRC-005-2 as its maintenance
program for specific Protection System components, they cannot revert to the
original program for those components” does improve the clarity of the standard.
Response: Thank you for your comment.
Ameren
Yes
Ameren supports this practical reality.
Response: Thank you for your comment.
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration LP sees the modifications to the implementation plan as a
clarification-only. We had anticipated that auditors will look for evidence that a
legacy program remains in place until a specifically-identified transition date.
In fact, the project team should consider adding an allowance for entities to adopt
PRC-005-2 immediately upon FERC’s approval. This may mean in rare cases that
maintenance activities and intervals managed in accordance with PRC-005-1b will
drop out of the program; but if the industry and regulatory bodies agree that the new
program is superior, there is no reliability purpose served by waiting. Furthermore,
the maintenance activities will continue anyways - they will just not be subject to
auditor review.
Unfortunately, NERC Compliance has taken the opposite position for the
implementation of the CIP version 4 “bright-line criteria” - which we believe is
counter-productive to our shared commitment to reliability. Just as with PRC-005-2,
a thorough evaluation showed that the elimination of ambiguity reduces risk to the
greater system. It is disingenuous to require outdated standards to remain in place
simply to avoid a possibility that a borderline facility remain on the regulatory books.
Response: Thank you for your comments. The drafting team suggests that, in the event that an entity fully implements PRC-005-2
for all components (i.e., has maintained everything according to PRC-005-2) upon regulatory approvals, the entity will have retired
PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-17-0 from their program at that time. However, the drafting team believes that the
Consideration of Comments: Project 2007-17
18
Organization
Yes or No
Question 2 Comment
phased Implementation Plan is necessary to avoid any gaps in applicability throughout the maintenance intervals currently in use.
Further, to demonstrate continuing compliance, an entity will need evidence that they have been in full compliance with
whichever version of the standard was in effect.
Northeast Power Coordinating
Council
Yes
Southwest Power Pool
Reliability Standards
Development Team
Yes
Duke Energy
Yes
Dominion
Yes
Chris Searles
Yes
Florida Municipal Power
Agency
Yes
Luminant
Yes
Bonneville Power
Administration
Yes
O&M Group
Yes
Nebraska Public Power District
Yes
City of Palo Alto
Yes
Consideration of Comments: Project 2007-17
19
Organization
Yes or No
Bridgeport Energy
Yes
Beaches Energy Services
Yes
Puget Sound Energy
Yes
Manitoba Hydro
Yes
Tacoma Power
Yes
American Transmission
Company
Yes
Illinois Municipal Electric
Agency
Yes
Idaho Power Company
Yes
CenterPoint Energy
Yes
KCP&L/ KCPL-GMO
Yes
Midtronics Inc
Yes
Consideration of Comments: Project 2007-17
Question 2 Comment
20
3.
The SDT made complementary changes in the “Supplementary Reference and FAQ Document” to provide supporting discussion
for the Requirements within the standard. Do you have any specific suggestions for further improvements?
Summary Consideration: Commenters offered several suggestions for improvements to the Supplementary Reference and FAQ
Document. Punctuation, spelling and content changes have been made to the Supplementary Reference and FAQ Document in
response to these suggestions.
Organization
Yes or No
Northeast Power Coordinating
Council
No
Duke Energy
No
Dominion
No
Tennessee Valley Authority
No
Bonneville Power
Administration
No
Nebraska Public Power District
No
City of Palo Alto
No
Bridgeport Energy
No
Puget Sound Energy
No
Ameren
No
Ingelside Cogeneration LP
No
Consideration of Comments: Project 2007-17
Question 3 Comment
21
Organization
Yes or No
American Transmission
Company
No
Idaho Power Company
No
CenterPoint Energy
No
KCP&L/ KCPL-GMO
No
Primax Technologies Inc.
Question 3 Comment
In 15.4.1 Frequently Asked Questions, to the question: What did the PSMT SDT mean
by “continuity” of the dc supply? One of the proposed methods for ensuring
continuity is the following: Specific gravity tests can infer continuity because, without
continuity, there could be no charging occurring; and if there is no charging, then
specific gravity will go down below acceptable levels.
Comment: I agree that the uncharged cell's specific gravity would drop but it would
take weeks or months to show. Should power be needed from the battery during this
period of time the battery would not be able to perform as it should. To me this an
unacceptable risk
Response: Thank you for your comments. The drafting team agrees with you that some methods of detecting continuity are better
than others, but the Supplementary Reference and FAQ Document is intended as a general aid to understanding the standard, and
not as a strict recommendation of particular maintenance methods. An entity can always do more, or more frequent maintenance
if they wish.
Southwest Power Pool
Reliability Standards
Development Team
Yes
1. On page 70 of the document we noticed that the word “reakers” was used and
would suggest this was intended to be “breakers”.
2. Also on page 81 of the document under the section of “My VRLA batteries have
multiple-cells within an individual battery jar (or unit); how am I expected to
comply with the cell-to-cell ohmic measurement requirements on these units that
I cannot get to?” We would suggest that the wording be changed on “in
Consideration of Comments: Project 2007-17
22
Organization
Yes or No
Question 3 Comment
accessible” to remove the space to give you “Inaccessible”.
Response: Thank you for your comments. Punctuation, spelling and content changes have been made to the Supplementary
Reference and FAQ Document.
Chris Searles
Yes
1. In Section 7.1-Frequently Asked Questions, pg 24 - add "or" before "other
measurements" inadvertently left out.
2. In Section 8.1.2.4 - 4th & 5th sentences. Consider changing the verbiage: "....The
Protection System owner may want to follow the guidelines in the applicable IEEE
recommended practices for battery maintenance and testing, especially if the
battery in question is used for application requirements in addition to the strict
protection and control demands covered under this standard."
3. In section 15.4.1 - (pg 74) "What is the State of Charge...." In the first paragraph
on page 74, the first complete sentence, I think the intent is to say "For these two
types of batteries, and also for VRLA batteries," . . .
Response: Thank you for your comments. Punctuation, spelling and content changes have been made to the Supplementary
Reference and FAQ Document.
ACES Standards Collaborators
Yes
We suggest that the document should clarify Table 1-4(f). We understand from
conversations with drafting team members that not all component attributes have to
be met for the exclusion to apply. Rather each component attribute only has to be
met individually for the exclusion to apply. We appreciate the drafting team
including the localized definitions in the supplementary reference document.
However, we believe there is still confusion with the use of component. Component
is capitalized within the definition but it is not capitalized throughout the document.
We believe the term should be capitalized throughout the document to be clear the
localized definition applies. Capitalization of most instances of “system” has been
correctly removed since the NERC definition was not consistent with the use.
However, there are a few instances where it was removed and should not have been.
One example occurs in the second paragraph on page 5 in the red-line document
Consideration of Comments: Project 2007-17
23
Organization
Yes or No
Question 3 Comment
where “system collapse” should be “System Collapse”. In the third paragraph on
page 5 in the red-line document, “transmission” should be capitalized since the NERC
definition would be applicable.
Response: Thank you for your comments. Punctuation, spelling and content changes including your suggestions for capitalization
have been made to the Supplementary Reference and FAQ Document. Based on your comment regarding Table 1-4(f), an
additional FAQ has been added to Section 15.4.1 of the Supplementary Reference and FAQ Document.
O&M Group
Yes
(1) We do not agree with no maintenance on the battery monitoring system
(2) Also, we do not agree with replacing a battery capacity test by evaluating cell/unit
measurements indicative of battery performance against station battery baseline.
Response: Thank you for your comments.
1.
Thank you for your comment concerning maintenance on the battery monitoring system. Based on comments concerning
the battery Component Attributes in table 1-4(f) a new Frequently Asked Question was added to the Supplementary Reference
and FAQ Document. As a part of that FAQ the drafting team gave rational why no maintenance on the battery monitoring system
is required by stating “the basis of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous self-monitoring. For failure of the
microprocessor device used in dc supply monitoring, the self-checking routine in the microprocessor must generate an alarm
which will be reported within 24 hours of device failure to a location where corrective action can be initiated.”
2.
Thank you for your comment concerning battery capacity testing. The drafting team agrees that a performance or modified
performance capacity test is the only industry recognized method for determining the actual capacity of a battery. However, the
maintenance activity required in the tables of PRC-005-2 is to “Verify that the station battery can perform as manufactured” not
to determine the capacity of the battery. For many of the lead acid batteries used in BES Protection Systems, the drafting team
believes that evaluating cell/unit measurements indicative of battery performance against a station battery baseline is as a valid
method of verifying “that the station battery can perform as manufactured.” That is why in Tables 1-4(a) and Tables 1-4(b)
owners are allowed to do either of the two listed maintenance activities in their appropriate maximum maintenance intervals to
“Verify that the station battery can perform as manufactured.”
Consideration of Comments: Project 2007-17
24
Organization
Yes or No
Western Area Power
Administration
Yes
Question 3 Comment
Yes. The standard itself should be more clearly written so that a 100+ page
Supplementary Reference and FAQ Document is not needed. This document is also
not enforceable, nor is it a standard, so verbiage which interprets the standard and
forces requirements should be removed.
Response: Thank you for your comments. This document provides supporting discussion, but is not part of the standard. The
drafting team intends that it be posted as a reference document, as expressed in Section F of the standard. The standard is to be
a terse statement of requirements, etc., and is not to include explanatory information like that included in the Supplementary
Reference and FAQ Document.
American Electric Power
Yes
On page 82, the text “in accessible” should be correct as “inaccessible”.
Response: Thank you for your comments. Punctuation, spelling and content changes have been made to the Supplementary
Reference and FAQ Document.
Manitoba Hydro
Yes
1. Table of Contents - The drawing should be removed from the Table of Contents.
2. Introduction and Summary: [Page 1] - Should include “Canada”. The sentence
should read “The standards are mandatory and enforceable in the United States
and Canada”.
3. Protection Systems Product Generations: [page 8] - We suggest changing "control
Systems" to "control systems".[Page 28]: “Voltage & Current Sensing Device ...”
should be “Voltage and current sensing device ...”[Page 29] "Control Circuit"
should not be capitalized.[Page 44] A space is missing: “performance formalperforming segments” should be “performance for mal-performing
segments”.[Page 45] "Other problems ..." ascribed to batteries may also apply to
other Protection System Components, and therefore does not require special
mention for batteries. This paragraph should be removed.
4. [Page 67]: Normally-open contacts of relays 94 & 86 should be treated the same
as the current-carrying contacts if they are in use.
Response: Thank you for your comments. Punctuation, spelling and content changes have been made to the Supplementary
Consideration of Comments: Project 2007-17
25
Organization
Yes or No
Question 3 Comment
Reference and FAQ Document. Based on your comment, “Canada” was added to the introductory sentence on page 1 of the
Supplementary Reference and FAQ Document. In the case of the normally-open contacts of the 94 and 86, entities may perform
more maintenance than is listed within the standard.
Tacoma Power
Yes
1. On page 88, third bullet, change “auxiliary communications equipment” to
“associated communications equipment” for consistency.
2. In Figure A-1, what is meant by “Also verify wiring and test switches”? The
emphasis of this question is on ‘test switches’.
Response: Thank you for your comments.
1. Punctuation, spelling and content changes have been made to the Supplementary Reference and FAQ Document.
2. The object of any test in any circuit that has test switches is the same as those tests in similar circuits without test switches.
There is no specific mandated test in the standard for “Test Switches,” but a test switch might well be a point of failure that
one needs to be aware of when performing the mandated routine tests.
Illinois Municipal Electric
Agency
Yes
Please see response to Question 4.
Response: Thank you for your comments.
Midtronics Inc
Yes
The paragraphs below are from page 83 of the document (page 89 of the pdf). The
first paragraph below contains the words, “risen above” and “over” a baseline. For
conductance trending would be going below a baseline. Since this is a technical
standard I think there should be a comment noting the difference in trending of
conductance as compared to resistance and impedance like it is in the next
paragraph.
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver
is for a means to trend battery life. Trending against the baseline of VRLA cells in a
battery string is essential to determine the approximate state of health of the
battery. Ohmic measurement testing may be used as the mechanism for measuring
Consideration of Comments: Project 2007-17
26
Organization
Yes or No
Question 3 Comment
the battery cells. If all the cells in the string exhibit a consistent trend line and that
trend line has not risen above a specific deviation (e.g. 30%) over baseline, then a
judgment can be made that the battery is still in a reasonably good state of health
and able to ‘perform as manufactured.’ It is essential that the specific deviation
mentioned above is based on data (test or otherwise) that correlates the ohmic
readings for a specific battery/tester combination to the health of the battery. This is
the intent of the “perform as manufactured six-month test” at Row 4 on Table 1-4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the
intent of the “thermal runaway test” at Row 2 on Table 1-4b. In order to detect a cell
in thermal runaway, you need not necessarily have a formal trending program. When
a single cell/unit changes significantly or significantly varies from the other cells (e.g.
a doubling of resistance/impedance or a 50% decrease in conductance), there is a
high probability that the cell/unit/string needs to be replaced as soon as possible. In
other words, if the battery is 10 years old and all the cells have approached a
significant change in ohmic values over baseline, then you have a battery which is
approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the
battery is five years old and you have one cell that has a markedly different ohmic
reading than all the other cells, then you need to be worried that this cell is in
thermal runaway and catastrophic failure is imminent.
Response: Thank you for your comments. Punctuation, spelling and content changes have been made to the Supplementary
Reference and FAQ Document. Based on your comment, the sentence was rewritten as follow: “If all the cells in the string exhibit
a consistent trend line and that trend line has not risen above a specific deviation (e.g. 30%) over baseline for impedance tests or
below baseline for conductance tests, then a judgment can be made that the battery is still in a reasonably good state of health
and able to ‘perform as manufactured.’”
Luminant
Yes
Southern Company
Yes
Consideration of Comments: Project 2007-17
27
4. If you have any other comments that you have NOT provided in response to the above questions, please provide them here.
(Please do not repeat comments that you provided elsewhere.)
Summary Consideration: Other than as noted below, no changes were made to the standard in response to comments in Question 4.
Commenters continued to object to Applicability 4.2.1 in contrast to the interpretation in PRC-005-1b. The drafting team explained
their position relative to this objection, and added discussion in Section 2.3.1 of the Supplementary Reference and FAQ Document to
further explain their position.
Several commenters objected to various VSLs, particularly as it relates to the Lower VSL for Requirement R3. The drafting team
explained that the VSLs are established in accordance with the VSL Guidelines. However, a minor editorial change was made to all
levels of VSL for Requirement R5.
Several commenters continued to object to inclusion of UFLS and UVLS relays, in that they may not be installed on BES equipment.
The drafting team responded that these devices, while not on BES equipment, are installed for the reliability of the BES, and are
therefore included. The drafting team further noted that these devices are currently addressed in PRC-008-0 and PRC-011-0.
Several commenters questioned the inclusion of breaker trip coil verification, auxiliary relay verification, and/or lockout relay
verification. The drafting team responded that each of these devices needs to be maintained at the prescribed intervals to assure
reliability.
A few comments were offered on unresolved maintenance issues, various aspects of battery maintenance, communications system
batteries, performance-based maintenance program criteria, and sudden pressure relay dc circuit testing. The drafting team
provided responses to each of these comments, explaining the importance of the requirements within the standard.
Organization
Yes or No
Consumers Energy
Question 4 Comment
1. We agree with the purpose in section 3 of the Standard. However, section 4.2.1
expands the scope from "affecting the reliability of the Bulk Electric System" to
"detecting Faults on BES Elements". In our opinion, the Applicability should be
limited to the stated Purpose. Expanding the scope as is done in 4.2.1 greatly
Consideration of Comments: Project 2007-17
28
Organization
Yes or No
Question 4 Comment
increases the number of Protection Systems covered without an increase in reliability
of the BES. We prefer the applicability as expressed in Appendix 1 of PRC-005-1b.
2. We suggest changing "Component Type" in R1.2 to something similar to "Segment"
as defined within the Standard. A "Component Type" limits to one of five categories,
whereas a "Segment" must share similar attributes.
Response: Thank you for your comments.
1. The drafting team believes the Applicability as stated in PRC-005-2 is correct and supports the reliability of the BES. The SDT
observes that the approved interpretation addresses the term, “transmission Protection System,” and notes that this term is
not used within PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically addresses: “Protection
Systems that are installed for the purpose of detecting faults on BES Elements.” The drafting team has added a discussion to
Section 2.3.1 of the Supplementary Reference and FAQ Document explaining their intent regarding the Applicability.
2. In the documentation to support Requirement R1.2, an entity can list different technologies within a Component Type along
with their respective monitoring attributes. The drafting team sees no appreciable improvement in the standard with your
proposed change, and respectfully declines to modify the standard.
Ameren
Ameren supports PRC-005-2 in the interest of BES reliability. We also appreciates
the SDT’s overall high quality product and looks forward to its implementation;
however, we still assert that
1) the zero tolerance approach, in this case involving significantly large number
(thousands) of devices, is an impractical requirement,
2) the VRF for R3 should be Medium, and
3) maintenance records for replaced equipment should not be retained. We’ have
raised these concerns and justified our position repeatedly but yet not convinced the
SDT to change their position.
Response: Thank you for your comments.
1.
The NERC VSL Guidelines do not allow some level of non-performance without being in violation.
Consideration of Comments: Project 2007-17
29
Organization
Yes or No
Question 4 Comment
2.
The drafting team believes that the assigned VRF is correct, in that that failure to implement and follow its PSMP could
cause or contribute to Bulk Electric System instability, separation, or a Cascading sequence of failures.
3. The drafting team believes the Compliance Monitor will need the data for the most recent performance of the maintenance,
as well as the data for the preceding maintenance period, to determine compliance. This seems to be consistent with what
auditors are expecting (per the drafting team’s experience), and is also consistent with Compliance Process Bulletins 2011-001 and
2009-05.
Florida Municipal Power
Agency
1. Applicability does not align with previously approved interpretation of
“transmission Protection System”, Appendix 1 of the current V1 standard, that
basically says that protection systems applicable to the standard are those that
both “detect faults” and “trip” BES equipment. Applicability 4.2.1 says:
“Protection Systems that are installed for the purpose of detecting Faults on BES
Elements”, which does not match “and” relationship of the interpretation.
Eliminating this “and” relationship will cause distribution protection to be swept
into the standards, such as reverse power relays designed to “detect” faults on
the transmission system but “trip” distribution breakers. Distribution is expressly
excluded in Section 215 and these types of relays have no impact on BES
reliability.
2. Zero defect approach, should move to what CIP v5 is moving towards of internal
controls rather than strict 100% compliance, or even better, a Total Quality
Management approach.
3. UFLS and UVLS testing - broaches on distribution which is expressly excluded from
Section 215 jurisdiction - when discussing control circuit testing, instrument
transformer testing, etc.. We believe the requirement should be relay-only
testing. We also believe that the incremental benefit is not worth the increased
costs, e.g., one UFLS relay not operating has insignificant impact on a UFLS event;
whereas one relay not operating to clear a fault has significant impact.
Response: Thank you for your comments.
1.
The drafting team believes the Applicability as stated in PRC-005-2 is correct and supports the reliability of the BES. The
Consideration of Comments: Project 2007-17
30
Organization
Yes or No
Question 4 Comment
drafting team observes that the approved interpretation addresses the term, “transmission Protection System,” and notes
that this term is not used within PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically
addresses: “Protection Systems that are installed for the purpose of detecting faults on BES Elements.” The drafting team has
added a discussion to Section 2.3.1 of the Supplementary Reference and FAQ Document explaining their intent regarding the
Applicability.
2.
The NERC VSL guidelines do not allow some level of non-performance without being in violation.
3.
FPA Section 215(a) definitions section defines bulk-power system as: “(A) facilities and control systems necessary for
operating an interconnected electric energy transmission network (or any portion thereof).” That definition then is limited by
a later statement which adds the term bulk-power System: “… does not include facilities used in the local distribution of
electric energy.” Also, Section 215 also covers users, owners, and operators of bulk-power facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage instability for BES reliability) are not
“used in the local distribution of electric energy,” despite their location on local distribution networks. Further, if UFLS/UVLS
facilities were not covered by the Reliability Standards, then in order to protect the integrity of the BES during underfrequency or under-voltage events, that load would have to be shed at the transmission bus to ensure the load-generation
balance and voltage stability is maintained on the BES.
Beaches Energy Services
1. Applicability does not align with previously approved interpretation of
“Transmission Protection System”, Appendix 1 of the current V1 standard, that
basically says that protection systems applicable to the standard are those that
both “detect faults” and “trip” BES equipment. Applicability 4.2.1 says:
“Protection Systems that are installed for the purpose of detecting Faults on BES
Elements”, which does not match “and” relationship of the interpretation.
Eliminating this “and” relationship will cause distribution protection to be swept
into the standards, such as reverse power relays designed to “detect” faults on
the transmission system but “trip” distribution breakers. Distribution is expressly
excluded in Section 215 and these types of relays have no impact on BES
reliability.
2. Zero defect approach, should move to what CIP v5 is moving towards of internal
controls rather than strict 100% compliance, or even better, a Total Quality
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Management approach.
3. UFLS and UVLS testing - broaches on distribution which is expressly excluded from
Section 215 jurisdiction - when discussing control circuit testing, instrument
transformer testing, etc.. We believe the requirement should be relay-only
testing. We also believe that the incremental benefit is not worth the increased
costs, e.g., one UFLS relay not operating has insignificant impact on a UFLS event;
whereas one relay not operating to clear a fault has significant impact.
Response: Thank you for your comments.
1.
The drafting team believes the Applicability as stated in PRC-005-2 is correct and supports the reliability of the BES. The
drafting team observes that the approved interpretation addresses the term, “transmission Protection System,” and notes
that this term is not used within PRC-005-2; thus, the interpretation does not apply to PRC-005-2. PRC-005-2 specifically
addresses: “Protection Systems that are installed for the purpose of detecting faults on BES Elements.” The drafting team has
added a discussion to Section 2.3.1 of the Supplementary Reference and FAQ Document explaining their intent regarding the
Applicability.
2.
The NERC VSL guidelines do not allow some level of non-performance without being in violation.
3.
FPA Section 215(a) definitions section defines bulk-power system as: “(A) facilities and control systems necessary for
operating an interconnected electric energy transmission network (or any portion thereof).” That definition then is limited by
a later statement which adds the term bulk-power system: “… does not include facilities used in the local distribution of
electric energy.” Also, Section 215 also covers users, owners, and operators of bulk-power facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage instability for BES reliability) are not
“used in the local distribution of electric energy,” despite their location on local distribution networks. Further, if UFLS/UVLS
facilities were not covered by the Reliability Standards, then in order to protect the integrity of the BES during underfrequency or under-voltage events, that load would have to be shed at the transmission bus to ensure the load-generation
balance and voltage stability is maintained on the BES.
Illinois Municipal Electric
Agency
As indicated in previous comments, Illinois Municipal Electric Agency (IMEA)
appreciates SDT efforts, and supports the overall refinements in PRC-005-2.
However, IMEA respectfully disagrees with the SDT’s decision to not resolve the
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inconsistency between 4.2.1 and the FERC-approved interpretation in PRC-005-1b.
Whether the term “transmission Protection System” is used in PRC-005-2, as
indicated in the SDT response to our comments, is not the point. The interpretation
in PRC-005-1b provides clarity to smaller entities in particular regarding which
protective devices need to be factored into compliance with PRC-005 (and other PRC
standards). This inconsistency should have been more clearly vetted within the
industry given the fact that this was a recently NERC- and FERC-approved Protection
System interpretation which was being compromised by the proposed language in
4.2.1. Once again, we find ourselves aiming at a constantly moving compliance
target. This issue has the potential to require more DPs to comply with PRC-005, and
draw more small entities into registration, which of course would require increased
resource expenditures associated with compliance. This issue does not appear to be
consistent with NERC and FERC efforts to minimize the impact on smaller entities that
have minimal or no potential to impact the BES. If the 4.2.1 language was carefully
considered so as not to unnecessarily impact small entities, it would be appreciated
that these provisions be more clearly addressed in the "Supplementary Reference
and FAQ". Thank you for this opportunity to comment. This issue is significant
enough that IMEA felt a Negative vote was unfortunately necessary on an otherwise
significant improvement to PRC-005.
Response: Thank you for your comments.
The drafting team believes that the Applicability 4.2.1 as stated in PRC-005-2 is correct and supports the reliability of the BES. The
drafting team believes all Protection Systems installed for the purpose of detecting faults on the BES need to be maintained per
the requirements of PRC-005-2. The drafting team observes that the approved Interpretation addresses the term, “transmission
Protection System,” and notes that this term is not used within PRC-005-2; thus, the Interpretation does not apply to PRC-005-2.
The drafting team has added a discussion to Section 2.3.1 of the Supplementary Reference and FAQ Document explaining their
intent regarding the Applicability.
American Transmission
Company
ATC recommends that the SDT change the text of “Standard PRC-005-2 - Protection
System Maintenance” Table 1-5 on page 24, Row 1, Column 3 to:”Verify that a trip
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coil is able to operate the circuit breaker, interrupting device, or mitigating device.”
Or alternately, “Electrically operate each interrupting device every 6 years”. Basis for
the change: Trip coils are designed to be energized no longer than the breaker
opening time (3-5 cycles). They are robust devices that will successfully operate the
breaker for 5,000-10,000 electrical operations. In addition, many utilities purchase
breakers with dual redundant trip coils to mitigate the possibility of a failure.
Interrupting devices with multiple trip coils operate the same mechanism. Therefore,
by requiring testing of each trip coil in a redundant system you double the amount of
times the system is out of its desired state without increasing the performance of the
device. It is well recognized that the most likely source of trip coil failure is the
breaker operating mechanism binding, thereby preventing the breaker auxiliary stack
from opening and keeping the trip coil energized for too long of a time period.
Therefore, trip coil failure is a function of the breaker mechanism failure. Exercising
the breakers and circuit switchers is an excellent practice to mitigate the most
prevalent cause of breaker failure. ATC would encourage language that would
suggest this task be done every 2 years, not to exceed 3 years. Exercising the
interrupting devices would help eliminate mechanism binding, reducing the chance
that the trip coils are energized too long. The language, as currently written in Table
1-5 row 1, will also have the unintentional effect of changing an entities existing
interrupting device maintenance interval (essentially driving interrupting device
testing to a less than 6 year cycle).ATC continues to recommend a negative ballot
since we believe that the testing of “each” trip coil will result in the increased amount
of time the BES is in a less intact system configuration. ATC hopes that the SDT will
consider these changes.
Response: Thank you for your comments. The definition of Protection System includes trip coils within the dc control circuitry
component, and it is necessary to perform maintenance on all of these devices to assure proper performance. Performance-based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
Bonneville Power
BPA appreciates that the Standards Development Team does not believe that
communications batteries are included in PRC-005-2 standard. While BPA believes
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the SDT did not intend to include communications batteries in the standard, this
intention is neither captured by the language of the standard nor explicit in the
Supplementary Reference and FAQ document. Ambiguity on regulation of
communications batteries provides no benefit and comprises a concrete regulatory
risk to BPA during an audit. BPA strongly believes that the standard should articulate
exactly what types and applications of batteries it means to regulate and which
batteries it does not.
Response: Thank you for your comments. The drafting team believes this issue is addressed in the response to FAQ: “Does this
standard refer to Station batteries or all batteries; for example, Communications Site Batteries?” in the Supplementary Reference
and FAQ Document.
CenterPoint Energy
CenterPoint Energy recommends that PRC-005-2 include a built-in tolerance and
move away from a zero-defect enforcement model. Achieving one-hundred percent
schedule and documentation compliance is negatively impacting resources on an
industry-wide basis for the sake of the “last one percent” and is not needed to
provide an adequate level of BES reliability. Entities should be allowed the
opportunity to correct minor deficiencies discovered in the program via customary
mitigation activities as part of an internal controls policy and good utility practice
instead of via the enforcement channel. One possible avenue for incorporating such a
tolerance into the Standard is to establish a threshold for the Lower VSL. For
example, the Lower VSL for requirement R3 could state: “For Protection System
Components included within a time-based maintenance program, the responsible
entity failed to maintain more than 1% but 5% or less of the total Components
included within a specific Protection System Component type in accordance with the
minimum maintenance activities and maximum maintenance intervals prescribed
within Tables 1-1 through 1-5, Table 2, and Table 3.”.
Response: Thank you for your comments. The drafting team believes that the assigned VSLs are correct. The SDT believes that
failure to implement and follow a PSMP could cause or contribute to Bulk Electric System instability, separation, or a Cascading
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sequence of failures. Anything less than 100% should be a violation.
NIPSCO
Comment: Test and maintenance data requirements need to be specific and not
open to interpretation. Examples: 1. The number of data points required on an
impedance circle graph for a relay calibration versus maximum torque angle only.2.
Verification of inputs into microprocessor relay records to include magnitude or is a
check box sufficient.
Response: Thank you for your comments. The drafting team believes it has struck the appropriate balance in affording some
freedom in applying the standard by Transmission Owners, while minimizing the possibility of adverse auditing interpretations.
Duke Energy
Duke Energy votes “Negative” because we strongly object to the wording in the
Applicability section 4.2.1 which expands the reach of the standard to relaying
schemes that detect faults on the BES but which are not intended to provide
protection for the BES. Duke Energy’s standard protection scheme for dispersed
generation at retail stations would become subject to the standard due to the
changes in section 4.2.1. These protection schemes are designed to detect faults on
the BES, but do not operate BES elements nor do they interrupt network current flow
from the BES. The new wording in section 4.2.1 would add significant O&M costs and
resource constraints due to the inclusion of protection system devices at retail
stations without increasing the reliability of the BES. FERC’s September 26, 2011
Order in Docket No. RD11-5 approved NERC’s interpretation of PRC-005-1 R1 and R2,
stating: “The interpretation clarifies that the Requirements are “applicable to any
Protection System that is installed for the purpose of detecting faults on transmission
elements (lines, buses, transformers, etc.) identified as being included in the [BES]
and trips an interrupting device that interrupts current supplied directly from the
BES.” This interpretation is consistent with the Commission’s understanding that a
“transmission Protection System” is installed for the purpose of detecting and
isolating faults affecting the reliability of the bulk electric system through the use of
current interrupting devices.” Duke Energy proposes the following wording for
Section 4.2.1: “Protection Systems that are installed for the purpose of protecting BES
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Elements (lines, buses, transformers, etc.)”.
Response: Thank you for your comments. The drafting team still believes that the Applicability as stated in PRC-005-2 is correct,
that it supports the reliability of the BES, and that all Protection Systems installed for the purpose of detecting faults on the BES
need to be maintained per the requirements of PRC-005-2. The drafting team observes that the approved Interpretation
addresses the term, “transmission Protection System,” and notes that this term is not used within PRC-005-2; thus, the
Interpretation does not apply to PRC-005-2. Please see Section 2.3 of the Supplementary Reference and FAQ Document for
additional discussion.
Nebraska Public Power District
1. Keeping records after the end of the audit period does not increase the current
reliability of the electric grid. Requiring records to be kept for longer time periods
will increase the risk to utilities of making a mistake in their record keeping and
receiving a fine due to the zero tolerance policy drafted in the standard. Records
beyond the audit period, up to 24 years old, don’t have any effect on the
reliability of the current bulk electric system.
2. A key concern is will the reliability of the bulk electric system be affected
negatively due to increased risk from human element initiated events as a result
of the more frequent functional trip checks that will be required. I suggest there
be consideration that the interval for functional tests be moved to the minimum
frequency of 12 years to minimize this unknown but present risk.
3. We recommend removing requirement 5. This is adding the requirement for a
corrective action program to the standard. Performance metrics should be
utilized to measure if a registered entity is correcting maintenance deficiencies in
a timely manner. Examples of performance metrics include:-A Countable event
has already been defined in the definition of terms, which would cover the need
to replace equipment. -The quantity and causes of Misoperations are a direct
correlation to good or poor maintenance practices and corrective actions by a
utility. -TADS records events which are initiated by failed protection system
equipment and would identify utilities with poor corrective action processes.
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Response: Thank you for your comments.
1. In order that a Compliance Monitor can be assured of compliance, the drafting team believes that the Compliance Monitor
will need the data of the most recent performance of the maintenance, as well as the data of the preceding one to validate
that entities have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The
drafting team has specified the data retention in the posted standard to establish this level of documentation. This seems to
be consistent with what auditors are expecting (per the drafting team’s experience), and is also consistent with Compliance
Process Bulletins 2011-001 and 2009-05. The entity is urged to assure that data is retained as specified within the standard.
2. The drafting team believes that performing these maintenance activities at the specified intervals will benefit the reliability
of the BES. The standard does not specify “functional trip tests,” but instead requires that various elements of the dc control
circuit be verified at various intervals.
3. The drafting team respectfully disagrees:
it’s the drafting team believes that returning Protection System devices to good working order exists currently as a required
element of a sound maintenance program subject to the existing Protection System maintenance and testing standard, PRC005-1. For reference, NERC Compliance Application Notice CAN-0043 (Posted Final 12/30/2011) directs Compliance
Enforcement Authorities (CEAs) to “…look for relay test results or field records with annotations such as “as-found” readings
or pass/fail results; if failed, then adjustments made. The maintenance record for adjustments may be requested”.
Management of completion of the identified unresolved maintenance issue is a complex topic that falls outside of the scope
of this standard. There can be any number of supply, process and management problems that make setting repair deadlines
impossible. The drafting team specifically chose the phrase: “… demonstrate efforts to correct” (with guidance from NERC
Staff) because of the concern that many more complex unresolved maintenance issues might require greater than the
remaining maintenance interval to resolve (and yet still be a “closed-end process”). For example, a problem might be
identified on a VRLA battery during a six-month check. In instances such as one that requires battery replacement as part of
the long term resolution, it is highly unlikely that the battery could be replaced in time to meet the six-calendar-month
requirement for this maintenance activity. The drafting team does believe corrective actions should be timely, but concludes
it would be impossible to postulate all possible remediation projects; and, therefore, impossible to specify bounding time
frames for resolution of all possible unresolved maintenance issues or what documentation might be sufficient to provide
proof that effective corrective action is being undertaken.
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Manitoba Hydro
Question 4 Comment
1. Manitoba Hydro is maintaining our negative vote based on our previously
submitted comments (see comments submitted in the comment period ending on
March 28th, 2012.
2. Additionally, Standard PRC-005-2:R3: "minimum maintenance activities" is not
specified in the Tables. We suggest removing the word "minimum".
3. R5: It is not clearly stated that the Unresolved Maintenance issues must be
identified. As written, only "identified Unresolved Maintenance Issues" are
applicable in R5.
4. Measure M1: “responsible entity(s)” is not defined in the standard. The format of
examples is inconsistent with the other measures. We suggest replacing "... (such
as ... drawings) ..." with "The evidence may include, but is not limited to,
manufacturer's specifications or engineering drawings. ...".
5. Evidence Retention: There is no statement in either the requirements or the
measures regarding a "dated" PSMP.
6. VSL:
a. R3 - "minimum maintenance activities" is not specified in the Tables. We
suggest removing the word "minimum".
b. R5 - We suggest "identified Unresolved Maintenance Issues" to agree with
the wording in R5.
7. Table 1.1: The Maintenance Activities statement "For all unmonitored relays:" is
redundant since it is specified in the Component Attributes.
8. Table 3: Voltage and current sensing devices for UFLS or UVLS should be excluded
from periodic maintenance if they are connected to microprocessors relays with
AC measurements continuously verified with alarming, as provided for voltage
and current sensing devices in Table 1-3.
9. The wording "Protection System dc supply for tripping non-BES interrupting
devices used only for a UFLS or UVLS system" is unclear. It is unclear if "used only
for a UFLS or UVLS system" applies to the "Protection System dc supply" or to the
"non-BES interrupting devices". Exclusions in Table 1-4(f) which pertain to
verifying dc supply voltage should also apply to the dc supply in Table 3.
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10. Attachment A
a. To maintain the technical justification Item 5: for consistency with Item 4
and the VSL, we suggest changing the wording to “If the Components in a
Protection System Segment maintained through a performance-based
PSMP experience more than 4% Countable Events, develop, document,
and implement an action plan to reduce the Countable Events to no more
than 4% of the Segment population within 3 years.
b. "Technical Justification: "Other problems ..." [page 7] ascribed to batteries
may also apply to other Components, and therefore does not require
special mention for batteries. This paragraph should be removed.
c. Pages 12 to 13 - The numbering should agree with the standard.
d. Item 10 [page 13] - For consistency with the previous item and the VSL, we
suggest changing the wording to "If the Components in a Protection
System Segment maintained through a performance-based PSMP
experience more than 4% Countable Events, develop, document, and
implement an action plan to reduce the Countable Events to no more than
4% of the Segment population within 3 years."
11. The bullet “All of the relevant communication system tests still apply” was added
in examples 1 and 2 on pages 68 and 69 of the Supplementary Reference and FAQ
- Draft PRC0005-2 Protection System Maintenance (JULY 2012) document
(SRFAQ). This makes reference to Table 3 (page 26) of the Standard, but Table 3
does not identify communication systems as a Component Attribute. Table 1-2
(Communications Systems) on page 14 of the standard also excludes the UFLS and
UVLS equipment on Table 3. Section 15.7, page 91, of the SRFAQ document also
states “No maintenance activity is required for associated communication
systems for distributed UFLS and distributed UVLS schemes”. I believe that since
no communications systems has been identified in Table 3, this bullet cannot be
added to the examples identified above in the SRFAQ document.
12. Implementation Plan: Should entities be given a single compliance date for each
of the maintenance intervals, and be allowed the flexibility to schedule and
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complete their maintenance as required while transitioning to the defined time
intervals in PRC-002-2. For example, if a maximum maintenance interval is 6
calendar years, should the implementation plan only require that “The entity shall
be 100% compliant on the first day of the first calendar quarter 84 months
following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 96
months following Board of Trustees adoption.”? The existing standard PRC-005-1
already requires protection systems to be maintained as part of a program.
Prescribing how an entity must reach full compliance may provide a negligible
improvement in reliability, while significantly increasing the compliance burden.
PRC-005-2 affects a large number of assets, and proving compliance for
prescribed percentages of assets during the transition period may create
unnecessary overhead with little added value.
Response: Thank you for your comments.
1. The drafting team has not changed its position from that expressed in response to the earlier comments.
2. Requirement R3 establishes that the maintenance activities specified in the Table are minimum maintenance activities.
3. The drafting team believes it is implicit that Unresolved Maintenance issues must be identified.
4. The term, “responsible entities” is used throughout NERC standards, and pertains to the applicable entities specified in a
particular requirement. The drafting team suggests that the evidence for Measure M1 is sufficiently variable that the term
“may include but is not limited to” would not be appropriate.
5. The drafting team believes it is self-evident that compliance documents must be dated in order that the time period to which
they apply is clear.
6. Requirement R3 establishes that the maintenance activities specified in the Table are minimum maintenance activities, and
therefore apply to the related VSL. The drafting team has added “identified” to the Requirement R5 VSL table.
7. The drafting team believes that the word “unmonitored” is still required for clarity in Table 1-1.
8. The drafting team observes that the third row of Table 3 (protective relays) addresses your suggestion.
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9. The drafting team believes that the wording in Table 3, third row of component attributes is clear and is applicable only to dc
supplies used for distributed UFLS and distributed UVLS systems.
10. The drafting team does not believe that your suggested changes improve the standard and declines to make the changes.
11. The drafting team has modified the Supplementary Reference and FAQ Document to remove the reference to the
communication system in these two locations.
12. The drafting team believes that implementation of the standard according to the milestones established within the
Implementation Plan is necessary to establish an effective ongoing Protection System Maintenance Program and to
demonstrate a commitment to implementing the new standard.
Dominion
Page 11 of the PRC-005-2 redline standard, Version History; Previous versions (i.e. 0,
1, 1a, 1b) need to be included here.
Response: Thank you for your comments. The Version History is intended to capture changes between the last-approved version
of the standard and the new standard being proposed.
ReliabilityFirst
ReliabilityFirst thanks the SDT for changing the maximum time for unmonitored
systems within Table 1-2 back to six years.
However, RFC continues to believe the language in Requirement R5 (“...shall
demonstrate efforts to correct...”) is subjective and will be hard to measure. RFC
believes at a minimum, the applicable entity should be required to develop a
Corrective Action Plan to address the Unresolved Maintenance Issue. Without
the formality and burden of a full-fledged Corrective Action Plan, ReliabilityFirst is
concerned the identified Unresolved Maintenance Issues may not get resolved or
resolved in a timely manner. ReliabilityFirst offers the following modification for
consideration: “Each Transmission Owner, Generator Owner, and Distribution
Provider shall put in place a Corrective Action Plan to remedy all identified
Unresolved Maintenance Issues.”
Response: Thank you for your comments. As to demonstrating efforts to address Unresolved Maintenance Issues, the drafting
team’s intent is to furnish a way for an entity to address Unresolved Maintenance Issues without the formality and burden of a
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full-fledged Corrective Action Plan.
Puget Sound Energy
1. Sealed Battery Maintenance: The requirement of impedance testing the batteries
every 6 months seems excessive based on our experience. We have been
successfully maintaining our sealed cells with impedance testing at 36 months.
2. CT testing on Neutrals: The requirement to verify operation is not possible on the
Neutral CT as they don’t normally carry current. There should be a clarification
that verification of readings can only occur (and is only required) on phase CT’s
and the neutral CT is excluded.
3. Dual Trip Coil Check: In our experience the requirement to verify operation of
both trip coils through a trip is overly burdensome and does not improve the
reliability of the system. Testing to verify operation of the output relays, proper
tripping of the breaker, and verification of trip coil continuity is sufficient to verify
the protective system will operate appropriately.
4. Breaker Failure Relay Testing: In our experience testing of the breaker failure
relay up to the relay outputs is sufficient to ensure proper operation. The tripping
of the breakers through the coils is maintained through the individual relay
maintenance. Requiring clearing of the main bus during maintenance is not
practical and may negatively impact the reliability of the Bulk Electric System.
Response: Thank you for your comments.
1. The drafting team believes that the six-month interval is proper for VRLA batteries.
2. See discussion in Section 8.1.3 of the Supplementary Reference and FAQ Document.
3. The definition of Protection System includes trip coils within the dc control circuitry component, and it is necessary to perform
maintenance on all of these devices to assure proper performance. Performance-based maintenance is an option to increase
the intervals if the performance of these devices supports those intervals.
4. The standard does not require that the bus be cleared for breaker failure relay testing, but does require that the circuitry from
the output of breaker failure relays be verified to the intended target (trip coil, lockout relay coil, input to another relay, etc).
The use of test switches or trip cutout switches may be used to break the control circuit into manageable portions so the
circuitry can be verified using overlapping zones without necessitating that all associated breakers be tripped for each
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maintenance activity.
ACES Standards Collaborators
The drafting team has done an outstanding job refining the standard. Because no
standard will ever be perfect, we believe industry and reliability would be best served
to move the standard to recirculation ballot at this point. Regarding Requirement R1
VSLs, we continue to believe that missing three component types should not jump to
a Severe VSL when missing two is a Moderate VSL. Missing three should be a High
VSL.
Response: Thank you for your response.
The drafting team believes that missing three Protection System component types (out of five) meets the definition of a Severe
VLS in the VSL Guidelines.
City of Palo Alto
These comments supercede the comments submitted earlier by Tom Finch by
mistake.
Attachment A "Criteria for a Performance-Based Protection System Maintenance
Program" requires a minimum segment population of 60 Components in order to
justify a PSMP. We feel the 60 component requirement is arbitrary and discriminates
against small entities such as Palo Alto which do not have 60 components and may
wish to implement a performance-based PSMP. We feel the decision on whether to
use a time-based or performance-based PSMP should be made by the Entity and not
NERC.
Response: Thank you for your comment. The minimum population of 60 components, as described in Section 9.1 of the
Supplemental Reference and FAQ Document, is a statistically-significant sample size to meet the performance goals of the
performance-based maintenance program. Section 9.2 of the Supplemental Reference and FAQ Document suggests that small
entities may be able to pool their component populations with other small entities to establish a common performance-based
maintenance program.
Tennessee Valley Authority
TVA appreciates the work that the standard drafting team has done on PRC-005-2.
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As stated in our comments on Draft 3, TVA is concerned with the maximum
maintenance interval of 4 calendar months specified for unmonitored
communications systems in Table 1-2, and for that reason has voted negative. A
longer implementation timeframe is needed for replacement of the unmonitored
units.
Response: Thank you for your comments. The drafting team suggests that performance-based maintenance is an option to
increase the intervals if the performance of these devices supports those intervals. If an entity’s experience is that these
components require less-frequent maintenance, a performance-based program in accordance with Requirement R2 and
Attachment A is an option.
Southwest Power Pool
Reliability Standards
Development Team
We have a concern that the RE would have difficulty in implementation of the phased
in approach. We would suggest extensive training for the auditors for this standard
and others which have these multi phased approaches to implementation. With this
training it would also be beneficial if NERC would hold a webinar to fill in the industry
on the training provided to keep everyone on the same page. We would like to also
suggest that NERC compliance staff work with the Drafting Team to develop the
RSAWs for this standard.
Response: Thank you for your comments. The drafting team believes that implementation of the standard according to the
milestones established within the Implementation Plan is necessary to establish an effective ongoing Protection System
Maintenance Program and to demonstrate a commitment to implementing the new standard. The drafting team will pass your
suggestion for auditor training and webinar on to NERC Compliance staff. The current NERC RSAW development process
encourages that NERC staff involve drafting team representatives when developing RSAWs.
Southern Company
We strongly suggest that the SDT modify the Applicability section to clarify that
Sections 4.2.1 thru 4.2.4 apply to transmission and distribution facilities, and that
Section 4.2.5 defines the generator owner applicability by making changes similar to
these proposed below. Without this distinctive change, there exists an ability to misinterpret Section 4.2.1 such that auditors may apply this standard to a generation
scope wider than is specified in the NERC Statement of Registry Criteria (Rev 5). We
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propose the following changes to 4.2.1 thru 4.2.4:1) Replace the existing 4.2.1 with
“Protection Systems for transmission and distribution Facilities, including:”2) Move
the existing 4.2.1 thru 4.2.4 to subparts of the new 4.2.1 as 4.2.1.1, 4.2.1.2, 4.2.1.3,
4.2.1.4.
Response: Thank you for your comments.
Protection Systems that are installed in non-BES facilities for the purpose of detecting faults on the BES are included in this
standard. The drafting team intends that Applicability 4.2.1 address non- generator BES elements. The drafting team has added a
discussion to Section 2.3.1 of the Supplementary Reference and FAQ Document explaining their intent regarding the Applicability.
Western Area Power
Administration
Western feels that our comments and concerns as provided on the previous
comment form were not adequately addressed. Those comments are repeated
below:
1. Western Area Power Administration is appreciative of the hard work done by the
SDT and NERC. We respectfully submit our professional opinion that the
increased relay testing required by the PRC-005-2 will result in a net degradation
to the reliability of the BES due to human hands disturbing working systems. We
propose that auxiliary relays be tested at commissioning and anytime the circuits
are rewired or redesigned. If there is evidence that the relay has functioned
properly in its current configuration then the best practice for ensuring reliability
is to leave it alone.
2. The maintenance interval of 6 years for lock-out relay testing is not consistent
with 12 year interval of auxiliary relay testing or control circuit testing. No
justification is provided for this increased testing interval of lock-out relays versus
other electro-mechanical devices. These inconsistent testing intervals, within the
same protection control schemes and protective devices, will complicate the
industry's Protection System Maintenance Program and cause an increase in
maintenance costs. Condition Based Monitoring or Performance Based
Monitoring are not allowed on trip coil circuits or lock-out relays. This is
inconsistent with current or future technology. Deviation from the 6 year testing
Consideration of Comments: Project 2007-17
46
Organization
Yes or No
Question 4 Comment
interval should be allowed, using CBM or PBM. The Standard should not present a
barrier to technology advancements or industry initiatives. The continuous,
frequent testing of these devices is detrimental to system reliability.
3. Disagree with testing of the dc control portion of the sudden pressure device as
defined by the FAQ. We feel that this device and its wiring were deemed out of
scope previously. Do not use the FAQ to modify the standard. The FAQ should
strictly be used for clarification only. A standard that relies on a lengthy FAQ and
multiple CAN's needs to be re-written concisely and clearly.
Response: Thank you for your comments
1. The drafting team recognizes the risk of human error trips when performing maintenance but believes these risks can be
managed. Auxiliary relays must be maintained every 12 years, and may be included within the 12-year unmonitored control
circuitry verification. Performance-based maintenance is an option if you want to extend your intervals beyond 12 years.
2. The drafting team believes that electromechanical lockout relays need periodic operation and that they need to be exercised
at the same six-year interval required for electromechanical relays. Performance-based maintenance is an option if you want
to extend your intervals beyond six years.
3. The need to verify the path from the sudden pressure relay trip contact through the auxiliary seal in and through to the
lockout relay coil is clearly within the scope of PRC-005-2 as part of the Protection System control circuitry. The sensing
element is omitted from PRC-005-2 testing requirements because the drafting team is unaware of industry-recognized
activities or intervals for the sensing elements. The drafting team believes that Protection Systems that trip (or can trip) the
BES should be included. This position is consistent with the currently-approved PRC-005-1b and consistent with the SAR for
Project 2007-17. However, a future revision of PRC-005 will likely add sudden pressure relays in response to directives from
FERC Order 758. The Supplementary Reference and FAQ Document provides supporting discussion and clarification but does
not modify the standard in any way. The standard is drafted such that the requirements are fully stated; however, the entire
field of maintenance of Protection Systems is sufficiently complex that that the drafting team has provided the Supplementary
Reference and FAQ Document to share effective methods of meeting the requirements (as anticipated by the drafting team)
and to share the drafting team’s rationale in establishing the required maximum intervals and minimum activities.
O&M Group
None
Consideration of Comments: Project 2007-17
47
Organization
Yes or No
Idaho Power Company
Question 4 Comment
None
END OF REPORT
Consideration of Comments: Project 2007-17
48
Exhibit I
Discussion of Assignments of VRFs and VSLs
Project 2007-17 – PRC-005-2
Protection System Maintenance
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in PRC-005-2 — Protection System
Maintenance.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements
support the determination of an initial value range for the Base Penalty Amount regarding
violations of requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction
Guidelines.
The Protection System Maintenance and Testing Standard Drafting Team applied the following
NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this
project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of a medium risk requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations,
directly and adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. However, violation of a
medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading
failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability
Standards in these identified areas appropriately reflect their historical critical impact on the
reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor
assignments and the main Requirement Violation Risk Factor assignment.
Project 2007-17 – PRC-005-2: Protection System Maintenance
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2
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements
that address similar reliability goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5.
The team did not address Guideline 1 directly because of an apparent conflict between Guidelines
1 and 4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within
NERC’s Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the
requirements.
PRC-005-2 Protection System Maintenance is a revision of PRC-005-1a Transmission and
Generation Protection System Maintenance and Testing with the stated purpose: To document
and implement programs for the maintenance of all Protection Systems affecting the reliability of
the Bulk Electric System (BES) so that these Protection Systems are kept in working order. PRC008-0 Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program, PRC-011-0 Undervoltage Load Shedding System Maintenance and Testing
and PRC-017-0 Special Protection System Maintenance and Testing are also being replaced by
merging them into PRC-005-2 in accordance with suggestions from FERC Order 693. PRC-005-2
also establishes maximum allowable maintenance intervals as directed by FERC in Order 693 in
their discussion of the legacy standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0.
PRC-005-2 has five (5) requirements that incorporate and enhance the intent of the requirements
of PRC-005-1a, PRC-008-0, PRC-011-0, and PRC-017-0. Several Tables of minimum maintenance
activities and maximum maintenance intervals are also included to addresses FERC’s directives
from Order 693. The revised standard requires that entities develop an appropriate Protection
System Maintenance Program (PSMP), that they implement their PSMP, and that, in the event
they are unable to restore Protection System Components to proper working order while
performing maintenance, they initiate the follow-up activities necessary to resolve those
maintenance issues.
The requirements of PRC-005-2 do not map, one-to-one, with the requirements of the legacy
standards, each of which comingle various attributes addressed within the new standard; thus, a
requirement-to-requirement comparison of VRFs is irrelevant. When developing VRFs for the
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
3
requirements of PRC-005-2, the Standard Drafting Team carefully considered the NERC criteria for
developing VRFs, as well as the FERC VRF guidelines. Therefore, PRC-005-2 Requirements R3 and
R4 are assigned a VRF of High, while Requirements R1, R2, and R5 are assigned VRFs of Medium.
PRC-005-2 Requirements R1 and R2 are related to developing and documenting a Protection
System Maintenance Program. The Standard Drafting Team determined that the assignment of a
VRF of Medium was consistent with the NERC criteria that violations of these requirements could
directly affect the electrical state or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but are unlikely to lead to bulk electric
system instability, separation, or cascading failures. Additionally, a review of the body of existing
NERC Standards with approved VRFs revealed that requirements with similar reliability objectives
in other standards are largely assigned a VRF of Medium.
PRC-005-2 Requirements R3 and R4 are related to implementation of the Protection System
Maintenance Program. The SDT determined that the assignment of a VRF of High was consistent
with the NERC criteria that that violation of these requirements could directly cause or contribute
to bulk electric system instability, separation, or a cascading sequence of failures, or could place
the bulk electric system at an unacceptable risk of instability, separation, or cascading failures.
Additionally, a review of the body of existing NERC Standards with approved VRFs revealed that
requirements with similar reliability objectives in other standards are assigned a VRF of High.
PRC-005-2 Requirement R5 relates to the initiation of resolution of unresolved maintenance
issues, which describe situations where an entity was unable to restore a Component to proper
working order during the performance of the maintenance activity. The Standard Drafting Team
determined that the assignment of a VRF of Medium was consistent with the NERC criteria that
violation of this requirements could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system but are
unlikely to lead to bulk electric system instability, separation, or cascading failures. Additionally, a
review of the body of existing NERC Standards with approved VRFs revealed that requirements
with similar reliability objectives in other standards are largely assigned a VRF of Medium.
Project 2007-17 – PRC-005-2: Protection System Maintenance
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4
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have
at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or a
small percentage) of the
required performance
The performance or product
measured has significant value
as it almost meets the full
intent of the requirement.
Moderate
Missing at least one significant
element (or a moderate
percentage) of the required
performance.
The performance or product
measured still has significant
value in meeting the intent of
the requirement.
Project 2007-17 – PRC-005-2: Protection System Maintenance
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High
Severe
Missing more than one
significant element (or is missing
a high percentage) of the
required performance or is
missing a single vital
Component.
The performance or product has
limited value in meeting the
intent of the requirement.
Missing most or all of the
significant elements (or a
significant percentage) of the
required performance.
The performance measured
does not meet the intent of the
requirement or the product
delivered cannot be used in
meeting the intent of the
requirement.
5
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining whether to
approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level of
compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of
Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
Project 2007-17 – PRC-005-2: Protection System Maintenance
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6
VRF and VSL Justifications
VRF and VSL Justifications – PRC-005-2, R1
Proposed VRF
Medium
NERC VRF Discussion
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal-performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no sub-requirements so only one VRF was assigned. The requirement utilizes Parts to
identify the items to be included within a Protection System Maintenance Program. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC-008-3 Requirement R2 and FAC-013-2 Requirement R1, which are similar in nature to PRC005-2 Requirement R1.
Project 2007-17 – PRC-005-2: Protection System Maintenance
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7
VRF and VSL Justifications – PRC-005-2, R1
Proposed VRF
Medium
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal-performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF..
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-2, R1
Lower
The responsible entity’s PSMP
failed to specify whether one
Component Type is being
addressed by time-based or
performance-based
maintenance, or a
combination of both. (Part 1.1)
Moderate
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based
maintenance, or a combination
of both. (Part 1.1)
Project 2007-17 – PRC-005-2: Protection System Maintenance
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High
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to
each Protection System
Component Type consistent with
the maintenance intervals
specified in Tables 1-1 through 1-
Severe
The responsible entity failed to
establish a PSMP.
OR
The responsible entity failed to
specify whether three or more
Component Types are being
8
Proposed VSL – PRC-005-2, R1
Lower
Moderate
OR
The responsible entity’s PSMP
failed to include applicable
station batteries in a timebased program (Part 1.1)
Project 2007-17 – PRC-005-2: Protection System Maintenance
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High
Severe
5, Table 2, and Table 3 where
monitoring is used to extend the
maintenance intervals beyond
those specified for unmonitored
Protection System Components
(Part 1.2).
addressed by time-based or
performance-based maintenance,
or a combination of both. (Part
1.1).
9
VRF and VSL Justifications – PRC-005-2, R1
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards being
replaced by this proposed standard.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and consistency
in the determination of similar penalties for similar violations.
Project 2007-17 – PRC-005-2: Protection System Maintenance
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10
VRF and VSL Justifications – PRC-005-2, R1
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
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VRF and VSL Justifications – PRC-005-2, R2
Proposed VRF
Medium
NERC VRF Discussion
Failure to properly establish a performance-based Protection System Maintenance Program (PSMP) for
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal-performing Protection System
Components. Failure to properly establish a performance-based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC-008-3 Requirement R2 and FAC-013-2 Requirement R1, which are similar in nature to
PRC-005-2 Requirement R1.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to properly establish a performance-based Protection System Maintenance Program (PSMP) for .
FERC VRF G4 Discussion
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VRF and VSL Justifications – PRC-005-2, R2
Proposed VRF
FERC VRF G5 Discussion
Medium
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal-performing Protection System
Components. Failure to properly establish a performance-based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-2, R2
Lower
The responsible entity uses
performance-based
maintenance intervals in its
PSMP but failed to reduce
Countable Events to no more
than 4% within three years.
Moderate
N/A
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High
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no
more than 4% within four years.
Severe
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1)Failed to establish the
technical justification described
within Requirement R2 for the
initial use of the performancebased PSMP
13
Proposed VSL – PRC-005-2, R2
Lower
Moderate
High
Severe
OR
2) Failed to reduce countable
events to no more than 4% within
five years
OR
3) Maintained a segment with less
than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater of
5% of the segment population
or 3 Components,
OR
• Annually analyze the program
activities and results for each
segment.
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14
VRF and VSL Justifications – PRC-005-2, R2
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
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VRF and VSL Justifications – PRC-005-2, R2
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
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VRF and VSL Justifications – PRC-005-2, R3
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
Guideline 3- Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
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Proposed VSL – PRC-005-2, R3
Lower
Moderate
High
Severe
For Protection System
Components included within a
time-based maintenance
program, the responsible entity
failed to maintain 5% or less of
the total Components included
within a specific Protection
System Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1-1 through 1-5, Table 2,
and Table 3.
For Protection System
Components included within a
time-based maintenance
program, the responsible entity
failed to maintain more than
5% but 10% or less of the total
Components included within a
specific Protection System
Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1-1 through 1-5, Table 2,
and Table 3.
For Protection System
Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15%
or less of the total Components
included within a specific
Protection System Component
Type, in accordance with the
minimum maintenance activities
and maximum maintenance
intervals prescribed within Tables
1-1 through 1-5, Table 2, and Table
3.
For Protection System
Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the
total Components included within
a specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3.
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
18
VRF and VSL Justificati3ons – PRC-005-2, R3
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
19
VRF and VSL Justifications – PRC-005-2, R3
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
20
VRF and VSL Justifications – PRC-005-2, R4
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
Guideline 3- Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
21
Proposed VSL – PRC-005-2, R4
Lower
Moderate
For Protection System
Components included within a
performance-based
maintenance program, the
responsible entity failed to
maintain 5% or less of the
annual scheduled maintenance
for a specific Protection System
Component Type in accordance
with their performance-based
PSMP.
For Protection System
Components included within a
performance-based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the annual
scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
High
For Protection System
Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
Severe
For Protection System
Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Protection System Component
Type in accordance with their
performance-based PSMP.
22
VRF and VSL Justifications – PRC-005-2, R4
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
23
VRF and VSL Justifications – PRC-005-2, R4
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
24
VRF and VSL Justifications – PRC-005-2, R5
Proposed VRF
Medium
NERC VRF Discussion
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system. However, violation of
this requirement is unlikely to lead to bulk power system instability, separation, or cascading failures. The
applicable entities are always responsible for maintaining the reliability of the bulk power system
regardless of the situation. This VRF emphasizes the risk to system performance that results from malperforming Protection System Components. Failure to initiate resolution of an unresolved maintenance
issue for a Protection System Component will not, by itself, lead to instability, separation, or cascading
failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
Guideline 3- Consistency among Reliability Standards:
The only requirement within approved Standards, PRC-004-2a Requirements R1 and R2 contain a similar
requirement and is assigned a HIGH VRF. However, these requirements contain several subparts, and the
VRF must address the most egregious risk related to these subparts, and a comparison to these
requirements may be irrelevant. PRC-022-1 Requirement R1.5 contains only a similar requirement, and is
assigned a MEDIUM VRF. FAC-003-2 Requirement R5 contains only a similar requirement, and is assigned
a MEDIUM VRF.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
25
VRF and VSL Justifications – PRC-005-2, R5
Proposed VRF
FERC VRF G5 Discussion
Medium
However, violation of this requirement is unlikely to lead to bulk power system instability, separation, or
cascading failures. The applicable entities are always responsible for maintaining the reliability of the bulk
power system regardless of the situation. This VRF emphasizes the risk to system performance that results
from mal-performing Protection System Components. Failure to initiate resolution of an unresolved
maintenance issue for a Protection System Component will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-2, R5
Lower
Moderate
The responsible entity failed to
undertake efforts to correct 5
or fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct
greater than 5, but less than or
equal to 10 identified
Unresolved Maintenance
Issues.
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
High
The responsible entity failed to
undertake efforts to correct
greater than 10, but less than or
equal to 15 identified Unresolved
Maintenance Issues.
Severe
The responsible entity failed to
undertake efforts to correct
greater than 15 identified
Unresolved Maintenance Issues.
26
VRF and VSL Justifications – PRC-005-2, R5
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This is a new Requirement; consequently, there is no prior level of compliance.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
27
VRF and VSL Justifications – PRC-005-2, R5
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007-17 – PRC-005-2: Protection System Maintenance
VRF and VSL Justifications | October 2012
28
Exhibit J
Record of Development of Proposed Reliability Standard PRC-005-2
Project 2007-17
Protection System Maintenance and Testing
Related Files
Status:
PRC-005-2 will be presented to the NERC Board of Trustees for adoption in November 2012
and if adopted, filed with regulators for approval.
Purpose/Industry Need:
The purpose of standard PRC-005 should remain “To ensure all transmission and
generation Protection Systems affecting the reliability of the Bulk Electric System
(BES) are maintained and tested.”
In Order 693, the Federal Energy Regulatory Commission directed that changes be
made to these standards.
These standards should be consolidated into a single standard to reduce the costs of
compliance and a number of technical short comings in these standards should be
corrected to provide reliable performance when responding to abnormal system
conditions.
Draft
Action
Dates
Results
Draft 4
Standard PRC005-2
Clean (225) |
Redline to Last
Posting(226)
Implementation
Plan
Clean (227)
Supporting
Materials:
Definition of
Protection
System (228)
Recirculation
Ballot
Info (241)
Vote>>
10/15/12 10/24/12
(closed)
Summary (242)
Ballot Results
(243)
Consideration of
Comments
Supplemental
Reference & FAQ
Clean (229)|
Redline to Last
Posting(230)
Technical
Justification
Clean (231)|
Redline (232)
Mapping
Document
Clean (233)
Table of Issues
and Directives
(234)
VRF and VSL
Justification
Clean (235) |
Redline (236)
Last Approved
Versions of
Standards to be
Retired:
PRC-005-1.1b
(237)
PRC-008-0 (238)
PRC-011-0 (239)
PRC-017-0 (240)
Draft 4
Standard PRC005-2
Clean (199)|
Redline to Last
Posting (200)
Implementation
Plan
Clean (201)|
Redline to Last
Posting(202)
Supporting
Materials:
Unofficial
Comment Form
(Word)(203)
Definition of
Protection
System (204)
(Updated
8/16/12)
Supplemental
Reference & FAQ
Clean(205) |
Redline to Last
Posting (206)
Technical
Justification
Clean (207)|
Redline (208)
Mapping
Document
Clean (209)|
Redline to Last
Posting (210)
Successive
Ballot
Updated Info
(218)
08/17/12 08/27/12
(closed)
Info (219)
Summary (221)
Ballot Results
(222)
Vote>>
Comment
Period
Info (220)
Submit
Comments>>
07/27/12 08/27/12
(closed)
Comments
Received (223)
Consideration of
Comments (224)
Table of Issues
and Directives
(211)
VRF and VSL
Justification
Clean (212) |
Redline (213)
Last Approved
Versions of
Standards to be
Retired:
PRC-005-1.1b
(214)
PRC-008-0 (215)
PRC-011-0 (216)
PRC-017-0 (217)
Draft 3
Standard PRC005-2
Clean (170)|
Redline to Last
Posting (171)
Implementation
Plan
Clean (172)|
Redline to Last
Posting (173)
Supporting
Materials:
Definition of
Protection
System (174)
IEEE Stationary
Battery
Summary (194)
Successive
Ballot
Updated Info
(191)
06/18/12 06/27/12
(closed)
Info (192)
Formal
Comment
Period
Info (193)
Submit
Comments>>
05/29/12 06/27/12
(closed)
Ballot Results
(195)
Non-binding
Poll Results
(196)
Comments
Received (197)
Consideration of
Comments (198)
Committee NERC
Task Force Report
and SDT
Response (175)
For Information:
Draft SAR for
Phase 2 of Project
2007-17 (176)
Supplemental
Reference & FAQ
Clean (177)|
Redline to Last
Posting (178)
Technical
Justification
Clean (179) |
Redline (180)
Mapping
Document
Clean (181)|
Redline to Last
Posting (182)
Table of Issues
and Directives
(183)
VRF and VSL
Justification
Clean (184) |
Redline (185)
Unofficial
Comment Form
(Word) (186)
Last Approved
Versions of
Standards to be
Retired:
PRC-005-1 (187)
PRC-008-0 (188)
PRC-011-0 (189)
PRC-017-0 (190)
Draft 2
Standard PRC005-2
Clean (145)|
Redline to Last
Posting (146)
Successive
Ballot and
Non-binding
Poll
03/19/12 03/28/12
(closed)
Updated Info
(163)
Vote>>
Full Record
(166)
Non-binding
Poll Results
(167)
Implementation
Plan
Clean (147)|
Redline to Last
Posting (148)
SAR
Clean (149) |
Redline to Last
Posting (150)
Supporting
Materials:
Definition of
Protection
System (151)
Supplemental
Reference & FAQ
Clean (152)|
Redline to Last
Posting (153)
Technical
Justification (154)
Mapping
Document(155)
Formal
Comment
Period
Updated Info
(164)
Info (165)
Submit
Comments>>
02/28/12 03/28/12
(closed)
Comments
Received (168)
Consideration of
Comments (169)
Table of Issues
and
Directives(156)
VRF and VSL
Justification (157)
Unofficial
Comment
Form(158)
Last Approved
Versions of
Standards to be
Retired:
PRC-005-1(159)
PRC-008-0 (160)
PRC-011-0 (161)
PRC-017-0 (162)
Nomination
Period
Drafting Team
Nominations
Info (144)
09/01/11 09/23/11
(closed)
Submit
Nomination>>
Standard PRC005-2
Clean
(124)|Redline to
Recirc Ballot(125)
Initial Ballot
and NonBinding Poll
of VRFs and
VSLs
Implementation
Plan
Clean(126) |
Redline to Recirc
Ballot(127)
Info (138)
SAR(128)
Supporting
Summary (139)
09/19/11 09/29/11
(closed)
Vote>>
Formal
Comment
Period
Submit
Comments>>
08/15/11 09/29/11
(closed)
Full Record
(140)
Non-Binding
Poll Results
(141)
Comments
Received (142)
Consideration of
Comments (143)
Materials:
Definition of
Protection
System(129)
Supplemental
Reference & FAQ
Clean(130) |
Redline to Last
Posting (131)
Mapping
Document(132)
Unofficial
Comment
Form(133)
Join Ballot
Pools>>
(Initial Ballot
and NonBinding Poll)
08/15/11 09/14/11
(closed)
Last Approved
Versions of
Standards to be
Retired
PRC-005-1(134)
PRC-008-0 (135)
PRC-011-0 (136)
PRC-017-0 (137)
After PRC-005-2 failed to reach ballot pool approval in the recirculation ballot that
ended on 6/30/11, the drafting team revised the standard. The Standards Committee
authorized re-initiating the project with a posting of the SAR and revised standard for a
45-day comment period, with an initial ballot of the standard conducted during the last
10 days of the comment period.
Standard Draft 4
PRC-005-2
Clean (109)|
Redline to Last
Posting(110)
Implementation
Plan for Standard
Clean(111) |
Recirculation
Ballot and
Non-binding
Poll
Info (120)
Vote>>
Summary(121)
6/20/116/30/11
(closed)
Full Record(122)
Non-Binding
Poll
Results(123)
Redline to Last
Posting(112)
Supporting
Materials:
Definition for
Approval(113)
Supplemental
Reference & FAQ
Clean (114)|
Redline to Last
Posting(115)
Last Approved
Versions of
Standards to be
Retired
PRC-005-1(116)
PRC-008-0 (117)
PRC-011-0 (118)
PRC-017-0 (119)
Standard Draft 4
PRC-005-2
Clean (96) |
Redline to Last
Posting (97)
Implementation
Plan for Standard
Clean (98)|
Redline to Last
Posting(99)
Supporting
Materials:
Comment Form
(Word)(100)
Successive
Ballot and
Non-Binding
Poll
Summary
Update (104)
05/03/11 05/13/11
(closed)
Info (102)
Vote>>
Full Records
Update (105)
Non-Binding
Poll
Results(106)
Comment
Period
Submit
Comments>>
Info(103)
04/13/11 05/13/11
(closed)
Comments
Received (107)
Consideration of
Comments (108)
Supplemental
Reference & FAQ
Clean (101)
Standard Draft 3
PRC-005-2
Clean (73)|
Redline to Last
Posting (74)
Successive
Ballot and
Non-binding
Poll of VRFs
and VSLs
Implementation
Plan for Standard
Clean (75)|
Redline to Last
Posting (76)
Updated Info
(86)
Info (87)
Join>>
12/10/1012/20/10
(closed)
Summary (89)
Full Records
(90)
Consideration of
Comments (93)
Successive
Ballot
(closed)
Non-Binding
Non-binding Poll Results (91)
Poll of VRFs
and VSLs
(closed)
Consideration of
Comments (94)
Supporting
Materials
Comment Form
(Word)(77)
Frequently Asked
Questions
Clean (78)|
Redline to Last
Posting(79)
Supplemental
Reference
Clean(80)
|Redline to Last
Posting (81)
Last Approved
Versions of
Standards to be
Retired
PRC-005-1 (82)
PRC-008-0 (83)
PRC-011-0 (84)
Comment
Period
Submit
Comments for
Standard >>
Info (88)
11/17/1012/17/10
(closed)
Comments
Received (92)
Consideration of
Comments (95)
PRC-017-0 (85)
Draft 5
Definition of
"Protection
System"
Clean (66)|
Redline to last
approval (67)
Implementation
Plan for
Definition
Clean (68) |
Redline to last
posting (69)
Draft 4
Definition of
"Protection
System"
Clean(54) |
Redline to Second
Ballot (55)
Redline to Last
Approval(56)
Implementation
Plan for
Definition
Clean (57)
Supporting
Materials:
Comment Form
(Word) (58)
Recirculation
Ballot >>
Vote>>
11/01/10 11/11/10
(closed)
Summary (71)
Full Record (72)
Info (70)
Successive
Ballot >>
Vote>>
10/2/10 10/14/10
(closed)
Summary (61)
Full Record (62)
Consideration of
Comments (64)
Info (59)
30-day
Formal
Comment
Period
Info (60)
Submit
Comments>>
9/13/10 10/12/10
(closed)
Comments
Received (63)
Consideration of
Comments (65)
Draft 3
Definition of
"Protection
System"
Clean (46)|
Redline to Initial
Ballot (47)
Implementation
Plan for
Definition
Clean (48) |
Redline to Initial
Ballot (49)
Second Ballot
for Definition
Vote>> | Info
(50)
07/23/10 08/02/10
(closed)
Draft 2
PRC-005-2
Clean (19)|
Redline to Last
Posting (20)
Implementation
Plan for Standard
Clean (21)|
Redline to Last
Posting (22)
Implementation
Plan for
Definition (23)
Supporting
Materials:
Comment Form
for Proposed
Definition
(Word)(24)
Summary (51)
Full Record (52)
Summary (35)
Initial Ballots
and Nonbinding
VRF/VSL Poll
07/08/10 07/17/10
(closed)
Vote>> |
Info(32)
Pre-ballot
Review
Join>> | Info
(33)
Full Record (37)
Definition
Non-binding
Poll Results(38)
Consideration of
Comments (standard)
(41)
Consideration
of Comments
(definition) (42)
Consideration of
Comments (nonbinding poll) (43)
06/11/10 07/02/10
(closed)
Comment
Period
Submit
Comments
(For
Standard)
Full Record (36)
Standard
Consideration of
Comments
(definition) (53)
06/11/10 07/16/10
(closed)
Comments
Received
(Standard)(39)
Comments
Received
(Definition)(40)
Consideration
of Comments
(definition) (44)
Consideration of
Comments (45)
Comment Form
for Standard
(Word) (25)
Frequently Asked
Questions
Clean (26)|
Redline to Last
Posting(27)
Submit
Comments
(For
Definition)
Info (34)
Supplemental
Reference
Clean (28)|
Redline to Last
Posting (29)
Definition of
"Protection
System" (30)
Proposed Version
of Issues
Database (31)
Draft 1
Protection
System
Maintenance and
Testing Standard
PRC-005-2 (9)
Supporting
Materials:
Comment Form
(Word) (10)
Implementation
Plan (11)
Supplementary
Reference (12)
Comment
Period
Info (16)
Submit
Comments>>
07/24/09 09/08/09
(closed)
Comments
Received (17)
Consideration of
Comments (18)
Status of
Addressing Issues
(13)
Frequently Asked
Questions (14)
Assessment of
Impact of
Proposed
Modification to
the Definition of
“Protection
System” (15)
Standard
Drafting Team
Nominations
Info (7)
Submit
Nomination
(8)
Draft SAR
Version 1
Protection
System
Maintenance and
Testing
Draft SAR Version
1 (1)
Supporting
Materials:
NERC SPCTF
Assessment of
Standards (2)
08/15/07 08/29/07
(closed)
Comment
Period
Info (3)
Submit
Comments(4)
06/11/07 07/10/07
(closed)
Comments
Received (5)
Consideration of
Comments (6)
E-mail completed form to
[email protected]
Standard Authorization Request Form
Title of Proposed Standard: Project 2007-17 — Transmission and Generation Protection
System Maintenance and Testing
Request Date:
May 7, 2007
SAR Requestor Information
SAR Type (Check a box for each one that applies.)
Name:
System Protection
and Controls Task Force
(Attachment A)
Primary Contact
Rogers
Charles
New Standard
X
Revision to existing Standards:
PRC-005-1 — Transmission and Generation
Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding
Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and
Testing
PRC-017-0 — Special Protection System
Maintenance and Testing
Telephone
(517) 788-0027
Fax
(517) 788-0917
E-mail [email protected]
X
Withdrawal of existing Standard
Urgent Action
Purpose (Describe the purpose of the standard — what the standard will achieve in support
of reliability.)
The purpose of standard PRC-005 should remain “To ensure all transmission and generation
Protection Systems affecting the reliability of the Bulk Electric System (BES) are maintained
and tested.”
Industry Need (Provide a detailed statement justifying the need for the proposed
standard, along with any supporting documentation.)
In Order 693, the Federal Energy Regulatory Commission directed that changes be made to
these standards.
These standards should be consolidated into a single standard to reduce the costs of
compliance and a number of technical short comings in these standards should be corrected
to provide reliable performance when responding to abnormal system conditions.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Brief Description (Describe the proposed standard in sufficient detail to clearly define the
scope in a manner that can be easily understood by others.)
Revise PRC-005-1 — Transmission and Generation Protection System Maintenance and
Testing, to consolidate PRC-005-1, PRC-008-0 — Underfrequency Load Shedding
Equipment Maintenance Programs; PRC-011-0 — UVLS System Maintenance and Testing;
and PRC-017-0 — Special Protection System Maintenance and Testing into a single
maintenance and testing standard. Standards PRC-008-0, PRC-011-0, and PRC-017-0
would then be withdrawn.
The revised PRC-005 standard should address the issues raised in the FERC Order 693 and
the issues addressed in the SPCTF report “Assessment of PRC-005-1 – Transmission and
Generation Protection System Maintenance and Testing; with implications for PRC-008-0,
PRC-011-0, and PRC-017-0” – Attachment A to this SAR The revised standard should also
address the comments submitted by stakeholders during the development of Version 0,
and Phase III & IV and should reflect improvements identified in the Reliability Standards
Review Guidelines – Attachment B to this SAR.
Detailed Description:
The PRC-005, 008, 011, and 017 reliability standards are intended to assure that
Transmission & Generation Protection Systems are maintained and tested so as to provide
reliable performance when responding to abnormal system conditions. It is the
responsibility of the Transmission Owner, Generation Owner, and Distribution Provider to
ensure the Transmission & Generation Protection Systems are maintained and tested in
such a manner that the protective systems operate to fulfill their function.
Applicable to all four standards — The listed requirements do not provide clear and
sufficient guidance concerning the maintenance and testing of the Protection Systems to
achieve the commonly stated purpose which is “To ensure all transmission and generation
Protection Systems affecting the reliability of the Bulk Electric System (BES) are maintained
and tested.”
• Applicable to PRC-017 — Part of the stated purpose in PRC-017 is: “To ensure that
maintenance and testing programs are developed and misoperations are analyzed
and corrected.” The phrase “and misoperations are analyzed and corrected” is not
clearly appropriate in a maintenance and testing standard. That is the purpose is
more appropriate in PRC-003 and PRC-004, which relate to the analysis and
mitigation of protection system misoperations. Analysis of correct operations or
misoperations may be an integral part of condition-based maintenance processes,
but need not be mandated in a maintenance standard.
•
Applicable to all four standards — The standards should clearly state which power
system elements are being addressed.
•
Applicable to all four standards — The requirements should reflect the inherent
differences between various protection system technologies.
•
Applicable to all four standards — The terms “maintenance programs” and “testing
programs” should be clearly defined in the glossary. The terms “maintenance” and
“testing” are not interchangeable, and the requirements must be clear in their
application. Additional terms may also have to be added to the glossary for clarity.
•
Applicable to all four standards — The requirements of the existing standards, as
stated, support time-based maintenance and testing, and should be expanded to
include condition-based and performance-based maintenance and testing. The
requirements for maintenance and testing procedures need to have more specificity
to insure that the stated intent of the standards is met to support review by the
compliance monitor.
The revised standard should also include the general improvements identified in the
attached Reliability Standard Review Guidelines.
SAR–2
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource Planner
Develops a >one year plan for the resource adequacy of its
specific loads within a Planning Coordinator area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within its portion of the Planning Coordinator
area.
Transmission
Service Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.
SAR–3
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all the following Market Interface
Principles? (Select “yes” or “no” from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
None
FRCC
None
MRO
None
NPCC
None
SERC
None
RFC
None
SPP
None
WECC
None
SAR–5
Attachment A — SPCTF Roster
SPCTF Roster
Charles W. Rogers
Chairman / RFC-ECAR Representative
Principal Engineer
Consumers Energy Co.
W. Mark Carpenter
Vice Chairman / ERCOT Representative
System Protection Manager
TXU Electric Delivery
John L. Ciufo
Canada Member-at-Large
Manager Reliability Standards (P&C/Telecom)
Hydro One, Inc.
John Mulhausen
FRCC Representative
Manager, Design and Standards
Florida Power & Light Co.
Jim Ingleson
ISO/RTO Representative
Senior Electric System Planning Engineer
New York Independent System Operator
Joseph M. Burdis
ISO/RTO Representative
Senior Consultant / Engineer, Transmission
and Interconnection Planning
PJM Interconnection, L.L.C.
Evan T. Sage
Investor Owned Utility
Senior Engineer
Potomac Electric Power Company
James D. Roberts
Federal
Transmission Planning
Tennessee Valley Authority
William J. Miller
RFC-MAIN Representative
Consulting Engineer
Exelon Corporation
Tom Wiedman
NERC Consultant
Wiedman Power System Consulting Ltd.
Deven Bhan
MRO Representative
Electrical Engineer, System Protection
Western Area Power Administration
Henry (Hank) Miller
RFC-ECAR Alternate
Principal Electrical Engineer
American Electric Power
Philip Tatro
NPCC Representative
Consulting Engineer
National Grid USA
Baj Agrawal
WECC Alternate
Principal Engineer
Arizona Public Service Company
Philip B. Winston
SERC Representative
Manager, Protection and Control
Georgia Power Company
Dean Sikes
SPP Representative
Manager - Transmission Protection, Apparatus, & Metering
Cleco Power
Michael J. McDonald
Senior Principal Engineer, System Protection
Ameren Services Company
Jonathan Sykes
Senior Principal Engineer, System Protection
Salt River Project
David Angell
WECC Representative
T&D Planning Engineering Leader
Idaho Power Company
Fred Ipock
Senior Engineer - Substations & Protection
City Utilities of Springfield, Missouri
W. O. (Bill) Kennedy
Canada Member-at-Large
Principal
Kennedy & Associates Inc.
W. O. (Bill) Kennedy
Canada Member-at-Large
Principal
b7kennedy & Associates Inc.
Bob Stuart
Director of Business Development, Principal
T&D Consultant
Elequant, Inc.
SAR–6
Attachment B — Reliability Standard Review Guidelines
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for complying
with the reliability standard, with any specific additions or exceptions noted? Where multiple functional
classes are identified is there a clear line of responsibility for each requirement identifying the functional
class and entity to be held accountable for compliance? Does the requirement allow overlapping
responsibilities between Registered Entities possibly creating confusion for who is ultimately accountable
for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the entire North
American bulk power system, an interconnection, or within a regional entity area? If no geographic
limitations are identified, the default is that the standard applies throughout North America.
Does this reliability standard identify any limitations on the applicability of the standard based on electric
facility characteristics, such as generators with a nameplate rating of 20 MW or greater, or transmission
facilities energized at 200 kV or greater or some other criteria? If no functional entity limitations are
identified, the default is that the standard applies to all identified functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a value
statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by the
applicable entities, will provide for a reliable bulk power system, consistent with good utility practices
and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively evaluate
compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or experience,
as determined by expert practitioners in that particular field?
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and regional entity
compliance documents, are the consequences of violating a standard clearly known to the responsible
entities?
SAR–7
Attachment B — Reliability Standard Review Guidelines
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible entities, using
reasonable judgment and in keeping with good utility practices, arrive at a consistent interpretation of the
required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the assigned
responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for certification.
The certification requirements should indicate that entities have a responsibility to ‘maintain’ their
capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions that are
approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability Standards,
then the term must be capitalized when it is used in the standard. New terms should not be added unless
they have a ‘unique’ definition when used in a NERC reliability standard. Common terms that could be
found in a college dictionary should not be defined and added to the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added to the
guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly cause or contribute to bulk electric
system instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. However, violation of a medium risk requirement is unlikely,
under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
SAR–8
Attachment B — Reliability Standard Review Guidelines
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. A planning requirement that is administrative
in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and including
seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not realtime.
•
Real-time Operations — actions required within one hour or less to preserve the reliability of
the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of non-compliance.’)
The violation severity levels must be applied for each requirement and may be combined to cover
multiple requirements, as long as it is clear which requirements are included and that all requirements are
included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly compliant
with and meets the intent of the requirement but is deficient with respect to one or more minor
details. Equivalent score: more than 95% but less than 100% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one or
more significant elements. Equivalent score: more than 85% but less than or equal to 95%
compliant.
•
High: marginal performance or results — The responsible entity has only partially achieved
the reliability objective of the requirement and is missing one or more significant elements.
Equivalent score: more than 70% but less than or equal to 85% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the reliability
objective of the requirement. Equivalent score: 70% or less compliant.
SAR–9
Attachment B — Reliability Standard Review Guidelines
Compliance Monitor
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
provide notice to responsible entities of the obligation to comply. If the standard is to be actively
monitored, time for the Compliance Monitoring and Enforcement Program to develop reporting
instructions and modify the Compliance Data Management System(s) both at NERC and
Regional Entities must be provided in the implementation plan. The effective date should be
linked to the NERC BOT adoption date.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
SAR–10
Attachment B — Reliability Standard Review Guidelines
SAR–11
NERC SPCTF Assessment of Standards:
• PRC-005-1 — Transmission and Generation Protection
System Maintenance and Testing
• PRC-008-0 — Underfrequency Load Shedding
Equipment Maintenance Programs
• PRC-011-0 — UVLS System Maintenance and Testing
• PRC-017-0 — Special Protection System Maintenance
and Testing
DRAFT 1.0
March 8, 2007
A Technical Review of Standards
Prepared by the
System Protection and Controls Task Force
of the
NERC Planning Committee
Table of Contents
Table of Contents
Introduction .................................................................................................................................................................2
Executive Summary.....................................................................................................................................................2
Assessment of PRC-005-1............................................................................................................................................3
Purpose .....................................................................................................................................................................3
General Comments....................................................................................................................................................3
Applicability ..............................................................................................................................................................4
Requirements.............................................................................................................................................................4
R1..........................................................................................................................................................................4
R2..........................................................................................................................................................................5
FERC Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 .........................................................5
PRC-005-1.................................................................................................................................................................5
PRC-008-0.................................................................................................................................................................6
PRC-011-0.................................................................................................................................................................6
PRC-017-0.................................................................................................................................................................7
Other Activities Related to PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 ................................................7
Conclusions and Recommendations...........................................................................................................................7
Appendix A — System Protection and Control Task Force ....................................................................................8
This report and its attendant Standards Authorization Request were approved by the Planning
Committee on March 21, 2007, for forwarding to the Standards Committee.
Page i
SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0
Introduction
When the original scope for the System Protection and Control Task Force was developed, one of the
assigned items was to review all of the existing PRC-series Reliability Standards, to advise the Planning
Committee of our assessment, and to develop Standards Authorization Requests, as appropriate, to
address any perceived deficiencies.
This report presents the SPCTF’s assessment of PRC-005-1 – Transmission and Generation Protection
System Maintenance and Testing. The report includes the SPCTF’s understanding of the intent of this
standard and contains specific observations relative to the existing standard.
The SPCTF sees the parallel intent for each of the PRC-005, PRC-008, PRC-011, and PRC-017 as being
maintenance and testing standards for different protective systems. In fact, PRC-005 & PRC-008, and
PRC-011 & PRC-017 have very similar format respectively. Since all protective relay systems require
some means of maintenance and testing, it would seem that all protective system maintenance and testing
could be included in one standard regardless of scheme type. The SPCTF recommends that these four
standards be reduced to one standard covering the issues detailed for PRC-005 on maintenance and
testing.
These four standards were developed primarily by translating the requirements of an earlier Phase I
Planning Standard; thus they have not been previously subjected to a critical review of the Requirements.
Executive Summary
Reliability standards PRC-005, 008, 011, and 017 are intended to assure that Transmission & Generation
Protection Systems are maintained and tested so as to provide reliable performance when responding to
abnormal system conditions. It is the responsibility of the Transmission Owner, Generation Owner, and
Distribution Provider to ensure the Transmission & Generation Protection Systems are maintained and
tested in such a manner that the protective systems operate to fulfill their function.
Only PRC-005 will be commented on in detail although the other three standards have the same concerns.
SPCTF concluded that:
•
Applicable to all four standards — The listed requirements do not provide clear and sufficient
guidance concerning the maintenance and testing of the Protection Systems to achieve the
commonly stated purpose which is “To ensure all transmission and generation Protection Systems
affecting the reliability of the Bulk Electric System (BES) are maintained and tested.”
•
Applicable to PRC-017 — Part of the stated purpose in PRC-017 states: “To ensure that
maintenance and testing programs are developed and misoperations are analyzed and corrected.”
The phrase “and misoperations are analyzed and corrected” is not clearly appropriate in a
maintenance and testing standard. That is, the purpose is more appropriate in PRC-003 and PRC004, which relate to the analysis and mitigation of protection system misoperations. Analysis of
correct operations or misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard.
•
Applicable to all four standards — The standards should clearly state which power system
elements are being addressed.
•
Applicable to all four standards — The requirements should reflect the inherent differences
between different technologies of protection systems.
Page 2
SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0
•
Applicable to all four standards — The terms maintenance programs and testing programs should
be clearly defined in the glossary. The terms “maintenance” and “testing” are not
interchangeable, and the requirements must be clear in their application. Additional terms may
also have to be added to the glossary for clarity.
•
Applicable to all four standards — The requirements of the existing standards, as stated, support
time-based maintenance and testing, and should be expanded to include condition-based and
performance-based maintenance and testing. The R1.2 summary of maintenance and testing
procedures needs to have some minimum defined sub-requirements to insure that the stated intent
of the standards is met to support review by the compliance monitor.
Assessment of PRC-005-1
Purpose
To ensure all transmission and generation Protection Systems affecting the reliability of the Bulk
Electric System (BES) are maintained and tested.
A review of PRC-005 indicates that this standard is intended to assure that all affected entities have
adequate maintenance and testing programs for their Protection Systems to ensure reliability. SPCTF
agrees with the Purpose statement of PRC-005-1.
General Comments
The SPCTF offers the following general comments:
•
None of the requirements within PRC-005-1 specifically indicate what minimum attributes
should be included in protective system maintenance and testing procedures.
•
For interval-based procedures, no allowable maximum interval is prescribed.
•
None of the requirements in the existing PRC-005-1 reflect condition-based or performancebased maintenance and testing criteria.
Standard PRC-005 should clarify that two goals are being covered:
•
The maintenance portion should have requirements that keep the protection system equipment
operating within manufacturers’ design specification throughout the service life.
•
The testing portion should have requirements that verify that the functional performance of the
protection systems is consistent with the design intent throughout the service life.
Page 3
SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0
Applicability
4.1.
Transmission Owners
4.2.
Generation Owners
4.3.
Distribution Providers that owns a transmission Protection System
Applicability 4.3 suggests that the definition of a Protection System in the Glossary of Terms should
clarify how a Distribution Provider may be the owner of a transmission Protection System.
Requirements
R1
R1.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
The following clarifications should be made to Requirement R1:
1.
How is the phrase “that affect the reliability of the BES” to be interpreted? The standard should
clearly specify which Protection Systems are subject to the requirements.
2.
The standard should clearly specify which components of the Generation Protection System are
subject to the requirements.
The following clarifications should be made to Subparts R1.1 & R1.2:
1.
Interval-based, condition-based, or performance-based maintenance and testing minimum criteria
should be established within R1.1, including, but not limited to the following:
a.
For time-based maintenance and testing programs, maximum maintenance intervals
should be specified.
b.
For condition-based or performance-based maintenance and testing programs, the
program should have sufficient justification and documentation.
2.
Definitions should be established for the terms “maintenance programs” and “testing programs.”
3.
A minimum set of attributes to be included in maintenance and testing programs should be
established within R1.2.
Page 4
SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0
R2
R2.
Each Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation Protection System shall
provide documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Reliability Organization on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1. Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained
The following clarification should be made to requirement R2:
•
The appropriate entity should have their Protection System maintenance program and testing
program and associated documentation, including maintenance records and testing records,
available to its Regional Reliability Organization and NERC during audits or upon request within
30 days.
FERC Assessment of PRC-005-1, PRC-008-0,
PRC-011-0, and PRC-017-0
In the October 20, 2006 Notice of Proposed Rulemaking for adoption of NERC Standards (Docket
Number RM06-16-000), the Federal Energy Regulatory Commission commented on these four standards
and proposed changes. The observations and proposals are excerpted from the NOPR and included
below.
PRC-005-1
The Commission proposes to approve PRC-005-1 as mandatory and enforceable. In addition, we
propose to direct that NERC develop modifications to the Reliability Standard as discussed below.
Proposed Reliability Standard PRC-005-1 does not specify the criteria to determine the appropriate
maintenance intervals, nor do it specify maximum allowable maintenance intervals for the protections
systems. The Commission therefore proposes that NERC include a requirement that maintenance and
testing of these protection systems must be carried out within a maximum allowable interval that is
appropriate to the type of the protection system and its impact on the reliability of the Bulk-Power
System.
Accordingly, giving due weight to the technical expertise of the ERO and with the expectation that the
Reliability Standard will accomplish the purpose represented to the Commission by the ERO and that
it will improve the reliability of the nation’s Bulk-Power System, the Commission proposes to approve
Reliability Standard PRC-005-1 as mandatory and enforceable. In addition, pursuant to section
215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposes to direct that NERC
submit a modification to PRC-005-1 that includes a requirement that maintenance and testing of a
protection system must be carried out within a maximum allowable interval that is appropriate to the
type of the protection system and its impact on the reliability of the Bulk-Power System.
Page 5
SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0
PRC-008-0
The Commission notes that the commenters generally share staff’s concern that the proposed
Reliability Standard does not specify the criteria to determine the appropriate maintenance intervals,
nor does it specify maximum allowable maintenance intervals for the protection systems. The
Commission agrees and proposes to require NERC to modify the proposed Reliability Standard to
include a requirement that maintenance and testing of UFLS programs must be carried out within a
maximum allowable interval that is appropriate to the type of relay used and the impact on the
reliability of the Bulk-Power System.
Accordingly, the Commission proposes to approve Reliability Standard PRC-008-0 as mandatory and
enforceable. In addition, the Commission proposes to direct that NERC submit a modification to PRC008-0 that includes a requirement that maintenance and testing of UFLS programs must be carried out
within a maximum allowable interval appropriate to the relay type and the potential impact on the
Bulk-Power System.
PRC-011-0
PRC-011-0 does not specify the criteria to determine the appropriate maintenance intervals, nor does it
specify maximum allowable maintenance intervals for the protections systems. The Commission
proposes that NERC include a Requirement that maintenance and testing of these UFLS programs
must be carried out within a maximum allowable interval that is appropriate to the type of the relay
used and the impact of these UFLS on the reliability of the Bulk-Power System.
The Commission believes that Reliability Standard PRC-011-0 serves an important purpose in
requiring transmission owners and distribution providers to implement their UVLS equipment
maintenance and testing programs. Further, the proposed Requirements are sufficiently clear and
objective to provide guidance for compliance.
Accordingly, giving due weight to the technical expertise of the ERO and with the expectation that the
Reliability Standard will accomplish the purpose represented to the Commission by the ERO and that
it will improve the reliability of the nation’s Bulk-Power System, the Commission proposes to approve
Reliability Standard PRC-011-0 as mandatory and enforceable. In addition, pursuant to section
215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposes to direct that NERC
submit a modification to PRC-011-0 that includes a requirement that maintenance and testing of
UVLS programs must be carried out within a maximum allowable interval appropriate to the
applicable relay and the impact on the reliability of the Bulk-Power System.
Page 6
SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0
PRC-017-0
PRC-017-0 does not specify the criteria to determine the appropriate maintenance intervals, nor does it
specify maximum allowable maintenance intervals for the protections systems. The Commission
proposes to require NERC to include a requirement that maintenance and testing of these special
protection system programs must be carried out within a maximum allowable interval that is
appropriate to the type of relaying used and the impact of these special protection system programs on
the reliability of the Bulk-Power System.
Accordingly, giving due weight to the technical expertise of the ERO and with the expectation that the
Reliability Standard will accomplish the purpose represented to the Commission by the ERO and that
it will improve the reliability of the nation’s Bulk-Power System, the Commission proposes to approve
Reliability Standard PRC-017-0 as mandatory and enforceable. In addition, pursuant to section
215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposes to direct that NERC
submit a modification to PRC-017-0 that: (1) includes a requirement that maintenance and testing of
these special protection system programs must be carried out within a maximum allowable interval
that is appropriate to the type of relaying used; and (2) identifies the impact of these special protection
system programs on the reliability of the Bulk-Power System.
Other Activities Related to PRC-005-1, PRC-008-0,
PRC-011-0, and PRC-017-0
These four Standards are contained in several projects and draft SARs as part of the “Draft Reliability
Standards Development Plan: 2007–2009”, which was approved by the NERC Board of Trustees.
The SPCTF recommends that standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 be removed
from the separate SARS in the Standards Development Plan, and that they be included in a new Standard
Authorization Request for a single Protection System maintenance and testing standard.
Conclusions and Recommendations
PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 require additions, clarifications, and definitions to
insure that the Protection Systems are properly maintained and tested.
The SPCTF recommends that standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 be removed
from the separate SARS in the “Draft Reliability Standards Development Plan: 2007–2009,” and that they
be included in a new Standard Authorization Request for a single Protection System maintenance and
testing standard.
SPCTF submits the attached SAR for that purpose of consolidating PRC-005-1, PRC-008-0, PRC-011-0,
and PRC-017-0 into a single standard to the Planning Committee for endorsement.
Page 7
Appendix A — SPCTF Roster
Appendix A — System Protection and Control Task
Force
Charles W. Rogers
Chairman / RFC-ECAR Representative
Principal Engineer
Consumers Energy Co.
W. Mark Carpenter
Vice Chairman / ERCOT Representative
System Protection Manager
TXU Electric Delivery
John L. Ciufo
Canada Member-at-Large
Manager Reliability Standards (P&C/Telecom)
Hydro One, Inc.
John Mulhausen
FRCC Representative
Manager, Design and Standards
Florida Power & Light Co.
Jim Ingleson
ISO/RTO Representative
Senior Electric System Planning Engineer
New York Independent System Operator
Joseph M. Burdis
ISO/RTO Representative
Senior Consultant / Engineer, Transmission
and Interconnection Planning
PJM Interconnection, L.L.C.
Evan T. Sage
Investor Owned Utility
Senior Engineer
Potomac Electric Power Company
James D. Roberts
Federal
Transmission Planning
Tennessee Valley Authority
William J. Miller
RFC-MAIN Representative
Consulting Engineer
Exelon Corporation
Tom Wiedman
NERC Consultant
Wiedman Power System Consulting Ltd.
Deven Bhan
MRO Representative
Electrical Engineer, System Protection
Western Area Power Administration
Henry (Hank) Miller
RFC-ECAR Alternate
Principal Electrical Engineer
American Electric Power
Philip Tatro
NPCC Representative
Consulting Engineer
National Grid USA
Baj Agrawal
WECC Alternate
Principal Engineer
Arizona Public Service Company
Philip B. Winston
SERC Representative
Manager, Protection and Control
Georgia Power Company
Michael J. McDonald
Senior Principal Engineer, System Protection
Ameren Services Company
Dean Sikes
SPP Representative
Manager - Transmission Protection, Apparatus, &
Metering
Cleco Power
Jonathan Sykes
Senior Principal Engineer, System Protection
Salt River Project
Fred Ipock
Senior Engineer - Substations & Protection
City Utilities of Springfield, Missouri
David Angell
WECC Representative
T&D Planning Engineering Leader
Idaho Power Company
W. O. (Bill) Kennedy
Canada Member-at-Large
Principal
b7kennedy & Associates Inc.
W. O. (Bill) Kennedy
Canada Member-at-Large
Principal
b7kennedy & Associates Inc.
Bob Stuart
Director of Business Development, Principal
T&D Consultant
Elequant, Inc.
Page 8
Maureen E. Long
Standards Process Manager
June 11, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Comment Periods Open
The Standards Committee (SC) announces the following standards actions:
SAR for System Protection Coordination (Project 2007-06) Posted for 30-day Comment Period
June 11–July 10, 2007
The SAR for Project 2007-06 — System Protection Coordination proposes to address the FERC directives in
Order 693 and to address a number of technical shortcomings identified by stakeholders and the System
Protection and Control Task Force and to bring the standard into conformance with the “Standard Review
Guidelines.”
The purpose of the proposed standard is to assure that protection system application and performance issues are
coordinated among all related entities. Please use this comment form to submit comments on this SAR.
SAR for Protection System Maintenance & Testing (Project 2007-17) Posted for 30-day Comment
Period June 11–July 10, 2007
This SAR for Project 2007-17 — Protection System Maintenance and Testing proposes to merge the requirements
from the following standards into a single standard to reduce the costs of compliance while also improving
efficiencies:
- PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
- PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
- PRC-011-0 — UVLS System Maintenance and Testing
- PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a number of technical
shortcomings identified by stakeholders and the System Protection and Control Task Force and to bring the
standard into conformance with the “Standard Review Guidelines.”
The purpose of the proposed standard is to ensure all transmission and generation protection systems affecting the
reliability of the bulk power system are maintained and tested to support reliable operation performance when
responding to abnormal system conditions. Please use this comment form to submit comments on this SAR.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. If you have any questions, please contact me at
813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments:
Page 4 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Thad K. Ness
Organization: American Electric Power (AEP)
Telephone:
614-716-2053
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments: AEP has not had an event, due to deficiencies in protection maintenance, in
it's long existence that jeopardized the reliability or availability of Bulk Power transfers.
Simply combining multiple standards into one, does nothing for improving reliability.
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments: On the surface, the premise of reducing costs and improving efficiencies by
combining multiple standards sounds excellent. Having to only keep up with one
standard instead of four will not generate significant savings due to the fact that the
maintenance will still have to be performed. But what lies hidden, is the fact that
prescribed maximum allowable maintenance intervals will result from the revisions.
They may require more frequent testing to be performed. Is there evidence that
increasing the interval frequency results in a measurable increase in reliability and
availability? Development of prescribed maximum intervals that are vastly different
than the utility's existing practices may actual increase their O&M costs and reduce
efficiencies.
The function of the protective system needs to be taken into account. The purpose of
the line protection is very different than the purpose of UFLS/UVLS and SPS's. The
UFLS program is there as the last line of defense against a decaying system after all
other measures have failed. The combination of all the different relaying systems
places them on equal ground. Shouldn't the reliability and dependablilty for one be
more important than the others?
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Regional Variance: None
Comments: None
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice: Possibly
Comments: AEP and other utilities, with many years of experience serving customers
and supporting the electric grid, have voluntarily integrated maintenance and testing
programs into the core of their work practices and processes. AEP fully supports
improvements if they truly foster reliability and availability benefits to bulk power
transfers. More Standards, Requirements and Business Practices are not always better.
If Standards create burdens on a utility's physical resources and budgets, then some
mechanism must be available to allow for the needed changes.
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: The standard should not use the term Bulk Electric System, but should
instead specify a voltage threshold for impacts to bulk system transfers - specifically;
'Facilites operated 200 kV and above and Regionally-defined, Operationally Significant
facilities operated greater than 100 kv, but less than 199 kV'. The term 'affects' also
needs to be clarified. Inclusion of all facilities greater than 100 kV does not benefit the
reliability of national bulk power transfers. For example, the loss or misoperation of a
138 kV line serving a localized load center would not be detremental to bulk power
transfers multiple busses away.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Dean Bender
Organization: Bonneville Power Administration
Telephone:
(360) 418-2040
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments: No known regional variance
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: In the "Detailed Description" section of the SAR, it states:
"Part of the stated purpose in PRC-017 is: “To ensure that maintenance and testing
programs are developed and misoperations are analyzed and corrected.” The phrase
“and misoperations are analyzed and corrected” is not clearly appropriate in a
maintenance and testing standard. That is the purpose is more appropriate in PRC-003
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
and PRC-004, which relate to the analysis and mitigation of protection system
misoperations. Analysis of correct operations or misoperations may be an integral part
of condition-based maintenance processes, but need not be mandated in a
maintenance standard."
The analysis of SPS misoperations is handled in PRC-016 (SPS Misoperations) and PRC
012 (SPS review Procedure) not in PRC-003 or PRC-004. Therefore, if the phrase is
removed from PRC-017, it does not need to be added to PRC-003 or PRC-004.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Nancy C. Denton
Organization: Consumers Energy Company
Telephone:
517-788-1310
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance: N/A
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice: N/A
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: None.
Page 4 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Greg Rowland
Organization: Duke Energy
Telephone:
704-382-5348
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments: Combining PRC-005, 008, 011 and 017 into one new standard does not
seem to be the best approach. Duke Energy does not have UVLS systems or Special
Protection Systems. Furthermore, Duke Energy's Underfrequency Load Shedding
system is on the transmission system in the Carolinas, but on the distribution system in
the Midwest. Combining these standards would likely create confusion and compliance
issues for us and others as well. Also, combining the standards is unlikely to result in
simplification, as different requirements associated with the different protection
systems could have different Violation Risk Factors and levels of non-compliance, which
would necessitate keeping them separate in the combined standard, which would
defeat the purpose of combining them in the first place.
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments:
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Doug Hohlbaugh
Organization: FirstEnergy
Telephone:
330-384-4698
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
FirstEnergy Corp
Lead Contact:
Doug Hohlbaugh
Contact Organization:
Contact Segment:
Contact Telephone:
330-384-4698
Contact E-mail:
[email protected]
Additional Member Name
Craig Boyle
Additional Member
Organization
FE, Tranmission Substation
Region*
Segment*
RFC
1
Maintenance
Ken Dresner
FE, Fossil Generation
RFC
5
Bill Duge
FE, Nuclear Generation
RFC
5
Dave Powell
FE, Transmission Planning &
RFC
1
RFC
1
Protection
Jeff Mackauer
FE, Transmission Planning &
Protection
Page 2 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 3 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 4 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments: Bullet #5 of the "Detailed Description" on page SAR-2 indicates the
following:
"Applicable to all four standards — The requirements of the existing standards, as
stated, support time-based maintenance and testing, and should be expanded to
include condition-based and performance-based maintenance and testing. The
requirements for maintenance and testing procedures need to have more specificity
to insure that the stated intent of the standards is met to support review by the
compliance monitor."
FE supports the scope of the SAR to consider adding the ability for condition-based and
performanced based testing, as suggested by the System Protection and Control Task
Force. Additionally, the SDT should consider the need to perform some level of
preventative maintenance on a periodic basis at an established maximum interval
length, that would vary per the equipment being maintained. The interval established
would be based on established guidelines from vendors, EPRI, industry experts, etc.
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments: The inclusion of the Distribution Provider is generally needed for UFLS and
UVLS relays. The confusion that previously existed in PRC-005 by including the DP
entity should be mitigated by the proposed consolidation of the four maintenance
standards.
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Page 5 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Regional Variance:
Comments: Not aware of any.
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments: Not aware of any
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: None.
Page 6 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
FRCC
Lead Contact:
Eric Senkowicz
Contact Organization:
FRCC
Contact Segment:
10
Contact Telephone:
813-207-7980
Contact E-mail:
[email protected]
Additional Member Name
Alan Gale
Additional Member
Organization
City of Tallahassee
Region*
FRCC
Segment*
5
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments: Centralizing System Protection equipment maintenance and testing
requirements in a single standard will add clarity, minimize synchronization issues
across standards, help provide consistent terminology and improve understanding of
system protection standards.
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments: Use of subject matter experts (NERC SPCTF) along with the NERC Planning
Committee review of the assessment is an effective and efficient way to supplement
project SARs and provides critical input at the front-end of the standards process.
Attachment A is described as the SPCTF assessment, but attachment A to the SAR is
the SPCTF roster. The assessment referenced in the scope of the SAR should include
"Draft 1.0" if the full assessment is not included as part of the SAR.
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments: This question may be better addressed as the standards are integrated.
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: There are many standards being addressed (Disturbance Monitoring,
System Protection Coordination, Reliability Coordination, along with Regional standard
developments). As these standards are integrated into PRC-005, the existing and new
terminology should be consistently applied in all system protection standards (with
respect to defined terms). Where terms are undefined or being revised, the drafting
team should carefully consider the terms used to ensure coordination of revised or new
definitions with other Reliability standards or flag conflicts within the implementation
plan.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Roger Champagne
Organization: Hydro-Québec TransÉnergie
Telephone:
514 289-2211, X 2766
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments: Each requirement needs to specifically address what protection systems
need to comply with the standard - i.e. a generator not connected to the BPS with
under frequency trip relay should only be subject to under frequency relay maintenance
requirements
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance: None
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments: none that we know of
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: Due consideration should be given to potential difficulties in obtaining
required outages. System reliability concerns may preclude performing maintenance at
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
the intervals required. Certain unavoidable delays like the inability to schedule outages
for reliability reasons, labor disputes, or force-majeure conditions could affect testing
period requirements. These factors should be considered and certain latitude needs to
be provided, with "appropriate" approvals, for delays in the testing process.
There is need to specify which types of relays will be covered by the new standard. The
SAR Team needs to focus on better defining the Generator Protection Schemes (“GPS”)
that would be subject to this Standard – i.e., what subset of GPS are critical to bulk
power system operation, as distinct from generator operation. For example, typically
there is no single generating unit that would, if a contingency event occurs on that
generating unit, result in significant adverse impacts outside of the local area in which
the single generating unit is located. As a result, if these NERC Standards are to apply
to all NERC-registered Generators, only a subset of the GPS need to be subjected to the
maintenance testing intervals.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Falsetti
Organization: IESO
Telephone:
905-855-6187
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments:
1. The IESO commends NERC, the SDT and the SPCTF for providing clarity and for
efforts to reduce the costs of compliance.
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
2 In the Standard PRC-008-0, Generation Owners were not included in the applicable
entities. Generation Owners may have underfrequency tripping devices for protection
of their units. Hence, it would be appropriate to include these devices for maintenance
and testing requirements also.
3. There is need to specify which types of relays will be covered by the new standard.
The SAR Team needs to focus on better defining the Generator Protection Schemes
("GPS") that are critical to bulk power system operation, as distinct from generator
operation. For example, a single generating unit may experience contingency events
that would not result in any significant adverse impacts outside the local area in which
the single generating unit is located. As a result, there remains a need to subject those
GPSs that are important to the Bulk Power System, such as generator underfrequency
trip settings, to the maintenance testing intervals to be derived in these standards.
4. Certain unavoidable delays like the inability to schedule outages for reliability
reasons, labor disputes, or force-majeure conditions could affect testing period
requirements. These factors should be considered and certain latitude needs to be
provided for delays in the testing process.
5. However, the SAR team needs to also consider, as part of its scope, assurance that
the asset owner has taken all appropriate steps to ensure that required outages are
appropriately planned, can be reasonably accommodated, and approved by the TOP or
RC.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Tony Clark
Organization: Manitoba Hydro
Telephone:
204-487-5478
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments: There is a need to better define and explain the terms "maintenance" and
"testing" as they relate to this standard. Also a tighter definition as to which systems
are considered to affect the BES is required. The need to improve the standard is
driven by the administration of the standard rather than reliability.
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments: We disagree that there is a need to change the standard to include more
specificity for maintenance and test procedures. We also disagree with mandating
minimum maintenance intervals for protection system equipment.
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Comments: Manitoba Hydro takes exception to the prescriptive nature of the proposed
changes to the maintenace procedures and maintenance intervals. The type of
maintenance performed and the minimum maintenance intervals should be determined
by the utility within the operating context of the protection system. There is no need
for the standard to reflect the inherent difference between various protection system
technologies as the utility would account for differences within their stated maintenance
practices.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest Reliability Organization (MRO)
Lead Contact:
Joe Knight
Contact Organization:
MRO for Group (GRE - for lead contact)
Contact Segment:
10
Contact Telephone:
763.241.5633
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Neal Balu
WPS
MRO
10
Terry Bilke
MISO
MRO
10
Robert Coish, Chair
MHEB
MRO
10
Carol Gerou
MP
MRO
10
Ken Goldsmith
ALT
MRO
10
Jim Haigh
WAPA
MRO
10
Tom Mielnik
MEC
MRO
10
Pam Oreschnick
XEL
MRO
10
Dave Rudolph
BEPC
MRO
10
Eric Ruskamp
LES
MRO
10
Mike Brytowski, Secretary
MRO
MRO
10
28 Additional Members
Not Named Above
MRO
10
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments: FERC Order 693 in both paragraph 1466 and in footnote 384, indicates that
in some areas of the country, Load Serving Entities (LSE) and Transmission Operators
(TOP) may individually or jointly own and operate a protection system. Thus, these
additional entities should be subject to the resulting consolidated standard. The MRO
believes that the following caveat should be added to the LSE where it is listed as an
Applicable Entity, (where operation of the protection system can affect the Bulk Electric
System).
2. The MRO requests that the SDT review whether or not the Reliability Coordinator
(RC) should be added to the list of Applicable Entities given their wide area view-for
example, the RC may need to be involved in determining which protection systems
below 100kV will affect the BES.
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance: None
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice: None
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments:
1. The MRO commends NERC and the SDT for taking steps to remove some of the
redundancy that currently exists among many of the standards today. The
consolidation of the protection system maintenance and testing standards is a good
first step.
2. The MRO requests that the following be considered during the initial drafting of the
Requirements for this new protection and maintenance standard. A minimum set of
evidence to be included in a maintenance and testing program should be established in
the measures for R1.2.
3. In the SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0,
the clarification for R2 states that documentation is available to its Regional Reliability
Organization and NERC during audits or upon request within 30 days but paragraph
1545 of FERC Order 693 states "be routinely provided to the ERO or Regional Entity
and not only when it is requested." The MRO believes that the FERC request would be
satisfied if the standard were to state: "the applicable entities shall provide testing
records to the Regional Entity on a periodic basis e.g. (annually).
4. In the event that the SAR DT does not become the SDT, the MRO requests that
these comments be forwarded on to the group that will do tha actual drafting of the
Standard.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
NPCC, CP9 Reliabiity Standards Working Group
Lead Contact:
Guy V. Zito
Contact Organization:
Northeast Power Coordinating Council
Contact Segment:
10
Contact Telephone:
212-840-1070
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Ralph Rufrano
New York Power Authority
NPCC
1
Kathleen Goodman
ISO-New England
NPCC
2
Greg Campoli
New York ISO
NPCC
2
Donald Nelson
MADPU
NPCC
9
David Kiguel
Hydro One Networks
NPCC
1
Ron Falsetti
The IESO
NPCC
2
Roger Champagne
TransEnergie HydroQuebec
NPCC
1
Murale Gopinathan
Northeast Utilities
NPCC
1
Michael Gildea
Constellation Energy
NPCC
6
Glen McCartney
Constellation Energy
NPCC
6
Al Adamson
New York State Reliability Council
NPCC
10
Michael Shiavone
National Grid US
NPCC
1
Guy V. Zito
NPCC
NPCC
10
Bill Shemley
ISO-New England
NPCC
2
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments: Each requirement needs to specifically address what protection systems
need to comply with the standard - i.e. a generator not connected to the BPS with
under frequency trip relay should only be subject to under frequency relay maintenance
requirements
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance: None
Comments: Certain unavoidable delays like the inability to schedule outages for
reliability reasons or labor disputes, or force-majeure conditions could affect testing
period requirements. These factors should be considered and certain latitude, with the
"appropriate approvals", needs to be provided for delays in the testing process.
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments: none that we know of
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: Due consideration should be given to potential difficulties in obtaining
required outages. System reliability concerns may preclude performing maintenance at
the intervals required. Certain unavoidable delays like the inability to schedule outages
for reliability reasons, labor disputes, or force-majeure conditions could affect testing
period requirements. These factors should be considered and certain latitude needs to
be provided, with "appropriate" approvals, for delays in the testing process.
There is need to specify which types of relays will be covered by the new standard. The
SAR Team needs to focus on better defining the Generator Protection Schemes (“GPS”)
that would be subject to this Standard – i.e., what subset of GPS are critical to bulk
power system operation, as distinct from generator operation. For example, typically
there is no single generating unit that would, if a contingency event occurs on that
generating unit, result in significant adverse impacts outside of the local area in which
the single generating unit is located. As a result, if these NERC Standards are to apply
to all NERC-registered Generators, only a subset of the GPS need to be subjected to the
maintenance testing intervals.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Pepco Holdings, Inc. - Affiliates
Lead Contact:
Richard Kafka
Contact Organization:
Pepco Holdings, Inc.
Contact Segment:
1
Contact Telephone:
301-469-5274
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Carl Kinsley
Delmarva Power & Light
RFC
1
Alvin Depew
Potomac Electric Power Company
RFC
1
Evan Sage
Potomac Electric Power Company
RFC
1
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: This SAR will bring needed coherence to what are now several related
standards.
Page 4 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Public Service Commission of South Carolina
Lead Contact:
Phil Riley
Contact Organization:
Public Service Commission of South Carolina
Contact Segment:
9
Contact Telephone:
803-896-5154
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mignon L. Clyburn
Public Service Commission of SC
SERC
9
Elizabeth B. "Lib" Fleming
Public Service Commission of SC
SERC
9
G. O'Neal Hamilton
Public Service Commission of SC
SERC
9
John E. "Butch" Howard
Public Service Commission of SC
SERC
9
Randy Mitchell
Public Service Commission of SC
SERC
9
C. Robert "Bob" Moseley
Public Service Commission of SC
SERC
9
David A. Wright
Public Service Commission of SC
SERC
9
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments: N/A
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments: N/A
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: N/A
Page 4 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Mike Gentry
Organization: Salt River Project
Telephone:
602-236-6408
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: None.
Page 4 of 4
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
SERC EC Protection & Control Subcommittee (PCS)
Lead Contact:
Jay Farrington
Contact Organization:
Alabama Electric Cooperative, Inc.
Contact Segment:
1
Contact Telephone:
(334) 427-3225
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Robert Rauschenbach
Ameren
SERC
1
Charlie Fink
Entergy
SERC
1
Jammie Lee
Entergy
SERC
1
Tom Seeley
E.ON-U.S.
SERC
1
Steve Waldrep
Georgia Power Company
SERC
1
Hong-Ming Shuh
Georgia Transmission Corporation
SERC
1
Neal Jones
Georgia Transmission Corporation
SERC
1
Jerry Blackley
Progress Energy Carolinas
SERC
1
Pat Huntley
SERC Reliability Corp.
SERC
10
Marion Frick
South Carolina Electric & Gas Co.
SERC
1
Bridget Coffman
South Carolina Public Service
SERC
1
Authority
George Pitts
Tennessee Valley Authority
SERC
1
Meyer Kao
Tennessee Valley Authority
SERC
1
Phil Winston
Georgia Power Company
SERC
1
Ernesto Paon
Municipal Electric Authority of
SERC
1
Georgia
Page 2 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 3 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 4 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments: Consolidation of the maintenance and testing standards is appropriate.
Separate definitions for maintenance and testing are needed.
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance: none
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice: none
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: The SERC EC PCS supports the work of the NERC SPCTF in their
assessments of these standards.
Page 5 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Page 6 of 6
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southern Company Transmission
Lead Contact:
Roman Carter
Contact Organization:
Southern Company Transmission
Contact Segment:
1
Contact Telephone:
205.257.6027
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Marc Butts
Southern Co. Transmission
SERC
1
JT Wood
Southern Co. Transmission
SERC
1
Jim Busbin
Southern Co. Transmission
SERC
1
Phil Winston
Georgia Power Co.
SERC
3
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice:
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: In the SAR you state "The revised PRC-005 standard should address the
issues raised in the FERC Order 693". With the exception of mentioning the
consolidation of the standards into one standard, the SAR drafting team didn't provide
readers with the exact language from FERC that would be useful to know with respect
to PRC-005 in the directive below:
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
The Commission directs the ERO to develop a modification to PRC-005-1 through the
Reliability Standards development process that includes a requirement that
maintenance and testing of a protection system must be carried out within a maximum
allowable interval that is appropriate to the type of the protection system and its
impact on the reliability of the Bulk-Power System. We further direct the ERO to
consider FirstEnergy’s and ISO-NE’s suggestion to combine PRC-005-1, PRC-008-0,
PRC-011-0 and PRC-017-0 into a single Reliability Standard through the Reliability
Standards development process.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
IRC Standards Review Committee
Lead Contact:
Charles Yeung
Contact Organization:
SPP
Contact Segment:
2
Contact Telephone:
832-724-6142
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Jim Castle
NYISO
NPCC
2
Alicia Daugherty
PJM
RFC
2
Ron Falsetti
IESO
NPCC
2
Matt Goldberg
ISO-NE
NPCC
2
Brent Kingsford
CAISO
WECC
2
Anita Lee
AESO
WECC
2
Steve Myers
ERCOT
ERCOT
2
William Phillips
MISO
RFC+MRO+SERC
2
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments:
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments:
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance:
Comments:
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice: none
Comments:
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments:
1. The SRC commends NERC, the SDT and the SPCTF for providing clarity and for
efforts to reduce the costs of compliance.
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
2 In the Standard PRC-008-0, Generation Owners were not included in the applicable
entities. Generation Owners may have underfrequency tripping devices for protection
of their units. It would be appropriate to include these devices for maintenance and
testing requirements also.
3. Further, there is need to specify which types of relays will be covered by the new
standard. The SAR Team needs to focus on better defining the Generator Protection
Schemes ("GPS") that are critical to bulk power system operation, as distinct from
generator operation. For example, a single generating unit may experience
contingency events that would not result in any significant adverse impacts outside the
local area in which the single generating unit is located. As a result, there remains a
need to subject those GPSs that are important to the Bulk Power System, such as
generator underfrequency trip settings, to the maintenance testing intervals to be
derived in these standards.
4. Certain unavoidable delays like the inability to schedule outages for reliability
reasons, labor disputes, or force-majeure conditions could affect testing period
requirements. These factors should be considered and certain latitude needs to be
provided for delays in the testing process.
5. However, the SAR team needs to also consider,as part of its scope, assurance that
the asset owner has taken all appropriate steps to assure that required outages are
appropriately planned and can be reasonably accommodated and approved by the TOP
or RC.
Page 5 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Please use this form to submit comments on the proposed SAR for Project 2007-17 —
Protection System Maintenance and Testing. Comments must be submitted by July 10,
2007. You may submit the completed form by e-mail to [email protected] with the
words “Protection Maintenance” in the subject line. If you have questions please contact Al
Calafiore at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southwest Transmission Cooperative, Inc.
Lead Contact:
E. William Riley
Contact Organization:
Southwest Transmission Cooperative, Inc.
Contact Segment:
1
Contact Telephone:
520-586-5440
Contact E-mail:
[email protected]
Additional Member Name
Tom D. Spence, P.E
Additional Member
Organization
Southwest Transmission Coop., Inc.
Region*
WECC
Segment*
1
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Background Information
This SAR proposes to merge the requirements from the following standards into a single
standard to reduce the costs of compliance while also improving efficiencies:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
-
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
-
PRC-011-0 — UVLS System Maintenance and Testing
-
PRC-017-0 — Special Protection System Maintenance and Testing
The SAR also proposes to address the FERC directives in Order 693 and to address a
number of technical short comings identified by stakeholders and the System Protection
and Control Task Force and to bring the standard into conformance with the “Standard
Review Guidelines.” The goal is to provide a set of requirements that will support reliable
performance when responding to abnormal system conditions.
Please review the SAR and then answer the questions on the following page. Please e-mail
your comments on this form to [email protected] with the subject “Protection
Maintenance SAR” by July 10, 2007.
Page 3 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to improve the requirements in this
set of standards?
Yes
No
Comments: This SAR proposes to revise several standards to eliminate ambiguities and
to provide requirements that are measurable. In addition, the SPCTF report
“Assessment of PRC-005-1 – Transmission and Generation Protection System
Maintenance and Testing; with implications for PRC-008-0, PRC-011-0, and PRC-017-0”
indicates the need to differentiate between the different technologies used and insure
the standard applies to all in the appropriate way (i.e. electromechanicals,
microprocessor-based, solid-state). Southwest Transmission Cooperative, Inc. also
recognizes this deficit in the existing standards.
2. Do you agree with the proposed scope of this SAR?
Yes
No
Comments: Since most protection schemes are maintained and tested in a similar
manner regardless of scheme type, we agree that combining the (4) PRC standards
related to maintenance and testing of different types of systems into one standard will
create a that is more streamlined and less burdensome standard with easily understood
measurable compliance elements.
The most exciting part of the proposed modifications is the inclusion of condition-based
and performance-based maintenance and testing and not just time-based criteria.
Presently Southwest Transmission Cooperative, Inc. uses this type of maintenance and
testing criteria (maintenance data server) which is the current system protection
industry technology.
3. Do you agree with the applicability of the proposed SAR (Transmission Owners,
Generator Owners and Distribution Providers - Distribution Providers may own the
devices that must be tested and maintained)?
Yes
No
Comments:
4. If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area.
Regional Variance: N/A
Page 4 of 5
Comment Form — First Draft of SAR for Project 2007-17 — Protection System
Maintenance and Testing
Comments: Not aware of any Regional Variance requirements
5. If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us.
Business Practice: N/A
Comments: Not aware of any Business Practice needs
6. If you have any other comments on this SAR that you haven’t provided above, please
provide them here.
Comments: N/A
Page 5 of 5
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
The Protection System Maintenance and Testing SAR requesters thank all commenters who
submitted comments on the first draft of SAR. This SAR was posted for a 30-day public
comment period from June 11 through July 10, 2007. The requesters asked stakeholders to
provide feedback on the standard through a special SAR Comment Form. There were 18 sets of
comments, including comments from 85 different people from more than 50 companies
representing 8 of the 10 Industry Segments as shown in the table on the following pages.
The SAR drafting team made no changes to the SAR based on stakeholder comments.
Based on the comments received, the drafting team is recommending that the Standards
Committee authorize moving the SAR forward to the standard drafting stage of the standards
development process.
In this “Consideration of Comments” document stakeholder comments have been organized so
that it is easier to see the responses associated with each question. All comments received on
the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal
is to give every comment serious consideration in this process! If you feel there has been an
error or omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060
or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
1.
Anita Lee (G6)
AESO
2.
Jay Farrington
(G2)
Alabama Electric Coop.,
Inc.
3.
Ken Goldsmith
(G5)
ALT
4.
Robert
Rauschenbach
(G2)
Ameren
9
5.
Thad Kness
American Electric Power
(AEP)
9
6.
Dave Rudolph
(G4)
BEPC
7.
Dean Bender
Bonneville Power
Administration (BPA)
8.
Brent Kingsford
(G6)
CAISO
9.
Alan Gale
City of Tallahassee
(FRCC)
10.
Glen McCartney
(G4)
Constellation Energy
9
11.
Michael Gildea
(G4)
Constellation Energy
9
12.
Nancy C. Denton
Consumers Energy
Company
13.
Greg Rowland
Duke Energy
14.
Tom Seeley (G2)
E. ON-U.S.
9
15.
Charlie Fink (G2)
Entergy
9
16.
Jammie Lee (G2)
Entergy
9
17.
Steve Myers (G6)
ERCOT
9
9
9
9
9
9
9
9
9
9
9
9
9
9
18.
Doug Hohlbaugh
(G7)
FirstEnergy Corp. (FE)
9
19.
Craig Boyle (G7)
Transm. Substa.
9
Page 2 of 19
9
9
9
July 26, 2007
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
Maintenance (FE)
20.
Ken Ddresner (G7)
Fossil Generation (FE)
9
21.
Bill Duge (G7)
Nuclear Generation (FE)
9
22.
Dave Powell (G7)
Transm. Planning &
Protection (FE)
9
23.
Jeff Mackauer(G7)
Transm. Planning &
Protection (FE)
9
24.
Eric Senkowizc
FRCC
25.
Phil Winston (G3)
Georgia Power Company
26.
Steve Waldrep
(G2)
Georgia Power Company
9
27.
Phil Winston (G2)
Georgia Power Company
9
28.
Hong-Ming Shuh
(G2)
Georgia Transmission
Corp.
9
29.
Neal Jones (G2)
Georgia Transmission
Corp.
9
30.
David Kiguel (G4)
Hydro One Networks
9
31.
Ron Falsetti (I)
(G6)
IESO
9
32.
Matt Goldberg
(G6)
ISO- New England
9
33.
Kathleen Goodman
(G4)
ISO-New England
9
34.
William Shemley
(G4)
ISO-New England
9
35.
Eric Ruskamp (G4)
LES
36.
Donald Nelson
(G4)
MADPC
37.
Tony Clark
Manitoba Hydro
38.
Tom Mielnik (G4)
MEC
9
39.
Robert Coish (G5)
MHEB
9
40.
Joe Knight (G5)
Midwest Reliability
Organization
9
41.
Mike Brytowski
(G4)
Midwest Reliability
Organization
9
42.
Terry Bilke (G5)
MISO
9
43.
William Phillips
(G6)
MISO
44.
Carol Gerou (G5)
Minnesota Power (MP)
45.
Ernesto Paon (G2)
Municipal Electric
Authority of GA
9
46.
Michael Shiavone
(G4)
National Grid US
9
9
9
9
9
9
9
9
9
9
Page 3 of 19
9
July 26, 2007
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
47.
Greg Campoli (G4)
New York ISO
48.
Ralph Rufrano
(G4)
New York Power
Authority
9
49.
Murale Gopinathan
(G4)
Northeast Utilities
9
50.
Guy V. Zito (G4)
NPCC
9
51.
Al Adamson (G4)
NY State Reliability
Council
9
52.
Jim Castle (G6)
NYISO
53.
Richard Kafka
(G8)
Pepco Holdings, Inc.
54.
Alicia Daugherty
(G6)
PJM
55.
Jerry Blackley
(G2)
Progress Energy
Carolinas
56.
Phil Riley (G1)
PSC of South Carolina
9
57.
Mignon L. Clyburn
(G1)
PSC of South Carolina
9
58.
Elizabeth B.
Fleming (G1)
PSC of South Carolina
9
59.
G. O’Neal
Hamilton (G1)
PSC of South Carolina
9
60.
John E. Howard
(G1)
PSC of South Carolina
9
61.
Randy Mitchell
(G1)
PSC of South Carolina
9
62.
C. Robert Moseley
(G1)
PSC of South Carolina
9
63.
David A. Wright
(G1)
PSC of South Carolina
9
64.
Mike Gentry
Salt River Project (SRP)
9
65.
Bridget Coffman
(G2)
SC Public Service
Authority
9
66.
Pat Huntley (G2)
SERC Reliability Corp.
67.
Roman Carter
(G3)
So. Company
Transmission
9
68.
Marc Butts (G3)
So. Company
Transmission
9
69.
JT Wood (G3)
So. Company
Transmission
9
70.
Jim Busbin (G3)
So. Company
Transmission
9
71.
Marion Frick (G2)
South Carolina Electric &
Gas Co.
9
9
9
Page 4 of 19
9
9
July 26, 2007
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
72.
Charles Yeung
(G6)
Southwest Power Pool
73.
E. William Riley
Southwest Transmission
Co., Inc.
9
74.
Tom D. Spence
Southwest Transmission
Co., Inc.
9
75.
George Pitts (G2)
Tennessee Valley
Authority
9
76.
Meyer Kao (G2)
Tennessee Valley
Authority
9
77.
Ron Falsetti (G4)
(G6)
The IESO
78.
Roger Champagne
(G4)(I)
TransÉnergie HydroQuébec (HQTE)
79.
Jim Haigh (G4)
WAPA
9
80.
Neal Balu (G5)
WPS
9
81.
Pam Oreschnick
(G4)
XEL
9
82.
Carl Kinsley (G8)
Delmarva Power & Light
9
83.
Alvin Depew (G8)
Potomac Electric Power
Company
9
84.
Evan Sage (G8)
Potomac Electric Power
Company
9
9
9
I – Indicates that individual comments were submitted in addition to comments submitted as part of a
group
G1 – Public Service Commission of South Carolina (PSC SC)
G2 – SERC EC Protection & Control Subcommittee (SERC EC PCS)
G3 – Southern Company Transmission
G4 – NPCC CP9 Reliability Standards Working Group (NPCC CP9 RSWG)
G5 – MRO Members (MRO)
G6 – IRC Standards Review Committee (IRC)
G7 – FirstEnergy Corp. (FE)
G8 – Pepco Holdings, Inc.
Page 5 of 19
July 26, 2007
Consideration of Comments on 1st Draft of Protection System Maintenance and
Testing SAR (Project 2007-17)
Index to Questions, Comments, and Responses
1.
Do you agree that there is a reliability-related need to improve the requirements in this
standard?.............................................................................................................. 7
2.
Do you agree with the proposed scope of this SAR?..................................................... 9
3.
Do you agree with the applicability of the proposed SAR (Transmission Owners, Generator
Owners and Distribution Providers - Distribution Providers may own the devices that must
be tested and maintained)? ....................................................................................12
4.
If you know of a Regional Variance that should be developed as part of this SAR, please
identify that for us. If not, please explain in the comment area. ..................................14
5.
If you are aware of a Business Practice that needs to be developed to support the
proposed SAR, please identify that for us. .................................................................15
6.
If you have any other comments on this SAR that you haven’t provided above, please
provide them here. ................................................................................................16
Page 6 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
1. Do you agree that there is a reliability-related need to improve the requirements in this standard?
Summary Consideration: Most commentators indicated they do believe there is a reliability-related need to improve the
requirements in this set of standards.
Question #1
Commenter
AEP
Yes
No
Comment
has not had an event, due to deficiencies in protection maintenance, in it's long
; AEP
existence that jeopardized the reliability or availability of Bulk Power transfers. Simply
combining multiple standards into one, does nothing for improving reliability.
Response: The proposed changes will improve clarity which should benefit reliability. While AEP may have an excellent
record of maintenance, the existing standards are quite vague and allow an entity that performs maintenance once every 100
years to be fully compliant.
Manitoba Hydro
There is a need to better define and explain the terms "maintenance" and "testing" as
; they
relate to this standard. Also a tighter definition as to which systems are considered
to affect the BES is required. The need to improve the standard is driven by the
administration of the standard rather than reliability.
Response: As envisioned, the SDT will work with stake holders to define the terms ‘maintenance’ and ‘testing.’
The SAR DT disagrees that the standard changes are driven by “administration”. The existing requirements are vague enough
to allow an entity to perform maintenance once every 100 years and still be compliant.
SWTC
This SAR proposes to revise several standards to eliminate ambiguities and to provide
;
requirements that are measurable. In addition, the SPCTF report “Assessment of PRC005-1 – Transmission and Generation Protection System Maintenance and Testing; with
implications for PRC-008-0, PRC-011-0, and PRC-017-0” indicates the need to
differentiate between the different technologies used and insure the standard applies to
all in the appropriate way (i.e. electro-mechanicals, microprocessor-based, solid-state).
Southwest Transmission Cooperative, Inc. also recognizes this deficit in the existing
standards.
Response: The SAR DT agrees and appreciates your support.
SERC EC PCS
Consolidation of the maintenance and testing standards is appropriate. Separate
;
definitions for maintenance and testing are needed.
Response: The SAR DT agrees and appreciates your support.
FRCC
Centralizing System Protection equipment maintenance and testing requirements in a
;
single standard will add clarity, minimize synchronization issues across standards, help
provide consistent terminology and improve understanding of system protection
standards.
Response: The SAR DT agrees and appreciates your support.
Page 7 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #1
Commenter
PSC SC
BPA
Consumers Energy
IESO
SRP
SOCO Transmission
NPCC CP9 RSWG
MRO
IRC
FirstEnergy
HQT
Pepco Holdings
Duke Energy
Yes
No
Comment
;
;
;
;
;
;
;
;
;
;
;
;
;
Page 8 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
2. Do you agree with the proposed scope of this SAR?
Summary Consideration: Some entities objected to the use of ‘maximum allowable intervals,’ however, FERC has ordered
that maximum allowable intervals be developed. No changes to the SAR were made in response to these comments.
Question #2
Commenter
AEP
Yes
No
;
Comment
On the surface, the premise of reducing costs and improving efficiencies by combining
multiple standards sounds excellent. Having to only keep up with one standard instead of
four will not generate significant savings due to the fact that the maintenance will still
have to be performed. But what lies hidden, is the fact that prescribed maximum
allowable maintenance intervals will result from the revisions. They may require more
frequent testing to be performed. Is there evidence that increasing the interval
frequency results in a measurable increase in reliability and availability? Development of
prescribed maximum intervals that are vastly different than the utility's existing
practices may actual increase their O&M costs and reduce efficiencies.
The function of the protective system needs to be taken into account. The purpose of
the line protection is very different than the purpose of UFLS/UVLS and SPS's. The UFLS
program is there as the last line of defense against a decaying system after all other
measures have failed. The combination of all the different relaying systems places them
on equal ground. Shouldn't the reliability and dependability for one be more important
than the others?
Response: In order to develop a measurable standard and conform to the direction from FERC regarding allowable
maintenance intervals, the SDT, working with stakeholders, will develop requirements for maximum allowable maintenance
intervals for protection systems.
Combining these 4 standards into 1 does not preclude the SDT from developing different criteria for different types of
protection systems. Your concerns regarding the different purposes of protection systems and your question regarding
varying importance of different protection systems will be forwarded to the SDT.
Manitoba Hydro
We disagree that there is a need to change the standard to include more specificity for
; maintenance
and test procedures. We also disagree with mandating minimum
maintenance intervals for protection system equipment.
Response: FERC has directed NERC as the ERO to specify maximum allowable maintenance intervals.
Duke Energy
PRC-005, 008, 011 and 017 into one new standard does not seem to be the
; Combining
best approach. Duke Energy does not have UVLS systems or Special Protection
Systems. Furthermore, Duke Energy's Underfrequency Load Shedding system is on the
transmission system in the Carolinas, but on the distribution system in the Midwest.
Page 9 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #2
Commenter
Yes
No
Comment
Combining these standards would likely create confusion and compliance issues for us
and others as well. Also, combining the standards is unlikely to result in simplification,
as different requirements associated with the different protection systems could have
different Violation Risk Factors and levels of non-compliance, which would necessitate
keeping them separate in the combined standard, which would defeat the purpose of
combining them in the first place.
Response: Combining these 4 standards into 1 does not preclude the SDT from developing different criteria for different
types of protection systems (concerns about different voltage levels remain regardless if there is one standard or more than
one).
SWTC
Since most protection schemes are maintained and tested in a similar manner regardless
;
of scheme type, we agree that combining the (4) PRC standards related to maintenance
and testing of different types of systems into one standard will create a that is more
streamlined and less burdensome standard with easily understood measurable
compliance elements.
The most exciting part of the proposed modifications is the inclusion of condition-based
and performance-based maintenance and testing and not just time-based criteria.
Presently Southwest Transmission Cooperative, Inc. uses this type of maintenance and
testing criteria (maintenance data server) which is the current system protection
industry technology.
Response: Thank you for your support.
FirstEnergy
Bullet #5 of the "Detailed Description" on page SAR-2 indicates the following:
;
"Applicable to all four standards — The requirements of the existing standards, as
stated, support time-based maintenance and testing, and should be expanded to
include condition-based and performance-based maintenance and testing. The
requirements for maintenance and testing procedures need to have more specificity
to insure that the stated intent of the standards is met to support review by the
compliance monitor."
FE supports the scope of the SAR to consider adding the ability for condition-based and
performance-based testing, as suggested by the System Protection and Control Task
Force. Additionally, the SDT should consider the need to perform some level of
preventative maintenance on a periodic basis at an established maximum interval length,
that would vary per the equipment being maintained. The interval established would be
based on established guidelines from vendors, EPRI, industry experts, etc.
Page 10 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #2
Commenter
Yes No
Comment
Response: Thank you- The SDT will develop maximum allowable maintenance intervals for protection systems, working with
stakeholders.
FRCC
of subject matter experts (NERC SPCTF) along with the NERC Planning Committee
; ; Use
review of the assessment is an effective and efficient way to supplement project SARs
and provides critical input at the front-end of the standards process.
Attachment A is described as the SPCTF assessment, but attachment A to the SAR is the
SPCTF roster. The assessment referenced in the scope of the SAR should include "Draft
1.0" if the full assessment is not included as part of the SAR.
Response: The attachments and supporting material references will be posted.
PSC SC
;
SERC EC PCS
BPA
Consumers Energy
IESO
SRP
SOCO Transmission
NPCC CP9 RSWG
MRO
IRC
HQT
Pepco Holdings
;
;
;
;
;
;
;
;
;
;
;
Page 11 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
3. Do you agree with the applicability of the proposed SAR (Transmission Owners, Generator Owners and Distribution
Providers - Distribution Providers may own the devices that must be tested and maintained)?
Summary Consideration: Based on comments received no changes were made to the SAR
Question #3
Commenter
Yes No
Comment
FRCC
This question may be better addressed as the standards are integrated.
Response: The SAR DT is obligated to address the applicability,
MRO
Order 693 in both paragraph 1466 and in footnote 384, indicates that in some
; FERC
areas of the country, Load Serving Entities (LSE) and Transmission Operators (TOP) may
individually or jointly own and operate a protection system. Thus, these additional
entities should be subject to the resulting consolidated standard. The MRO believes that
the following caveat should be added to the LSE where it is listed as an Applicable Entity,
(where operation of the protection system can affect the Bulk Electric System).
2. The MRO requests that the SDT review whether or not the Reliability Coordinator
(RC) should be added to the list of Applicable Entities given their wide area view-for
example, the RC may need to be involved in determining which protection systems below
100kV will affect the BES.
Response: FERC Order 693 in both paragraph 1466 and in footnote 384 reiterates IESO-NE comments on the NOPPR. The
FERC directive was to consider this comment. According to the NERC Functional Model, Load-serving Entities, Transmission
Operators and Reliability Coordinators are not owners of protection systems – and the entity responsible for maintenance is
the facility owner.
NPCC CP9 RSWG
requirement needs to specifically address what protection systems need to comply
; ; Each
HQT
with the standard - i.e. a generator not connected to the BPS with under frequency trip
relay should only be subject to under frequency relay maintenance requirements.
Response: Your comment will be referred to the SDT for consideration when convened.
FirstEnergy
The inclusion of the Distribution Provider is generally needed for UFLS and UVLS relays.
;
The confusion that previously existed in PRC-005 by including the DP entity should be
mitigated by the proposed consolidation of the four maintenance standards.
Response: Thank you for your comment.
PSC SC
;
SERC EC PCS
AEP
BPA
;
;
;
Page 12 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #3
Commenter
Consumers Energy
IESO
SRP
SOCO Transmission
SWTC
IRC
Pepco Holdings
Duke Energy
Yes
No
Comment
;
;
;
;
;
;
;
;
Page 13 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
4. If you know of a Regional Variance that should be developed as part of this SAR, please identify that for us. If not,
please explain in the comment area.
Summary Consideration: No regional variances were identified by the commentators
Question #4
Commenter
NPCC CP9 RSWG
Regional
Variance
None
Comment
Certain unavoidable delays like the inability to schedule outages for reliability reasons or
labor disputes, or force-majeure conditions could affect testing period requirements.
These factors should be considered and certain latitude, with the "appropriate
approvals", needs to be provided for delays in the testing process.
Response: This is a compliance issue not a regional variance – The compliance enforcement program does give the
compliance monitor latitude to consider extenuating circumstances.
PSC SC
N/A
SERC EC PCS
None
AEP
None
BPA
No known
regional
variance.
Consumers Energy
N/A
SWTC
N/A
Not aware of any Regional Variance requirements.
MRO
None
FirstEnergy
Not aware of any.
HQT
None
Page 14 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
5. If you are aware of a Business Practice that needs to be developed to support the proposed SAR, please identify that for
us.
Summary Consideration: No needs for development of Business Practices were identified by the commentators.
Question #5
Commenter
AEP
Business
Practice
Possibly
Comment
AEP and other utilities, with many years of experience serving customers and supporting
the electric grid, have voluntarily integrated maintenance and testing programs into the
core of their work practices and processes. AEP fully supports improvements if they
truly foster reliability and availability benefits to bulk power transfers. More Standards,
Requirements and Business Practices are not always better. If Standards create burdens
on a utility's physical resources and budgets, then some mechanism must be available to
allow for the needed changes.
Response: Please monitor the work of the SDT and advise the team if added burdens are created by any of the proposed
requirement and advise the team of the need for any business practice or other mechanism necessary to support the
proposed requirements.
PSC SC
N/A
SERC EC PCS
None
Consumers Energy
N/A
SWTC
N/A
Not aware of any Business Practice needs.
NPCC CP9 RSWG
None that
we know
of.
MRO
None
IRC
None
FirstEnergy
Not aware of any.
HQT
None that we know of.
Page 15 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
6. If you have any other comments on this SAR that you haven’t provided above, please provide them here.
Question #6
Commenter
Comment
SERC EC PCS
The SERC EC PCS supports the work of the NERC SPCTF in their assessments of these standards.
Response: Thank you for your support
AEP
The standard should not use the term Bulk Electric System, but should instead specify a voltage
threshold for impacts to bulk system transfers - specifically; 'Facilities operated 200 kV and above
and Regionally-defined, Operationally Significant facilities operated greater than 100 kV, but less
than 199 kV'. The term 'affects' also needs to be clarified. Inclusion of all facilities greater than 100
kV does not benefit the reliability of national bulk power transfers. For example, the loss or
misoperation of a 138 kV line serving a localized load center would not be detrimental to bulk power
transfers multiple busses away.
Response: Your comment will be referred to the drafting team when convened for consideration when drafting the standard.
BPA
In the "Detailed Description" section of the SAR, it states:
"Part of the stated purpose in PRC-017 is: “To ensure that maintenance and testing programs are
developed and misoperations are analyzed and corrected.” The phrase “and misoperations are
analyzed and corrected” is not clearly appropriate in a maintenance and testing standard. That is the
purpose is more appropriate in PRC-003 and PRC-004, which relate to the analysis and mitigation of
protection system misoperations. Analysis of correct operations or misoperations may be an integral
part of condition-based maintenance processes, but need not be mandated in a maintenance
standard."
The analysis of SPS misoperations is handled in PRC-016 (SPS Misoperations) and PRC 012 (SPS
review Procedure) not in PRC-003 or PRC-004. Therefore, if the phrase is removed from PRC-017, it
does not need to be added to PRC-003 or PRC-004.
Response: We agree. Please see the purpose statement as stated in the SAR.
SOCO Transmission
In the SAR you state "The revised PRC-005 standard should address the issues raised in the FERC
Order 693". With the exception of mentioning the consolidation of the standards into one standard,
the SAR drafting team didn't provide readers with the exact language from FERC that would be useful
to know with respect to PRC-005 in the directive below:
The Commission directs the ERO to develop a modification to PRC-005-1 through the Reliability
Standards development process that includes a requirement that maintenance and testing of a
protection system must be carried out within a maximum allowable interval that is appropriate to the
type of the protection system and its impact on the reliability of the Bulk-Power System. We further
direct the ERO to consider FirstEnergy’s and ISO-NE’s suggestion to combine PRC-005-1, PRC-008-0,
Page 16 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #6
Commenter
Comment
PRC-011-0 and PRC-017-0 into a single Reliability Standard through the Reliability Standards
development process.
Response: The SAR DT Agrees – the SAR DT will make sure that all appropriate documents are included in its next posting
of the SAR.
MRO
1. The MRO commends NERC and the SDT for taking steps to remove some of the redundancy that
currently exists among many of the standards today. The consolidation of the protection system
maintenance and testing standards is a good first step.
2. The MRO requests that the following be considered during the initial drafting of the Requirements
for this new protection and maintenance standard. A minimum set of evidence to be included in a
maintenance and testing program should be established in the measures for R1.2.
3. In the SPCTF Assessment of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0, the clarification
for R2 states that documentation is available to its Regional Reliability Organization and NERC during
audits or upon request within 30 days but paragraph 1545 of FERC Order 693 states "be routinely
provided to the ERO or Regional Entity and not only when it is requested." The MRO believes that the
FERC request would be satisfied if the standard were to state: "the applicable entities shall provide
testing records to the Regional Entity on a periodic basis e.g. (annually).
4. In the event that the SAR DT does not become the SDT, the MRO requests that these comments
be forwarded on to the group that will do tha actual drafting of the Standard.
Response: The SAR DT will forward your comments to the SDT for consideration as required by the process
IRC
1. The SRC (IESO) commends NERC, the SDT and the SPCTF for providing clarity and for efforts to
IESO
reduce the costs of compliance.
2 In the Standard PRC-008-0, Generation Owners were not included in the applicable entities.
Generation Owners may have underfrequency tripping devices for protection of their units. It would
be appropriate to include these devices for maintenance and testing requirements also.
3. Further, there is need to specify which types of relays will be covered by the new standard. The
SAR Team needs to focus on better defining the Generator Protection Schemes ("GPS") that are
critical to bulk power system operation, as distinct from generator operation. For example, a single
generating unit may experience contingency events that would not result in any significant adverse
impacts outside the local area in which the single generating unit is located. As a result, there
remains a need to subject those GPSs that are important to the Bulk Power System, such as
generator underfrequency trip settings, to the maintenance testing intervals to be derived in these
standards.
4. Certain unavoidable delays like the inability to schedule outages for reliability reasons, labor
Page 17 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #6
Commenter
Comment
disputes, or force-majeure conditions could affect testing period requirements. These factors should
be considered and certain latitude needs to be provided for delays in the testing process.
5. However, the SAR team needs to also consider, as part of its scope, assurance that the asset
owner has taken all appropriate steps to assure that required outages are appropriately planned and
can be reasonably accommodated and approved by the TOP or RC.
Response:
1.Thank you
2. Generator owners are included in the SAR
3. This comment will be forwarded to the SDT
4. The compliance enforcement program does give the compliance monitor latitude to consider extenuating circumstances.
5. There are other standards that require coordination of comments
FRCC
There are many standards being addressed (Disturbance Monitoring, System Protection Coordination,
Reliability Coordination, along with Regional standard developments). As these standards are
integrated into PRC-005, the existing and new terminology should be consistently applied in all
system protection standards (with respect to defined terms). Where terms are undefined or being
revised, the drafting team should carefully consider the terms used to ensure coordination of revised
or new definitions with other Reliability standards or flag conflicts within the implementation plan.
Response: Thank you for your comment, your observation will be forwarded to the SDT for consideration.
NPCC CP9 RSWG
Due consideration should be given to potential difficulties in obtaining required outages. System
HQT
reliability concerns may preclude performing maintenance at the intervals required. Certain
unavoidable delays like the inability to schedule outages for reliability reasons, labor disputes, or
force-majeure conditions could affect testing period requirements. These factors should be considered
and certain latitude needs to be provided, with "appropriate" approvals, for delays in the testing
process.
There is need to specify which types of relays will be covered by the new standard. The SAR Team
needs to focus on better defining the Generator Protection Schemes (“GPS”) that would be subject to
this Standard – i.e., what subset of GPS are critical to bulk power system operation, as distinct from
generator operation. For example, typically there is no single generating unit that would, if a
contingency event occurs on that generating unit, result in significant adverse impacts outside of the
local area in which the single generating unit is located. As a result, if these NERC Standards are to
apply to all NERC-registered Generators, only a subset of the GPS need to be subjected to the
maintenance testing intervals.
Response: 1. The compliance enforcement program does give the compliance monitor latitude to consider extenuating
circumstances.
Page 18 of 19
July 26, 2007
Consideration of Comments on 1st Draft of SAR for Protection System Maintenance and Testing (Project 2007-17)
Question #6
Commenter
Comment
2 Your second comment will be forwarded to the SDT for consideration
Manitoba Hydro
Manitoba Hydro takes exception to the prescriptive nature of the proposed changes to the
maintenance procedures and maintenance intervals. The type of maintenance performed and the
minimum maintenance intervals should be determined by the utility within the operating context of
the protection system. There is no need for the standard to reflect the inherent difference between
various protection system technologies as the utility would account for differences within their stated
maintenance practices.
Response: The proposed changes will improve clarity which should benefit reliability. While Manitoba Hydro may have an
excellent record of maintenance, the existing standards are quite vague and allow an entity that performs maintenance once
every 100 years to be fully compliant.
Pepco Holdings
This SAR will bring needed coherence to what are now several related standards.
Response: Thank you
SRP
None.
PSC SC
N/A
Consumers Energy
None.
SWTC
N/A
FirstEnergy
None.
Page 19 of 19
July 26, 2007
Maureen E. Long
Standards Process Manager
August 15, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Nomination Periods Open for Three Drafting Teams
The Standards Committee announces the following standards actions:
Nominations for Project 2006-01 System Personnel Training Standard Drafting
Team (August 15–29, 2007)
The Standards Committee is seeking additional industry experts to serve on the System
Personnel Training Standard Drafting Team. The new members will join the already-formed
drafting team in developing the following standard:
- PER-005 — System Personnel Training
If you are interested in serving on this standard drafting team, please complete this nomination
form and return it to [email protected] by August 29, 2007 with “System Personnel Training
SDT” in the subject line. For questions, please contact Linda Clarke at 610-310-7210 or
[email protected].
Nominations for Project 2007-06 System Protection Coordination Standard
Drafting Team (August 15–29, 2007)
The Standards Committee is seeking industry experts to serve on the System Protection
Coordination Standard Drafting Team. The drafting team will work on modifications to the
following standard:
- PRC-001 — System Protection Coordination
If you are interested in serving on this standard drafting team, please complete this nomination
form and return it to [email protected] by August 29, 2007 with “System Protection
Coordination SDT” in the subject line. For questions, please contact Al Calafiore at 678-5241188 or at [email protected].
Nominations for Project 2007-17 Protection System Maintenance and Testing
Standard Drafting Team (August 15–29, 2007)
The Standards Committee is seeking industry experts to serve on the Protection System
Maintenance and Testing Standard Drafting Team. If you are interested in serving on this team,
please complete this nomination form and return it to [email protected] with “Protection
System Maintenance SDT” in the subject line by August 29, 2007. For questions, please contact
Al Calafiore at 678-524-1188 or at [email protected].
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
REGISTERED BALLOT BODY
August 15, 2007
Page Two
The drafting team will work on revising the following standards:
-
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate. If you
have any questions, please contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
Nomination Form for Protection System Maintenance and Testing Standard Drafting
Team (Project 2007-17)
Please return this form to [email protected] by August 29, 2007 with the words “Protection
System Maintenance SDT” in the subject line. If you have questions please contact
[email protected] or at 678-524-1188.
All candidates should be prepared to participate actively at these meetings.
Name:
Organization:
Address:
Office
Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the
Protection System Maintenance and Testing Standard Drafting Team. Candidates
should have experience in developing, managing or supporting a maintenance
program or a testing program for one or more of the following:
-
Generator protection systems
-
Transmission protection systems
-
Underfrequency load shedding equipment
-
Undervoltage load shedding equipment
-
Special protection systems
Previous experience working on or applying NERC or IEEE standards is beneficial,
but not a requirement.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Nomination Form for Protection System Maintenance and Testing Standard Drafting Team
(Project 2007-17)
I represent the
following NERC
Reliability
Region(s) (check
all that apply):
I represent the following Industry Segment (check one):
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, and Provincial Regulatory or other
Government Entities
10 — Regional Reliability Organizations and Regional Entities
Which of the following Function(s)1 do you have expertise or responsibilities:
Balancing Authority
Planning Coordinator
Compliance Monitor
Transmission Operator
Distribution Provider
Transmission Owner
Generator Operator
Transmission Planner
Generator Owner
Transmission Service Provider
Interchange Authority
Purchasing-selling Entity
Load-serving Entity
Resource Planner
Market Operator
Reliability Coordinator
Provide the names and contact information for two references who could attest
to your technical qualifications and your ability to work well in a group.
Name:
Office
Telephone:
Organization:
E-mail:
Name:
Office
Telephone:
Organization:
E-mail:
1
These functions are defined in the NERC Functional Model, which is downloadable from the NERC Web site:
http://www.nerc.com/~filez/functionalmodel.html
-2-
Standard PRC-005-2 — Protection System Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approves SAR for posting on June 5, 2007.
2. The SAR was posted for comment from June 11, 2007–July 10, 2007.
3. The SC approves development of the standard on August 13, 2007.
4. Drafting team posts first draft for comments (July 23, 2009).
Description of Current Draft:
This is the initial draft of the Standard. This standard merges previous standards PRC-005-0,
PRC-008-0, PRC-011-0, and PRC-017-0. It also addresses FERC comments from Order 693,
and addresses observations from the NERC System Protection and Control Task Force, as
presented in NERC SPCTF Assessment of Standards: PRC-005-1 — Transmission and
Generation Protection System Maintenance and Testing, PRC-008-0 — Underfrequency Load
Shedding Equipment Maintenance Programs, PRC-011-0 — UVLS System Maintenance and
Testing, PRC-017-0 — Special Protection System Maintenance and Testing.
Future Development Plan:
Anticipated Actions
1. Post response to comments and second draft of standard
and associated documents.
Draft 1: July 21, 2009
Anticipated Date
To be determined.
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which
Protection System components are kept in working order and proper operation of malfunctioning
components is restored. A maintenance program can include:
Verification — A means of determining that the component is functioning
correctly.
Monitoring — Observation of the routine in-service operation of the component.
Testing — Application of signals to a component to observe functional
performance or output behavior, or to diagnose problems.
Physical inspection — To detect visible signs of component failure, reduced
performance and degradation.
Calibration — Adjustment of the operating threshold or measurement accuracy of
a measuring element to meet the intended performance requirement.
Upkeep — Routine activities necessary to assure that the component remains in
good working order and implementation of any manufacturer’s hardware and
software service advisories which are relevant to the application of the device.
Restoration — The actions to restore proper operation of malfunctioning
components.
Protection System (modification) — Protective relays, associated communication systems
necessary for correct operation of protective devices, voltage and current sensing inputs to
protective relays, station DC supply, and DC control circuitry from the station DC supply
through the trip coil(s) of the circuit breakers or other interrupting devices.
Draft 1: July 21, 2009
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose: To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems that are applied on, or are designed to provide
protection for the BES.
4.2.2
Protection System components used for underfrequency load-shedding
systems which are installed per ERO underfrequency load-shedding
requirements.
4.2.3
Protection System components used for undervoltage load-shedding
systems which are installed to prevent system voltage collapse or voltage
instability for BES reliability.
4.2.4
Protection System components which is installed as a Special Protection
System for BES reliability.
4.2.5
Protection Systems for Generator Facilities that are part of the BES,
including:
4.2.5.1 Protection system components that act to trip the generator either
directly or via generator lockout or auxiliary tripping relays.
4.2.5.2 Protection systems for generator step-up transformers for
generators that are part of the BES.
4.2.5.3 Protection systems for transformers connecting aggregated
generation, where the aggregated generation is part of the BES
(e.g., transformers connecting facilities such as wind-farms to the
BES).
4.2.5.4 Protection systems for generator-connected station service
transformers for generators that are part of the BES.
4.2.5.5 Protection systems for system-connected station service
transformers for generators that are part of the BES.
5.
(Proposed) Effective Date:
Draft 1: July 21, 2009
TBD
Standard PRC-005-2 — Protection System Maintenance
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish
a Protection System Maintenance Program (PSMP) for its Protection Systems that use
measurements of voltage, current, frequency and/or phase angle to determine
anomalies and to trip a portion of the BES 1 and that are applied on, or are designed to
provide protection for the BES. The PSMP shall meet the following criteria:
[Violation Risk Factor: TBD] [Time Horizon: Long Term Planning]
1.1. For each component used in each Protection System, include all maintenance
activities specified in Tables 1a, 1b, and 1c.
1.2. Identify whether each Protection System component is addressed through timebased, condition-based, performance-based, or a combination of these
maintenance methods and identify the associated maintenance interval.
1.3. Include all batteries associated with a Protection System in a time-based program.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses
condition-based maintenance intervals in its PSMP for partially or fully monitored
Protection Systems shall ensure the components to which the condition-based criteria
are applied (as specified in Tables 1b or 1c), possess the necessary monitoring
attributes. [Violation Risk Factor: TBD] [Time Horizon: Long Term Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that uses
performance-based maintenance intervals in its PSMP shall follow the procedure
established in PRC-005 Attachment A. [Violation Risk Factor: TBD] [Time Horizon:
Long Term Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall
implement its PSMP, including identification of the resolution of all maintenance
correctible issues 2 as follows: [Violation Risk Factor: TBD] [Time Horizon: Long
Term Planning]
4.1.
For time-based or condition-based maintenance programs perform the
Maintenance activities detailed in Table 1 (for the appropriate monitoring
level(s)) for all Protection System components within maximum allowable
intervals not to exceed those established in Tables 1a, 1b, and 1c.
4.2.
For performance-based maintenance programs perform the maintenance
activities detailed in Table 1 (for the appropriate monitoring level(s)) for all
Protection System components in accordance within the maximum allowable
intervals established per Requirement R3.
C. Measures (TBD)
1
Devices that sense non-electrical conditions, such as thermal or transformer sudden pressure relays, are not
included within the scope of this standard.
2
A maintenance correctable issue is a failure of a device to operate within design parameters that can be restored to
functional order by calibration, repair or replacement.
Draft 1: July 21, 2009
Standard PRC-005-2 — Protection System Maintenance
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
1.2. Compliance Monitoring Period and Reset Time Frame
Not Applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each
retain documentation for two maintenance intervals for the Protection System
components.
The Compliance Enforcement Authority shall keep the last periodic audit report
and all requested and submitted subsequent compliance records.
1.5. Additional Compliance Information
2.
Violation Severity Levels — TBD
E. Regional Differences
None
F. Supplemental Reference Documents
The following documents present a detailed discussion about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference — July 2009.
2. NERC Protection System Maintenance Standard PRC-005-2 FREQUENTLY ASKED
QUESTIONS — Practical Compliance and Implementation DRAFT 1.0 — June 2009
Version History
Version
Date
Draft 1: July 21, 2009
Action
Change Tracking
Standard PRC-005-2 — Protection System Maintenance
Table 1a — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection Systems
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
Type of Component
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays) with simulated electrical inputs. (Note 1)
Verify proper functioning of the relay trip outputs.
Protective Relays
6 Calendar Years
For microprocessor relays verify proper functioning of the A/D converters (Note 2)
Verify that settings are as specified.
Voltage and Current
Sensing Devices
Inputs to Protective Relays
12 Calendar
Years
Verify proper functioning of the current and voltage circuit inputs from the voltage and current sensing devices to the
protective relays
Protection System Control
Circuitry (Breaker Trip Coil
Only) (except for UFLS or
UVLS)
3 Months
Protection System Control
Circuitry (Trip Circuits)
(except for UFLS or UVLS)
6 Calendar Years
Perform a complete functional trip test that includes all sections of the Protection System trip circuit, including all
auxiliary contacts essential to proper functioning of the Protection System.
Protection System Control
Circuitry (Trip Circuits)
(UFLS/UVLS Systems Only)
(when the
associated UVLS
or UFLS system
is maintained)
Perform a complete functional trip test that includes all sections of the Protection System trip circuit, including all
auxiliary contacts essential to proper functioning of the Protection System.
Draft 1: July 21, 2009
Verify the continuity of the breaker trip circuit including trip coil (except for protection system control circuitry associated
with breakers that remain open for the entire “maintenance interval” period”)
6
Standard PRC-005-2 — Protection System Maintenance
Table 1a — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection Systems
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
Type of Component
Maximum
Maintenance
Interval
Maintenance Activities
Verify proper electrolyte level (excluding valve-regulated lead acid batteries).
Station dc supply (that has
as a component any type of
battery)
3 Months
Verify proper voltage of the station battery.
Verify that no dc supply grounds are present.
Verify proper voltage of each individual cell or unit in the station battery.
Verify that station battery charger provides the correct float and equalize voltages.
Verify continuity and cell integrity of entire battery.
Station dc supply
(that has as a component
any type of battery)
18 Months
Perform a visual cell inspection of all cells for “cell condition” (where cells are visible) or measurement of cell/unit
internal ohmic values (where cells are not visible).
Measure that specific gravity and temperature of each cell is within tolerance(where applicable)
Verify cell to cell and terminal connection resistance is within tolerance
Inspect the structural integrity of the battery rack.
Station dc supply (that has
as a component Valve
Regulated Lead-Acid
batteries)
Draft 1: July 21, 2009
3 Calendar Years
- or 3 Months
Verify that the station battery can perform as designed by conducting a performance or service capacity test of the
entire battery bank. (3 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values to
station battery baseline. (3 months)
7
Standard PRC-005-2 — Protection System Maintenance
Table 1a — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection Systems
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
Type of Component
Maximum
Maintenance
Interval
Station dc supply
6 Calendar Years
(that has as a component
Vented Lead-Acid Batteries)
- or 18 Months
Maintenance Activities
Verify that the station battery can perform as designed by conducting a performance, service, or modified performance
capacity test of the entire battery bank. (6 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values to
station battery baseline. (18 Months)
Station dc supply (that has
as a component NickelCadmium batteries)
6 Calendar Years
Verify that the substation battery can perform as designed by conducting a performance service, or modified
performance capacity test of the entire battery bank.
Station dc supply (that uses
a battery and charger)
6 Calendar Years
Verify that the battery charger can perform as designed by testing that the charger will provide full rated current and will
properly current-limit.
Verify proper voltage of the station dc supply
Verify that no dc supply grounds are present.
Station dc Supply (battery is
not used)
18 Months
Perform a visual inspection, of all components of the station dc supply to verify that the physical condition of the station
dc supply is as desired and any visual inspection if required by the manufacturer on the condition of the dc supply that
is the source of dc power when ac power is unavailable.
Verify where applicable the proper voltage level of each component of the station dc supply.
Verify the correct operation of ac powered dc power supplies.
Verify the continuity of all circuit connections that can be affected by wear or corrosion.
Station dc Supply (used only
for UVLS or UFLS)
Draft 1: July 21, 2009
(when the
associated UVLS
or UFLS system
is maintained)
Verify proper voltage of the dc supply.
8
Standard PRC-005-2 — Protection System Maintenance
Table 1a — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection Systems
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
Type of Component
Maximum
Maintenance
Interval
Protection system
communications equipment
and channels.
3 Months
Protection system
communications equipment
and channels.
6 Calendar Years
Maintenance Activities
Verify that the Protection System communications monitoring and alarms reflect the intended communications system
condition by means of a substation inspection.
Verify that the performance of the channel and the quality of the channel meets performance criteria, such as via
measurement of signal level, reflected power, or data error rate.
Verify proper functioning of communications equipment outputs.
Test and calibrate the relays (other than microprocessor relays) with simulated electrical inputs. (Note 1)
UVLS and UFLS relays that
comprise a protection
scheme distributed over the
power system
6 Calendar Years
Verify proper functioning of the relay trip outputs.
For microprocessor relays verify the proper functioning of the A/D converters (Note 2)
Verify that settings are as specified.
Relay sensing for
Centralized UFLS or UVLS
systems
SPS
Draft 1: July 21, 2009
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of the UFLS or UVLS systems at
the intervals established for those individual components. The output action may be breaker tripping, or other control
action that must be verified, but may be verified in overlapping segments. A grouped output control action need be
verified only once within the specified time interval, but all of the UFLS or UVLS components whose operation leads to
that control action must each be verified.
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of the SPS at the intervals
established for those individual components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output control action need be verified only
once within the specified time interval, but all of the SPS components whose operation leads to that control action must
each be verified.
9
Standard PRC-005-2 — Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
alarmed failures. Monitoring includes all elements of level 1 monitoring with additional monitoring attributes as listed below for the individual type of component.
Maximum
Maintenance
Interval
Type of
Component
Level 2 Monitoring Attributes for
Component
Protective Relays
Includes internal self diagnosis and
alarm capability, which must assert for
power supply failures. Includes input
voltage or current waveform sampling
three or more times per power cycle,
and conversion of samples to numeric
values for measurement calculations
by microprocessor electronics that are
also performing self diagnosis and
alarming.
12 Calendar Years
Voltage and
Current Sensing
Devices - Inputs
to Protective
Relays
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
12 Calendar Years
Verify the proper functioning of current and voltage circuit inputs from the voltage and
current sensing devices to the protective relays
Protection
System Control
Circuitry (Trip
Coils and
Auxiliary Relays)
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities and intervals
6 Calendar Years
Verify that each breaker trip coil, each auxiliary relay, and each lockout relay is
electrically operated within this time interval.
Maintenance Activities
Verify the status of relays is normal with no alarms indicated.
Protection
System Control
Circuitry (Trip
Circuits) (except
for UFLS/UVLS)
Monitoring and alarming of continuity of
trip coil(s)
Draft 1: July 21, 2009
Verify the proper functioning of the A/D converters within the relay by testing or
comparing values against other devices.
Verify proper functioning of the relay trip outputs.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can be taken.
See Note 2.
12 Calendar Years
Perform a complete functional trip test that includes all sections of the Protection
System trip circuit, including all auxiliary contacts essential to proper functioning of the
Protection System.
Verify that the relay alarms will be received at the location where action can be taken.
10
Standard PRC-005-2 — Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
alarmed failures. Monitoring includes all elements of level 1 monitoring with additional monitoring attributes as listed below for the individual type of component.
Type of
Component
Protection
System Control
Circuitry (Trip
Circuits)
(UFLS/UVLS
Systems Only)
Station dc supply
(that has as a
component any
type of battery)
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Monitoring and alarming of continuity of
trip coil(s)
(when the
associated UVLS
or UFLS system is
maintained)
Monitoring and alarming of the station
dc supply voltage.
3 Months
Maintenance Activities
Perform a complete functional trip test that includes all sections of the Protection
System trip circuit, including all auxiliary contacts essential to proper functioning of the
Protection System. (Verification does not require actual tripping of circuit breakers or
interrupting devices.)
Verify that the relay alarms will be received at the location where action can be taken.
Verify proper electrolyte level (excluding Valve-Regulated Lead Acid batteries).
Detection and alarming of dc grounds.
Verify proper voltage of each individual cell or unit in the station battery.
Verify that station battery charger provides the correct float and equalize voltages.
Verify electrical continuity of the entire battery.
Station dc supply
(that has as a
component any
type of battery)
Monitoring and alarming of the station
dc supply voltage.
Detection and alarming of dc grounds.
Perform a visual cell inspection of all cells for “cell condition” (where cells are visible)
or measurement of cell/unit internal ohmic values. (where cells are not visible)
18 Months
Measure that specific gravity and temperature of each cell is within tolerance. (where
applicable)
Verify cell to cell and terminal connection resistance is within tolerance.
Inspect the structural integrity of the battery rack.
Verify that the battery voltage and dc supply ground alarms will be received at the
location where action can be taken.
Draft 1: July 21, 2009
11
Standard PRC-005-2 — Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
alarmed failures. Monitoring includes all elements of level 1 monitoring with additional monitoring attributes as listed below for the individual type of component.
Type of
Component
Level 2 Monitoring Attributes for
Component
Station dc supply
(that has as a
component Valve
Regulated LeadAcid batteries)
Station dc supply
(that has as a
component
Vented LeadAcid batteries)
Station dc supply
(that has as a
component
Nickel-Cadmium
batteries)
Station dc supply
(that uses a
battery and
charger)
Monitoring and alarming of the station
dc supply voltage.
Detection and alarming of dc grounds.
Maximum
Maintenance
Interval
Maintenance Activities
3 Calendar Years
Verify that the station battery can perform as designed by conducting a performance or
service capacity test of the entire battery bank. (3 calendar years)
- or 3 Months
Monitoring and alarming of the station
dc supply voltage.
6 Calendar Years
Detection and alarming of dc grounds.
18 Months
- or -
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (3 months)
Verify that the substation battery can perform as designed by conducting a
performance service, or modified performance capacity test of the entire battery bank.
(6 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (18 Months)
Monitoring and alarming of the station
dc supply voltage.
6 Calendar Years
Verify that the substation battery can perform as designed by conducting a
performance service, or modified performance capacity test of the entire battery bank.
6 Calendar Years
Verify that the battery charger can perform as designed by testing that the charger will
provide full rated current and will properly current-limit.
Detection and alarming of dc grounds.
Monitoring and alarming of the station
dc supply voltage.
Detection and alarming of dc grounds.
Draft 1: July 21, 2009
12
Standard PRC-005-2 — Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
alarmed failures. Monitoring includes all elements of level 1 monitoring with additional monitoring attributes as listed below for the individual type of component.
Type of
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Verify proper voltage of the station dc supply, and where applicable, of each
component of the station dc supply.
Verify the proper operation of ac powered dc power supplies.
Station dc Supply
(battery is not
used)
Monitoring and alarming of the station
dc supply voltage.
Verify the continuity of all circuit connections that can be affected by wear or corrosion.
18 Months
Detection and alarming of dc grounds.
Perform a visual inspection, of all components of the station dc supply to verify that the
physical condition of the station dc supply is as desired and any visual inspection if
required by the manufacturer on the condition of the dc supply that is the source of dc
power when ac power is unavailable.
Verify that the station dc supply voltage and dc supply ground alarms will be received
at a location where action can be taken.
Station dc Supply
(used only for
UVLS or UFLS)
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities and intervals
Protection
system
communications
equipment and
channels.
Monitoring and alarming of protection
communications system by
mechanisms that check for presence of
the communications channel.
Draft 1: July 21, 2009
(when the
associated UVLS
or UFLS system is
maintained)
12 Calendar Years
Verify proper voltage of the dc supply
Verify that the performance of the channel and the quality of the channel meets
performance criteria, such as via measurement of signal level, reflected power, or data
error rate.
Verify proper functioning of communications equipment outputs.
Verify proper functioning of alarm notification.
13
Standard PRC-005-2 — Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
alarmed failures. Monitoring includes all elements of level 1 monitoring with additional monitoring attributes as listed below for the individual type of component.
Maximum
Maintenance
Interval
Type of
Component
Level 2 Monitoring Attributes for
Component
UVLS and UFLS
relays that
comprise a
protection
scheme
distributed over
the power
system.
Includes internal self diagnosis and
alarm capability, which must assert for
power supply failures. Includes input
voltage or current waveform sampling
three or more times per power cycle,
and conversion of samples to numeric
values for measurement calculations
by microprocessor electronics that are
also performing self diagnosis and
alarming.
12 Calendar Years
See the attributes of Level 1 Monitoring
for the individual components of the
SPS
See Maintenance
Intervals for the
individual
components of the
UFLS/UVLS
Perform all of the Maintenance activities listed above as established for components of
the UFLS or UVLS systems at the intervals established for those individual
components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified time interval, but all of the
UFLS or UVLS components whose operation leads to that control action must each be
verified.
See the attributes of Level 1 Monitoring
for the individual components of the
SPS
See Maintenance
Intervals for the
individual
components of the
SPS
Perform all of the Maintenance activities listed above as established for components of
the SPS, at the intervals established for those individual components. The output
action may be breaker tripping, or other control action that must be verified, but may be
verified in overlapping segments. A grouped output control action need be verified
only once within the specified time interval, but all of the SPS components whose
operation leads to that control action must each be verified.
Relay sensing for
centralized UFLS
or UVLS
systems.
SPS
Draft 1: July 21, 2009
Maintenance Activities
Verify the status of relays as in service with no alarms.
Verify the proper function of the A/D converters (if included in relay).
Verify proper functioning of the relay trip outputs.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can be taken.
14
Standard PRC-005-2 — Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection Systems
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken. Level 3 Monitoring includes all elements of Level 2 Monitoring, with additional
monitoring attributes as listed below for the individual type of component.
Type of Component
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Protective Relays
The relay A/D converters are
continuously monitored and alarmed.
Continuous
Protective Relays
with trip contacts
All Level attributes, except relay
possesses mechanical output
contacts.
12 Calendar
Years
Verify proper functioning of the relay trip contacts.
Verification of the ac analog values
(magnitude and phase angle)
measured by the microprocessor
relay or comparable device, by
comparing against other
measurements using other instrument
transformers.
Continuous
Continuous verification and comparison of the current and voltage signals from the
voltage and current sensing devices of the Protection System.
Voltage and Current
Sensing Devices
Inputs to Protective
Relays
Protection System
Control Circuitry (Trip
Coils and Auxiliary
Relays)
No Level 3 monitoring attributes are
defined – use Level 2 Maintenance
Activities and intervals
Draft 1: July 21, 2009
Maintenance Activities
Continuous verification of the status of the relays. (Note 2)
Alarm on change of settings.
6 Calendar Years
Each breaker trip coil, each auxiliary relay, and each lockout relay must be electrically
operated within this time interval.
15
Standard PRC-005-2 — Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection Systems
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken. Level 3 Monitoring includes all elements of Level 2 Monitoring, with additional
monitoring attributes as listed below for the individual type of component.
Type of Component
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Protection System
Control Circuitry (Trip
Circuits)
Monitoring of the continuity of breaker
trip circuits (with alarming for noncontinuity), along with the presence of
tripping voltage supply all the way
from relay terminals (or from inside
the relay) through to the trip coil,
including any auxiliary contacts
essential to proper Protection System
operation. If a trip circuit comprises
multiple paths, each of the paths must
be monitored, including monitoring of
the operating coil circuit(s) and the
tripping circuits of auxiliary tripping
relays and lockout relays.
Continuous
Draft 1: July 21, 2009
Maintenance Activities
Continuous monitoring of trip voltage and trip path integrity of entire trip circuit is
provided with alarming to remote terminal unit upon any failure of the trip path.
16
Standard PRC-005-2 — Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection Systems
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken. Level 3 Monitoring includes all elements of Level 2 Monitoring, with additional
monitoring attributes as listed below for the individual type of component.
Type of Component
Station dc Supply
(any battery
technology)
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Monitoring and alarming the station
dc supply status, including, for station
dc supplies that have as a component
a battery, the voltage, specific gravity,
electrolyte level, temperature and
connectivity (cell to cell and terminal
connection resistance) of each cell as
well as the battery system terminal
voltage and electrical continuity of the
overall battery system.
Monitoring and alarming if the
performance capability of the battery
is degraded.
Maintenance Activities
Verify that station battery charger operation provides the correct float and equalize
voltages
18 Months
Perform a visual inspection of the station battery and charger, individual cells (including
electrolyte level), connections, and racks to verify that the physical condition of the
battery is as desired, and that no associated alarm lamps are illuminated.
Monitoring and alarming the ac
powered dc power supply status
including low and high voltage and
charge rate for station dc supplies
that have battery systems.
Detection and alarming of dc
grounds.
Draft 1: July 21, 2009
17
Standard PRC-005-2 — Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection Systems
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken. Level 3 Monitoring includes all elements of Level 2 Monitoring, with additional
monitoring attributes as listed below for the individual type of component.
Type of Component
Station dc supply
(that uses a battery
and charger)
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Monitoring and alarming the station
dc supply status, including, for station
dc supplies that have as a component
a battery, the voltage, specific gravity,
electrolyte level, temperature and
connectivity (cell to cell and terminal
connection resistance) of each cell as
well as the battery system terminal
voltage and electrical continuity of the
overall battery system.
Monitoring and alarming if the
performance capability of the battery
is degraded.
6 Calendar Years
Maintenance Activities
Verify that the battery charger can perform as designed by testing that the charger will
provide full rated current and will properly current-limit.
Monitoring and alarming the ac
powered dc power supply status
including low and high voltage and
charge rate for station dc supplies
that have battery systems.
Detection and alarming of dc
grounds.
Draft 1: July 21, 2009
18
Standard PRC-005-2 — Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection Systems
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken. Level 3 Monitoring includes all elements of Level 2 Monitoring, with additional
monitoring attributes as listed below for the individual type of component.
Type of Component
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Monitoring and alarming the station
dc supply status, including output
voltage of the dc supply.
Station dc Supply
(battery is not used)
Monitoring and alarming if the
performance capability of the dc
supply is degraded.
Continuous
Continuous verification of the status of the station dc supply and its ability to deliver dc
power when required, is provided.
Detection and alarming of dc
grounds.
Station dc Supply
(used only for UVLS
or UFLS)
No Level 3 monitoring attributes are
defined – use Level 2 Maintenance
Activities and intervals
Protection system
telecommunications
equipment and
channels.
Evaluating the performance of the
channel and its interface to protective
relays to determine the quality of the
channel and alarming if the channel
does not meet performance criteria
UVLS and UFLS
relays that comprise a
protection scheme
distributed over the
power system.
The relay A/D converters are
continuously monitored and alarmed.
(when the
associated UVLS
or UFLS system
is maintained)
Continuous
Verify proper voltage of the dc supply
Continuous verification that the performance and quality of the channel meets
performance criteria is provided.
Continuous verification of the communications equipment alarm system is provided.
Continuous verification of the status of the relays. (Note 2)
Draft 1: July 21, 2009
Continuous
Alarm on change of settings. Verification does not require actual tripping of circuit
breakers or interrupting devices.
19
Standard PRC-005-2 — Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection Systems
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken. Level 3 Monitoring includes all elements of Level 2 Monitoring, with additional
monitoring attributes as listed below for the individual type of component.
Type of Component
Relay sensing for
centralized UFLS or
UVLS systems.
SPS
Level 3 Monitoring Attributes for
Component
See the attributes of Level 3
Monitoring for the individual
components of the UFLS/UVLS
See the attributes of Level 3
Monitoring for the individual
components of the SPS
Maximum
Maintenance
Interval
Maintenance Activities
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of
the UFLS or UVLS systems at the intervals established for those individual
components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified time interval, but all of the
UFLS or UVLS components whose operation leads to that control action must each be
verified.
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of
the SPS at the intervals established for those individual components. The output action
may be breaker tripping, or other control action that must be verified, but may be
verified in overlapping segments. A grouped output control action need be verified only
once within the specified time interval, but all of the SPS components whose operation
leads to that control action must each be verified.
Notes for Table 1a, Table 1b, and Table 1c
1. For some Protection System components, adjustment is required to bring measurement accuracy within parameters established by the asset owner based on the specific
application of the component. A calibration failure is the result if testing finds the specified parameters to be out of tolerance.
2. Microprocessor relays typically are specified by manufacturers as not requiring calibration, but power system input values must be verified as correct within the Table
intervals. The integrity of the digital inputs and outputs will be verified with the Protection System Control Circuitry.
Draft 1: July 21, 2009
20
Standard PRC-005-2 — Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
Segment: In this procedure, the term, “segment” is a grouping of Protection Systems or
component devices from a single manufacturer, with common factors such that consistent
performance is expected across the entire population of the segment, and shall only be defined
for a population of 60 or more individual components. 3
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of components included in each designated segment of
the Protection System component population.
2. Maintain the components in each segment according to the time-based maximum
allowable intervals established in Table 1 until results of maintenance activities for the
segment are available for a minimum of 30 individual components of the segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events 4 for each included component.
4. Analyze the maintenance program activities and results for each segment to determine the
overall performance of the segment and develop maintenance intervals.
5. Determine the maximum allowable maintenance interval for each segment such that the
segment experiences countable events on no more than 4% of the components within the
segment, for the greater of either the last 30 components maintained or all components
maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
4. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
3
Entities with smaller populations of component devices may aggregate their populations to define a segment and
shall share all attributes of a single performance-based program for that segment.
4
Countable events include any failure of a component requiring repair or replacement, any condition discovered
during the verification activities in Table 1a through Table 1c which requires corrective action, or a Misoperation
attributed to hardware failure or calibration failure.
Draft 1: July 21, 2009
Standard PRC-005-2 — Protection System Maintenance
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
5. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
Draft 1: July 21, 2009
Unofficial Comment Form for Protection System Maintenance and Testing
(Project 2007-17)
Please DO NOT use this form. Please use the electronic comment form located at the link
below to submit comments on the draft Protection System Maintenance and Testing.
Comments must be submitted by September 8, 2009. If you have questions please
contact Al Calafiore at [email protected] or by telephone at 678-524-1188.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_200717.html
Background Information:
The draft standard combines the previous standards, PRC-005-1 — Transmission and
Generation Protection System Maintenance and Testing, PRC-008-0 — Underfrequency Load
Shedding Equipment Maintenance Program, PRC-011-0 — UVLS System Maintenance and
Testing, and PRC-017-0 — Special Protection System Maintenance and Testing. It also
addresses FERC directives from FERC Order 693, including that NERC establish maximum
allowable maintenance intervals.
In accordance with the FERC directive, this draft standard establishes requirements for a
time-based maintenance program, where all relevant devices are maintained according to
prescribed maximum intervals. It further establishes requirements for a condition-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect
the known and reported condition of the relevant devices, and for a performance-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect
the historical performance of the relevant devices.
1. The Standard Drafting Team proposes to change the name of the draft standard from
“Protection System Maintenance and Testing” to “Protection System Maintenance”, and
to include testing as one component of “Protection System Maintenance Program”, which
will be a defined term. Do you agree? If not, please explain in the comment area.
Yes
No
Comments:
2. Within Table 1a, Table 1b, and Table 1c, the draft standard establishes specific minimum
maintenance activities for the various types of devices defined within the definition of
“Protection System”. Do you agree with these minimum maintenance activities? If not,
please explain in the comment area.
Yes
No
Comments:
3. Within Table 1a, the draft standard establishes maximum allowable maintenance
intervals for the various types of devices defined within the definition of “Protection
System”, where nothing is known about the in-service condition of the devices. Do you
agree with these intervals? If not, please explain in the comment area.
Yes
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Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Unofficial Comment Form — Protection System Maintenance and Testing Project 2007-17
No
Comments:
4. Within Tables 1b and 1c, the draft standard establishes parameters for condition-based
maintenance, where the condition of the devices is known by means of monitoring within
the substation or plant and the condition is reported. Do you agree with this approach?
If not, please explain in the comment area.
Yes
No
Comments:
5. Within PRC-005 Attachment A, the draft standard establishes parameters for
performance-based maintenance, where the historical performance of the devices is
known and analyzed to support adjustment of the maximum intervals. Do you agree
with this approach? If not, please explain in the comment area.
Yes
No
Comments:
6. The Standard Drafting Team has provided a “Supplementary Reference Document” to
provide supporting discussion for the Requirements within the standard. Do you have
any comments on the Supplementary Reference Document? Please explain in the
comment area.
Yes
No
Comments:
7. The Standard Drafting Team has provided a “Frequently-asked Questions” document to
address anticipated questions relative to the standard. Do you have any comments on
the FAQ? Please explain in the comment area.
Yes
No
Comments:
8. If you are aware of any conflicts between the proposed standard and any regulatory
function, rule, order, tariff, rate schedule, legislative requirement, or agreement please
identify the conflict here.
Conflict:
Comments:
9. If you are aware of the need for a regional variance or business practice that we should
consider with this project, please identify it here.
Regional Variance:
Business Practice:
Comments:
3
Unofficial Comment Form — Protection System Maintenance and Testing Project 2007-17
10. If you have any other comments on this Standard that you have not already provided in
response to the prior questions, please provide them here.
Comments:
3
Draft Implementation Plan for PRC-005-02
Background:
In developing the implementation plan, the Standard Drafting Team considered the following:
1. The requirements set forth in the proposed standard establish maximum allowable
maintenance intervals for the first time. The established maximum allowable intervals may
be shorter than those currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the
proposed standard, it is unrealistic for those entities to be immediately in compliance with the
new intervals. Further, entities should be allowed to become compliant in such a way as to
facilitate a continuing maintenance program.
3. Until an entity is 100% compliant with PRC-005-2, the entity must be in compliance with
PRC-005-1 for those components for which the implementation schedule for PRC-005-2 is
not yet applicable.
4. Entities that have previously been performing maintenance within the newly specified
intervals may not have all the documentation needed to demonstrate compliance with all of
the maintenance activities specified.
Implementation plan for R1:
Entities shall be 100% compliant on the first day of the first calendar quarter three
months following applicable regulatory approvals, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter three months
following Board of Trustees adoption.
Implementation plan for R2, R3, and R4:
1. For Protection System Components with maximum allowable intervals of less than 1
year, as established in Table 1a,
a. The entity shall be 100% compliant on the first day of the first calendar quarter 12
months following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 12
months following Board of Trustees adoption.
2. For Protection System Components with maximum allowable intervals 1 year or more,
but 2 years or less, as established in Table 1a,
a. The entity shall be 100% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar
quarter 2 calendar years following Board of Trustees adoption.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
3. For Protection System Components with maximum allowable intervals of 6 years, as
established in Table 1a,
a. The entity shall be 30% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar
quarter 2 calendar years following Board of Trustees adoption.
b. The entity shall be 60% compliant on the first day of the first calendar quarter 4
calendar years following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar
quarter 4 calendar years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 6
calendar years following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar
quarter 6 calendar years following Board of Trustees adoption.
4. For Protection System Components with maximum allowable intervals of 12 years, as
established in Table 1a,
a. The entity shall be 30% compliant on the first day of the first calendar quarter 4
calendar years following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar
quarter 4 calendar years following Board of Trustees adoption.
b. The entity shall be 60% compliant on the first day of the first calendar quarter
following 8 calendar years following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 8 calendar years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 12
calendar years following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar
quarter 12 calendar years following Board of Trustees adoption.
Applicability:
This standard applies to the following functional entities:
Transmission Owners
Generator Owners
Distribution Providers
Draft 1: July 21, 2009
2
PRC-005-2 Protection — System
Maintenance Supplementary
Reference (Draft 1)
Protection System Maintenance and Testing
Standard Drafting Team
July, 2009
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Table of Contents
1. Introduction and Summary ..........................................................................................................3
2. Need for Verifying Protection System Performance ...................................................................3
2.1 Existing NERC Standards for Protection System Maintenance and Testing ......................3
2.2 Proposed Modification to NERC Glossary Definition ........................................................4
2.3 Applicability of New Protection System Maintenance Standards.......................................4
2.4 Applicable Relays ................................................................................................................4
3. Relay Product Generations ........................................................................................................4
4. Definitions..................................................................................................................................5
5. Time Based Maintenance (TBM) Programs ...............................................................................5
Maintenance Practices .................................................................................................................6
5.1 Extending Time-Based Maintenance.....................................................................................7
6. Condition Based Maintenance (CBM) Programs ........................................................................8
7. Time Based versus Condition Based Maintenance....................................................................8
8. Maximum Allowable Verification Intervals..............................................................................9
Maintenance Tests .......................................................................................................................9
8.1 Table of Maximum Allowable Verification Intervals .........................................................9
Level 1 Monitoring (Unmonitored) Table 1a ............................................................................10
Level 2 Monitoring (Partially Monitored) Table 1b..................................................................10
Level 3 Monitoring (Fully Monitored) Table 1c .......................................................................11
8.2 Retention of Records ..........................................................................................................12
8.3 Basis for Table 1 Intervals ..................................................................................................12
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays..............................13
9. Performance-Based Maintenance Process ...............................................................................14
9.1 Minimum Sample Size........................................................................................................15
10. Overlapping the Verification of Sections of the Protection System ........................................17
11. Monitoring by Analysis of Fault Records................................................................................18
12. Importance of Relay Settings in Maintenance Programs.........................................................18
13. Self-Monitoring Capabilities and Limitations .........................................................................19
14. Notification of Protection System Failures..............................................................................20
15. Maintenance Activities ............................................................................................................20
15.1 Protective Relays ...............................................................................................................20
15.2 Voltage & Current Sensing Devices..................................................................................20
15.3 DC Control Circuitry .........................................................................................................21
15.4 Batteries and DC Supplies .................................................................................................21
15.5 Tele-protection equipment .................................................................................................22
16. References................................................................................................................................24
Figures............................................................................................................................................25
Figure 1: Typical Transmission System ....................................................................................25
Figure 2: Typical Generation System ........................................................................................26
Figure 3: Requirements Flowchart ............................................................................................28
Appendix A....................................................................................................................................28
PRC-005-2 Protection Systems Maintenance & Testing Standard Drafting Team.......................32
Draft 1: July, 2009
Page 2
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
This supplementary reference to PRC-005-2 borrows heavily from the technical reference by the System
Protection and Control Task Force (SPCTF) Protection System Maintenance Technical Reference paper
approved by the Planning Committee in September 2007). Additionally the Protection System
Maintenance and Testing Standard Drafting Team (PSMT SDT) for PRC-005-2 (Project 2007-17)
utilized data available from IEEE, EPRI and maintenance programs from various generation and
transmission utilities across the NERC boundaries.
1. Introduction and Summary
NERC currently has four reliability standards that are mandatory and enforceable in the United States and
address various aspects of maintenance and testing of protection and control systems. These standards
are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for Protection Systems,
and that these entities must be able to demonstrate they are carrying out such a program, there are no
specifics regarding the technical requirements for Protection System maintenance programs. Furthermore,
FERC Order 693 directed additional modifications respective to Protection System maintenance
programs.
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate their
performance until a fault or other power system problem requires that they operate to protect power
system elements, or even the entire Bulk Electric System (BES). Lacking faults or system problems, the
protection systems may not operate for extended periods. A misoperation - a false operation of a
protection system or a failure of the protection system to operate, as designed, when needed - can result in
equipment damage, personnel hazards, and wide area disturbances or unnecessary customer outages. A
maintenance or testing program is used to determine the performance and availability of protection
systems.
Typically, utilities have tested protection systems at fixed time intervals, unless they had some incidental
evidence that a particular protection system was not behaving as expected. Testing practices vary widely
across the industry. Testing has included system functionality, calibration of measuring relays, and
correctness of settings. Typically, a protection system must be visited at its installation site and removed
from service for this testing.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset owner
define a testing program. The starting point is the existing Standard PRC-005, briefly restated as follows:
Purpose: To ensure all transmission and generation Protection Systems affecting the reliability of the
Bulk Electric System (BES) are maintained and tested.
PRC-005 is not specific on where the boundaries of the Protection Systems lie. However, the definition of
Protection System in the NERC Glossary of Terms Used in Reliability Standards indicates what must be
included as a minimum.
Definition of Protection System (excerpted from the NERC Standards Glossary of Terms):
Draft 1: July, 2009
Page 3
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Protective relays, associated communication systems, voltage and current sensing devices, station
batteries and dc control circuitry.
Applicability: Owners of generation, transmission, and transmission Protection Systems.
Requirements: The owner shall have a documented maintenance program with test intervals. The owner
must keep records showing that the maintenance was performed at the specified intervals.
2.2 Proposed Modification to NERC Glossary Definition
The Protection Systems Maintenance and Testing Standard Drafting Team (PSM SDT), proposes changes
to the NERC glossary definition of Protection Systems as follows:
Protection System (modification) - Protective relays, associated communication systems necessary for
correct operation of protective devices, voltage and current sensing devices inputs to protective relays,
station DC supply, and DC control circuitry from the station DC supply through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from the
original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“… and that are applied on, or are designed to provide protection for the BES.”
The drafting team intends that this Standard will not apply to “merely possible” parallel paths, (subtransmission and distribution circuits), but rather the standard applies to any Protection System that is
designed to detect a fault on the BES and take action in response to that fault. The Standard Drafting
Team does not feel that Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the Regional definitions of the
BES.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and voltage
sensing devices, dc control circuitry and associated communications circuits. The relays to which this
standard applies are those relays that that use measurements of voltage, current, frequency and/or phase
angle and provide a trip output to trip coils, dc control circuitry or associated communications equipment.
This definition extends to IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or trip-free
relay) as these devices are tripping relays that respond to the trip signal of the protective relay that
processed the signals from the current and voltage sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration, pressure,
seismic, thermal or gas accumulation) are not included.
3. Relay Product Generations
The likelihood of failure and the ability to observe the operational state of a critical protection system,
both depends on the technological generation of the relays as well as how long they have been in service.
Unlike many other transmission asset groups, protection and control systems have seen dramatic
technological changes spanning several generations. During the past 20 years, major functional advances
are primarily due to the introduction of microprocessor technology for power system devices such as
primary measuring relays, monitoring devices, control systems, and telecommunications equipment.
Modern microprocessor based relays have six significant traits that impact a maintenance strategy:
Draft 1: July, 2009
Page 4
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Self monitoring capability - the processors can check themselves, peripheral circuits, and some
connected substation inputs and outputs such as trip coil continuity. Most relay users are aware
that these relays have self monitoring, but are not focusing on exactly what internal functions are
actually being monitored. As explained further below, every element critical to the protection
system must be monitored, or else verified periodically.
Ability to capture fault records showing how the protection system responded to a fault in its zone
of protection, or to a nearby fault for which it is required not to operate.
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-fault times. The relays can compute values such as MW and MVAR line
flows that are sometimes used for operational purposes such as SCADA.
Data communications via ports that provide remote access to all of the results of protection
system monitoring, recording, and measurement.
Ability to trip or close circuit breakers and switches through the protection system outputs, on
command from remote data communications messages or from relay front panel button requests.
Construction from electronic components some of which have shorter technical life or service life
than electromechanical components of prior protection system generations.
4. Definitions
Protection System Maintenance Program (PSMP) – An ongoing program by which Protection System
components are kept in working order and proper operation of malfunctioning components is restored. A
maintenance program can include:
Verification — A means of determining that the component is functioning correctly.
Monitoring — Observation of the routine in-service operation of the component.
Testing — Application of signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Physical Inspection — To detect visible signs of component failure, reduced performance and
degradation.
Calibration — Adjustment of the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Upkeep — Routine activities necessary to assure that the component remains in good working
order and implementation of any manufacturer’s hardware and software service advisories which
are relevant to the application of the device.
Restoration — The actions to restore proper operation of malfunctioning components.
5. Time Based Maintenance (TBM) Programs
Time based maintenance is the process in which protection systems are maintained or verified according
to a time schedule. The scheduled program often calls for technicians to travel to the physical site and
perform a functional test on protection system components. However, some components of a TBM
program may be conducted from a remote location - for example, tripping a circuit breaker by
communicating a trip command to a microprocessor relay to determine if the entire protection system
tripping chain is able to operate the breaker.
Draft 1: July, 2009
Page 5
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance practices:
TBM — time based maintenance — externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have been
developed from prior experience or manufacturers’ recommendations. The TBM verification
interval is based on a variety of factors, including experience of the particular asset owner,
collective experiences of several asset owners who are members of a country or regional council,
etc. The maintenance intervals are fixed, and may range in number of months or in years.
TBM can include review of recent power system events near the particular terminal. Operating
records may prove that some portion of the protection system has operated correctly since the last
test occurred. If specific protection scheme components have demonstrated correct performance
within specifications, the maintenance test time clock is reset for those components.
PBM — performance based maintenance — maintenance intervals are established based on
analytical or historical results of TBM failure rates on a statistically significant population of
similar components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBM-developed
extended intervals when test failures or in-service failures occur infrequently.
CBM — condition based maintenance — continuously or frequently reported results from nondisruptive self monitoring of components demonstrate operational status as those components
remain in service. Whatever is verified by CBM does not require manual testing, but taking
advantage of this requires precise technical focus on exactly what parts are included as part of the
self diagnostics.
Microprocessor based protective relays that perform continuous self-monitoring verify correct
operation of most components within the device. Self-monitoring capabilities may include the ac
signal inputs, analog measuring circuits, processors and memory for measurement, protection,
and data communications, trip circuit monitoring, and protection or data communications signals.
For those conditions, failure of a self-monitoring routine generates an alarm and may inhibit
operation to avoid false trips. When internal components, such as critical output relay contacts,
are not equipped with self-monitoring, they can be manually tested. The method of testing may
be local or remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike TBM,
PBM intervals are adjusted based on good or bad experiences. The CBM verification intervals can be
hours or even milliseconds between non-disruptive self monitoring checks within or around components
as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete Protection
System. The following diagram illustrates the relationship between various types of maintenance
practices described in this section. In the Venn diagram the overlapping regions show the relationship of
TBM with PBM historical information and the inherent continuous monitoring offered through CBM.
This figure shows:
Region 1: The TBM intervals that are increased based on known reported operational condition of
individual components that are monitoring themselves.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been
subject to TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
TBM
1
2
3
CBM
PBM
Relationship of time based maintenance types
5.1 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly established to
assure proper functioning of each component of the protection system, when data on the reliability of the
components is not available other than observations from time-based maintenance. The following factors
may influence the established default intervals:
If continuous indication of the functional condition of a component is available (from relay self
monitoring, for example), the intervals may be extended or manual testing may be eliminated.
This is referred to as condition-based maintenance or CBM. CBM is valid only for precisely the
components subject to monitoring. In the case of microprocessor-based relays, self-monitoring
may not include automated diagnostics of every component within a microprocessor.
Previous maintenance history for a group of components of a common type may indicate that the
maintenance intervals can be extended while still achieving the desired level of performance. This
is referred to as performance-based maintenance or PBM. It is also sometimes also referred to as
reliability-centered maintenance or RCM, but PBM is used in this document.
Observed proper operation of a component may be regarded as a maintenance verification of the
respective component or element in a microprocessor-based device. For such an observation, the
maintenance interval may be reset only to the degree that can be verified by data available on the
operation. For example, the trip of an electromechanical relay for a fault verifies the trip contact
and trip path, but only through the relays in series that actually operated; one operation of this
relay cannot prove correct calibration.
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Excessive maintenance can actually decrease the reliability of the component or system. It is not unusual
to cause failure of a component by removing it from service and restoring it. The improper application of
test signals may cause failure of a component. For example, in electromechanical overcurrent relays, test
currents have been known to destroy convolution springs.
In addition, maintenance usually takes the component out of service, during which time it is not able to
perform its function. Cutout switch failures, or failure to restore switch position, commonly lead to
protection failures.
6. Condition Based Maintenance (CBM) Programs
Condition based maintenance is the process of gathering and monitoring the information available from
modern microprocessor-based relays and other intelligent electronic devices (IEDs) that monitor
protection system elements. These relays and IEDs generate monitoring information during normal
operation, and the information can be assessed at a convenient location remote from the substation. The
information from these relays and IEDs is divided into two basic types:
Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in relay logic settings. The results are presented by alarm contacts or
points, front panel indications, and by data communications messages.
Information can come from event logs, captured files, and/or oscillograph records for faults and
disturbances, metered values, and binary input status reports. Some of these are available on the
relay front panel display, but may be available via data communications ports. Large files of fault
information can only be retrieved via data communications. These results comprise a mass of data
that must be further analyzed for evidence of the operational condition of the protection system.
Using these two types of information, the user can develop an effective maintenance program carried out
mostly from a central location remote from the substation. This approach offers the following advantages:
Non-invasive Maintenance: The system is kept in its normal operating state, without human
intervention for checking. This reduces risk of damage, or risk of leaving the system in an
inoperable state after a manual test. Experience has shown that keeping human hands away from
equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for repair
within seconds or minutes of when they happen. This reduces the percentage of problems that are
discovered through incorrect relaying performance. By contrast, a hardware failure discovered by
TBM may have been there for much of the time interval between tests, and there is a good chance
that some relays will show health problems by incorrect relaying before being caught in the next
test round. The frequent or continuous nature of CBM makes the effective verification interval far
shorter than any required TBM maximum interval.
7. Time Based versus Condition Based Maintenance
Time based and condition based maintenance programs are both acceptable, if implemented according to
technically sound requirements. Practical programs can employ a combination of time based and
condition based maintenance. The standard requirements introduce the concept of optionally using
condition monitoring as a documented element of a maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule dated March
16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability Standards for the BulkPower System, directed NERC to submit a modification to PRC-005-1 that includes a requirement that
maintenance and testing of a protection system must be carried out within a maximum allowable interval
that is appropriate to the type of the protection system and its impact on the reliability of the Bulk Power
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
System. Accordingly, this Supplementary Reference Paper refers to the specific maximum allowable
intervals in PRC-005-2. The defined time limits allow for longer time intervals if the maintained device is
monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay between the
moment of a protection failure and time the protection system owner knows about it, for the monitored
segments of the protection system. In some cases, the verification is practically continuous - the time
interval between verifications is minutes or seconds. Thus, technically sound, condition-based verification
(as specified in the header and the “Monitoring Attributes” column of Tables 1a, 1b and 1c of PRC-0052), meets the verification requirements of the FERC order even more effectively than the strictly timebased tests of the same system elements as contained in Table 1a.
The result is that:
This NERC standards permits utilities to use a technically sound approach and to take advantage of
remote monitoring, data analysis, and control capabilities of modern protection systems to reduce the
need for periodic site visits and invasive testing of components by on-site technicians. This periodic
testing must be conducted within maximum time intervals specified in Tables 1a, 1b and 1c of PRC-0052.
8. Maximum Allowable Verification Intervals
The Table of Maintenance Activities and Maximum Interval requirements shows how CBM with newer
relay types can reduce the need for many of the tests and site visits that older protection systems require.
As explained below, there are some sections of the protection system that monitoring or data analysis may
not verify. Verifying these sections of the Protection Systems requires some persistent TBM activity in
the maintenance program. However, some of this TBM can be carried out remotely - for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control capabilities
via data communications, if there has been no fault or routine operation to demonstrate performance of
relay tripping circuits.
Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is operating
correctly after a period of time of field installation. These tests may be used to ensure that individual
components are still operating within acceptable performance parameters - this type of test is needed for
components susceptible to degraded or changing characteristics due to aging and wear. Full system
performance tests may be used to confirm that the total protection system functions from measurement of
power system values, to properly identifying fault characteristics, to the operation of the interrupting
devices.
8.1 Table of Maximum Allowable Verification Intervals
Table 1, in the standard, specifies maximum allowable verification intervals for various generations of
protection systems and categories of equipment that comprise protection systems. The right column
indicates verification or testing activities required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1 shows an
example of telecommunications-assisted line protection system comprising substation equipment at each
terminal and a telecommunications channel for relaying between the two substations. Figure 2 shows a
typical Generation station layout. The various subsystems of a Protection System that need to be verified
are shown. UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated in these
Figures.
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While it is easy to associate protective relays to the three levels of monitoring, it is also true that most of
the components that can make up a Protection System can also have technological advancements that
place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables (Tables 1a, 1b and 1c collectively Tables) from
PRC-005-2:
First check the table header description to verify that your equipment meets the monitoring
requirements. If your equipment does not meet the monitoring requirements of Table 1c then
check Table 1b. If your equipment does not meet the requirements of Table 1b then use Table 1a.
If you find a piece of equipment that meets the monitoring requirements of Table 1b or 1c then
you can take advantage of the extended time intervals allowed by Table 1b and 1c. Your
maintenance plan must document that this category of equipment can be maintained by the
requirements of Table 1b or 1c because it has the necessary attributes required within that Table.
Once you determine which table applies to your equipment’s monitoring requirements then check
the Maintenance Activity that is required for that particular category of equipment. This
Maintenance Activity is the minimum maintenance activity that must be documented.
After the maintenance activity is known, check the Maximum Maintenance Interval; this time is
the maximum time allowed between hands-on maintenance activity cycles of this category of
your equipment.
Any given set of Protection System equipment can be maintained with any combination of Tables
1a, 1b and 1c. An entity does not have to stick to Table 1a just because some of its equipment is
un-monitored.
An entity does not have to utilize the extended time intervals in Tables 1b or 1c. An easy choice
to make is to simply utilize Table 1a. While the maintenance activities resulting from choosing to
use only Table 1a would require more maintenance man-hours, the maintenance requirements
may be simpler to document and the resulting maintenance plans may be easier to create.
For each Protection System component, Table 1 shows maximum allowable testing intervals for
unmonitored, partially monitored and fully monitored protection systems:
Table 1 Maintenance Activities and Maximum Intervals
Level 1 Monitoring (Unmonitored) Table 1a
This table applies to electromechanical, analog solid state and other un-monitored Protection Systems
components. This table represents the starting point for all required maintenance activities. The object of
this group of requirements is to have specific activities accomplished at maximum set time intervals.
From this group of activities it follows that CBM or PBM can increase the time intervals between the
hands-on maintenance actions.
Level 2 Monitoring (Partially Monitored) Table 1b
This table applies to microprocessor relays and other associated Protection System components whose
self-monitoring alarms are transmitted to a location where action can be taken for alarmed failures. The
attributes of the monitoring system must meet the requirements specified in the header of the Table 1b.
Given these advanced monitoring capabilities, it is known that there are specific and routine testing
functions occurring within the device. Because of this ongoing monitoring hands-on action is required
less often because routine testing is automated. However, there is now an additional task that must be
accomplished during the hands-on process – the monitoring and alarming functions must be shown to
work.
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Level 3 Monitoring (Fully Monitored) Table 1c
This table applies to microprocessor relays and other associated Protection System components in which
every element or function required for correct operation of the Protection System component is monitored
continuously and verified, including verification of the means by which failure alarms or indicators are
transmitted to a central location for immediate action. This is the highest level of monitoring and if it is
available then this gives an entity the ability to have continuous testing of their (Level 3 Monitored)
Protection System Component and thus does not have to manually intervene to accomplish routine testing
chores. Level 3 Fully Monitored yields continuous monitoring advantages but has substantial technical
hurdles that must be overcome; namely that monitoring also verifies the failure of the monitoring and
alarming equipment. Without this important ingredient a device that is thought to be continuously
monitored could be in an alarm state without the central location being made aware.
Additional Notes for Table 1a, Table 1b, and Table 1c
1. For electro-mechanical relays, adjustment is required to bring measurement accuracy within the
tolerance needed by the asset owner. Microprocessor-relays with no remote monitoring of alarm
contacts, etc, are un-monitored relays and need to be verified within the Table interval as other
un-monitored relays but may be verified as functional by means other than testing by simulated
inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring calibration, but
acceptable measurement of power system input values must be verified (verification of the
Analog to Digital [A/D] converters) within the Table intervals. The integrity of the digital inputs
and outputs must be verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a protection system or
SPS (as opposed to a monitoring task) must be verified as a component in a protection system.
4. In addition to verifying the circuitry that supplies dc to the protection system, the owner must
maintain the station dc supply. The most widespread station dc supply is the station battery and
charger. Unlike most Protection System elements physical inspection of station batteries for
signs of component failure, reduced performance, and degradation are required to ensure that the
station battery is reliable enough to deliver dc power when required. IEEE Standards 450, 1188,
and 1106 for Vented Lead-Acid, Valve-Regulated Lead-Acid, and Nickel-Cadmium batteries,
respectively (which are the most commonly used substation batteries on the NERC BES) have
been developed as an important reference source of maintenance recommendations. The
Protection System owner should attempt to use the applicable IEEE recommended practice which
contains information and recommendations concerning the maintenance, testing and replacement
of its substation battery. However, the methods prescribed in these IEEE recommendations
cannot be specifically required because they do not apply to all battery applications.
5. Aggregated small entities will naturally distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given year.
Additionally, if relatively small quantities of such systems do not perform properly, it will not
affect the integrity of the overall program.
6. Voltage & Current Sensing Device circuit input connections to the protection system relays can
be verified by comparison of known values of other sources on live circuits or by using test
currents and voltages on equipment out of service for maintenance. The verification process can
be automated or manual. The values should be verified to be as expected, (phase value and phase
relationships are both equally important to prove).
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7. Verify the protection system tripping function by performing an operational trip test on all
components contained in the trip circuit. This includes circuit breaker or circuit switcher trip
coils, auxiliary tripping relays (94), lock-out relays (86), and communications-assisted trip
scheme elements. Each control circuit path that carries trip signal must be verified, although each
path must be checked only once. A maintenance program may include performing an overall test
for the entire system at one time, or several split system tests with overlapping trip verification.
Trip coil continuity and aux-contact verification may be accomplished by inspection for the
proper control panel light indication. Remote alarm monitoring of the trip coil and aux-contact
continuity eliminates the need for tri-monthly inspections of trip coil indications. A documented
real-time trip of any given trip path is acceptable in lieu of a functional trip test.
8. “End-to-end test” as used in this supplementary reference is any testing procedure that creates a
remote input to the local communications-assisted trip scheme. While this can be interpreted as a
GPS-type functional test it is not limited to testing via GPS. Any remote scheme manipulation
that can cause action at the local trip path can be used to functionally-test the dc Control
Circuitry. A documented real-time trip of any given trip path is acceptable in lieu of a functional
trip test. It is possible, with sufficient monitoring, to be able to prove each and every parallel trip
path that participated in any given dc Control Circuit trip. Or, another possible solution is that a
single trip path from a single monitored relay can be proven to be the trip path that successfully
tripped during a real-time operation. The variations are only limited by the degree of engineering
and monitoring that an entity desires to pursue.
9. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus feeder
currents) can be used for comparison if calibration requirements assure acceptable measurement
of power system input values.
8.2
Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three years.
However, with a three year retention cycle, the records of verification for a protection system will
typically be discarded before the next verification, leaving no record of what was done if a misoperation
or failure is to be analyzed.
PRC-005-2 corrects this by requiring that the documentation be retained for two maintenance intervals.
Additionally, this requirement assures that the interval between maintenance cycles correctly meets the
maintenance interval limits.
8.3 Basis for Table 1 Intervals
SPCTF authors collected all available data from Regional Entities (REs) on time intervals recommended
for maintenance and test programs. The recommendations vary widely in categorization of relays, defined
maintenance actions, and time intervals, precluding development of intervals by averaging. SPCTF also
reviewed the 2005 Report [2] of the IEEE Power System Relaying Committee Working Group I-17
(Transmission Relay System Performance Comparison). Review of the I-17 report shows data from a
small number of utilities, with no company identification or means of investigating the significance of
particular results.
To develop a solid current base of practice, SPCTF surveyed its members regarding their maintenance
intervals for electromechanical and microprocessor relays, and asked the members to also provide
definitively-known data for other entities. The survey represented 470 GW of peak load, or 64% of the
NERC peak load. Maintenance interval averages were compiled by weighting reported intervals
according to the size (based on peak load) of the reporting utility. Thus, the averages more accurately
represent practices for the large populations of protection systems used across the NERC regions.
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The results of this survey with weighted averaging indicate maintenance intervals of 5 years for
electromechanical or solid state relays, and 7 years for un-monitored microprocessor relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond 7 years,
based on favorable experience with the particular products they have installed. To provide a technical
basis for such extension, SPCTF authors developed a recommendation of 10 years using the Markov
modeling approach from [1] as summarized in Section 8.4. The results of this modeling depend on the
completeness of self-testing or monitoring. Accordingly, this extended interval is allowed by Table 1 only
when such relays are monitored as specified in the header of Table 1b. Monitoring is capable of reporting
protection system health issues that are likely to affect performance within the 10 year time interval
between verifications.
It is important to note that, according to modeling results, protection system availability barely changes as
the maintenance interval is varied below the 10-year mark. Thus, reducing the maintenance interval does
not improve protection system availability. With the assumptions of the model regarding how
maintenance is carried out, reducing the maintenance interval actually degrades protection system
availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level. The industry
has experience with self-monitoring microprocessor relays that leads to the Table 1 value for partial
monitoring as explained in Section 8.3. To develop a basis for the maximum interval for monitored
relays in their Protection System Maintenance — A Technical Reference, the SPCTF used the
methodology of Reference [1], which specifically addresses optimum routine maintenance intervals. The
Markov modeling approach of [1] is judged to be valid for the design and typical failure modes of
microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability measures:
Relay Unavailability — the probability that the relay is out of service due to failure or
maintenance activity while the power system element to be protected is in service.
Abnormal Unavailability — the probability that the relay is out of service due to failure or
maintenance activity when a fault occurs, leading to failure to operate for the fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test). ST = 0 if
there is no self-monitoring; ST = 1 for full monitoring. Practical STvalues are estimated to range from
.75 to .95. The SPCTF simulation runs used constants in the Markov model that were the same as those
used in [1] with the following exceptions:
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal fault clearing time of 10 cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup fault clearing time of 50 cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a protection system)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a protection system repair after failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to these
parameter adjustments.
The resulting curves for Relay Unavailability and Abnormal Unavailability versus maintenance interval
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showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years – the curve is flat,
with no significant change in either unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years, much lower than MTBF values
typically published for these relays. Also, the Markov modeling indicates that both the relay
unavailability and abnormal unavailability actually become higher with more frequent testing. This
shows that the time spent on these more frequent tests yields no failure discoveries that approach the
negative impact of removing the relays from service and running the tests.
PSMT SDT further notes that the SPCTF also allowed 25% extensions to the “maximum time intervals”.
With a 5 year time interval established between manual maintenance activities and a 25% time extension
then this equates to a 6.25 year maximum time interval. It is the belief of the PSMT SDT that the SPCTF
understood that 6.25 years was thereby an adequate maximum time interval between manual maintenance
activities. The PSMT SDT has followed the FERC directive for a maximum time interval and has
determined that no extensions will be allowed. Six years has been set for the maximum time interval
between manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval between
maintenance activities. A 10 year interval with a 25% allowed extension equates to a maximum allowed
interval of 12.5 years between manual maintenance activities. The Standard does not allow extensions on
any component of the protection system; thus the maximum allowed interval for these devices has been
set to12 years. Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum Maintenance
Interval”. The PSMT SDT deemed it necessary to include the term “Calendar” to facilitate annual
maintenance planning, scheduling and implementation. This need is the result of known occurrences of
system requirements that could cause maintenance schedules to be missed by a few days or weeks. The
PSMT SDT chose the term “Calendar” to preclude the need to have schedules be met to the day. An
electro-mechanical protective relay that is maintained in year #1 need not be revisited until 6 years later
(year #7). For example: a relay was maintained December 15, 2008; it would be due for maintenance
again no later than December 31, 2014.
Section 9 describes a performance-based maintenance process which can be used to justify maintenance
intervals other than those described in Table 1.
Section 10 describes sections of the protection system, and overlapping considerations for full verification
of the protection system by segments. Segments refer to pieces of the protection system, which can range
from a single device to a panel to an entire substation.
Section 11 describes how relay operating records can serve as a basis for verification, reducing the
frequency of manual testing.
Section 13 describes how a cooperative effort of relay manufacturers and protection system users can
improve the coverage of self-monitoring functions, leading to full monitoring of the bulk of the
protection system, and eventual elimination of manual verification or testing.
9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a performance-based maintenance process may be used to establish
maintenance intervals. A performance-based maintenance process may justify longer maintenance
intervals, or require shorter intervals relative to Table 1. In order to use a performance-based maintenance
process, the documented maintenance program must include records of repairs, adjustments, and
corrections to covered protection systems in order to provide historical justification for intervals other
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than those established in Table 1. Furthermore, the asset owner must regularly analyze these records of
corrective actions to develop a ranking of causes. Recurrent problems are to be highlighted, and remedial
action plans are to be documented to mitigate or eliminate recurrent problems.
Utilities with performance-based maintenance track performance of protection systems, demonstrate how
they analyze findings of performance failures and aberrations, and implement continuous improvement
actions. Since no maintenance program can ever guarantee that no malfunction can possibly occur,
documentation of a performance-based maintenance program would serve the utility well in explaining to
regulators and the public a misoperation leading to a major system outage event.
A performance-based maintenance program requires auditing processes like those included in widely used
industrial quality systems (such as ISO 9001-2000, Quality management systems — Requirements; or
applicable parts of the NIST Baldridge National Quality Program). The audits periodically evaluate:
•
•
•
•
•
The completeness of the documented maintenance process
Organizational knowledge of and adherence to the process
Performance metrics and documentation of results
Remediation of issues
Demonstration of continuous improvement.
In order to opt into a Performance Based Maintenance (PBM) program the asset owner must first sort the
various Protection System components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM but does not own 60 units to
comprise a population then that asset owner may combine data from other asset owners until the needed
60 units is aggregated. Each population segment must be composed of like devices from the same
manufacturer and subjected to similar environmental factors. For example: One segment cannot be
comprised of both GE & Westinghouse electro-mechanical lock-out relays; likewise, one segment cannot
be comprised of 60 GE lock-out relays, 30 of which are in a dirty environment and the remaining 30 from
a clean environment.
9.1
Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling distribution of the
sample mean can be approximated by a normal probability distribution.” The Central Limit Theorem
states: “In selecting simple random samples of size n from a population, the sampling distribution of the
sample mean x can be approximated by a normal probability distribution as the sample size becomes
large.” (Essentials of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003)
To use the Central Limit Theorem in statistics, the population size should be large. The references below
are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30), the
central limit theorem enables us to conclude that the sampling distribution of the sample
mean can be approximated by a normal distribution.” (Essentials of Statistics for
Business and Economics, Anderson, Sweeney, Williams, 2003)
“If samples of size n, when n>=30, are drawn from any population with a mean u and a
standard deviation , the sampling distribution of sample means approximates a normal
distribution. The greater the sample size, the better the approximation.” (Elementary
Statistics - Picturing the World, Larson, Farber, 2003)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005)
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“… the normal is often used as an approximation to the t distribution in a test of a null
hypothesis about the mean of a normally distributed population when the population
variance is estimated from a relatively large sample. A sample size exceeding 30 is often
given as a minimal size in this connection.” (Statistical Analysis for Business Decisions,
Peters, Summers, 1968)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated using the
bound on the Error of Distribution Formula when the expected result is of a “Pass/Fail” format and will
be between 0 and 1.0.
The Error of Distribution Formula is:
z
1
n
Where:
= bound on the error of distribution (allowable error)
z = standard error
= expected failure rate
n = sample size required
Solving for n provides:
z
n 1
2
Minimum Population Size to use Performance Based Program
One entity’s population of components should be large enough to represent a sizeable sample of a
vendor’s overall population of manufactured devices. For this reason the following assumptions are
made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
= 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance Based Program
The number of components that should be included in a sample size for evaluation of the appropriate
testing interval can be smaller because a lower confidence level is acceptable since the sample testing is
repeated or updated annually. For this reason, the following assumptions are made:
B = 5%
z = 1.44 (85% confidence level)
= 4%
Using the equation above, n=31.8.
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Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation mentioned.
Using this and the results of the equation, the following numbers are recommended:
Minimum Population Size to use Performance Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance Based Program = 30.
Once the population segment is defined then maintenance must begin within the intervals as outlined for
Level 1 monitoring, (Table 1a). Time intervals can be lengthened provided the last year’s worth of
devices tested (or 30 units, whichever is more) had fewer than 4% countable events. It is notable that 4%
is specifically chosen because an entity with a small population (60 units) would have to adjust its time
intervals between maintenance if more than 1 countable event was found to have occurred during the last
analysis period. A smaller percentage would require that entity to adjust the time interval between
maintenance activities if even one unit is found out of tolerance or causes a mis-operation.
The minimum number of units that can be tested in any given year is 5% of the population. Note that this
5% threshold sets a practical limitation on total length of time between intervals at 20 years.
If at any time the number of countable events equals or exceeds 4% of the last year’s tested-devices (or 30
units whichever is more) then the time period between manual maintenance activities must be decreased.
There is a time limit on reaching the decreased time at which the countable events is less than 4%; this
must be attained within three years.
This additional time period of three years to restore segment performance to <4% countable events is
mandated to keep entities from “gaming the PBM system”. It is believed that this requirement provides
the economic disincentives to discourage asset owners from arbitrarily pushing the PBM time intervals
out to 20 years as subsequent analysis might show that an excessive number of countable events could
then require that the entire population segment be re-tested and re-evaluated within 3 years.
10. Overlapping the Verification of Sections of the Protection System
Table 1 requires that every protection system element be periodically verified. One approach is to test the
entire protection scheme as a unit, from voltage and current sources to breaker tripping. For practical
ongoing verification, sections of the protection system may be tested or monitored individually. The
boundaries of the verified sections must overlap to ensure that there are no gaps in the verification.
All of the methodologies expressed within this report may be combined by an entity, as appropriate, to
establish and operate a maintenance program. For example, a protection system may be divided into
multiple overlapping sections with a different maintenance methodology for each section:
•
Time based maintenance with appropriate maximum verification intervals for categories
of equipment as given in the Unmonitored, Partially Monitored, or Fully Monitored
Tables;
•
Full monitoring as described in header of Table 1c;
•
A performance-based maintenance program as described in Section 9;
•
Opportunistic verification using analysis of fault records as described in Section 11
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve fault event records and oscillographic records by data
communications after a fault. They analyze the data closely if there has been an apparent misoperation, as
NERC standards require. Some advanced users have commissioned automatic fault record processing
systems that gather and archive the data. They search for evidence of component failures or setting
problems hidden behind an operation whose overall outcome seems to be correct. The relay data may be
augmented with independently captured digital fault recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for a manual
time-interval based check on protection systems whose operations are analyzed. Even electromechanical
protection systems instrumented with DFR channels may achieve some CBM benefit. The completeness
of the verification then depends on the number and variety of faults in the vicinity of the relay that
produce relay response records, and the specific data captured.
A typical fault record will verify particular parts of certain protection systems in the vicinity of the fault.
For a given protection system installation, it may or may not be possible to gather within a reasonable
amount of time an ensemble of internal and external fault records that completely verify the protection
system.
For example, fault records may verify that the particular relays that tripped are able to trip via the control
circuit path that was specifically used to clear that fault. A relay or DFR record may indicate correct
operation of the protection communications channel. Furthermore, other nearby protection systems may
verify that they restrain from tripping for a fault just outside their respective zones of protection. The
ensemble of internal fault and nearby external fault event data can verify major portions of the protection
system, and reset the time clock for the Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel with
multiple relays, only the specific relay(s) whose operation can be observed without ambiguity in the
record and the associated wiring paths are verified. Be careful about using fault response data to verify
that settings or calibration are correct. Unless records have been captured for multiple faults close to
either side of a setting boundary, setting or calibration could still be incorrect.
If fault record data is used to show that portions or all of a protection system have been verified to meet
Table 1 requirements, the owner must retain the fault records used, and the maintenance related
conclusions drawn from this data and used to defer Table 1 tests, for at least the retention time interval
given in Section 8.2.
12. Importance of Relay Settings in Maintenance Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to show that
the relays have correct settings and calibration. Microprocessor relays, by contrast, provide the means for
continuously monitoring measurement accuracy. Furthermore, the relay digitizes inputs from one set of
signals to perform all measurement functions in a single self-monitoring microprocessor system. These
relays do not require testing or calibration of each setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older relays. Some
microprocessor relays have hundreds or thousands of settings, many of which are critical to protection
system performance.
Monitoring does not check measuring element settings. Analysis of fault records may or may not reveal
setting problems. To minimize risk of setting errors after commissioning, the user should enforce strict
settings data base management, with reconfirmation (manual or automatic) that the installed settings are
correct whenever maintenance activity might have changed them. For background and guidance, see [5].
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Table 1 requires that settings must be verified to be as specified. The reason for this requirement is
simple. With legacy relays (non-microprocessor protective relays) it is necessary to know the value of the
intended setting in order to test, adjust and calibrate the relay. Proving that the relay works per specified
setting was the de facto procedure. However, with the advanced microprocessor relays it is possible to
change relay settings for the purpose of verifying specific functions and then neglect to return the settings
to the specified values. While there is no specific requirement to maintain a settings management process
there remains a need to verify that the settings left in the relay are the intended, specified settings. This
need may manifest itself after any of the following:
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products for nearly
20 years. Theoretically, any element that is monitored does not need a periodic manual test. A problem
today is that the community of manufacturers and users has not created clear documentation of exactly
what is and is not monitored. Some unmonitored but critical elements are buried in installed systems that
are described as self-monitoring.
Until users are able to document how all parts of a system which are required for the protective functions
are monitored or verified (with help from manufacturers), they must continue with the unmonitored or
partially monitored intervals established in Table 1.
Going forward, manufacturers and users can develop mappings of the monitoring within relays, and
monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of full monitoring, the manufacturers of the microprocessor-based self-monitoring
components in the protection system should publish for the user a document or map that shows:
How all internal elements of the product are monitored for any failure that could
impact protection system performance.
Which connected circuits are monitored by checks implemented within the product;
how to connect and set the product to assure monitoring of these connected circuits;
and what circuits or potential problems are not monitored.
With this information in hand, the user can document full monitoring for some or all sections by:
Presenting or referencing the product manufacturer’s documents.
Explaining in a system design document the mapping of how every component and
circuit that is critical to protection is monitored by the microprocessor product(s) or by
other design features.
Extending the monitoring to include the alarm transmission facilities through which
failures are reported to remote centers for immediate action, so that failures of monitoring
or alarming systems also lead to alarms and action.
Documenting the plans for verification of any unmonitored elements according to the
requirements of Table 1.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
14. Notification of Protection System Failures
When a failure occurs in a protection system, power system security may be compromised, and
notification of the failure must be conducted in accordance with relevant NERC standard(s). Knowledge
of the failure may impact the system operator’s decisions on acceptable loading conditions.
This formal reporting of the failure and repair status to the system operator by the protection system
owner also encourages the system owner to execute repairs as rapidly as possible. In some cases, a
microprocessor relay or carrier set can be replaced in hours; wiring termination failures may be repaired
in a similar time frame. On the other hand, a component in an electromechanical or early-generation
electronic relay may be difficult to find and may hold up repair for weeks. In some situations, the owner
may have to resort to a temporary protection panel, or complete panel replacement.
15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would be that a
BES entity could be prudent in its protective relay maintenance but if its battery maintenance program is
lacking then reliability could still suffer. The NERC glossary outlines a Protection System as containing
specific components. PRC-005-02 requires specific maintenance activities be accomplished within a
specific time interval. As noted previously, higher technology equipment can contain integral monitoring
capability that actually performs maintenance verification activities routinely and often; therefore manual
intervention to perform certain activities on these type devices may not be needed.
15.1 Protective Relays
These relays are defined as the devices that receive the input signal from the current and voltage sensing
devices and are used to isolate a faulted portion of the BES. Devices that sense thermal, vibration,
seismic, pressure, gas or any other non-electrical input are excluded.
Non-microprocessor based equipment is treated differently than microprocessor based equipment in the
following ways, but the relays must meet the calibration requirements of the asset owner.
Non-microprocessor devices must be tested with voltage and/or current applied to the device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test mandated.
o There is no specific documentation mandated.
15.2 Voltage & Current Sensing Devices
These are the current and voltage sensing devices, usually known as instrument transformers. There is
presently a technology available (fiber-optic Hall-effect) that does not utilize conventional transformer
technology; these devices and other technologies that produce quantities that represent the primary values
of voltage and current are included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the device that
produces the current or voltage signal sample.
There is no specific test mandated for these devices. The important thing about these signals is to know
that the expected output from these devices actually reaches the protective relay. Therefore, the proof of
the proper operation of these devices also demonstrates the integrity of the wiring (or other medium used
to convey the signal) from the current and voltage sensing device all the way to the protective relay. The
following observations apply.
There is no specific ratio test, routine test or commissioning test mandated.
There is no specific documentation mandated.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
It is required that the signal be present at the relay.
This expectation can be arrived at from any of a number of means; by calculation, by comparison
to other circuits, by commissioning tests, by thorough inspection, or by any means needed to
prove the circuit to the satisfaction of the asset owner.
An example of testing might be a saturation test of a CT with the test values applied at the relay
panel; this therefore tests the CT as well as the wiring from the relay all the back to the CT.
Another possible test is to measure the signal from the voltage and/or current sensing devices,
during load conditions, at the input to the relay.
Another example of testing the various voltage and/or current sensing devices is to query the
microprocessor relay for the real-time loading; this can then be compared to other devices to
verify the quantities applied to this relay. Since the input devices have supplied the proper values
to the protective relay then the verification activity has been satisfied. Thus event reports (and
oscillographs) can be used to prove that the voltage and current sensing devices are performing
satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this should add up to
zero watts and zero vars thus proving the voltage and/or current sensing devices system
throughout the bus.
Another method for proving the voltage and/or current sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
Other methods that provide documentation that the expected transformer values are applied to the
inputs to the protective relays are acceptable.
15.3 DC Control Circuitry
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit switcher or
any other interrupting device. It includes the wiring from the batteries to the relays. It includes the wiring
from every trip output to every trip coil. In short, every trip path must be verified; the method of
verification is optional to the asset owner. Each trip coil must be tested to trip the circuit breaker (or other
interrupting device) at least once.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay (86) in
any given trip scheme. These electro-mechanical devices must be trip tested. The PSMT SDT considers
these devices to share some similarities in failure modes as electro-mechanical protective relays; as such
there is a six year maximum interval between mandated maintenance tasks.
When verifying the operation of the 94 and 86 relays each normally-open contact that closes to pass a trip
signal must be verified as operating correctly. Normally-open contacts that are not used to pass a trip
signal and normally-closed contacts do not have to be verified. Verification of the tripping paths is the
requirement.
New technology is also accommodated here; there are some tripping systems that have replaced the
traditional hard-wired trip circuitry with other methods of trip-signal conveyance such as fiber-optics. It is
the intent of the PSMT SDT to include this, and any other, technology that is used to convey a trip signal
from a protective relay to a circuit breaker (or other interrupting device) within this category of
equipment.
15.4 Batteries and DC Supplies
IEEE guidelines were used to mandate maintenance activities for batteries. The following guidelines were
used: IEEE 450 (for Vented Lead-Acid batteries), IEEE 1188 (for Valve-Regulated Lead-Acid batteries)
and IEEE 1106 (for Nickel-Cadmium batteries).
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
The present NERC definition of a Protection System is “protective relays, associated communication
systems, voltage and current sensing devices, station batteries and dc control circuitry.” The station
battery is not the only component that provides dc power to a Protection System. In the new definition
for Protection System “station batteries” are replaced with “station dc supply” to make the battery charger
and dc producing stored energy devices (that are not a battery) part of the Protection System that must be
maintained.
To insure that there are no open circuits in a lead acid battery string, IEEE 450-2002 recommends that
during the monthly inspection “battery float charging current or pilot cell specific gravity” should be
measured and recorded. Similarly IEEE 1188-2005 states that during the monthly general inspection, the
“dc float current (per string)” should be checked and recorded “using equipment that is accurate at low
(typically less than 1 A) currents.” These tests are recommended by the IEEE standards for lead acid
batteries to detect an open circuit in a battery set that will make a battery unable to deliver dc power.
The PSMT SDT recognizes that there are several technological advances in equipment and testing
procedures that allow the owner to choose how to verify that a battery string is free of open circuits. The
term “continuity” was introduced into the standard to allow the owner to choose how to verify continuity
of a battery set by various methods, and not to limit the owner to the two methods recommended in the
IEEE standards. Continuity as used in Table 1 of the standard refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative terminal.
Without verifying continuity of a station battery, there is no way to determine that the station battery is
available to supply dc power to the station.
Batteries cannot be a unique population segment of a Performance Based Maintenance Program (PBM)
because there are too many variables in the electro-chemical process to completely isolate all of the
performance-changing criteria necessary for using PBM on battery systems.
15.5 Tele-protection equipment
This is also known as associated telecommunications equipment. The equipment used for tripping in a
communications assisted trip scheme is a vital piece of the trip circuit. Remote action causing a local trip
can be thought of as another parallel trip path to the trip coil that must be tested.
Besides the trip output and wiring to the trip coil(s) there is also a communications medium that must be
maintained.
Newer technologies now exist that achieve communications-assisted tripping without the conventional
wiring practices of older technology.
For example: older technologies may have included Frequency Shift Key methods. This technology
requires that guard and trip levels be maintained.
The actual tripping path(s) to the trip coil(s) may be tested as a parallel trip path within the dc control
circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are then
interpreted locally as trip signals.
The requirements apply to the communicated signal needed for the proper operation of the protective
relay trip logic or scheme. Therefore this standard is applied to equipment used to convey both trip signals
and block signals.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
It was the intent of this standard to require that a test be made of any communications-assisted trip
scheme regardless of the vintage of the technology. The essential element is that the tripping occurs
locally when the remote action has been asserted.
Evidence of operational test or documentation of measurement of signal level, reflected power or dataerror rates is needed.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the control
house to the circuit interrupting device in the yard. This method of tripping the circuit breaker, even
though it might be considered communications, must be maintained per the dc control circuitry
maintenance requirements.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
16. References
NERC/SPCTF/Relay_Maintenance_Tech_Ref_approved_by_PC.pdf
1. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J. Kumm, M.S.
Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power Delivery, Vol. 10,
No. 2, April 1995.
2. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003, 2004
and 2005,” Working Group I17 of Power System Relaying Committee of IEEE Power
Engineering Society, May 2006.
3. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System Relaying
Committee of IEEE Power Engineering Society, September 16, 1999.
4. “Transmission Protective Relay System Performance Measuring Methodology,” Working
Group I3 of Power System Relaying Committee of IEEE Power Engineering Society, January
2002.
5. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3 of
Power System Relaying Committee of IEEE Power Engineering Society, December 2006.
6. “Proposed Statistical Performance Measures for Microprocessor-Based Transmission-Line
Protective Relays, Part I - Explanation of the Statistics, and Part II - Collection and Uses of
Data,” Working Group D5 of Power System Relaying Committee of IEEE Power
Engineering Society, May 1995; Papers 96WM 016-6 PWRD and 96WM 127-1 PWRD,
1996 IEEE Power Engineering Society Winter Meeting.
7. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
8. “Use of Preventative Maintenance and System Performance Data to Optimize Scheduled
Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia Tech Protective
Relay Conference, May 1996.
PSMT SDT References
9. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams, 2003
10. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore, 2005
11. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Figures
Figure 1: Typical Transmission System
For information on numbered components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Figure 2: Typical Generation System
For information on numbered components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Figure 1 and 2 Legend — Components of Protection Systems
Number In
Figure
Component of Protection
System
Includes
Excludes
1
Protective relays
All protective relays that use current and/or voltage
inputs from current & voltage sensors and that trip the
86, 94 or trip coil.
Devices that use non-electrical methods of operation
including thermal, pressure, gas accumulation, and
vibration. Any ancillary equipment not specified in the
definition of Protection systems. Control and/or
monitoring equipment that is not a part of the automatic
tripping action of the Protection System
2
Current & voltage sensors
Transformers or other current & voltage sensing
devices that produce signals for protective relays as
well as the wiring (or other medium) used to convey
signal output from the sensor to the protective relay
input.
Voltage & current sensing devices that are not a part of
the Protection System, including sync-check systems,
metering systems and data acquisition systems.
3
DC Circuitry
All control wiring (or other medium for conveying trip
signals) associated with the tripping action of 86
devices, 94 devices or trip coils (from all parallel trip
paths). This would include fiber-optic systems that
carry a trip signal as well as hard-wired systems that
carry trip current. Also, it includes auxiliary contacts
providing breaker position data that is necessary for the
proper operation of the Protection System.
Closing circuits, SCADA circuits
4
DC Supply
Batteries and battery chargers and any control
power system which has the function of
supplying power to the protective relays,
associated trip circuits and trip coils.
Any power supplies that are not used to power
protective relays or their associated trip circuits
and trip coils.
5
Associated
communications
equipment
Tele-protection equipment used to convey
remote tripping action to a local trip coil or
blocking signal to the trip logic (if applicable)
Any communications equipment that is not used
for remote tripping action to a local trip coil or
blocking signal to the trip logic (if applicable)
(Return)
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Figure 3: Requirements Flowchart
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in Section 10
of the paper. As an example, Figure A-1 shows protection for a critical transmission line by carrier
blocking directional comparison pilot relaying. The goal is to verify the ability of the entire two-terminal
pilot protection scheme to protect for line faults, and to avoid over-tripping for faults external to the
transmission line zone of protection bounded by the current transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays themselves,
the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of internal
electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report the
state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of other
relays, meters, or DFRs. The other readings may be from redundant relaying or measurement
systems or they may be derived from values in other protection zones. Comparison with other
such readings to within required relaying accuracy verifies Voltage & Current Sensing
Devices, wiring, and analog signal input processing of the relays. One effective way to do
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
this is to utilize the relay metered values directly in SCADA, where they can be compared
with other references or state estimator values.
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the protection
system, so each carrier set has a connected or integrated automatic checkback test unit. The
automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation or
noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the protection
system elements that experience tells us are the most prone to fail. But, does this comprise a complete
verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded regions
show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
2. Within each line relay, all the microprocessors that participate in the trip decision have been
verified by internal monitoring. However, the trip circuit is actually energized by the contacts
of a small telephone-type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a fault.
3. The check-back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying circuit
or the carrier receiver output state. These connections include microprocessor I/O ports,
electronic driver circuits, wiring, and sometimes telephone-type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but this
does not confirm that the state change indication is correct when the breaker or switch opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified maximum time
interval between trip tests. Clearing of naturally-occurring faults are demonstrations of operation that
reset the time interval clock for testing of each breaker tripped in this way. If faults do not occur, manual
tripping of the breaker through the relay trip output via data communications to the relay microprocessor
meets the requirement for periodic testing.
PRC-005 does not address breaker maintenance, and its protection system test requirements can be met by
energizing the trip circuit in a test mode (breaker disconnected) through the relay microprocessor. This
can be done via a front-panel button command to the relay logic, or application of a simulated fault with a
relay test set. However, utilities have found that breakers often show problems during protection system
tests. It is recommended that protection system verification include periodic testing of the actual tripping
of connected circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and that the
other relay demonstrate reception of that blocking carrier. This can be observed from relay or DFR
records during naturally occurring faults, or by a manual test. If the checkback test sequence were
incorporated in the relay logic, the carrier sets and carrier channel are then included in the overlapping
segments monitored by the two relays, and the monitoring gap is completely eliminated.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
PRC-005-2 Protection Systems Maintenance & Testing Standard Drafting Team
Charles W. Rogers – Chair
Consumers Energy
Merle Ashton
Tri-State Generation & Transmission Assn, Inc.
Bob Bentert
Florida Power & Light Co.
John Ciufo
Hydro One, Inc
Richard Ferner
Western Area Power Administration
Sam Francis
Oncor
Carol A Gerou
Midwest Reliability Organization.
Roger D Green
Southern Company Generation
Russell Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
John Kruse
Commonwealth Edison Co.
Mark Peterson
Great River Energy
William D Shultz
Southern Company Generation
Leonard Swanson, Jr.
National Grid USA
Eric A Udren
Quanta Technology
Philip B Winston
Georgia Power Company
John A Zipp
ITC Holdings
Draft 1: July, 2009
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Status of Addressing Issues (identified by FERC and stakeholders) Associated with PRC-005-1, PRC008-0, PRC-011-0 and PRC-017-0
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
Source
Language
Drafting Team Resolution
FERC Order
693
Maintenance and testing of a protection system must be carried
out within a maximum allowable time interval that is appropriate
for the type of protection system and its impact on the reliability of
the bulk power system.
Specific time intervals are included in the draft standard.
The justification for the intervals is provided in the
supplemental reference document.
FERC Order
693
Consider FirstEnergy’s and ISO-NE’s suggestions to combine
PRC-005, PRC-008, PRC-011, and PRC-017 into a single
standard.
This suggestion is being used.
NERC Audit
Observation
Team
How do you verify compliance for for cts/pts? How do you audit
these within a scheduled maintenance program. As part of the
procedure, most have accepted visual inspection. Some entities
state that testing of the relays verify functionality of the ct/p
Records must be maintained -- records only means of
proof if was done. Verification activities in Table 1
establish the activities required for CTs/PTs.
Version 0
Team
Not a standalone standard
Being combined with three other standards all
addressing maintenance of protection systems.
Version 0
Team
Include breakers/switches in list
Breakers are specifically NOT included in the Protection
System definition, and therefore are NOT addressed in
the draft standard.
Version 0
Team
Define evidence
Requirement R4 established that the program must be
implemented. Evidence that the program is
implemented is a measure; evidence is not discussed in
requirements.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
Source
Language
Drafting Team Resolution
NERC Audit
Observation
Team
Determine what on schedule means. Is an entity who
maintained/tested 95% of their relays at the same level of noncompliance as an entity who maintained/tested 10% of their
relays?
100% compliance is required - violation severity levels
to address time. Will consider implementation of this
observation when developing compliance elements.
NERC Audit
Observation
Team
As applicable, each TO, DP and GOP shall have a protection
system maintenance and testing program for protection systems
that affect the reliability of the BES. Does this include major
equipment like circuit breakers and transformers?
Yes – the proposed standard does include protection
systems for breakers and transformers.
NERC Audit
Observation
Team
How do you verify DC control power? All regions require
functional testing of the breaker. This should include functional
relay & station battery checks, including breaker tripping, not just
a visual inspection.
Specific verification activities are established in Table 1
and more details are provided in the supplemental
reference.
Phase III/IV
Team
All protection systems on the bulk electric system.
The applicability section addresses Protection Systems
that are "applied on, or designed to protect the BES",
and provides additional specificity regarding applicable
generator Protection Systems
Phase III/IV
Team
PRC 003 to 005 only address generator (and transmission)
protective systems, without defining this term.
The applicability section addresses Protection Systems
that are "applied on, or designed to protect the BES",
and provides additional specificity regarding applicable
generator Protection Systems
Phase III/IV
Team
Need to add language to ensure the Regional Requirements
focus on the most impactive scenarios
The draft standard established minimum ERO-wide
requirements; any Regional requirements would have to
exceed the ERO requirements.
Phase III/IV
Team
Modify applicability to clarify that the requirements are applicable
to the following:
See the applicability section of the standard.
July 22, 2009
Breakers are specifically NOT included in the Protection
System definition, and therefore are NOT addressed as
components of Protection Systems.
2
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
Source
Language
Drafting Team Resolution
Phase III/IV
Team
All generation protection systems whose misoperations impact
the bulk electric system
Specificity is provided in 4.2.5 addressing generator
Protection Systems
Phase III/IV
Team
There is no performance requirement or measure of effectiveness
of a maintenance program required by the standard
For Time-Based (or Condition-Based) maintenance,
minimum activities and maximum intervals are specified;
for performance-based maintenance, performance (or
effectiveness) goals are established.
July 22, 2009
3
PRC-008-0 — Implementation and Documentation of Underfrequency Load Shedding
Equipment Maintenance Program
Source
Language
Drafting Team Resolution
FERC Order
693
Maintenance and testing of a protection system must be carried out within a
maximum allowable time interval that is appropriate for the type of protection
system and its impact on the reliability of the bulk power system.
Specific time intervals are included in the
draft standard.
Version 0
Team
Definition of evidence required
Requirement R4 established that the program
must be implemented. Evidence that the
program is implemented is a measure;
evidence is not discussed in requirements.
Version 0
Team
Consistent wording from standard to standard required
Combining maintenance standards and being
careful to do this.
Fill in the
Blank Team
Okay if PRC-006 is fixed
Applicability section of PRC-005-2 (4.2.2)
establishes applicability to UFLS established
in accordance with ERO requirements.
July 22, 2009
4
PRC-011-0 — Undervoltage Load Shedding System Maintenance and Testing
Source
Language
Drafting Team Resolution
FERC Order
693
Maintenance and testing of a protection system must be carried out within a
maximum allowable time interval that is appropriate for the type of protection
system and its impact on the reliability of the bulk power system.
Specific time intervals are included in the
draft standard.
Version 0
Team
Exemptions for those with shunt reactors
UV Relays on shunt reactors are not UVLS;
these relays would be included as pertinent to
relays "applied on or to protect the BES".
Version 0
Team
Define evidence
Requirement R4 established that the program
must be implemented. Evidence that the
program is implemented is a measure;
evidence is not discussed in requirements.
July 22, 2009
5
PRC-017-0 — Special Protection System Maintenance and Testing
Source
Language
Drafting Team Resolution
FERC Order
693
Require that documentation identified in requirement R2 be routinely
provided to NERC or the regional entity.
Language to be addressed in the compliance
section of the standard.
FERC Order
693
Maintenance and testing of a protection system must be carried out within a
maximum allowable time interval that is appropriate for the type of protection
system and its impact on the reliability of the bulk power system.
Table 1 establishes maximum allowable
maintenance intervals, with different intervals
for different technologies of protective system
equipment, and for different components
defined within "Protection System"
Version 0
Team
Need to retain two dates
Not sure what this is.
Version 0
Team
Define evidence
Requirement R4 established that the program
must be implemented. Evidence that the
program is implemented is a measure;
evidence is not discussed in requirements.
July 22, 2009
6
PRC-005-2 — Protection System Maintenance
Frequently Asked Questions
Practical Compliance and Implementation (Draft 1)
Protection System Maintenance and Testing
Standard Drafting Team
July, 2009
PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
Table of Contents
Introduction................................................................................................................................................. 2
Executive Summary .................................................................................................................................... 2
Terms Used in PRC-005-2.......................................................................................................................... 2
Frequently Asked Questions ...................................................................................................................... 3
General FAQs:.......................................................................................................................................... 3
Group by Type of Protection System Component:.................................................................................... 5
1.
All ................................................................................................................................................... 5
2.
Protective Relays .............................................................................................................................. 5
3.
Voltage and Current Sensing Device Inputs to Protective Relays .................................................... 6
4.
Protection System Control Circuitry................................................................................................. 7
5.
Station dc Supply............................................................................................................................... 8
6.
Protection System Communications Equipment ............................................................................. 12
7.
UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power
System........................................................................................................................................... 14
8.
SPS or Relay Sensing for Centralized UFLS or UVLS ................................................................... 14
Group by Type of BES Facility:.............................................................................................................. 15
1.
All BES Facilities ............................................................................................................................ 15
2.
Generation ...................................................................................................................................... 15
3.
Transmission ................................................................................................................................... 16
Group by Type of Maintenance Program: .............................................................................................. 16
1.
All Protection System Maintenance Programs ............................................................................... 16
2.
Time-Based Protection System Maintenance (TBM) Programs ..................................................... 17
3.
Performance-Based Protection System Maintenance (PBM) Programs ........................................ 18
Group by Monitoring Level: ................................................................................................................... 20
1.
All Monitoring Levels ..................................................................................................................... 20
2.
Level 1 Monitored Protection Systems (Unmonitored Protection Systems) ................................... 28
3.
Level 2 Monitored Protection Systems (Partially Monitored Protection Systems)......................... 29
4.
Level 3 Monitored Protection Systems (Fully Monitored Protection Systems) .............................. 29
Appendix A — Protection System Maintenance Standard Drafting Team......................................... 30
Draft 1: July 21, 2009
Page i
PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
Introduction
The following is a draft collection of questions and answers that the PSMT SDT believes could be helpful
to those implementing NERC Standard PRC-005-2 Protection System Maintenance. As the draft standard
proceeds through development, this FAQ document will be revised, including responses to key or frequent
comments from the posting process. The FAQ will be organized at a later time during the development of
the draft Standard.
This FAQ document will support both the Standard and the associated Technical Reference document.
Executive Summary
To be added later if needed.
Terms Used in PRC-005-2
Maintenance Correctable Issue — As indicated in footnote 2 of the draft standard, a maintenance
correctable issue is a failure of a device to operate within design parameters that can be restored to
functional order by calibration, repair or replacement
Segment — As indicated in PRC-005 Attachment A Criteria for a Performance-Based Protection System
Maintenance Program, a segment is a “A grouping of Protection Systems or component devices of a
particular model or type from a single manufacturer, with other common factors such that consistent
performance is expected across the entire population of the segment, and shall only be defined for a
population of 60 or more individual components.”
Component — This equipment is first mentioned in Requirement 1, Part 1.1 of this standard. A component
is any individual discrete piece of equipment included in a Protection System, such as a protective relay or
current sensing device. Types of components are listed in Table 1 (“Maximum Allowable Testing Intervals
and Maintenance Activities for Unmonitored Protection Systems”). For components such as dc circuits, the
designation of what constitutes a dc control circuit element is somewhat arbitrary and is very dependent
upon how an entity performs and tracks the testing of the dc circuitry. Some entities test their dc circuits on
a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus, entities are
allowed the latitude to designate their own definitions of “dc control circuit elements.” Another example of
where the entity has some discretion on determining what constitutes a single component is the voltage and
current sensing devices, where the entity may choose either to designate a full three-phase set of such
devices or a single device as a single component.
Countable Event — As indicated in footnote 4 of PRC-005 Attachment A, Criteria for a Performancebased Protection System Maintenance Program, countable events include any failure of a component
requiring repair or replacement, any condition discovered during the verification activities in Table 1a
through Table 1c which requires corrective action, or a Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different from
specified settings, Protection System component configuration errors, or Protection System application
errors are not included in Countable Events.
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
Frequently Asked Questions
General FAQs:
1. The standard seems very complicated, and is difficult to understand. Can it be simplified?
Because the standard is establishing parameters for condition-based Maintenance (R2) and
performance-based Maintenance (R3) in addition to simple time-based Maintenance, it does appear
to be complicated. At its simplest, an entity needs to follow R1 and R4 and perform ONLY timebased maintenance according to Table 1a, eliminating R2 and R3 from consideration altogether. If
an entity then wishes to take advantage of monitoring on its Protection System components, R2
comes into play, along with Tables 1b and 1c. If an entity wishes to use historical performance of
its Protection System components to perform performance-based Maintenance, R3 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
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Page 3
PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
Draft 1: July 21, 2009
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
Group by Type of Protection System Component:
1. All
A.
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this standard?
No. As stated in R1, this standard covers protective relays that use measurements of voltage,
current and/or phase angle to determine anomalies and to trip a portion of the BES. Reclosers,
reclosing relays, closing circuits and auto-restoration schemes are used to cause devices to
close as opposed to electrical-measurement relays and their associated circuits that cause
circuit interruption from the BES; such closing devices and schemes are more appropriately
covered under other NERC Standards. There is one notable exception: if a Special Protection
System incorporates automatic closing of breakers, the related closing devices are part of the
SPS and must be tested accordingly.
B.
Why does PRC-005-2 not specifically require maintenance and testing procedures as
reflected in the previous standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2
requires a documented Maintenance program, and is focused on establishing Requirements
rather than prescribing methodology to meet those Requirements. Between the activities
identified in Tables 1a, 1b, and 1c, and the various components of the definition established
for a “Protection System Maintenance Program”, PRC-005-2 establishes the activities and
time-basis for a Protection System Maintenance Program to a level of detail not previously
required.
2. Protective Relays
A.
How do I approach testing when I have to upgrade firmware of a microprocessor relay?
The component “Upkeep” in the definition of a Protection System Maintenance Program,
addresses “Routine activities necessary to assure that the component remains in good working
order and implementation of any manufacturer’s hardware and software service advisories
which are relevant to the application of the device.” The Maintenance Activities specified in
Table 1a, Table 1b, and Table 1c do not present any requirements related to Upkeep for
Protective Relays. However, the entity should assure that the relay continues to function
properly after implementation of firmware changes.
B.
I use my protective relays only as sources of metered quantities and breaker status for
SCADA and EMS through a substation distributed RTU or data concentrator to the
control center. What are the maintenance requirements for the relays?
This standard addresses only devices “that are applied on, or are designed to provide
protection for the BES.” Protective relays, providing only the functions mentioned in the
question, are not included.
C.
I use my protective relays for fault and disturbance recording, collecting oscillographic
records and event records via communications for fault analysis to meet NERC and
DME requirements. What are the maintenance requirements for the relays?
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
For relays used only as disturbance monitoring equipment, the NERC standard PRC-018-1 R3
& R6 states the maintenance requirements, and is being addressed by a Standards activity that
is revising PRC-002-1 and PRC-018-1. For protective relays “that are applied on, or are
designed to provide protection for the BES,” this standard applies, even if they also perform
DME functions.
3. Voltage and Current Sensing Device Inputs to Protective Relays
A.
What is meant by “…verify the current and voltage circuit inputs from the voltage and
current sensing devices to the protective relays …” Do we need to perform ratio,
polarity and saturation tests every few years?
No. You must prove that the protective relay is receiving the expected values from the voltage
and current sensing devices (typically voltage and current transformers). This can be as
difficult as is proposed by the question (with additional testing on the cabling and substation
wiring to ensure that the values arrive at the relays); or simplicity can be achieved by other
verification methods. Some examples follow:
Compare the secondary values, at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay circuit.
Compare the values, as determined by the questioned relay, to another protective relay
monitoring the same line, with currents supplied by different CTs.
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned relay.
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that, an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring systems.
B.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral currents, or
3V0 voltages, by comparison, when my system is closely balanced?
These values will be zero, or very small, for any reasonably balanced system. To verify these
values by comparison, you will need to rely on the normal condition that your system is not
perfectly balanced, and there will usually be a small zero-sequence current or voltage, and
these values can be measured with instruments having a sufficiently low resolution range. A
reading of precisely zero will probably suggest that there is an opening (or some other
problem) in the measuring circuit. A finite value of a few percent of the phase quantities,
however, may suggest that the measuring circuit is indeed performing properly.
These quantities may be also verified by use of oscillographic records for connected
microprocessor relays as recorded during system disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known fault locations.
C.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not required by the Maintenance
Standard.
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
4. Protection System Control Circuitry
A.
Is it permissible to verify circuit breaker tripping at a different time (and interval) than
when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual components’
maximum allowable testing intervals.
B.
The Protection System Maintenance Standard describes requirements for verifying the
tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC-005-2 are intended to verify the integrity of tripping circuits, including
the breaker trip coil, as well as the presence of auxiliary supply (usually a dc battery) for
energizing the trip coil if a protection function operates. Beyond this, PRC-005-2 sets no
requirements for verifying circuit breaker performance, or for maintenance of the circuit
breaker.
C.
How do I test each dc Control Circuit path, as established for level 2 (partially monitored
protection systems) monitoring of a “Protection System Control Circuitry (Trip coils and
auxiliary relays)”?
Table 1b specifies that each breaker trip coil, auxiliary relay, and lockout relay must
be operated within the specified time period. The required operations may be via
targeted maintenance activities, or by documented operation of these devices for other
purposes such as fault clearing.
D.
What does this standard require for testing an Auxiliary Tripping Relay?
Table 1 requires that the trip test must verify that the auxiliary tripping relay (94) or lockout
relay (86) operates electrically and that their trip output(s) perform as expected.
E.
What does a functional trip test include?
An operational trip test must be performed on each portion of a trip circuit. Each control
circuit path that produces trip signal must be verified; this includes trip coils, auxiliary tripping
relays (94), lockout relays (86) and communications-assisted-trip schemes.
A trip test may be an overall test that verifies the operation of the entire trip scheme at once, or
it may be several tests of the various portions that make up the entire trip scheme, provided
that testing of the various portions of the trip scheme verifies all of the portions, including
parallel paths, and overlaps those portions.
A circuit breaker or other interrupting device needs to be trip tested at least once per trip coil.
Breaker auxiliary contacts that are essential for the proper operation of the protective relay
trip-circuit (or trip-logic) must be verified as providing the correct breaker open/close status
information to the Protection System.
Discrete-component auxiliary relays (94) and lock-out relays (86) must be proven by trip test.
The trip test must verify that the auxiliary or lock-out relay operates electrically and that the
relay’s trip output(s) change(s) state. Software latches or control algorithms, including trip
logic processing implemented as programming component such as a microprocessor relay that
take the place of (conventional) discrete component auxiliary relays or lock-out relays do not
have to be routinely trip tested.
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
Normally-closed auxiliary contacts from other devices (for example, switchyard-voltage-level
disconnect switches, interlock switches, or pressure switches) which are in the breaker trip
path do not need to be tested.
F.
Is a Sudden Pressure Relay an Auxiliary Tripping Relay?
No. IEEE C37.2-2008 assigns the device number 94 to auxiliary tripping relays. Sudden
pressure relays are assigned device number 63, and is excluded from the Standard by footnote 1.
G.
The standard specifically mentions Auxiliary and Lock-out relays; what is an Auxiliary
Tripping Relay?
An auxiliary relay, IEEE Device Number 94, is described in IEEE Standard C37.2-2008 as “A
device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate
tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should
open automatically, even though its closing circuit is maintained closed.”
H.
What is a Lock-out Relay?
A lock-out relay, IEEE Device Number 86, is described in IEEE Standard C37.2 as “A device
that trips and maintains the associated equipment or devices inoperative until it is reset by an
operator, either locally or remotely.”
I.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of the trip circuit. This standard does not
cover circuit breaker maintenance or transformer maintenance. The standard also does not
cover testing of devices such as sudden pressure relays (63), temperature relays (49), and other
relays which respond to mechanical parameters rather than electrical parameters.
5. Station dc Supply
A.
What constitutes the station dc supply as mentioned in the definition of Protective
System?
The station direct current (dc) supply normally consists of two components: the battery
charger and the station battery itself. There are also emerging technologies that provide a
source of dc supply that does not include either a battery or charger.
Battery Charger — The battery charger is supplied by an available ac source. At a minimum,
the battery charger must be sized to charge the battery (after discharge) and supply the
constant dc load. In many cases, it may be sized also to provide sufficient dc current to handle
the higher energy requirements of tripping breakers and switches when actuated by the
protective relays in the Protection System.
Station Battery — Station batteries provide the dc power required for tripping and for
supplying normal dc power to the station in the event of loss of the battery charger. There are
several technologies of battery that require unique forms of maintenance as established in
Table 1.
Emerging Technologies — Station dc supplies are currently being developed that use other
energy storage technologies beside the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1 presents maintenance activities and maximum allowable testing
Draft 1: July 21, 2009
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
intervals for these new station dc supply technologies. However, because these technologies
are relatively new the maintenance activities for these station dc supplies may change over
time.
B.
In the Maintenance Activities for station dc supply in Table 1, what do you mean by
“continuity”?
Because the Standard pertains to maintenance not only of the station battery, but also the
whole station dc supply, continuity checks of the station dc supply are required. “Continuity”
as used in Table 1 refers to verifying that there is a continuous current path from the positive
terminal of the station battery set to the negative terminal, otherwise there is no way of
determining that a station battery is available to supply dc current to the station.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path the battery set will not be
available for service.
C.
Why is it necessary to verify the continuity of the dc supply?
In the event of the loss of the ac source or battery charger, the battery must be capable of
supplying dc current, both for continuous dc loads and for tripping breakers and switches.
Without continuity, the battery cannot perform this function.
If the battery charger is not sized to handle the maximum dc current required to operate the
protective systems, it is sized only to handle the constant dc load of the station and the
charging current required to bring the battery back to full charge following a discharge. At
those stations, the battery charger would not be able to trip breakers and switches if the battery
experiences loss of continuity.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
D.
Many battery chargers produce harmonics which can cause failure of dc power supplies in
microprocessor based protective relays and other electronic devices connected to station
dc supply. In these cases, the substation battery serves as a filter for these harmonics.
With the loss of continuity in the battery, the filter provided by the battery is no longer
present.
Loss of electrical continuity of the station battery will cause, regardless of the battery
charger’s output current capability, a delayed response in full output current from the
charger. Almost all chargers have an intentional 1 to 2 second delay to switch from a low
substation dc load current to the maximum output of the charger. This delay would cause
the opening of circuit breakers to be delayed which could violate system performance
standards.
How do you verify continuity of the dc supply?
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery unless the battery charger is taken out of service. At that time
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
a break in the continuity of the station battery current path will be revealed because there will
be no voltage on the substation dc circuitry.
Although the Standard prescribes what must be done during the maintenance activity it does
not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery.
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path through
the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of the
various dc-supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor based battery chargers have developed methods for their
equipment to periodically (or continuously) tested for battery continuity. For example,
one manufacturer periodically reduces the float voltage on the battery until current from
the battery to the dc load can be measured to confirm continuity.
No matter how the electrical continuity of a battery set is verified it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1 to insure that the station
dc supply will provide the required current to the Protection System at all times.
E.
Why is specific gravity testing required?
Specific gravity testing measures the state of the charge for each individual cell, and is
performed to determine the condition of the charging system as well as the condition of the
individual cell.
Specific gravity measurements can also be used as an indication of loss of continuity over a
period of time. Specific gravity measurement is a method of determining the state of charge of
a battery. Loss of continuity in the battery circuit will not allow charging current to flow
through the battery and the battery cells will eventually self discharge causing the specific
gravity to approach the specific gravity value of water which is 1.0.
If the specific gravity measurements taken during an inspection are determined to be low, this
indicates that the battery is in a state of discharge. If no recent high discharges of the battery
have occurred and the float voltage is normal, then the continuity of the battery circuit can be
suspected and other tests such as measuring battery current should be made to determine if the
specific gravity readings are an indication of loss of battery continuity.
F.
When should I check the station batteries to see if they have sufficient energy to perform
as designed?
The answer to this question depends on the type of battery (valve regulated lead-acid, vented
lead acid, or nickel-cadmium), the maintenance activity chosen, and the type of time based
monitoring level selected.
For example, if you have a Valve Regulated Lead-Acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
you will have to perform verification at a maximum maintenance interval of no greater than
every three months.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every 3 calendar years.
G.
Why in Table 1 are there two Maintenance Activities with different Maximum
Maintenance Intervals listed to verify that the station battery can perform as designed?
The two acceptable methods for proving that a station battery can perform as designed are
based on two different philosophies. The first activity requires a capacitive discharge test of
the entire battery set to prove that degradation of one or several components (cells) in the set
has not deteriorated to a point where the total capacity of the battery system falls below its
designed rating. The second maintenance activity requires tests and evaluation of the internal
ohmic measurements on each of the individual cells/units of the battery set to determine that
each component can perform as designed and therefore the entire battery set can be proven to
perform as designed.
The maximum maintenance interval for discharge capacity testing is longer than the interval
for testing and evaluation of internal ohmic cell measurements. An individual component of a
battery set may degrade to an unacceptable level without causing the total battery set to fall
below its designed rating under capacity testing. However, since the philosophy behind
internal ohmic measurement evaluation is based on the fact that each battery component must
be proven to be able to perform as designed, the interval for verification by this maintenance
activity must be shorter to catch individual cell/unit degradation.
H.
What is the justification for having two different Maintenance Activities listed in Table 1
to verify that the station battery can perform as designed?
IEEE Standards 450, 1188, and 1106 for vented lead-acid, valve-regulated lead-acid (VRLA),
and nickel-cadmium batteries, respectively (which together are the most commonly used
substation batteries on the BES) go into great detail about capacity testing of the entire battery
set to determine that a battery can perform as designed.
The first maintenance activity listed in Table 1 for verifying that a station battery can perform
as designed uses maximum maintenance intervals for capacity testing that were designed to
align with the IEEE battery standards. This maintenance activity is applicable for vented leadacid, valve-regulated lead-acid, and nickel-cadmium batteries.
The second maintenance activity listed in Table 1 for verifying that a station battery can
perform as designed uses maximum maintenance intervals for evaluating internal ohmic
measurements in relation to their baseline measurements that are based on industry experience,
EPRI technical reports and application guides, and the IEEE battery standards. By evaluating
the internal ohmic measurements for each cell and comparing that measurement to the cell’s
baseline ohmic measurement (taken at the time of the battery set’s acceptance capacity test),
low-capacity cells can be identified and eliminated to keep the battery set capable of
performing as designed. This maintenance activity is applicable only for vented lead-acid and
VRLA batteries.
I.
Why in Table 1 of PRC-005-2 is there a maintenance activity to inspect the structural
intergrity of the battery rack?
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PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
The three IEEE standards (1188, 450, and 1106) for VRLA, vented lead-acid, and nickelcadmium batteries all recommend that as part of any battery inspection the battery rack should
be inspected. The purpose of this inspection is to prove that the battery rack is correctly
installed and has no deterioration that could weaken its structural integrity. Because the
battery rack is specifically designed for the battery that is mounted on it, weakening of its
structural members by rust or corrosion can physically jeopardize the battery.
6. Protection System Communications Equipment
A.
What are some examples of mechanisms to check communications equipment
functioning?
For Level 1 unmonitored Protection Systems, various types of communications systems will
have different facilities for on-site integrity checking to be performed at least every three
months during a substation visit. Some examples are:
On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier checkback test from one terminal.
Systems which use frequency-shift communications with a continuous guard signal (over a
telephone circuit, analog microwave system, etc.) can be checked by observing a loss-ofguard indication or alarm. For frequency-shift power line power-line carrier systems, the
guard signal level meter can also be checked.
Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
Digital communications systems have some sort of data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For Level 2 partially monitored Protection Systems, various types of communications systems
will have different facilities for monitoring the presence of the communications channel, and
activating alarms that can be monitored remotely. Some examples are:
On-off power-line carrier systems can be shown to be operational by automated periodic
power-line carrier checkback tests, with remote alarming of failures.
Systems which use a frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be remotely monitored with a lossof-guard alarm or low signal level alarm.
Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
Digital communications systems can activate remotely monitored alarms for data reception
loss or data error indications.
For Level 3 fully monitored Protection Systems, the communications system must monitor all
aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
In many communications systems signal quality measurements including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio, propagation
delay, and data error rates are compared to alarm limits. These alarms are connected for
remote monitoring.
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Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment location
is continuously being reflected at the remote monitoring site.
B.
What is needed for the 3-month inspection of communication-assisted trip scheme
equipment?
The 3-month inspection applies to Level 1 (Unmonitored) equipment. With each site visit,
check that the equipment is free from alarms, check any metered signal levels, and that power
is still applied.
C.
Does a fiber optic I/O scheme used for breaker tripping or control within a station, for
example - transmitting a trip signal or control logic between the control house and the
breaker control cabinet, constitute a communication system?
This equipment is presently classified as being part of the Protection System Control Circuitry
and tested per the portions of Table 1 applicable to Protection System Control Circuitry rather
than those portions of the table applicable to communication equipment.
D.
In Table 1b, the Maintenance Activities section of the Protective System
Communications Equipment and Channels refers to the quality of the channel meeting
“performance criteria”. What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating
normally an alarm will be indicated. For Level 1 systems this alarm will probably be on the
panel. For Level 2 and Level 3 systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each protective system
communications channel that is consistent with proper functioning of the Protection System.
If that level of nominal performance is not being met, the system will go into alarm.
Following are some examples of protective system communications channel performance
criteria:
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system is
calibrated and if the signal level drops below an established level, the system will indicate
an alarm.
An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use checkback testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes this
signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full power
and reduced power tests are typically run. Power levels for these tests are determined at the
time of calibration.
Pilot wire relay systems use a hardwire communications circuit to communicate between
the local and remote ends of the protective zone. This circuit is monitored by circulating a
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dc current between the relay systems. A typical level may be 1 mA. If the level drops
below the setting of the alarm monitor, the system will indicate an alarm.
Modern digital relay systems use data communications to transmit relay information to the
remote end relays. An example of this is a line current differential scheme commonly used
on transmission lines. The protective relays communicate current magnitude and phase
information over the communications path to determine if the fault is located in the
protective zone. Quantities such as digital packet loss, bit error rate and channel delay are
monitored to determine the quality of the channel. These limits are determined and set
during relay commissioning. Once set, any channel quality problems that fall outside the
set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be - it
just requires that the entity establish nominal criteria so protective system channel monitoring
can be performed.
7. UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power
System
A.
We have an Under Voltage Load Shedding (UVLS) system in place that prevents one of
our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation as stated indicates that the tripping action was intended to prevent low
distribution voltage for a transmission system that was intact except for the line that was out of
service.
This Standard is not applicable to this UVLS.
UVLS installed to prevent system voltage collapse or voltage instability for BES reliability is
covered by this standard.
8. SPS or Relay Sensing for Centralized UFLS or UVLS
A.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end-to-end test.
B.
What about SPS interfaces between different entities or owners?
All SPS owners should have maintenance agreements that state which owner will perform
specific tasks. SPS segments can be tested individually, but must overlap.
C.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
Any Phasor Measurement Unit (PMU) function whose output is used in a protection system or
Special Protection System (as opposed to a monitoring task) must be verified as a component
in a Protection System.
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D.
How do I maintain a Special Protection System or Relay Sensing for Centralized UFLS
or UVLS Systems?
Components of the SPS, UFLS, or UVLS should be maintained like similar components used
for other Protection System functions.
The output action verification may be breaker tripping, or other control action that must be
verified, but may be verified in overlapping segments. A grouped output control action need
be verified only once within the specified time interval, but all of the SPS, UFLS, or UVLS
components whose operation leads to that control action must each be verified.
Group by Type of BES Facility:
1. All BES Facilities
A.
What, exactly, is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms
Used in Reliability Standards, and is not being modified within this draft Standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving
only load with one transmission source are generally not included in this definition.
Each Regional Entity implements a definition of the Bulk Electric System that is based on this
NERC definition, in some cases, supplemented by additional criteria. These regional
definitions have been documented and provided to FERC as part of a June 16, 2007
Informational Filing.
2. Generation
A.
Please provide a sample list of devices or systems that must be verified in a generator,
generator step-up transformer, and generator connected station auxiliary transformer to
meet the requirements of this Maintenance Standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay may include but are not necessarily limited to:
Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
Loss-of-field relays
Volts-per-hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator-ground relays
Communications-based protection systems such as transfer-trip systems
Generator differential relays
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Reverse power relays
Frequency relays
Out-of-step relays
Inadvertent energization protection
Breaker failure protection
For generator step up or generator connected station auxiliary transformers, operation of any
the following associated protective relays frequently would result in a trip of the generating unit
and, as such, would be included in the program:
Transformer differential relays
Neutral overcurrent relay
Phase overcurrent relays
A loss of a system connected station auxiliary transformer could result in a loss of the
generating plant if the plant was being provided with auxiliary power from that source. Thus,
operation of any of the following relays associated with system connected station auxiliary
transformers would be included in the program:
Transformer differential relays
Neutral overcurrent relay
Phase overcurrent relays
Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program even if the loss of the those loads could
result in a trip of the generating unit.
3. Transmission
A.
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having relevant
facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
Group by Type of Maintenance Program:
1. All Protection System Maintenance Programs
A. I can’t figure out how to demonstrate compliance with the requirements for level 3 (fully
monitored) Protection Systems. Why does this Maintenance Standard describe a
maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for level 3 (fully monitored) Protection
Systems is likely to be very involved, and may include detailed manufacturer documentation of
complete internal monitoring within a device, comprehensive design drawing reviews, and
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other detailed documentation. This Standard does not presume to specify what documentation
must be developed; only that it must be comprehensive.
There may actually be some equipment available that is capable of meeting level-3 monitoring
criteria, in which case it may be maintained according to Table 1c. However, even if there is
no equipment available today that can meet this level of monitoring, the Standard establishes
the necessary requirements for when such equipment becomes available.
By creating a roadmap for development, this provision makes the Standard technology-neutral.
The standard drafting team wants to avoid the need to revise the Standard in a few years to
accommodate technology advances that are certainly coming to the industry.
B. What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the Requirement being documented, include but
are not limited to:
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database screen shots that demonstrate compliance information
Diagrams, engineering prints, schematics, maintenance and testing records, etc.
Logs (operator, substation, and other types of log)
U.S. or Canadian mail, memos, or email proving the required information was exchanged,
coordinated, submitted or received
Database lists
C. If I replace a failed Protection System component with another component, what testing
do I need to perform on the new component?
The replacement component must be tested to a degree that assures that it will perform as
intended. If it is desired to reset the Table 1 maintenance interval for the replacement
component, all relevant Table 1 activities for the component should be performed.
2. Time-Based Protection System Maintenance (TBM) Programs
A. What does this Maintenance Standard say about commissioning?
Commissioning tests are regarded as a construction activity, not a maintenance activity.
B. The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled outage
following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals.
C. If I am unable to complete the maintenance as required due to a major natural disaster
(hurricane, earthquake, etc), how will this affect my compliance with this standard.
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The NERC Sanction Guidelines provides that the Compliance Monitor will consider
extenuating circumstances when considering any sanctions. 1
D. What if my observed testing results show a high incidence of out-of-tolerance relays, or,
even worse, I am experiencing numerous relay misoperations due to the relays being outof-tolerance?
Any entity can choose to test some or all of their Protection System more frequently (or, to
express it differently, exceed the minimum requirements of the Standard). Particularly, if you
find that the maximum intervals in the Standard do not achieve your expected level of
performance, it is understandable that you would maintain the related equipment more
frequently.
3. Performance-Based Protection System Maintenance (PBM) Programs
A. I’m a small entity and cannot aggregate a population of Protection System components to
establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of
individual Protection System components to create a segment that crosses ownership
boundaries. All entities participating in a joint program should have a single documented joint
management process, with consistent Protection System Maintenance Programs (practices,
maintenance intervals and criteria), for which the multiple owners are individually responsible
with respect to the requirements of the Standard. The requirements established for
performance-based maintenance must be met for the overall aggregated program on an ongoing
basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power-plant
vs. substation, and weather conditions.
B. Can an owner go straight to a performance-based maintenance program schedule, if they
have previously gathered records?
Yes. An owner can go to a performance-based maintenance program immediately. The owner
will need to comply with the requirements of a performance-based maintenance program as
listed in the standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they can not prove that they have collected the data as required
for a performance-based maintenance program then they will need to wait until they can prove
compliance.
C. When establishing a perfomance-based maintenance program, can I use test data from
the device manufacturer, or industry survey results, as results to help establish a basis for
my performance-based intervals?
No. You must use actual in-service test data for the components in the segment.
D. What types of misoperations or events are not considered countable events in the
performance-based Protection System Maintenance (PBM) Program?
1 Sanction Guidelines of the North American Electric Reliability Corporation. Effective January 15, 2008.
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Countable events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned.
Human errors resulting in Protection System Misoperations during system installation or
maintenance activities are not considered countable events. Examples of excluded human
errors include relay setting errors, design errors, wiring errors, inadvertent tripping of devices
during testing or installation, and misapplication of Protection System components. Examples
of misapplication of Protection System components include wrong CT or PT tap position,
protective relay function misapplication, and components not specified correctly for their
installation.
Certain types of Protection System component errors that cause Misoperations are not
considered countable events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
E. What are some examples of methods of correcting segment perfomance for PerformanceBased Maintenance?
There are a number of methods that may be useful for correcting segment performance for malperforming segments in a performance-based maintenance system. Some examples are listed
below.
The maximum allowable interval, as established by the performance-based maintenance
system, can be decreased. This may, however, be slow to correct the performance of the
segment.
Identifiable sub-groups of components within the established segment, which have been
identified to be the mal-performing portion of the segment, can be broken out as an
independent segment for target action. Each resulting segment must satisfy the minimum
population requirements for a performance-based maintenance program in order to remain
within the program.
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
Components within the mal-performing segment can be replaced with other components
(electromechanical distance relays with microprocessor relays, for example) to remove the
mal-performing segment.
F. If I find (and correct) a maintenance-correctable issue as a result of a misoperation
investigation (Re: PRC-004), how does this affect my performance-based maintenance
program?
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC-004 required misoperation investigation/corrective action), the actions performed
count as a maintenance activity, and “reset the clock” on everything you’ve done. In a
performance-based maintenance program, you also need to record the maintenance-correctable
issue with the relevant component group and use it in the analysis to determine your correct
performance-based maintenance interval for that component group.
G. Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
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Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation from
the factory to the job site, length of time before a charge is put on the battery, the method of
installation, the voltage level and duration of equalize charges, the float voltage level used, and
the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance-based Protection System Maintenance
(PBM) program. These inherent variances in the aging process of a battery cell make
establishment of a designated segment based on manufacturer and type of battery impossible.
The whole point of PBM is that if all variables are isolated then common aging and
performance criteria would be the same. However, there are too many variables in the electrochemical process to completely isolate all of the performance-changing criteria.
Similarly Functional Entities that want to establish a condition based maintenance program
using Level 3 monitoring of the battery used in a station dc supply can not do so. Inspection of
the battery is required on a Maximum Maintenance Interval listed in the tables due to the aging
processes of station batteries. However, Level 3 monitoring of a battery can eliminate the
requirement for periodic testing and some inspections (see Level 3 Monitoring Attributes for
Component of table 1c).
Group by Monitoring Level:
1. All Monitoring Levels
A.
Please provide an example of the level 1 monitored (unmonitored) versus other levels of
monitoring available?
A level 1 (Unmonitored) Protection System has no monitoring and alarm circuits on the
Protection System components.
A level 2 (Partially) monitored Protection System or an individual component of a level 2
(Partially) monitored Protection System has monitoring and alarm circuits on the Protection
System components. The alarm circuits must alert a 24-hr staffed operations center.
There can be a combination of monitored and unmonitored Protection Systems within any
given substation or plant; there can also be a combination of monitored and unmonitored
components within any given Protection System.
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Example #1: A combination of level 2 (Partially) monitored and level 1 (unmonitored)
components within a given Protection System is:
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center. (level 2)
Instrumentation transformers, with no monitoring, connected as inputs to that relay. (level
1)
A vented lead-acid battery with low voltage alarm connected to SCADA. (level 2)
A circuit breaker with a trip coil, with no monitor circuit. (level 1)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum test
intervals of:
The microprocessor relay is verified every 12 calendar years.
The instrumentation transformers are verified every 12 calendar years.
The battery is verified every 6 calendar years by performing a performance capacity test of
the entire battery bank or by evaluating the measured cell/unit internal ohmic values to
station battery baseline every 18 months.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
Example #2: A combination of level 2 (partially) monitored and level 1 (unmonitored)
components within a given Protection System is:
A microprocessor relay with integral alarm that is not connected to SCADA. (level 1)
Instrument transformers, with no monitoring, connected as inputs to that relay. (level 1)
A vented lead-acid battery with low voltage alarm connected to SCADA. (level 2)
A circuit breaker with a trip coil, with no circuits monitored. (level 1)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum test
intervals of:
The microprocessor relay is verified every 6 calendar years.
The instrumentation transformers are verified every 12 calendar years.
The battery is verified every 6 calendar years by performing a performance capacity test of
the entire battery bank or by evaluating the measured cell/unit internal ohmic values to
station battery baseline every 18 months.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
Example #3: A combination of level 2 (partially) monitored and level 1 (unmonitored)
components within a given Protection System is:
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed operations
center. (level 2)
Instrument transformers, with no monitoring, connected as inputs to that relay (level 1)
Battery without any alarms connected to SCADA (level 1)
Circuit breaker with a trip coil, with no circuits monitored (level 1)
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Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum test
intervals of:
B.
The microprocessor relay is verified every 12 calendar years.
The instrument transformers are verified every 12 calendar years.
The battery is verified every 3 months, every 18 months, plus, depending upon the type of
battery used it may be verified at other maximum test intervals, as well.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
What is the intent behind the different levels of monitoring?
The intent behind different levels of monitoring is to allow less frequent manual intervention
when more information is known about the condition of Protection System components.
C.
Do all monitoring levels apply to all components in a protection system?
No. For some components in a protection system, certain levels of monitoring will not be
relevant. See table below:
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Monitoring Level Applicability Table
(See related definition and decision tree for various level requirements)
Level 1
(Unmonitored)
Level 2
(Partially
Monitored)
Level 3
(Fully
Monitored)
Protective relays
Y
Y
Y
Instrument transformer Inputs to
Protective Relays
Y
N
Y
Protection System control circuitry
(Other than aux-relays & lock-out
relays)
Y
Y
Y
Aux-relays & lock-out relays
Y
N
N
DC supply (other than station
batteries)
Y
Y
Y
Station batteries
Y
N
N
Y
Y
Y
UVLS and UFLS relays that comprise
a protection scheme distributed over
the power system
Y
Y
Y
SPS, including verification of end-toend performance, or relay sensing
for centralized UFLS or UVLS
systems
Y
Y
Y
Protection Component
Protection system communications
equipment and channels
Y = Monitoring Level Applies
N = Monitoring Level Not Applicable
D.
When documenting the basis for inclusion of components into the appropriate levels of
monitoring as per Requirement R2 of the standard, is it necessary to provide this
documentation via a device by device listing of components and the specific monitoring
attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
systems are Level 2 - Partially Monitored by stating the following within the program
description:
“All substation dc systems are considered Level 2 - Partially Monitored and subject to
Table 1b requirements as all substation dc systems are equipped with dc voltage
alarms and ground detection alarms that are sent to the manned control center.”
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Similarly, it would be acceptable to use a combination of a global statement and a device level
list of exclusions. Example:
“Except as noted below, all substation dc systems are considered Level 2 - Partially
Monitored and subject to Table 1b requirements as all substation dc systems are
equipped with dc voltage alarms and ground detection alarms that are sent to the
manned control center. The dc systems of Substation X, Substation Y, and Substation
Z are considered Level 1 - Unmonitored and subject to Table 1a requirements as they
are not equipped with ground detection capability.”
Regardless whether this documentation is provided via a device by device listing of
monitoring attributes, by global statements of the monitoring attributes of an entire population
of component types, or by some combination of these methods, it should be noted that auditors
may request supporting drawings or other documentation necessary to validate the inclusion of
the device(s) within the appropriate level of monitoring. This supporting background
information need not be maintained within the program document structure but should be
retrievable if requested by an auditor.
E.
How do I know what monitoring level I am under? – Include Decision Trees
Decision Trees are provided below for each of the following categories of equipment to assist
in the determination of the level of monitoring.
Protective Relays
Protection System Control Circuitry
Station dc Supply
Protection System Communications Equipment and Channels
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2. Level 1 Monitored Protection Systems (Unmonitored Protection Systems)
A.
We have an electromechanical (unmonitored) relay that has a trip output to a lockout
relay (unmonitored) which trips our transformer off-line by tripping the transformer’s
high-side and low-side circuit breakers. What testing must be done for this system?
This system is made up of components that are level 1 (unmonitored). Assuming a time-based
protection system maintenance program schedule, each component must be maintained per
Table 1a – Level 1 Monitoring Maximum Allowable Testing Intervals and Maintenance
Activities.
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3. Level 2 Monitored Protection Systems (Partially Monitored Protection Systems)
A.
We have a 30 year old oil circuit breaker with a red indicating lamp on the substation
relay panel that is illuminated only if there is continuity through the breaker trip coil.
There is no SCADA monitor or relay monitor of this trip coil. The line protection relay
package that trips this circuit breaker is a microprocessor relay that has an integral
alarm relay that will assert on a number of conditions that includes a loss of power to the
relay. This alarm contact connects to our SCADA system and alerts our 24-hour
operations center of relay trouble when the alarm contact closes. This microprocessor
relay trips the circuit breaker only and does not monitor trip coil continuity or other
things such as trip current. Is this an unmonitored or a partially-monitored system?
How often must I perform maintenance?
The protective relay is a level 2 (partially) monitored component of your protection system
and can be maintained every 12 years or when a maintenance correctable issue arises.
Assuming a time-based protection system maintenance program schedule, this component
must be maintained per Table 1b – Level 2 Monitoring Maximum Allowable Testing Intervals
and Maintenance Activities
The rest of your protection system contains components that are level 1 (unmonitored) and
must be maintained within at least the maximum verification intervals of Table 1a.
B.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Examples include using values gathered via data
communications and automatically comparing these values with values from other sources,
and using groupings of other measurements (such as vector summation of bus feeder currents)
for comparison if calibration requirements assure acceptable measurement of power system
input values. Other methods are possible.
C.
For a level 2 monitored Protection System (Partially Monitored Protection System)
pertaining to Protection System communications equipment and channels, how is the
performance criteria involved in the maintenance program?
The entity determines the performance criteria for each installation, depending on the
technology implemented. If the communication channel performance of a Protection System
varies from the pre-determined performance criteria for that system, these results should be
investigated and resolved.
4. Level 3 Monitored Protection Systems (Fully Monitored Protection Systems)
A.
Why are there activities defined for a level-3 monitored Protection System? The
technology does not seem to exist at this time to implement this monitoring level.
There may actually be some equipment available that is capable of meeting level-3 monitoring
criteria, in which case it may be maintained according to Table 1c.
However, even if there is no equipment available today that can meet this level of monitoring,
the Standard establishes the necessary requirements for when such equipment becomes
available. By creating a roadmap for development, this provision makes the Standard
technology-neutral. The standard drafting team wants to avoid the need to revise the Standard
in a few years to accommodate technology advances that are certainly coming to the industry.
Draft 1: July 21, 2009
Page 29
PRC-005-2 — Protection System Maintenance - Frequently Asked Questions
Appendix A — Protection System Maintenance Standard
Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Leonard Swanson, Jr
National Grid USA
Merle E. Ashton
Tri-State Transmission and Generation
Cooperative
Eric A Udren
Quanta Technology
Bob Bentert
Florida Power & Light Company
Al Calafiore
NERC Staff
North American Electric Reliability
Corporation
Philip B Winston
Georgia Power Company
John A Zipp
ITC Holdings
John Ciufo
Hydro One Inc
Richard Ferner
Western Area Power Administration
Carol A Gerou
Midwest Reliability Organization
Roger D Greene
Southern Company Generation
Russell C Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
John Kruse
ComEd
Mark Peterson
Great River Energy
William Shultz
Southern Company Generation
Draft 1: July 21, 2009
Page 30
Assessment of Impact of Proposed Modification to the Definition of “Protection
System”
Existing Definition:
Protection System — Protective relays, associated communication systems, voltage and current
sensing devices, station batteries, and DC control circuitry.
Proposed Definition (Clean):
Protection System - Protective relays, associated communication systems necessary for correct
operation of protective devices, voltage and current sensing inputs to protective relays, station
DC supply, and DC control circuitry from the station DC supply through the trip coil(s) of the
circuit breakers or other interrupting devices.
General Description of Definition Change
The proposed definition of Protection System modifies the existing definition to
1) More precisely define the applicable communication systems
2) More precisely define the involved voltage and current sensing inputs
3) Expand the existing definition to include the entire station DC supply
4) More expansively and precisely define the applicable DC control circuitry.
General Assessment of Impact of Change
After adoption of the proposed change, the definition remains consistent with the existing uses.
The modifications make it more useful and lead to an increased ability to monitor compliance of
some of the standards using the definition. The following table illustrates each use of the term,
“Protective System” in the existing FERC-approved standards, whether the term is capitalized
(indicating that the intent is to use the defined term) or not. The modifications, though, address
ambiguities that have been identified within the existing approved definition, and are important
for the detailed use of the definition within the draft PRC-005-2 Standard.
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Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
Clause (excluding Measures and compliance elements)
Impact
NUC-001-1 — Nuclear
Plant Interface
Coordination
R7. Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall inform the applicable Transmission Entities of actual or proposed
changes to nuclear plant design, configuration, operations, limits, protection systems, or
capabilities that may impact the ability of the electric system to meet the NPIRs.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
NUC-001-1 — Nuclear
Plant Interface
Coordination
R8. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall inform the Nuclear Plant Generator Operator of actual or
proposed changes to electric system design, configuration, operations, limits, protection
systems, or capabilities that may impact the ability of the electric system to meet the
NPIRs.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
PER-005-1 — System
Personnel Training
R3.1. Each Reliability Coordinator, Balancing Authority and Transmission Operator that
has operational authority or control over Facilities with established IROLs or has
established operating guides or protection systems to mitigate IROL violations shall
provide each System Operator with emergency operations training using simulation
technology such as a simulator, virtual technology, or other technology that replicates the
operational behavior of the BES during normal and emergency conditions.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
PRC-001-1 — System
Protection Coordination
R1. Each Transmission Operator, Balancing Authority, and Generator Operator shall be
familiar with the purpose and limitations of protection system schemes applied in its area.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
PRC-001-1 —– System
Protection Coordination
R4. Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
July 22, 2009
2
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
PRC-001-1 — System
Protection Coordination
Clause (excluding Measures and compliance elements)
R5. A Generator Operator or Transmission Operator shall coordinate changes in
generation, transmission, load or operating conditions that could require changes in the
protection systems of others:
R5.1. Each Generator Operator shall notify its Transmission Operator in advance of
changes in generation or operating conditions that could require changes in the
Transmission Operator’s protection systems.
Impact
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
R5.2. Each Transmission Operator shall notify neighboring Transmission Operators in
advance of changes in generation, transmission, load, or operating conditions that could
require changes in the other Transmission Operators’ protection systems.
PRC-003-1 — Regional
Procedure for Analysis of
Misoperations of
Transmission and
Generation Protection
Systems
Purpose - To ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
PRC-003-1 — Regional
Procedure for Analysis of
Misoperations of
Transmission and
Generation Protection
Systems
R1. Each Regional Reliability Organization shall establish, document and maintain its
procedures for, review, analysis, reporting and mitigation of transmission and generation
Protection System Misoperations. These procedures shall include the following elements:
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
July 22, 2009
R1.1. The Protection Systems to be reviewed and analyzed for Misoperations (due to their
potential impact on BES reliability).
3
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
Clause (excluding Measures and compliance elements)
Impact
PRC-003-1 — Regional
Procedure for Analysis of
Misoperations of
Transmission and
Generation Protection
Systems
R2. Each Regional Reliability Organization shall maintain and periodically update
documentation of its procedures for review, analysis, reporting, and mitigation of
transmission and generation Protection System Misoperations.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
PRC-003-1 — Regional
Procedure for Analysis of
Misoperations of
Transmission and
Generation Protection
Systems
R3. Each Regional Reliability Organization shall distribute procedures in Requirement 1
and any changes to those procedures, to the affected Transmission Owners, Distribution
Providers that own transmission Protection Systems, and Generator Owners within 30
calendar days of approval of those procedures.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
PRC-004-1 — Analysis
and Mitigation of
Transmission and
Generation Protection
System Misoperations
Purpose - Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
PRC-004-1 — Analysis
and Mitigation of
Transmission and
Generation Protection
System Misoperations
R1. The Transmission Owner and any Distribution Provider that owns a transmission
Protection System shall each analyze its transmission Protection System Misoperations
and shall develop and implement a Corrective Action Plan to avoid future Misoperations of
a similar nature according to the Regional Reliability Organization’s procedures developed
for Reliability Standard PRC-003 Requirement 1.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
July 22, 2009
4
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
Clause (excluding Measures and compliance elements)
Impact
PRC-004-1 — Analysis
and Mitigation of
Transmission and
Generation Protection
System Misoperations
R2. The Generator Owner shall analyze its generator Protection System Misoperations,
and shall develop and implement a Corrective Action Plan to avoid future Misoperations of
a similar nature according to the Regional Reliability Organization’s procedures developed
for PRC-003 R1.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
PRC-004-1 — Analysis
and Mitigation of
Transmission and
Generation Protection
System Misoperations
R3. The Transmission Owner, any Distribution Provider that owns a transmission
Protection System, and the Generator Owner shall each provide to its Regional Reliability
Organization, documentation of its Misoperations analyses and Corrective Action Plans
according to the Regional Reliability Organization’s procedures developed for PRC-003
R1.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
WECC Standard PRC004-WECC-1 —
Protection System and
Remedial Action Scheme
Misoperation
Purpose - Regional Reliability Standard to ensure all transmission and generation
Protection System and Remedial Action Scheme (RAS) Misoperations on Transmission
Paths and RAS defined in section 4 are analyzed and/or mitigated.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
WECC Standard PRC004-WECC-1 —
Protection System and
Remedial Action Scheme
Misoperation
R1. System Operators and System Protection personnel of the Transmission Owners and
Generator Owners shall analyze all Protection System and RAS operations.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
July 22, 2009
R1.2. System Protection personnel shall analyze all operations of Protection Systems and
RAS within 20 business days for correctness to characterize whether a Misoperation has
occurred that may not have been identified by System Operators.
5
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
WECC Standard PRC004-WECC-1 —
Protection System and
Remedial Action Scheme
Misoperation
Clause (excluding Measures and compliance elements)
R2. Transmission Owners and Generator Owners shall perform the following actions for
each Misoperation of the Protection System or RAS. It is not intended that Requirements
R2.1 through R2.4 apply to Protection System and/or RAS actions that appear to be
entirely reasonable and correct at the time of occurrence and associated system
performance is fully compliant with NERC Reliability Standards. If the Transmission
Owner or Generator Owner later finds the Protection System or RAS operation to be
incorrect through System Protection personnel analysis, the requirements of R2.1 through
R2.4 become applicable at the time the Transmission Owner or Generator Owner identifies
the Misoperation:
Impact
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
R2.1 If the Protection System or RAS has a Security-Based Misoperation and two or more
Functionally Equivalent Protection Systems (FEPS) or Functionally Equivalent RAS
(FERAS) remain in service to ensure Bulk Electric System (BES) reliability, the
Transmission Owners or Generator Owners shall remove from service the Protection
System or RAS that misoperated within 22 hours following identification of the
Misoperation. Repair or replacement of the failed Protection System or RAS is at the
Transmission Owners’ and Generator Owners’ discretion.
R2.2. If the Protection System or RAS has a Security-Based Misoperation and only one
FEPS or FERAS remains in service to ensure BES reliability, the Transmission Owner or
Generator Owner shall perform the following.
R2.2.1. Following identification of the Protection System or RAS Misoperation,
Transmission Owners and Generator Owners shall remove from service within 22 hours
for repair or modification the Protection System or RAS that misoperated.
R2.2.2. The Transmission Owner or Generator Owner shall repair or replace any
Protection System or RAS that misoperated with a FEPS or FERAS within 20 business
days of the date of removal. The Transmission Owner or Generator Owner shall remove
the Element from service or disable the RAS if repair or replacement is not completed
within 20 business days.
July 22, 2009
6
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
WECC Standard PRC004-WECC-1 —
Protection System and
Remedial Action Scheme
Misoperation
Clause (excluding Measures and compliance elements)
R2.3. If the Protection System or RAS has a Security-Based or Dependability-Based
Misoperation and a FEPS and FERAS is not in service to ensure BES reliability,
Transmission Owners or Generator Owners shall repair and place back in service within 22
hours the Protection System or RAS that misoperated. If this cannot be done, then
Transmission Owners and Generator Owners shall perform the following.
Impact
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
R2.3.1. When a FEPS is not available, the Transmission Owners shall remove the
associated Element from service.
R2.4. If the Protection System or RAS has a Dependability-Based Misoperation but has
one or more FEPS or FERAS that operated correctly, the associated Element or
transmission path may remain in service without removing from service the Protection
System or RAS that failed, provided one of the following is performed.
R2.4.1. Transmission Owners or Generator Owners shall repair or replace any Protection
System or RAS that misoperated with FEPS and FERAS within 20 business days of the
date of the Misoperation identification, or
R2.4.2. Transmission Owners or Generator Owners shall remove from service the
associated Element or RAS.
WECC Standard PRC004-WECC-1 —
Protection System and
Remedial Action Scheme
Misoperation
July 22, 2009
R3. Transmission Owners and Generation Owners shall submit Misoperation incident
reports to WECC within 10 business days for the following.
R3.1. Identification of a Misoperation of a Protection System and/or RAS,
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
R3.2. Completion of repairs or the replacement of Protection System and/or RAS that
misoperated.
7
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
WECC Standard PRCSTD-003-1 — Protective
Relay and Remedial
Action Scheme
Misoperation
Clause (excluding Measures and compliance elements)
Purpose - Regional Reliability Standard to ensure all transmission and generation
Protection System Misoperations affecting the reliability of the Bulk Electric System
(BES) are analyzed and mitigated. PRC-STD-003-1 is a Regional Reliability Standard that
meets Requirement 1 of the NERC Standard PRC-003-1.
Impact
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
TPL-001-0.1 — System
Performance Under
Normal Conditions (also
TPL-002-0, TPL-003-0,
and TPL-004-0)
Table 1C - SLG Fault, with Delayed Clearing (stuck breaker or protection system failure):
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
TPL-001-0.1 — System
Performance Under
Normal Conditions (also
TPL-002-0, TPL-003-0,
and TPL-004-0)
Table 1D - 3Ø Fault, with Delayed Clearing (stuck breaker or protection system failure):
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
TPL-001-0.1 — System
Performance Under
Normal Conditions (also
TPL-002-0, TPL-003-0,
and TPL-004-0)
Table 1 – Footnote e. Normal clearing is when the protection system operates as designed
and the Fault is cleared in the time normally expected with proper functioning of the
installed protection systems. Delayed clearing of a Fault is due to failure of any
protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
July 22, 2009
8
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
TPL-002-0a — System
Performance Following
Loss of a Single BES
Element
Clause (excluding Measures and compliance elements)
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned such
that the Network can be operated to supply projected customer demands and projected
Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range
of forecast system demands, under the contingency conditions as defined in Category B of
Table I. To be valid, the Planning Authority and Transmission Planner assessments shall:
Impact
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
R1.3. Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories,, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from each of
the following categories) for inclusion in these studies and simulations shall be acceptable
to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those demand levels for
which planned (including maintenance) outages are performed.
July 22, 2009
9
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
TPL-003-0a — System
Performance Following
Loss Two or More BES
Elements
Clause (excluding Measures and compliance elements)
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission systems is planned such
that the network can be operated to supply projected customer demands and projected Firm
(nonrecallable reserved) Transmission Services, at all demand Levels over the range of
forecast system demands, under the contingency conditions as defined in Category C of
Table I (attached). The controlled interruption of customer Demand, the planned removal
of generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission
Planner assessments shall:
Impact
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
R1.3. Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from each
of the following categories) for inclusion in these studies and simulations shall be
acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those Demand levels for
which planned (including maintenance) outages are performed.
July 22, 2009
10
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
TPL-004 — System
Performance Following
Extreme BES Events
Clause (excluding Measures and compliance elements)
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is evaluated for
the risks and consequences of a number of each of the extreme contingencies that are listed
under Category D of Table I. To be valid, the Planning Authority’s and Transmission
Planner’s assessment shall:
Impact
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
R1.3. Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within each of
the following categories) for inclusion in these studies and simulations shall be acceptable
to the associated Regional Reliability Organization(s).
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.
TPL-006-0 — Assessment
Data from Regional
Reliability Organizations
R1. Each Regional Reliability Organization shall provide, as requested (seasonally,
annually, or as otherwise specified) by NERC, system data, including past, existing, and
future facility and Bulk Electric System data, reports, and system performance information,
necessary to assess reliability and compliance with the NERC Reliability Standards and the
respective Regional planning criteria.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
The facility and Bulk Electric System data, reports, and system performance information
shall include, but not be limited to, one or more of the following types of information as
outlined below:
R1.5. Transmission system and supporting information (thermal, voltage, and Stability
Limits, contingency analyses, system restoration, system modeling and data requirements,
and protection systems.)
July 22, 2009
11
Assessment of Impact on Existing Standards – Based on May 20, 2009 Revision of NERC Standards
Standard Number and
Name
Clause (excluding Measures and compliance elements)
Impact
Glossary of Terms
Definition — Delayed
Fault Clearing
Fault clearing consistent with correct operation of a breaker failure protection system and
its associated breakers, or of a backup protection system with an intentional time delay.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
Glossary of Terms
Definition — Misoperation
Any failure of a Protection System element to operate within the specified time when a
fault or abnormal condition occurs within a zone of protection.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
Any operation for a fault not within a zone of protection (other than operation as backup
protection for a fault in an adjacent zone that is not cleared within a specified time for
the protection for that zone).
Any unintentional Protection System operation when no fault or other abnormal
condition has occurred unrelated to on-site maintenance and testing activity.
Glossary of Terms
Definition — Normal
Clearing
A protection system operates as designed and the fault is cleared in the time normally
expected with proper functioning of the installed protection systems.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
Glossary of Terms
Definition — Planning
Authority
The responsible entity that coordinates and integrates transmission facility and service
plans, resource plans, and protection systems.
The proposed revisions to the
definition are consistent with this
use, and do not affect the
applicability of the definition.
July 22, 2009
12
Standards Announcement
Comment Period Open
July 24–September 8, 2009
Now available at:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_20
07-17.html
Project Name:
Project 2007-17: Transmission and Generation Protection System Maintenance and Testing
Due Date and Submittal Information:
The comment period is open until 8 p.m. EDT on September 8, 2009. Please use this
electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Lauren Koller at [email protected]. An off-line, unofficial copy of
the comment form is posted on the project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Content for Comment Period:
The Transmission and Generation Protection System Maintenance and Testing Standard Drafting
Team is seeking comments on its first draft of proposed standard PRC-005-2 — Protection
System Maintenance.
Other Documents Posted:
Implementation plan
Table showing how the team addressed issues and input from FERC and stakeholders
Frequently asked questions
Supplemental reference
Evaluation of the impact of changing the definition of Protection System
Project Background:
The draft standard combines the following previous standards:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing.
The proposed standard addresses FERC directives from FERC Order 693 as well as issues
identified by stakeholders. In accordance with the FERC directives, this draft standard
establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a
condition-based maintenance program, where the hands-on maintenance intervals are adjusted to
reflect the known and reported condition of the relevant devices, and for a performance-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect the
historical performance of the relevant devices.
Applicability of Standards in Project:
Transmission Owners
Generator Owners
Distribution Providers
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Shaun Streeter at [email protected] or at 609.452.8060.
Checkbox® 4.4
Newsroom Site Map Contact NERC
Individual or group. (55 Responses)
Name (36 Responses)
Organization (36 Responses)
Group Name (19 Responses)
Lead Contact (19 Responses)
Question 1 (52 Responses)
Question 1 Comments (55 Responses)
Question 2 (54 Responses)
Question 2 Comments (55 Responses)
Question 3 (52 Responses)
Question 3 Comments (55 Responses)
Question 4 (47 Responses)
Question 4 Comments (55 Responses)
Question 5 (45 Responses)
Question 5 Comments (55 Responses)
Question 6 (49 Responses)
Question 6 Comments (55 Responses)
Question 7 (48 Responses)
Question 7 Comments (55 Responses)
Question 8 (0 Responses)
Question 8 Comments or Conflict (55 Responses)
Question 9 (10 Responses)
Question 9 Comments (55 Responses)
Question 10 (0 Responses)
Question 10 Comments (55 Responses)
Individual
James Starling
SCE&G
Yes
The SDT is to be commended for developing a clear and well documented draft. Overall it
provides a balanced view of Protection System Maintenance, and good justification for its
maximum intervals.
No
Table 1a – Level 1 Monitoring has a requirement to “Verify the continuity of the breaker trip
circuit including trip coil” at least every 3 months. This is interpreted to be applicable to both the
low-side generator output breaker and the high-side breaker for the GSU. The generator output
breaker has 3 separate trip coils (one for each pole) that are connected in a parallel
configuration and there is no means available to verify continuity of each of these coils
INDIVIDUALLY in this arrangement. Is the intent of this requirement to have each trip signal
parallel leg verified every three months even though the trip contacts are normally open (these
circuits are functionally checked during LOR Functional Verification)? Also, is the Red Indication
Light (RIL), which includes the trip coil in the power circuit, adequate for verification (note that
the breaker does not include the parallel legs that contain the tripping sensor contacts)? Also,
more clarification is needed on the section “Verify proper functioning of the current and voltage
circuit inputs from the voltage and current sensing devices to the protective relays” under
“Voltage and Current Sensing Devices Inputs to Protective Relays.” How would this be done if no
redundancy is available for cross-checking voltage and current sources? In certain situations,
“verify proper functioning” is not clear enough. Documentation of verification consistent with the
entities procedures should be adequate to indicate compliance.
No
Several maximum maintenance intervals are 3 months. Since this is an absolute maximum
period, entities would need to schedule on a 2 month basis to assure the 3 month maximum is
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met, i.e., 6 times per year. We recommend that 3 month periods be increased to 4 months
which allows scheduling every 3 months. Other methods of achieving the same result is to state
periodic requirements of quarterly or 4 times per year.
No
Several maximum maintenance intervals are 3 months. Since this is an absolute maximum
period, entities would need to schedule on a 2 month basis to assure the 3 month maximum is
met, i.e., 6 times per year. We recommend that 3 month periods be increased to 4 months
which allows scheduling every 3 months. An alternate method of achieving the same result is to
state periodic requirements of quarterly or 4 times per year.
Yes
No
The FAQ should be expanded to address the issues raised above with verification of trip circuits
as to what is an acceptable method meeting the intent of the standard We also suggest changing
“prove” to “verify” on FAQ 3a to be consistent with the wording of the requirement. Also, for a
single bus with one set of bus potential transformers, how does one verify proper functioning of
the potentials? Is a reasonableness criterion adequate?
Individual
Rick Koch
Nebraska Public Power District
Yes
No
Table 1a, for Protective Relays identifies the following Maintenance Activities: Test and calibrate
the relays (other than microprocessor relays) with simulated electrical inputs. Verify proper
functioning of the relay trip outputs. What is the difference between these two requirements?
They appear to be practically equivalent. Tables 1a & 1b, for Station DC supply identify the
following Maintenance Activity: Measure that specific gravity and temperature of each cell is
within tolerance (where applicable). What is the advantage of testing the SG in every cell
compared to using a pilot cell as representative sample of the entire bank? NPPD has not
experienced any problems using a pilot cell compared to testing every individual cell. Typically, if
the SG is low the cell voltage will be low, which is detected by the voltage test. This seems to be
an excessive requirement and does increase personnel exposure to hazardous fluid. What unique
information is provided by this test that other tests do not provide?
No
Table 1a, for Station DC supply (that has as a component Valve Regulated Lead-Acid batteries)
establishes a Maximum Maintenance Interval of 3 Calendar Years for the following Maintenance
Activity: Verify that the station battery can perform as designed by conducting a performance or
service capacity test of the entire battery bank. What is the basis for this interval? NPPD’s
experience indicates that a 5 Year interval is adequate, especially during the early service life of
the battery bank, with increasing frequency as the bank ages.
Yes
Yes
No
Yes
On page 17, the answers to questions 2B and 2C indicate that there is no allowance or provision
to exceed the Maximum Maintenance Interval under any circumstances, except that natural
disasters or other events of force majeure will receive special consideration when determining
sanctions. The rigidity of this performance requirement could conceivably require equipment to
be tested even though it is out of service in order to remain compliant, adding unnecessary cost
and waste to the PSMP of the regulated entities. We believe that a prescriptive process for
deferring testing and maintenance beyond the stated interval would be beneficial to allow the
necessary flexibility to manage the PSMP effectively.
None
None
Definition of Terms: Footnote 2 for R4 defines a "maintenance correctable issue". This should be
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added to the Definition of Terms section. Sections 4.2.5.4 and 4.2.5.5 inappropriately extends
Generator Protection Systems to Station Service Transformers. These are components necessary
for plant operation however they are not part of the generator protection scheme. This
conclusion is supported by the explanations on page 16 of the FAQ. The FAQ states the operation
of the listed station auxiliary transforms protective relays would result in the trip of the
generating unit and, as such, would be included in the program. The FAQ goes on to state that
relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program even if the loss of those loades could result
in a trip of the generating unit. The FAQ appears to be inconsistent. Station auxiliary
transformers are included because they would result in the trip of the generating unit while other
loads such as pumps, fans, etc., are excluded even if their trip could result in a trip of the
generating unit. In my opinion, the station service transformers like pumps, fans, etc. are
components necessary for plant operation but not necessary for generator protection and should
therefore be excluded from PRC-005-2 by removing Sections 4.2.5.4 and 4.2.5.5 from the
Standard and modifying the FAQ accordingly. R1 (1.1) First sentence: "For each component used
in each Protection System,..." is ambiguous. The sentence should be revised to say..."For each
Protection System component, include all maintenance activities specified in Tables 1a, 1b, and
1c." This limits the components to only those identified by the definition of a Protection System.
R2 End of sentence: "possess the necessary monitoring attributes." is ambiguous. The sentence
should be revised to say..."possess the monitoring attributes identified in Tables 1b or 1c." This
specifically defines which attributes are necessary. R4 I am concerned with including the phrase
"including identification of the resolution of all maintenance correctible issues". Providing
evidence of implementation of the PSMP will require the collection and submittal of all work
documents that restored a device to functional order by calibration, repair, or replacement. It is
reasonable to assume that appropriate corrective actions were taken for each specific situation.
Identification of the resolution will add a significant documentation burden without adding to the
reliability of the BES. Implementation of the PSMP may be evidenced without including
identification of the resolution of all maintenance correctible issues. It is interesting to note that
nowhere in PRC-005-2 does it state that you have to take corrective actions to return a
component to normal operating conditions. "No action taken" can be the resolution taken by the
utility of a maintenance correctible issue.
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
No
What documentation or evidence is required to prove that the Protection System Control
Circuitry has been maintained every three months, if just a visual inspection of the breaker
control trip circuit RED panel light has been completed, to verify continuity of breaker trip coil?
How do we handle breakers with dual trip coils and only one RED light for trip coil continuity?
What do the terms DISTRIBUTED and CENTRALIZED with respect to UFLS mean? In Table 1C
under the heading "Maximum Maintenance Interval" some of the entries are stated as being
"Continuous". In the case of other maintenance activities the descriptor for Maintenance Interval
indentifies the maximum period of time that may elapse before action must be taken.
"Continuous" implies continuous action; however, in reality continuous monitoring enables no
maintenance action to be taken until such time as trends indicate the need to do so. Therefore
we recommend that where the maintenance interval is stated as "Continuous" it should be
changed to read "Never" or "Not Applicable". The Table 1A requirement of 3 months for
Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS) should be
omitted as it is not realistic. Recommend following the Table 1B requirement of 6 years (Trip
testing) for this. Does 27 undervoltage monitoring of this circuit qualify as self monitoring?
No
When we have redundant digital relay system that would fall under Level 1c category with a 12
year mtce cycle, but the Protection System Control Circuitry is non-monitored so it falls under
Level 1a, with a 6 year mtce cycle. We will have to complete relay mtce and trip testing every
12 years and trip testing only every 6 years, therefore we must complete trip testing twice as
often as we are doing the maintenance. We feel that relay maintenance and trip testing should
be completed at the same frequency. The Protection System Control Circuitry (Breaker Trip Coil)
checks every three months is too excessive. These circuits are checked during trip testing of the
Protection scheme, at the 6 or 12 year interval. If we have a redundant digital relay system,
using a IEC61850 communication from the relay to a common breaker aux trip relay, what level
does this system fall under?
Yes
Yes
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No
Yes
Individual
Kristina Loudermilk
ENOSERV
Yes
No
Table 1A, protective replays for 6 calendar years, Testing and calibrating the relays other than
microprocessors relays with simulated electrical inputs... does that mean that micro processor
relays do not need to be checked? Verify proper function of the relay trip outputs... Does this
involve both electro AND micro processors? Then when mentioning the verifying microprocessor
relays, does that include the trip output.
Yes
Yes
Yes
No
No
On Table 1A, the maximum time lengths are too long, especially for electro relays. A prime
example is when testing a KD relay on a yearly basis and most of the time needs to be adjusted
because of how far off it comes out. Allowing entities to take their time up to six calendar years
may be too long.
Individual
Wade Davis
Otter Tail Power
Yes
No
Station DC supply - (Maintenance Activity) As a company we do not think that measuring specific
gravity and temperature of each cell is necessary. Their is a better test that we use with the Bite
Impedance Test. We have had good success with the impedance test for determining the
batteries condition. See article (Impedance Testing Is The Coming Thing For Substation Battery
Maintenance)written in Transmission & Distribution 11/1991 by Ritchard Kelleher, Test &
Maintenance Specialist, Northeast Utilities.
Yes
Yes
Individual
Alison Mackellar
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Exelon Generation Company, LLC - Exelon Nuclear
Yes
None
No
1. Minimum maintenance activities should be on a yearly multiplier verses a monthly multiplier.
Nuclear generating stations are typically on an 18-month or 24-month refueling cycle. The draft
standard does not take into consideration a nuclear generators refueling cycle. Specifically, most
Boiling Water Reactors (BWRs) are on a 24-month refueling cycle and may run continuously
between refueling outages. Performing maintenance on-line puts the generating unit at risk
without any commensurate increase in reliability to the bulk electric system. 2. All maintenance
activities should include a "grace" period to allow for changes to a nuclear generator's refueling
schedule and emergent conditions that would prevent the safe isolation of equipment and/or
testing of function. "Grace" periods align with currently implemented nuclear generator's
maintenance and testing programs. 3. Activities that begin with "verify" should be modified to
"Validate_________are/is within acceptable limits. Initiate corrective actions as required." For
example, some level of DC grounds are acceptable based on circuit design and component
installation. Troubleshooting or ground isolation may increase the risk to the system depending
on ground magnitude and conditions. 4. Please provide clarification on "verify that no dc supply
grounds are present" most stations have some level of ground current. Should this be interpreted
to be a measure of resistance or current values? Suggest rewording to say "Check and record
unintentional battery grounds" 5. "Verify Station Battery Chargers provides the correct float and
equalize voltage" should be deleted. Equalizing a battery is a maintenance function and should
only be performed as needed. Suggest rewording to say "Check and record charger output
current and voltage." 6. Activities associated with Battery Charger performance should be
deleted. The ability of the Battery Charger to maintain the battery at full charge state is verified
by checking proper "float voltage." The ability to provide full rated current only affects the ability
to recharge a battery AFTER an event has occurred. 7. In Table 1a does the requirement to
"verify proper electrolyte level" refer to all batteries or only a sampling? Current practice is to
use the "pilot cell" as the monitoring cell as this cell is usually the least healthy of the battery
bank from a specific gravity and/or voltage standpoint. If the pilot cell continues to degrade then
the other batteries will be monitored more often. Suggest rewording to "Check electrolyte level."
8. In Table 1a the 18-month requirement to measure that the specific gravity and temperature
of each cell is within tolerance is "where applicable" – what does "where applicable" mean? 9. For
the Station dc supply (battery is not used) 18-month interval – should this be interpreted that it
is just the battery charger with no attached battery? Or a dc supply system that does not contain
a battery? 10. Table 1a Station dc supply 18-month interval to verify cell-to-cell and terminal
connection resistance is within "tolerance" should be revised to say "tolerance or acceptable
limits." 11. Table 1a Station dc supply (that has as a component valve regulated lead-acid
batteries) should provide an additional optional activity for "Total replacement of battery at an
interval of four (4) years" in lieu of not conducting performance or service capacity test at
maximum maintenance interval.
No
1. All maintenance activities should include a "grace" period to allow for changes to a nuclear
generator's refueling schedule and emergent conditions that would prevent the safe isolation of
equipment and/or testing of function. "Grace" periods align with currently implemented nuclear
generator's maintenance and testing programs. 2. Table 1a – page 6 regarding the 3 Month
"Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS)" states
that the maintenance activity shall verify the continuity of the breaker trip circuit including the
trip coil. There is unclear guidance on how this activity is to be performed, particular on
generator output breakers. Does this activity imply actual trip testing of the breaker itself? If so,
performing this type of activity with the generator on-line puts the unit at risk without any
commensurate increase in reliability to the bulk electric system. If this is the case it is requested
that this particular test is extended from 3 months to 24 months to align with nuclear generating
units refueling cycle. If not, and this activity is simply verification of continuity by means of light
indication, then please clarify in Table 1a.
No
1. Please provide more clarification on what constitutes "partially monitoring." For example, is a
computer auxiliary contact alarm count as partial monitoring? Would a common alarm between
relays meet the definition of partial monitoring? 2. All maintenance activities should include a
"grace" period to allow for changes to a nuclear generator's refueling schedule and emergent
conditions that would prevent the safe isolation of equipment and/or testing of function. "Grace"
periods align with currently implemented nuclear generator's maintenance and testing programs.
3. Table 1b Station dc supply (that has as a component valve regulated lead-acid batteries)
should provide an additional optional activity for "Total replacement of battery at an interval of
four (4) years. 4. There seems to be a disconnect between the monitoring attribute and
maintenance activity. For example, the monitoring attribute "Monitoring and alarming of the
station dc supply voltage/detection and alarming of dc grounds" has the maintenance activity
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"verify that the station battery can perform as designed by conducting a performance or service
capacity test of the entire batter bank. (3 calendar years) – or – Verify that the station battery
can perform as designed by evaluating the measure cell/unit internal ohmic values to station
battery baseline (3 months)." The maintenance activity does not support the monitoring
attribute. 5. If an entity has implemented Table 1b and/ or Table 1c, is there an acceptable
length of time that the monitoring equipment can be out of service without falling back to Table
1a requirements?
Yes
None
No
None
No
None
Conflict 1. Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory
Commission (NRC). Each licensee operates in accordance with plant specific Technical
Specifications (TSs) issued by the NRC. TS allow for a 25% grace period may be applied to TS
Surveillance Requirements (SRs). Referencing NRC issued NUREGs for Standard Issued Technical
Specifications (NUREG-143 through NUREG-1434) Section 3.0, "Surveillance Requirement (SR)
Applicability, SR 3.02 states the following: " The specified Frequency for each SR is met if the
Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured
from the previous performance or as measured from the time a specified condition of the
Frequency is met." 2. Battery Charger Testing 3. All conditions (grounds, voltages etc) should be
compared to "acceptable limits" as specified in nuclear station design basis documents, industry
standards or vendor data. 4. IEEE 450 does not use the word "proper" as utilized in Table 1a
(e.g., "record voltage of each cell v/s verify proper voltage of each individual cell….") 5. The NRC
Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness of maintenance to ensure
reliable operation of equipment within the scope of the Rule. Adjustments are made to the PM
(preventative maintenance) program based on equipment performance. The Maintenance Rule
program should provide an acceptable level of reliability and availability for equipment within its
scope. Comments: 1. All maintenance activities should include a "grace" period to allow for
changes to a nuclear generator's refueling schedule and emergent conditions that would prevent
the safe isolation of equipment and/or testing of function. "Grace" periods align with currently
implemented nuclear generator's maintenance and testing programs. 2. The 3-month maximum
interval should be extended to include a grace period to ensure that a 25% grace period is
included to align with current nuclear templates that implement NRC TS SRs are documented in
the response to Question 8.
Business Practice
Business Practice: Nuclear Electric Insurance Limited (NEIL) variance allowance.
1. Battery testing should be added to Table 1c for Station dc supply (that uses a battery and
charger) 2. Table 1c – Condition based maintenance. Consider adding Battery Capacity Test on a
6-year interval regardless of other condition based maintenance performed. 3. Evaluating the
measured cell/unit internal ohmic values to station battery baseline does not provide an
evaluation of battery capacity – please explain rational for maintenance activity. 4. If the Table
1a maintenance interval is reached and the entity is unable to perform the maintenance task, is
it acceptable to install temporary external monitoring or other measures to defer the
maintenance to Table 1b or Table 1c interval? Is it acceptable in Table 1b to substitute additional
or augmented maintenance activities or operator rounds to extend intervals? 5. Table 1c for
equipment with "continuous monitoring" states the maximum maintenance interval of
"continuous" – this does not seem correct wording – consider revising to state "not required." 6.
The NERC Standard should be revised to include a specific allowance for a deferral or variances
of a maintenance activity based on a formal technical evaluation. Nuclear generating units allow
for deferrals and/or variances on certain equipment based on emergent conditions that would
prevent safe isolation and/or testing of function. It should be noted that any deferrals and/or
variances if justified are to be based on a formal evaluation and not based on work management
or resource issues. 7. The maintenance intervals and maintenance activities should be referenced
directly to a basis document to ensure guidelines have a specific technical basis (e.g., IEEE450).
Group
SERC Protection and Controls Sub-committee (PCS)
Joe Spencer - SERC staff
Yes
We commend the SDT for developing such a clear and well documented first draft. It generally
provides a well reasoned and balanced view of Protection System Maintenance, and good
justification for its maximum intervals.
Yes
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We agree with the majority of the activities. Below is an example where clarification is needed.
“Verify proper functioning of the current and voltage circuit inputs from the voltage and current
sensing devices to the protective relays” under “Voltage and Current Sensing Devices Inputs to
Protective Relays.” How would this be done if no redundancy is available for cross-checking
voltage and current sources? In certain situations, “verify proper functioning” is not clear
enough. Documentation of verification consistent with the entities procedures should be adequate
to indicate compliance.
No
Recommend that all Level 1 three-month maintenance intervals be changed from 3 months to
quarterly. Given a 3 month maximum interval an entity would need to schedule these tasks
every 2 months. This would result in six inspections per year. In the experience of many of our
utilities, four inspections per year have proven to be successful.
No
Recommend that all Level 2 three-month maintenance intervals be changed from 3 months to
quarterly. Given a 3 month maximum interval an entity would need to schedule these tasks
every 2 months. This would result in six inspections per year. In the experience of many of our
utilities, four inspections per year have proven to be successful.
Yes
No
Yes
Change “prove” to “verify” on FAQ 3a (under Voltage and Current Sensing Devise Inputs to
Protective Relays) to be consistent with the wording of the requirement.
None known.
Regional Variance
It is our understanding that once Project 2009-17: “Interpretation of PRC-004-1 and PRC-005-1
for Y-W Electric and Tri-State” is approved, that the definition of a “Transmission Protection
System” would be included within PRC-005-2 or included within the NERC Glossary of Terms.
However, the specific protection that would be considered part of the “Transmission Protection
System” would also depend on the regional definition of the BES. We suggest that the regions
develop a supplement that provides further clarification on what constitutes a “Transmission
Protection System” given the regional definition of the BES.
The “zero tolerance” structure proposed combined with the large volume and complexity of
Protection System components forces an entity to shorten their intervals well below maximum.
We instead propose a calendar increment carryover period in which a small percentage of
carryover components would be tracked and addressed. For example, up to 1% of an entity’s
communication channel 6 year verifications could carryover into the next year. These carryover
components would be addressed with high priority in that next calendar increment. There are
many barriers to 100% completion or zero tolerance. Some utilities have over ten thousand
components.
Group
NextEra Energy Resources
Benjamin Church
Yes
No
a. Tables 1a, 1b & 1c should offer as an alternative, measuring battery float voltages and float
currents in lieu of measuring specific gravities as described in Annex A4 of IEEE Std 450-2002. b.
Inspection of CVT gaps, MOVs and gas tubes should be added to the communications equipment
time based maintenance tables. Failure of the CVT protective devices may cause failure of the
Protection System. c. Maintenance Activities for UVLS or UFLS station dc supplies shows “Verify
proper voltage of dc supply”. Does this imply that, except for voltage readings of the dc supply,
distribution battery banks are not maintained? d. Why does the Maintenance Activities for UVLS
or UFLS relays state that verification does not require actual tripping of circuit breakers? e.
Please clarify the Maintenance Activities for Voltage and Current Sensing Devices. Must voltage,
current and their respective phase angles be measured at each discrete electromechanical relay?
f. NextEra Energy concurs with other entities comments concerning this question: This entity
believes the approach taken by the SDT is overly prescriptive and too complex to be practically
implemented. The inflexible “minimum maintenance activities” approach fails to recognize the
harmful effects of over-maintenance and precludes the ability of entities to tailor their
maintenance program based on their configurations and operating experience. In particular, the
loss of maintenance flexibility embodied in this approach would have perverse consequences for
entities with redundant systems. Entities with redundant systems have less need for maintenance
of individual components (due to redundancy) yet have twice the maintenance requirements
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under the “minimum maintenance activities” approach. For example, Table 1A calls for
performing a specific gravity test on “each cell’ of lead acid batteries. Our company believes such
a requirement is dubious for entities that do not have redundant batteries, and absurd for
entities that do. We have installed redundant batteries in most locations and has had an
excellent operating history with batteries by using a combination of internal resistance testing
and specific gravity testing of a single “pilot cell”. This practice, combined with DC system
alarming capability, has worked well. We are opposed to approving a standard that imposes
unnecessary burden and reliability risk by imposing an overly prescriptive approach that in many
cases would “fix” non-existent problems. To clarify this last point, we are not asserting that
maintenance problems do not exist. However, requiring all entities to modify their practices to
conform to the inflexible approach embodied in this proposal, regardless of how existing practices
are working, is not an appropriate solution. Among other things, requiring entities to modify
practices that are working well to conform to the rigid requirements proposed herein carries the
downside risk that the revised practices, made solely to comply with the rigid requirements,
degrade reliability performance. Arguably, an entity could possibly return to its existing practices,
if those practices are working well, by navigating through the complex set of options and
supporting documentation that the SDT has crafted in this proposal. However, like many entities,
we have an army of substation technicians with various ranges of experience to perform
maintenance on protective systems and other substation components. It is unrealistic to expect
most entities making a good faith effort to comply with this proposal to have a full
understanding throughout the entire organization of all the nuances crafted into this complex
proposal. For the reasons outlined above, we do not agree with the proposal to specify minimum
maintenance activities. However, if the majority of industry commenters agree with the SDT’s
proposal, we have concerns about some of the proposed minimum tasks. For Protection System
control circuitry (trip circuits), Table 1A calls for performing a complete functional trip test. The
“Frequently-asked Questions” document states that this “may be an overall test that verifies the
operation of the entire trip scheme at once, or it may be several tests of the various portions
that make up the entire trip scheme”. Such a requirement creates its own set of reliability risks,
especially when monitoring already mitigates risks. We are concerned with this standard
promoting an overall functional trip test for transmission Protection Systems. This type of testing
can negatively impact reliability with the outages that are required and by exposing the electric
system to incorrect tripping. Our company views overall functional trip testing as a
commissioning task, not a preventive maintenance task. We perform such testing on new
stations and whenever expansion or modification of existing stations dictates such testing.
No
a. (i) Protective relays, (ii) Protection Control Circuitry (Trip Circuits) and (iii) Protection System
Communications Equipment and Channels should be changed from 6 calendar years to 8
calendar years. Based on FPL Group’s experience and Reliability Centered Maintenance (RCM)
program, FPL Group has established an 8 year program and has found that an aggressive 6 year
program would not substantially increase the effectiveness of a preventative maintenance
program. b. Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of
today’s lead-calcium batteries are relatively stable for a 6 month period compared to leadantimony batteries used in the past. c. The maximum maintenance interval for communications
equipment should be changed from 3 months to 12 months. Based on FPL Group’s experience
and RCM program, FPL Group has established a 12 month program that is effective. d.
Additionally, NextEra Energy concurs with other entities comments concerning this question:
Imposing inflexible maximum interval requirements has the same basic problems as imposing
inflexible minimum task requirements. The inflexible “maximum interval” approach fails to
recognize the harmful effects of over-maintenance and precludes the ability of entities to tailor
their maintenance program based on their configurations and operating experience. The
maximum interval approach also has same perverse consequences for entities with redundant
systems as the minimum interval approach. Furthermore, the rigid maximum interval approach
embodied herein does not sufficiently take into consideration common natural disaster situations.
Several of the preventive maintenance tasks proposed in this standard have a maximum interval
of 3 months, which is problematic under normal circumstances and unworkable when routine
maintenance activities have a much lower priority than emergency repair and restoration. An
interval as short as this does not provide a sufficient maintenance scheduling horizon to complete
the tasks. The SDT could attempt to address this shortfall by modifying the draft to account for
natural disaster situations. For example, the FERC-approved NERC reliability standard FAC-003
for Vegetation Management does include such allowances for natural disasters, such as tornados
and hurricanes. However, even if that specific problem is addressed, the fundamental problems
created by an overly prescriptive maximum interval approach remains.
Yes
Yes
No
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Yes
a. NextEra Energy believes the need for an extensive “Supplementary Reference Document”, in
addition to 13 pages of tables and an attachment in the standard itself, illustrates that the
proposal is too prescriptive and complex for most entities to practically implement. NextEra
Energy would prefer the SDT leave the existing requirements substantially intact or, if most
industry commenters prefer the SDT’s approach, that the SDT attempt to simplify it. 7. The
Standard Drafting Team has provided a “Frequently-asked Questions” document to address
anticipated questions relative to the standard. Do you have any comments on the FAQ? Please
explain in the comment area. 1 Yes 0 No Comments: a. An alternative to measuring battery
specific gravity is to measure float voltage and float current as described in Annex A4 of IEEE Std
450-2002. b. FAQ Page 17 (#1B): It is outside the jurisdiction of the standards development
team to determine acceptable forms of evidence. This should be decided by the Regional Entities.
c. FAQ Page 15 (#1A): This question should not have been included since it is addressing the
definition of BES, which is currently being addressed by another NERC Group. d. FAQ Page 15
(#2): Although the FAQ is not enforceable, the answer provided may be interpreted as
enforceable. This should be included in the standard and not in the FAQ.
a. The level of effort that will be required to be in compliance in accordance to PRC-005-2 is
substantial. Also, it will be difficult to create one maintenance program for all NextEra Energy
sites that establishes maintenance intervals based the implementation of a combination of the
three allowable types of maintenance programs (time-based, condition based, and/or
performance based maintenance). As a result, a high risk exists that something will be missed or
carried out incorrectly. b. What is the implementation period? How will the standard be
implemented in relation to the entity’s maintenance scheduled in accordance with existing
intervals specified in the current Protection System Maintenance and Testing Procedure that
meets the requirements of PRC-005-1 but will exceed PRC-005-2’s established maximum
intervals? Once PRC-005-2 becomes mandatory, entities should not be required to re-do testing
in accordance with the new intervals. Instead, entities should be allowed to implement the newly
established intervals after the last known cycle. c. Protection System Maintenance Program
(PSMP): (c1) The PSMP definition would be better defined if the first sentence was changed to
“An ongoing program by which Protection System components are kept in working order and
where malfunctioning components are restored to working order.” (c2) Please clarify what is
meant by “relevant” under the definition of Upkeep. Should “relevant” be changed to
“necessary”? (c3) The definition of Restoration would also be more explicit if changed to “The
actions to return malfunctioning components back to working order by calibration, repair or
replacement. (c4) Please clarify the definition of Restoration. For example, if a direct transfer trip
system has dual channels for extra security even though only one channel is required to protect
the reliability of the BES and one channel fails, must both be restored to be compliant? d.
Protection System (modification): (d1) ”Voltage and current sensing inputs to protective relays”
should be changed to “voltage and current sensors for protective relays.” Voltage and current
sensors are components that produce voltage and current inputs to protective relays. (d2)
“Auxiliary relays” should be changed to “auxiliary tripping relays” throughout PRC-005-2, FAQ
and the Draft Supplementary Reference. (d3) The word “proper” should be removed from the
standard. It is ambiguous and should be replaced with a word or words that are clear and
concise. e. Additionaly, NextEra Energy concurs with the following comments made by other
entities: (e1) PRC-005 Sect B (R2): More clarity needs to be provided. Does this requirement
require the utility to document the capabilities of its various protection components to determine
fully and partially monitored protection systems? If so the requirement for such documentation
should be clearly spelled out. Usually each requirement has a measurement (of compliance) and
I'm not clear how this will be done. (e2) PRC-005 Sect B (R4.1): A “grace period” similar to the
NPCC Criteria should be considered in case it is not possible to obtain necessary outages.
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
No
IMPA does not agree with the battery charger testing requirements. Per the battery charger
manual, the manufacturer sets the current limit at the factory, and it only needs to be adjusted
if a lower current limit is desired. The manufacturer gives directions on how to lower the current
limiter, and the directions seem to be for this purpose only (not for the sole purpose of
performing a current limiter test). The manufacturer also does not give directions on how to
perform a full load current test and does not give any recommendation to the user that such test
is needed. IMPA believes that both of these maintenance items are not needed to maintain the
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battery charger and that only the manufacturer's recommendations on maintenance and testing
need to be followed.
Group
Green Country Energy LLC
Rick Shackleford
Yes
No
1) Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) also The
maintenance activity causes excessive breaker operation, and the intrusive nature increases the
risk of subsequent misoperations on operating units. System configuration of many plants will
require an extensive interruption of total plant production to complete the test. 2)Protection
System Control Circuitry (Trip Circuits) (UFLS or UVLS systems only) The maintenance activity
causes excessive breaker operation, and the intrusive nature increases the risk of subsequent
misoperations on operating units. System configuration of many plants will require an extensive
interruption of total plant production to complete the test.
No
1) Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) also The
maintenance activity causes excessive breaker operation, and the intrusive nature increases the
risk of subsequent misoperations on operating units. System configuration of many plants will
require an extensive interruption of total plant production to complete the test. 2)Protection
System Control Circuitry (Trip Circuits) (UFLS or UVLS systems only) The maintenance activity
causes excessive breaker operation, and the intrusive nature increases the risk of subsequent
misoperations on operating units. System configuration of many plants will require an extensive
interruption of total plant production to complete the test.
No Preference at this time.
N/A does not apply
Yes
Huge help to us!
No
It would be beneficial to include some administrative (man hour) and cost estimates to comply
with this and any future proposed standards so if major budget impacts could be addressed.
Business Practice
Contractual commitments existing prior to NERC stds make it difficult to comply with some of
the maintenance activities.
None
Group
Northeast Power Coordinating Council
Guy Zito
Yes
No
We agree there is a need for minimum maintenance activities; however, the standard does not
clearly define the differences between Table 1a, 1b, and 1c. It is recommended that the drafting
team develop definitions for the equipment listed in these tables. For example, Table 1a
equipment consists of mechanical and solid state equipment without monitoring capability, Table
1b consists of mechanical and solid state equipment with monitoring capability, and Table 1c
consists of equipment capable of self monitoring. In addition, all battery, charger and power
supply maintenance activities should be removed from Table 1a, 1b, and 1c, and summarized in
a separate Table (i.e. Table 2). Tables 1a and 1b for 'Station dc supply (that has as a component
any type of battery) and Table 1c for 'Station dc Supply (any battery technology) for an 18
Month 'Maximum Maintenance Interval' identifies the need to 'Measure that the specific gravity
and temperature of each cell is within tolerance (where applicable).' Following industry best
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practices, we would recommend using the MBRITE diagnostic test. MBRITE testing provides more
information than a specific gravity test while reducing the risk of injury to testing personnel. In
Table 1a, the Type of Component “Protection system communications equipment and channels.”
has a 3 month “Maximum Maintenance Interval”. Clarification needs to be provided as to how an
unmonitored (do not have self-monitoring alarms) will be tested. Table 1a refers to
“Unmonitored Protection Systems”. The “6 Calendar Years” “Maximum Maintenance Interval”
“Maintenance Activities” is excessive.
No
We question whether any maintenance activity should be as long as 12 years. Considering the
rate of change in personnel and technology, the working group should reduce the time period by
redefining the requirement if necessary, or eliminate the standard requirement. In addition, the
DC components have too many tests at confusing intervals. Confusion will make it difficult to
implement or follow the exact method used.
Yes
No
The concept is acceptable, but the requirements to follow in Appendix A seem to be a deterrent
from attempting to use this process. Is the term “common factors” meant to take into account
variables at locations that can affect the components’ performance (lightning, water damage,
humidity, heat, cold)?
No
Yes
The FAQ is helpful in answering many of the obvious questions.
Yes--NPCC Directory #3, NPCC Key Facility Maintenance Tables. All areas must implement
changes at the same time.
Not aware of any regional variance or business practice.
• Requirements 4.2.5.4 and 4.2.5.5 require clarification. It is recommended that the drafting
team provide a schematic diagram to provide clarity as to which generator and system connected
transformers are included in this facility identification. • When Measures are added to the
Standard, the Standard Drafting Team must consider how the owner will be required to assess
and document the decision of which table will apply to each protection. While this is a compliance
element, the Standard should provide clarity on this matter. As written, the requirement does not
seem to be measurable. • Requirement R4 requires clarification on what is meant by “including
identification of the resolution of all maintenance correctible issues as follows:” Correctible issues
should not be combined in the same sentence with the layout of the tables. • Table 1b: In the
section for “Protection system communication equipment and channels”, there needs to be
clarification on “verify that the performance of the channel and the quality of the channel meets
the performance criteria, such as via measurement of signal level, reflected power, or data error
rate.” This may be done as a pass fail test during trip checks. If the communication line
successfully sends proper signals for the trip checks, then the communication line is acceptable
and no additional measurement are taken. • Table 1c: There is some confusion on what is
expected on items that have a Maximum Maintenance Interval reported as “Continuous”. For
example, a component in the “Protection System telecommunication equipment and channels”
how would one provide documentation or proof of the continuous verification of the two items
listed in the maintenance activities? In other words how does one prove “Continuous verification
of the communication equipment alarm system is provided” and “Continuous verification that the
performance and the quality of the channel meet the performance criteria is provided”. These
activities appear to be “monitoring attributes” more so than they are maintenance activities.
Additionally, the Continuous “Maximum Maintenance Interval” needs clarification because: o the
interval is a monitoring interval and not a maintenance interval o a strict interpretation of
“Continuous” could require redundant monitoring systems be installed or locations staffed by
personnel to monitor equipment in the event remote monitoring capabilities are unavailable o It
is unclear how to provide proof to an auditor that continuous monitoring has occurred over a
given interval • Table 1a, 1b, and 1c: The maintenance activity for battery chargers are to
perform testing of the charger at full rated current and verify current-limit performance. The
drafting team should provide an industry standard as how to perform this check, or specify an
industry equivalent test. • The Table 1b Level 2 Monitoring Attributes for Component “Monitoring
and alarming of continuity of trip coil(s)” should be changed to read “Monitoring and alarming of
continuity of all DC circuits including the trip coil(s)”. The present wording is confusing and can
be interpreted to mean that the DC control circuitry needs to be checked every 12 years, as
opposed to what we perceive to be the intended 6 years. • The Maintenance Activities in Table 1c
are not consistent with the Level 3 Monitoring Attributes for Component “Protection system
telecommunications equipment and channels.” “Continuous verification of interface to protective
relays” should be added as a third activity should be added under the Maintenance Activities
column. • In Section A. Introduction, 4.2.4 should be made to read “Protection System
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components which are installed as a Special Protection System for BES reliability.” • For
Requirement 4.1, a “grace period” similar to the NPCC criteria should be considered in case it is
not possible to obtain any necessary outages to get the prescribed maintenance done. •
Requirement R1 should be modified to read “Each Transmission Owner, Generator Owner, and
Distribution Provider shall develop, document, and implement a Protection System Maintenance
Program (PSMP) for its Protection Systems that use… This revision reinforces what is necessary
to ensure proper compliance with the program. • The standard has multiple component tests
required at different and conflicting intervals, some interdependent. Preference is to have the
component listed with a common maintenance and testing interval assigned (list the testing
required at 2, 4 and 6 years). This same interval should apply to all areas in the table. • Life
span of PC’s, software and software license’s are much less than 12 years or asset life. This
presents a problem during an audit where proof is required. The components in modern relays
have not been proven over these extended time periods, users are dependent on proper
functions of the alarm output of IED’s. Prefer more frequent maintenance cycles over having to
continuously document proof of a robust CBM or PBM program. • The burden placed to provide
proof of compliance with a CBM or PBM maintenance program seems to outweigh any benefit in
maintenance costs or reliability.
Individual
John E. Emrich
Indianapolis Power & Light Co.
Yes
No
Many preventive maintenance programs have testing tolerances which are tighter than the
manufacturer’s tolerances. This practice is used to force an action prior to falling outside of the
manufacture’s tolerances and accounts for slight variations in test equipment and environment.
Maintenance correctable issues should not be reportable unless the test failure falls outside of the
manufacturer’s published tolerances. In tables 1a through 1c the “Type of Component” columns
in each table do not have consistent listings from one 1a to 1b to 1c. The type of component
should be identified consistently in each table. By doing so this would eliminate confusion in
moving from one table to the other. The maintenance activities for some types of components
specifies how (ie Test and calibrate the relays….with simulated electrical inputs) while other
maintenance activities do not specify how. The maintenance activities should either all be specific
or all be generic. For Station dc Supply (that has as a component any type of battery) the
maintenance activity of “verify that no dc supply grounds are present” there is a problem of
tolerance. It is impossible to have “no dc supply grounds present”. There has to be some
tolerance given here such as a voltage measurement form each battery terminal to ground +15 volts of nominal for example. For the type of component of “Protection System Control
Circuitry (trip circuits) (UFLS/UVLS Systems only), the maintenance activity requires a complete
functional trip test….of the Protection System. This suggests that a breaker trip test is required
at each maintenance interval. This requires tripping breakers that supply customers. It is
impossible to trip each individual distribution feeder without forcing an outage on some
customers as when there are no other usable circuits to tie the load off to. A failure to trip of a
single distribution circuit in the overall scheme of a UVLS or UFLS scheme would have little effect
on the BES. Trip testing BES breakers and verifying correct operation of breaker auxiliary
contacts could become very difficult to accomplish since opening a breaker on a line might
adversely affect the BES. ISOs may prohibit such an activity at any time. Allowances should be
made for BES circuit breakers that can not be operated for such reasons if documented
sufficiently.
No
See comments in number 2 above.
Yes
No
Establishing historical performance and keeping the documentation up to date makes this almost
useless
No
No
Performing some of the maintenance activities may cause conflict with regional ISOs and their
safe operation of the BES
Individual
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Glenn Hargrave
CPS Energy
Yes
No
While I agree for the most part, there are some activities that are unclear. Specifically, the
testing of voltage and current sensing devices, some of the trip coil testing, and some of the
communications testing. If the trip coil is now going to be included in the definition of the
protective system, is the testing defined adequate? The testing of the voltage and current
sensing devices is not entirely clear.
No
The first problem that I have is the 3 Months for the Protection system communications
equipment and channels component. My main concern with this interval is that it is so extremely
short and I am concerned that there may not be any rational behind it. What studies, surveys, or
statistical data were used to determine that 3 months is necessary to protect the reliability of
the BES? It doesn't make sense that a communications signal needs to be checked every 3
months but the protective relay that utilizes that scheme needs to be checked at most only every
6 years. What concerns me the most with the 3 month interval for my company is with on-off
power line carrier DCB schemes. We only have these schemes on tie lines, and it can be difficult
to implement a checkback system with another utility who might utilize different carrier
equipment. This type of scheme is also intended to be inheritantly insecure and is frequently
more or less tested with faults in the system. The SPCTF should do surveys to determine what is
presently done with these type of systems or provide some other rationale for the communication
requirements. It is not totally clear from the documents, but it appears that the only way to
avoid the 3 month check for an on-off power-line carried DCB scheme is to have an automated
check back scheme. Is this correct? Or is alarming from the carrier equipment adequate? My
second problem is with the 6 year maximum maintenance interval for the breaker trip coil in
tables 1b and 1c. By having to verify that each breaker trip coil is electrically operated, you
might as well perform a functional test to test the protection system control circuitry. Electrically
operating the trip coil tests the breaker as much as it test the actual trip coil. Also, if you have a
primary and secondary trip coil, is it really necessary to test this often? What studies or
statistical data were used to determine that testing the breaker trip coils every 6 years is
necessary to protect the reliability of the BES? My third problem is with the intervals
requirements for the UVLS/UFLS systems. Other than testing and calibration of electromechanical
UVLS/UFLS, most other tests probably should require at most 10 years for these type of systems.
These systems don't require the performance level of most other systems as stated in the
supplementary reference. The testing and calibration of electromechanical UFLS should possibly
be even shorter than the 6 year requirement due to problems with drift with these type of relays.
What studies, surveys, or statistical data were used to determine the intervals in related to
UFLS/UVLS.?
Yes
Yes
Yes
Adds to the confusion with the standard, FAQ, and Supplemental. The three documents at times
describe things a little differently.
Yes
Adds to the confusion with the standard, FAQ, and Supplemental. The three documents at times
describe things a little differently.
Have several comments and questions: 1. I think that the way that the tables are done is
confusing. My biggest complaint is that the "breakdown" of the Type of Component varies
between the tables. For example, in tables 1a and 1B, you have Protective Relays, but in table
1c, you have Protective Relays and Protective Relays with trip contacts. This is a little confusing
at times. 2. I also find the UFLS/UVLS requirments confusing as well. It can be confusing to
figure out when the UFLS/UVLS has a separate requirement. Would prefer to see the UVLS/UFLS
in separate tables; e.g. 2a, 2b, 2c. 3. SPCTF should provide the basis for how the intervals in
table 1 were derived. While the supplemental describes that a survey of its members with a
weighted average was used to determine the maintenance intervals. However, what is not clear
is what exactly was surveyed in terms of components. Was it just relay calibration testing?
Functional testing? What about communications, voltage and current sensing devices, trip coils,
etc? Was UVLS and UFLS looked at separately from transmission? Was generation also
considered as well? Why did values change from the SPCTF technical reference "Relay
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Maintenance Technical Reference" dated September 13, 2007. For example, UVLS/UFLS testing
and calibration went from 10 years to 6 years for un-monitored, communications went from 6
months to 3 months for un-monitored, and instrument transformer testing went from 7 years to
12 years for un-monitored systems. What are the basis for the intervals? 4. The committee
should reconsider the use of the term "A/D converters". The point of the requirement is to assure
that the analog signal from the instrument transformer is correct to the processor. Two problems
with just saying "A/D converters". One, it ignores the digital relay input transformers of
microprocessor relays. The SEL-4000 test set can bypass these transformers. Would using this
test set be adequate to test the "A/D converters"? Two, some relays, such as the SEL-311L,
perform an A/D self-test. I do not think that the A/D self-test performs the testing that is being
sought by the document. 5. Could a better example of "Calendar Year" be provided? Is it simply
the years difference, or should the days be included as well? I your example in the reference
document, you show that December 15, 2008 and December 31, 2014 as meeting the
requirement of 6 calendar years. Woudl like to see a more exaggerated example. Would an
unmonitored protective relay is calibrated on January 1, 2008 and then again on December 31,
2014 meet the "Maximum Maintenance Interval" of "6 Calendar Years"? 6. Does the standard
address breakers and other switching devices that do not have "trip coils". Magnetic actuated
circuit breakers, reclosers, and possibly other devices do not have trip coils to monitor or test.
Do the trip coil testing and requirements fully take this account? If a breaker does not have a
trip coil, is some other type of test required? Does not having a trip coil prevent extending the
Protection System Control Circuitry inteval to 12 years? 7. The requirement for testing Voltage
and Current Sensing devices should be better thought out as to what is trying to be
accomplished. On page 11 of the reference document, item 6 under "Additional Notes for
Table…", it states that "phase value and phase relationships are both equally important to
prove". In both the FAQ document (page 6, 3A) and the reference document (page 21, 15.2),
several methods to verify the voltage and current sensing inputs to the protective relays and
satisfy the requirement are given. However, these methods do not all seem to verify the same
thing. Totalizing watts and vars on the bus verifies that the current transformers are correctly
and providing correct signals to the relays, but do not necessarily verify that the voltage sensing
device is necessarily correct if the same PT is used for all relays on the bus. Performing a
saturation test on a CT and a ratio test on the PT does not verify the phase angle relationships,
which is stated as important on page 11 of the reference document. What exactly needs to be
accomplished by the Voltage and Current Sensing devices testing? That an analog signal is
getting from the instrument transformer to the device? That the signal is an accurate
representation of the measured quantity? What about frequency for UFLS relays, where voltage
magnitude may not be that important? Do CT's need to be verified for multiple CT grounds? Do
the any examples described necessarily find multiple ct grounds? 8. This standard should also
address the ramifications of RRO's not allowing for equipment to be removed from service for
testing. Either RRO's should be required to allow outages in some time frame or leeway should
be given to entities that cannot get equipment out for maintenance because RRO's will not grant
reasonable outage times for testing and maintenance. 9. Page 13 of the reference document
states that the 3-month inspection should include checking that "equipment is free of alarms,
check any metered signal levels, and that power is still applied." What is meant by "metered
signal levels"? What does the term "metered" mean, specifically in terms of an on-off power line
carrier scheme. 10. It appears that if a company on a TBM plan has shorter intervals than the
maximum allowable of this proposed standard, the company would not be in violation if they did
not meet their own plan but still met the intervals required by this proposed standard. Is this
true? Could this actually reduce reliability of the BES if companies are now allowed to extend
intervals to those listed in this document without any justification?
Individual
Darryl Curtis
Oncor Electric Delivery
Yes
Yes
Yes
Yes
Yes
Yes
The “Supplementary Reference Document” provides good technical justification for the various
approaches to a maintenance program (Time Based, Performance Based, and Condition Based)
or combinations of these programs that an owner of a Protection System can follow.
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Yes
The FAQ document is an excellent resource document for Protection System Owners to
understand why the maintenance activities listed in the proposed standard were chosen.
The drafting team is to be commended for taking the Technical Paper and Draft Standard that
was prepared by the NERC System Protection and Control Taskforce (SPCTF) and the
recommendations of the SAR drafting team to create PRC-005-2. This draft standard allows the
owners of Protection Systems several options in establishing a maintenance program tailored to
their equipment and the topography of their system.
Group
PacifiCorp
Sandra Shaffer
Yes
No
No comment.
No
No comment.
Yes
Yes
No
Very helpful.
No
Very helpful.
None known.
None known.
What is the definiton of "Calendar Year"? Does the term "Six calendar years" include any date in
2004 to any date in 2010?
Individual
Armin Klusman
CenterPoint Energy
No
a. CenterPoint Energy believes the approach taken by the SDT is overly prescriptive and too
complex to be practically implemented. The inflexible minimum “maintenance activities”
approach fails to recognize the harmful effects of over-maintenance and precludes the ability of
entities to tailor their maintenance program based on their configurations and operating
experience. In particular, the loss of maintenance flexibility embodied in this approach would
have perverse consequences for entities with redundant systems. Entities with redundant
systems have less need for maintenance of individual components (due to redundancy) yet have
twice the maintenance requirements under the minimum “maintenance activities” approach. For
example, Table 1A calls for performing a specific gravity test on “each cell’ of vented lead-acid
batteries. CenterPoint Energy believes such a requirement is dubious for entities that do not
have redundant batteries, and absurd for entities that do. CenterPoint Energy has installed
redundant batteries in most locations and has had an excellent operating history with batteries
by using a combination of internal resistance testing and specific gravity testing of a single “pilot
cell”. This practice, combined with DC system alarming capability, has worked well. b.
CenterPoint Energy is opposed to approving a standard that imposes unnecessary burden and
reliability risk by imposing an overly prescriptive approach that in many cases would “fix” nonexistent problems. To clarify this last point, CenterPoint Energy is not asserting that maintenance
problems do not exist. However, requiring all entities to modify their practices to conform to the
inflexible approach embodied in this proposal, regardless of how existing practices are working, is
not an appropriate solution. Among other things, requiring entities to modify practices that are
working well to conform to the rigid requirements proposed herein carries the downside risk that
the revised practices, made solely to comply with the rigid requirements, degrade reliability
performance. c. Arguably, an entity could possibly return to its existing practices, if those
practices are working well, by navigating through the complex set of options and supporting
documentation that the SDT has crafted in this proposal. However, most entities, have an army
of substation technicians with various ranges of experience to perform maintenance on protection
systems and other substation components. It is unrealistic to expect most entities making a good
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faith effort to comply with this proposal to have a full understanding throughout the entire
organization of all the nuances crafted into this complex proposal. d. For the reasons outlined
above, CenterPoint Energy does not agree with the proposal to specify minimum maintenance
activities. However, if the majority of industry commenters agree with the SDT’s proposal,
CenterPoint Energy has concerns about some of the proposed tasks. For Protection System
control circuitry (trip circuits), Table 1A calls for performing a complete functional trip test. The
“Frequently-asked Questions” document states that this “may be an overall test that verifies the
operation of the entire trip scheme at once, or it may be several tests of the various portions
that make up the entire trip scheme”. Such a requirement creates its own set of reliability risks,
especially when monitoring already mitigates risks. CenterPoint Energy is concerned with this
standard promoting an overall functional trip test for transmission protection systems. This type
of testing can negatively impact reliability with the outages that are required and by exposing
the electric system to incorrect tripping. CenterPoint Energy views overall functional trip testing
as a commissioning task, not a preventive maintenance task. CenterPoint Energy performs such
testing on new stations and whenever expansion or modification of existing stations dictates such
testing. Overall, CenterPoint Energy recommends minimizing, to the extent possible,
maintenance activities that disturb the protection system; that is, placing the protection system
in an abnormal state in order to perform a test. e. For Protection System control circuitry
(breaker trip coils only), Table 1A calls for verifying the continuity of the trip circuit every 3
months. CenterPoint Energy is not sure what would be the expected task to meet this
requirement (it is not addressed in the “Frequently-asked Questions’ document).
No
a. See CenterPoint Energy’s comments made in response to question 2. Imposing inflexible
maximum interval requirements has the same basic problems as imposing inflexible minimum
task requirements. The inflexible “maximum interval” approach fails to recognize the harmful
effects of over-maintenance and precludes the ability of entities to tailor their maintenance
program based on their configurations and operating experience. The maximum interval
approach also has same perverse consequences for entities with redundant systems as the
minimum interval approach. b. Furthermore, the rigid maximum interval approach embodied
herein does not sufficiently take into consideration common natural disaster situations. Several of
the preventive maintenance tasks proposed in this standard have a maximum interval of 3
months, which is problematic under normal circumstances and unworkable when routine
maintenance activities have a much lower priority than emergency repair and restoration. An
interval as short as this does not provide a sufficient maintenance scheduling horizon to complete
the tasks. The SDT could attempt to address this shortfall by modifying the draft to account for
natural disaster situations. For example, the FERC-approved NERC reliability standard FAC-003
for Vegetation Management does include such allowances for natural disasters, such as tornados
and hurricanes. However, even if that specific problem is addressed, the fundamental problems
created by an overly prescriptive maximum interval approach remains.
No
a. CenterPoint Energy lauds the SDT for recognizing that strict imposition of the maximum
interval approach creates problems which the SDT attempts to correct by allowing performancebased adjustments. CenterPoint Energy believes the majority of industry commenters will agree
with CenterPoint Energy’s assessment that the maximum interval approach is problematic and
should be dropped from the proposal. However, if the majority of industry commenters agree
with the SDT’s approach, then a performance-based option to correct the problems introduced by
the maximum interval requirements should remain. b. CenterPoint Energy answered “No” to
question 5 because CenterPoint Energy believes the arduous path of creating a new set of
problems with a rigid approach (maximum interval requirements) and then introducing a
complex set of auditable requirements to provide an option (performance-based maintenance) to
mitigate the harm of the rigid approach is ill-advised and fraught with pitfalls. Stated otherwise,
using performance-based adjustments to correct inappropriate maximum intervals would not be
necessary if the inappropriate maximum intervals were not imposed. CenterPoint Energy believes
a better approach is to avoid introducing the new set of problems that then have to be mitigated
by not imposing problematic maximum intervals. c. Followed to its logical conclusion, using
performance-based adjustments to correct inappropriate maximum intervals is a contorted way
of arriving at the philosophy embodied in the current set of standards in which entities determine
the maximum intervals appropriate for their circumstances and performance. CenterPoint
Energy’s concern is that the contortions needed to arrive at the same point, in addition to being
unnecessary, will be difficult for most entities to navigate. An entity making a good faith effort to
comply with the performance-based adjustments will have to navigate through the complexities
and nuances of the approach, as illustrated by the extensive set of documents the SDT has
provided in an attempt to explain all the requirements and nuances. As an entity attempts to
manage this hurdle, the entity will likely have to deal with the reality that the granularity of
performance metrics do not exist in most cases to justify to an auditor the rationale for the
adjustments to the inappropriate maximum intervals. For example, CenterPoint Energy has
asserted that it has had good battery performance using existing practices. However, the
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assertion is anecdotal. CenterPoint Energy cannot recall any instances where it had a relay
misoperation due to battery failure in over twenty five years. CenterPoint Energy does not
attempt to keep performance metrics on events that historically occur less than four times a
century and CenterPoint Energy believes most entities will be in the same situation. d. If an
entity is somehow able to overcome these hurdles, the entity will almost certainly encounter
skepticism for what will be viewed as an exception to the default requirement embodied in the
standard. Even if an entity can overcome likely skepticism in an audit, the entity will be in a
severely disadvantaged situation if a protection system component for which the maintenance
interval has been adjusted, based on the entity’s good faith effort and reasoned judgment,
nevertheless is a contributing factor in a major reliability event investigation, regardless of
whether the maintenance interval adjustment contributed to the failure. No matter what
maintenance intervals are used, protection system components could fail. If the maintenance
interval has been adjusted and if failure occurs, it will likely be unknown whether the interval
adjustment was in fact a contributing factor or whether the failure would have occurred anyway.
e. Faced with this dilemma, in addition to all the other hurdles to overcome in attempting to
adjust an inappropriate maximum interval, the reality is that most entities will accept the
inappropriate maximum interval and over-maintain their protection system components, and
introduce a new set of reliability risks from such over-maintenance. For these reasons,
CenterPoint Energy advises against creating a new set of problem by imposing rigid maximum
intervals and then attempting to correct the problems through a performance-based mechanism
that in actual practice would likely be illusory.
Yes
CenterPoint Energy believes the need for an extensive “Supplementary Reference Document”, in
addition to 13 pages of tables and an attachment in the standard itself, illustrates that the
proposal is too prescriptive and complex for most entities to practically implement. CenterPoint
Energy would prefer the SDT leave the existing requirements substantially intact or, if most
industry commenters prefer the SDT’s approach, that the SDT attempt to simplify it.
Yes
See CenterPoint Energy’s response to question 6. The need for an FAQ document in addition to
an extensive “Supplementary Reference Document” further illustrates the complexity and
impracticality of the proposed standard revisions.
a. CenterPoint Energy believes the existing maintenance standards are preferable to the
approach embodied in this proposal. However, if most entities agree with the SDT’s approach,
CenterPoint Energy recommends deleting Under-Frequency Load Shedding (UFLS) and UnderVoltage Load Shedding (UVLS) system equipment from the scope of this proposal because the
performance requirements for UVLS and UFLS are substantially different from transmission and
generation protection schemes. Few would argue that protection schemes that clear faults on the
Bulk Electric System must be very reliable, much more reliable than schemes that shed
distribution load for under-voltage or under-frequency situations. If an entity plans to shed a
contemplated level of load for a contemplated set of circumstances based upon planning
simulations, that plan would translate into a certain number of distribution feeders that are
reasonably predicted to shed a load amount that is reasonably close, but not exactly equal
(unless by chance) to the contemplated amount of load shed. For example, if a certain number
of distribution circuits equals 10% of the entity’s load during one time (such as system peak),
that same amount of distribution circuits will almost certainly equal a different percentage of the
entity’s load at other times. So, if hypothetically 100 distribution circuits are armed with UVLS or
UFLS relays set a given trip point, the actual percentage of load that will be shed will vary under
different system conditions. Therefore, if 95 of the distribution circuits actually trip on one
occasion and 98 trip on another occasion, the difference in system performance is immaterial
because the exercise is not that precise, especially when planning simulation uncertainties are
also introduced into the picture. For these reasons, CenterPoint Energy believes it is
unreasonable to impose a high level of rigidity into load shedding schemes when the designs of
the schemes inherently do not depend on such rigidity. If the SDT agrees, then the revised
standard would not be applicable to Distribution Providers, and 4.1.3 can be deleted. b.
CenterPoint Energy also disagrees with the proposed expansion of the Protection System
definition. The present definition does not include trip coils; and correctly so, as trip coils are part
of the circuit breaker. A protection system has correctly performed its function if it provides
tripping voltage up to the breaker’s trip coils. From that point, the breaker can fail to timely
interrupt fault current due to several factors such as a binding mechanism that affects breaker
clearing time, a broken pull rod, a bad insulating medium, or bad trip coils. Local breaker failure
protection is installed to address the various possible causes of circuit breaker failure. Planning
standard TPL-001 tables 1C and 1D specifically support the present definition, as Delayed
Clearing is noted as due to “stuck breaker or protection system failure”.
Individual
Howard Gugel
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Progress Energy
Yes
No
Progress Energy does not agree with the activity “Verify that the battery charger can perform as
designed by testing that the charger will provide full rated current and will properly currentlimit.” We are unclear how this test should be performed.
No
The rational for microprocessor-based relay intervals is examined, but all others are strictly
based on industry weighted average of survey results. We believe the team should use a more
empirical, documented approach to determining these intervals, as many companies have longer
intervals that they currently have documented for their basis. If these have been accepted as
satisfactory in previous audits, why should they be required to change just to meet an arbitrary
number?
Yes
Progress Energy is concerned that separating this document from the standard may lead to
issues down the road. If the desire is to consolidate and clarify existing standards, then the two
documents should be merged. Otherwise the reference document may get lost from the
standard, or might get changed without due process, or might not even be recognized by FERC.
Yes
Progress Energy is unclear how a new/revised standard can have a 30 page FAQ document
associated with it. If questions need to be addressed, the answers should be incorporated into
the existing standard. During this stage of the draft, all questions should be addressed, not left
to the side in an “interpretation” paper.
Comments: 1- Requirement R4 “Each Transmission Owner, Generator Owner, and Distribution
Provider shall implement its PSMP, including identification of the resolution of all maintenance
correctible issues as follows: “ Based on the definition provided (A maintenance correctable issue
is a failure of a device to operate within design parameters that can be restored to functional
order by calibration, repair or replacement.) Pr ogress Energy believes that this will become a
potential tracking issue. To maintain all of the data required to meet this definition can be
onerous. 2- The biggest concern with the proposed PRC is that for many entities, the proposed
maintenance and intervals will greatly increase the entities’ workloads. There are not enough
relay technicians available to handle this increased workload across the country. 3- The
Implementation Plan for R2, R3, and R4 identified in the Draft Implementation Plan for PRC-00502, dated July 21, 2009, is very reasonable. This plan recognizes that it is unrealistic to expect
entities that are presently using intervals that exceed the maximum allowable intervals to
immediately be in compliance with the new intervals. It allows implementation to be
implemented across the maximum allowable interval. This is a reasonable approach for the
following reasons: a. Sufficient resources are not available to perform the additional maintenance
proposed on an accelerated basis. b. It allows the staggering of the PMs so that resource loading
can be balanced. Without the ability to stagger the PMs, there would be an initial “bow-wave” of
PMs and future “bow-waves” each time the interval is up. 4- The Implementation Plan for R1
identified in the Draft Implementation Plan for PRC-005-02, dated July 21, 2009, is not
reasonable. The implementation plan requires entities to be 100% compliant three months
following approval of the PRC. This is not a reasonable timeframe given the program changes
required, including: a. A massive effort to review circuit schematics to determine whether
equipment meets the definition of partial-monitored or unmonitored. b. Many procedures, basis
documents, and job plans will need to be revised or created. c. The work management tool will
have to be modified to reflect the new intervals. 5- PRC-008-1 placed only the relays associated
with UFLS in the compliance program. Contrary to PRC-008-1, the draft PRC-005-02 places all
components (relays, instrument transformers, dc supply, breaker trip paths) in the compliance
program. This forces much of the distribution-level components to be placed in the compliance
program. 6- The response to Item 2A of the FAQ Document, page 17, seems to indicate that
commissioning test results do not have to be captured as the initial test record, only the inservice date. Is this a correct interpretation of the response? 7- Table 1a (Unmonitored
Protection Systems) seems to indicate that a complete functional trip test must be performed for
the UFLS/UVLS protection system control circuitry. This wording is identical with the wording for
the protection system control circuitry (except UFLS/UVLS) table entry. This implies that
UFLS/UVLS functional testing should include tripping of the feeder breakers for these
unmonitored systems. Table 1b (Partially-Monitored Protection Systems) indicates that actual
tripping of circuit breakers is not required under the UFLS/UVLS control circuit functional testing.
Is this because trip coil continuity is being monitored and alarmed under Level 2 Monitoring?
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Must feeder breakers be tripped during the functional testing if the trip coil continuity is not
monitored and alarmed (unmonitored protection system)? 8- All standards to be retired should
be specifically listed in the Implementation Plan.
Individual
John Moraski
BGE
PRC-005-2 R1 1.2 “Identify whether each Protection System component is addressed through
time-based, condition-based, performance-based, or a combination of these maintenance
methods and identify the associated maintenance interval.” Comment: The existing standard
PRC-005-1 requirement R1.1 says a maintenance program must include the maintenance and
testing intervals and their basis. PRC-005-2 does not have a similar requirement, and the
associated FAQ indicates the standard “establishes the time-basis for a Protection System
Maintenance Program to a level of detail not previously required”. Does PRC-005-2 require
evidence to support the basis for a defined maintenance interval, or is the basis now purely
defined by PRC-005-2? R2 “ Each transmission owner .......shall ensure the components to which
condition-based criteria are applied....possess the necessary monitoring attributes” Comment:
Depending on the evidence requirements that are enforced this could be a very large
undertaking offsetting the benefit of extending intervals with CBM. It would be helpful to
understand what the drafting team or other stakeholders would envision as appropriate evidence
supporting this requirement. R4 “Each transmission owner .......shall implement its PSMP,
including the identification of the resolution of all maintenance correctable issues as follows : 4.1
....within the maximum allowable intervals not to exceed those established in table 1a, 1b, 1c
Comment: It’s inferred that this requirement applies to maintenance correctable issues that are
discovered as a consequence of scheduled maintenance and not as a consequence of monitoring
or misoperations. If that inference is incorrect the requirement imposes an unequal playing field
for the resolution of known correctable issues depending on the monitoring being employed, not
to mention an unreasonably long allowance for the correction of some serious problems. On the
other hand, the requirement imposes an unreasonably short period of time for the resolution of
some issues that may be associated with short interval maintenance/inspection intervals, such as
battery grounds. Section D 1.4 Data Retention “The Transmission Owner..shall...retain
documentation for two maintenance intervals....” Comment: Recognizing that in order to achieve
compliance PS owners will execute scheduled maintenance on shorter intervals than the
maximum requirement it’s uncertain what this means. Example: Max interval for instrument
transformers is 12 years, we maintain every six. Is the requirement for 24 years of data or 12. It
seems like there ought to be an upper limit. 24 years is a very long time. Table 1a Protection
System Control Circuitry (Breaker trip coil only) ; 3 month maximum interval ; “verify the
continuity....of the trip circuit .....except for breakers that remain open for the entire
maintenance interval.” Comments: What’s the failure-probability justification for this requirement
when other similar dc control components have a maximum interval of 6 years? It seems like the
SDT made an assumption that all trip coils are monitored by red lights and could be verified by
inspection and said somewhat arbitrarily, “do it because you can”. “Remaining open for the
entire maintenance interval” is a poorly reasoned effort to arrive at a necessary exception. Even
if the red-light-through-the-trip-coil assumption is accurate for a normally open breaker, it’s
unreasonable to demand that an inspection take place if its closed at anytime during the interval.
The actual time that its closed might be seconds or a few minutes, but that time would make the
exception moot and put the owner out of compliance. On the subject of three month maximum
intervals in general: One can agree that three months is about the right time for some of these
inspections, batteries in particular. However as written, three months and a day is “out of
compliance”. More flexibility would avoid a lot of meaningless “technical fouls”. How about four
times a year not more than four months between each...or something like that. Table 1a Station
DC supply (that has as a component any type of battery); “verify that no dc supply grounds are
present” Comment: All grounds are not created equal. No guidance for acceptance criteria is
given, nor is evaluation/acceptance criteria explicitly made the responsibility of the battery owner
(as it is for relay calibration) . Without any guidance the requirement of “no” grounds is open to
unreasonable interpretation (there is always a ground if one considers a high enough resistance)
and high impedance grounds that do not present a risk to the PS will consume effort and
attention unnecessarily. Station DC supply (that has as a component any type of battery);
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“Measure the specific gravity and temperature of each cell is within tolerance” Comment: It is
not clear that a specific gravity test provides any better data concerning battery health than an
impedance test, but specific gravity testing is a requirement. Can the impedance test be
performed as routine maintenance in lieu of a specific gravity test? General Comment: It is not
clear whether Communications batteries should be held to the same testing/maintenance
requirements as the station battery. Communications batteries are in place to supply relatively
low power electronic equipment and do not have to provide energy to trip a breaker. Simple
monitoring of the channel may be sufficient to assure battery availability, and a less rigorous
maintenance plan may be appropriate based on the continuous monitoring and low duty of the
battery. FAQ Group by Monitoring Level A level 2 (partially) monitored Protection System or an
individual component of a level 2 monitored Protection System has monitoring and Alarm circuits
on the Protection System components. The alarm circuits must alert a 24-hour staffed operations
center. Comment: The Standard Table 1b, General Description for Level 2 monitoring is simply
described as Protection System components whose alarms are automatically provided daily (or
more frequently) to a location where action can be taken for alarmed features. This appears to
be a conflict between the FAQ and the standard. The more stringent requirement of the FAQ, for
the reporting facility to be manned 24 hours per day, could be read to imply a requirement for a
specific time to respond to an alarm. Is there such a requirement? Is there an implied
requirement to document the alarm condition and the response time?
Individual
Dale Fredrickson
Wisconsin Electric
Yes
No
1. Page 7 Station DC Supply (Batteries): The activity to verify proper electrolyte level should
only apply to unstaffed (unmanned) stations; checking battery electrolyte levels is routinely done
in generating stations, which are staffed with personnel continuously (24 x 7). In addition, the
three activities listed here with a 3 month interval for batteries (electrolyte, voltage,
grounds)should NOT require documentation for compliance purposes. It should be sufficient that
these routine and recurring activities (every 3 months) are identified in the Maintenance Plan.
Otherwise the administrative burden to provide documentation will become excessive and
counterproductive to assuring BES reliability. 2. Page 7 Station DC Supply (Batteries): The 18
month interval includes an activity to verify the battery charger equalize voltage. This activity is
normally done only when the bank is load tested. Therefore the activity to verify equalize voltage
of a charger should have a 6 year interval along with the other battery charger activities to verify
full rated current and current-limiting. 3. Page 9 Communications Equipment: Similar to #1
above, the activity to verify monitoring and alarms should NOT require documentation in order to
demonstrate compliance. Having these routine 3 month activities in the Maintenance Plan is
sufficient. This needs to be clarified in the standard. Also, this requirement should be re-worded
to refer to generating stations also, not just substations. 4. Page 11 Station DC Supply
(Batteries): Like #1 above, the similar requirement in Table 1b for verifying battery electrolyte
levels should be revised to indicate that documentation is NOT required. 5. Page 6 Prot System
Control Circuitry: Like #1 above, the 3 month activity to verify continuity of breaker trip circuits
is fine, but there should be no requirement to document the readings or observations; it is
sufficient that this activity be addressed in the Maintenance Plan, especially for staffed generating
stations. 6. Page 6 Prot System Control Circuitry: For the 6 year activity to "perform a functional
trip test...": is this a requirement to actually trip the circuit breaker ? If yes, this should be
stated clearly in the Maintenance Activity description. 7. We are concerned that the Maintenance
Activities are not appropriate for certain equipment. The RFC definition of Bulk Electric System
includes any protection equipment that can trip a BES facility independent of voltage level. As an
LSE, this includes distribution-level equipment that was not designed to the same level of
redundancy as Transmission equipment. Complying with the requirements for control circuitry
functional testing and current sensing device testing will actually decrease system reliability since
this often cannot be accomplished without requiring outages to major distribution system
components and/or temporarily breaking protection circuits. We propose that this type of testing
on distribution systems which fall under the definition of BES Protection Systems should be
addressed separately from the rest of the BES Protection Systems in this standard. The intervals
and/or maintenance activities should reflect the differences in how these distribution protection
systems are designed and operated.
No
Similar to comments in #7 above: It is our practice on distribution-level protection systems to
utilize a 6 year interval plus/minus 1 year to accomodate potential scheduling conflicts. This is
consistent with other LSE's relay testing practices as well. Thus the potential 7 year maintenance
interval would be a violation of the draft requirements. The maintenance intervals in this
standard should be increased accordingly for distribution protection system equipment.
Yes
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Yes
Yes
How much authority or weight will this document have with Compliance staff? If potential
violations of the standard requirements are alleged by Compliance staff, can this document be
cited by an entity when the document provides clarifying information on the requirements ?
No
Regional Variance
See above Question 2, Item 7: There needs to be some recognition that Protection System's
applied on distribution-voltage systems may be included in a regional definition of a BES
Protection System. These systems are not designed or operated in the same way as
Transmission or Generation Protection Systems. Therefore, it is reasonable that these systems be
subject to less rigorous requirements.
1. In the definition of a Protection System Maintenance Program, the statement is made that "A
maintenance program CAN include...", with a list of seven attributes following. Is it the intent
that the PSMP "SHALL include one or more of the following" ? What is to prevent Compliance
staff from concluding that all seven of these attributes MUST be included in the PSMP ? 2. The
standard should more clearly describe what is meant by "verify..." when used in a Maintenance
Activity description. Does this require actual paper or electronic documentation? If so, then this
should be explicitly stated in the Maintenance Activity description. We maintain above that the
recurring and routine maintenance activities having a 3 month interval should be revised to use
alternate words such as "Check" or "Observe". For example, "Check the continuity of the breaker
trip circuit...", or "Observe the voltage of the station battery". This activity should not be
required to have paper or electronic documentation or evidence. It should be sufficient to have
these activities included in the PSMP. 3. It is stated in the Supplementary Reference that actual
event data from fault records may be used to satisfy certain Maintenance Activities, yet the
standard itself does not appear to allow for this. Will such evidence be accepted by Compliance
staff?
Group
Florida Municipal Power Agency, and its Member Cities as follows: New Smyrna Beach; City of
Vero Beach; and Lakeland Electric
Frank Gaffney
Yes
No
FMPA does not believe that maintenance of each UFLS / UFLS systems are as important as
maintenance of BES protection systems. The fundamental reason is that delayed or uncleared
faults on the BES can cause system “instability, uncontrolled separation, and cascading
outages”; therefore, BES protection systems are very important; however, if a small percentage
of UFLS / UVLS relays mis-operate as a result of a frequency or voltage event, the impact of the
mis-operation is much smaller, if even measurable. As a result, FMPA believes that the emphasis
of the maintenance activities ought to be placed on those systems that can have the most
impact on what the standards are all about, as Section 215(a)(4) of the Federal Power Act says,
“avoiding instability, uncontrolled separation, and cascading outages”. As a result, FMPA believes
that full functional testing, while important for BES protection systems, is not necessary for UFLS
and UVLS systems (Table 1a, page 6 and Table 1b, page 11). Because most UFLS / UVLS are on
radial distribution feeders, such testing will cause outages to customers fed on radial distribution
circuits and transmission lines without sufficient cause, in other words, the maintenance itself will
reduce the reliability the customer experiences. In addition, distribution tripping circuits are more
regularly exercised by distribution faults than are transmission tripping circuits; therefore, full
functional testing of distribution tripping circuits is far less valuable than testing trip circuits of
transmission elements which are exercised less frequently due to actual system events. FMPA is
confused with the wording of Table 1a, page 6, row 3 that talks about breaker trip coils. In the
“Type of Component” column, the subject says “Breaker Trip Coils Only (except for UFLS or
UVLS)”, yet the maintenance activity described states “Verify the continuity of the breaker trip
circuit including trip coil”. These two statements are inconsistent because the first statement
limits the applicability to just the trip coil and the second statement goes beyond the trip coil.
And, FMPA believes the second statement should only apply to the trip coil, e.g., the second
statement should say: “Verify the continuity of the trip coil”. In addition, the parenthetical is
confusing, is it meant to say that the continuity of the trip coil only needs to be verified when
the breaker operates during the 3 month interval, or that the intended continuity check is from
the relay contacts through the trip coil, and not from the relay contacts back to the batteries?
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FMPA is also confused concerning station DC supply testing. There are multiple rows in Table 1a
concerning various types of testing for various types of batteries and chargers that do not
exclude UVLS and UFLS, yet on page 8, on the bottom row, the row is exclusive to UVLS and
UFLS yet overlaps other rows discussing station DC supply testing. Is it intended that the other
rows that are silent as to what they apply to exclude UVLS and UFLS? FMPA believes that should
be the case. The same comment applies to Table 1b. FMPA also has concern over the battery
charger testing requirements. Per the charger manufacturers recommendations there is no
reason to test the chargers as proposed in PRC-005-2. It is their opinion that the chargers are
self diagnostic and do not require these tests (full load current and current limiting tests). The
charger O&M manuals do not even provide instructions for such tests as optional. Therefore,
FMPA takes exception to this requirement and suggests that battery chargers be maintained and
tested in accordance with manufacturer’s recommendations
No
FMPA agrees in general with many of the maximum maintenance intervals; however we have
been unable to determine what basis was used to arrive at the time based intervals provided in
the tables. Further explanation would be appreciated FMPA is concerned with the use of the term
“continuous” in Table 1c. As stated, it would seem that, on loss of communications that would
communicate the alarm, thereby causing a loss of “continuous” monitoring and alarming, the
entity who invested in a reliability improving monitoring system would be found non-compliant
with an infinitesimal maintenance period required for “continuous” monitoring. Therefore, FMPA
recommends using “not applicable” or some other term in this column.
Yes
FMPA agrees with the approach, but, may not agree with the exact wording in the tables. For
instance, the use of the word “every” in table 1c in “Protection System components in which
every function required for correct operation of that component is continuously monitored and
verified” may be overstating the level of monitoring that would realistically enable a Protection
System to use table 1c.
No
FMPA believes that the documented process outlined in Attachment A; "Criteria for Performance
Based Protection System Maintenance Program" is biased towards larger entities. The
requirement that the minimum population of 60 individual components of a particular segment is
required to make a component applicable to this program automatically eliminates most of the
small or medium sized entities. Further the need to first test a minimum of 30 indivudual
components in any segment reinforces the same size limitation. FMPA suggests that the
Performance-Based Protection System Maintenance Program allow for regional shared databases
applicable towards meeting the establishment and testing criteria of similar individual
components. This practice will allow for the inclusion of entities of all sizes. This will also provide
a greater format for the discussion of lessons learned and improvements to the testing database
on a regional basis.
No
No
FMPA is not aware of any conflicts
FMPA is not aware of a need for a regional variance
Facilities applicability 4.2.2, due to the changes in applicability of the draft PRC-006, ought to
refer say something like UFLS which are installed per requirements of PRC-006 rather than per
ERO requirements. In requirement R1, bullet 1.1 ought to state “For each component used in
each Protection System, include all “applicable” maintenance activities specified in Tables 1a, 1b
and 1c”. For instance, if every component has continuous monitoring, why should the program
include 1a and 1b?
Individual
Russell C Hardison
TVA
Yes
Yes
Add clarifying statement from Table 1b for Protection System Control Circuitry (Trip Circuits)
(UFLS/UVLS Systems Only) to the same section in Table 1a. Statement is “(Verification does not
require actual tripping of circuit breakers or interrupting devices.)"
Yes
Yes
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Yes
Should allow inclusion of dc systems as well.
No
No
Business Practice
Allow for deferals to coordinate with generator outages.
Individual
Kirit Shah
Ameren
Yes
We commend the SDT for developing such a clear and well documented first draft. It generally
provides a well reasoned and balanced view of Protection System Maintenance, and good
justification for its maximum intervals. Our existing M&T Program has and continues to yield a
very reliable BES with mostly similar intervals, though some are longer and others shorter. We
strongly support the almost all of the applicability revision, which clarifies the boundary of NERC
maintenance and testing oversight. We question the addition of UFLS station DC Supply,
auxiliary relays, and Generating facility system-connected station service transformers. Have
these components been a significant source of problems leading to cascading outages? The SDT
also modifies the Protection System definition, mostly clarifying the boundaries. We generally
agree except that we recommend adding “fault” before “interrupting devices”.
No
We agree with the vast majority of them, listed below are our few concerns, questions, and pleas
for clarification. 1) We disagree with doing specific gravity and temperature of every cell in the
18 month test because the other tests being done are already comprehensive. 2) FAQ 3B p 29
digital relay A/D verification should include simply comparing digital relay displayed metered
values to another metered source. 3) FAQ 3A p6 Change “prove that” to “verify”. For single CT
or VT, this can be challenging and some measure of reasonableness in determining an expected
value comparable to the measured value must be acceptable. 4) FAQ 1B p17 Combining
evidence forms of “Process documentation or plans” and “Data” or “screen shots” shows
compliance. Please add an example or verbiage to clarify that a field technician’s (or operator)
recorded check-off combined with a company’s process is sufficient evidence. Otherwise
documentation alone could consume considerable field personnel time. 5) FAQ p2 Add FAQ to
clarify “verify settings”. If EM relays are included, explain that minor tap or time dial differences
of the order of relay tolerances are acceptable. For digital relays state that software compare
functions are a sufficient means to “verify settings.” 6) Omit Table 1b row 3 because row 4
actually applies to Monitoring Level 2 Trip Circuits. Row 3 already appears in Table 1a, and
repeating it in Table 1b is confusing. 7) FAQ 4D p 7 then defines auxiliary relays as device 86
and 94. Does device number nomenclature or function determine and restrict inclusion? 8)
Please state that “a location where action can be taken for alarmed failures” would include a
dispatch center or control room. From there the custodial authority would be called out to take
action. 9) Please explain the expansion from station battery to station DC supply, specifically the
addition of the charger, an AC to DC device. The charger load test up to its current limiter would
add a significant amount of work with little known benefit. Have charger problems been a
significant cause of cascading outages? 10) We oppose your expansion of Station DC Supply to
UFLS (the last row on page 8.) PRC-008-0 is restricted to UFLS equipment. UFLS is often applied
in distribution substations to trip feeders directly serving load. Your scope expansion has the
potential to greatly increase the number of substation DC Supplies covered by NERC standards.
,. While we agree that UFLS is BES applicable, and those substations are included in our overall
maintenance program, this expansion to NERC scrutiny is not warranted. Have there been UF
events in which a material amount of load was not shed because of DC problems? UFLS is spread
out amongst many distribution stations, and even if a couple did fail to trip in an underfrequency
event, it would have little effect. 11) FAQ 2 p 17 expands the scope at Generating Facilities so
that system connected station auxiliary transformers would be included. We oppose this
expansion as these are radially served loads, and they often do not result in generation loss.
Even if they did, the BES can readily tolerate the loss of a single generator.
No
1) The “zero tolerance” structure proposed combined with the large volume and complexity of
Protection System components forces an entity to shorten their intervals well below maximum.
We instead propose a calendar increment grace period in which a small percentage of carryover
components would be tracked and addressed. For example, up to 10% of all breaker trip coils
subject to the 3 month “verify breaker trip coil continuity” could carry over into the first month of
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the next period. And for example, up to 5% of an entity’s communication channel 6 year
verifications could carryover into the next year. These carryover components would be addressed
with high priority in that next calendar increment. There are many barriers to 100% completion
or zero tolerance. Barriers include sheer volume, obtaining outages, resource availability,
coordination, and documentation (over ten thousand components in our utility alone; taking a
BES outage to permit maintenance can incur a greater reliability risk than delaying the
maintenance; emergent issues such as major storms impact resource availability; coordination
with interconnected neighbors, their resources and maintenance timing; record keeping errors or
oversights; etc. ) 2) Alternatively, components with intervals less than a year should be stated in
terms of the number of times annually it should be performed, rather than a short duration
interval. The expectation is that they would be roughly equally spaced throughout the year; for
example quarterly instead of 3 months. Comment 1 grace period would still apply to components
with maximum intervals of 1 year or greater. 3) Some of our maintenance intervals are shorter
than maximum. Please confirm that documentation is only to be kept for two of the entity’s
intervals, not two of the maximum interval. 4) Please add standard language or FAQ near 2D on
p 18 that an entity can validly use an interval with % tolerance to achieve maintenance goals, as
long as the applicable maximum interval is honored.
Yes
We agree with the condition-based approach. Our comments in 3 above apply to Tables 1b and
1c as well. We note that Table 1b Station dc supply intervals are the same as Table 1a. Why
doesn’t the monitoring cause 1b intervals to be longer than 1a?
Yes
While we agree with the approach, batteries should be allowed, not excluded.
Yes
1) We disagree with the page 22 statement that batteries cannot be a unique population
segment of a PBM. 2) What role does the Supplement play in Compliance Monitoring and
Enforcement?
Yes
1) We don’t think an Executive Summary is needed. 2) Please include the Supplement’s
explanation of A/D verification method from Supplement page 9. 3) What role does the FAQ play
in Compliance Monitoring and Enforcement? 4) Refer to question 2 and add our items # 2, 3, 4,
5, 7, and 11 to FAQ. 5) Please add FAQ that provides the NERC Compliance Reqistry Criteria for
Generating Facilities, to clarify applicability to >20MVA direct BES connection, aggregate
>75MVA etc. 6) FAQ 2A p17 states that commissioning is construction, not maintenance. It
seems like you’re ignoring the significant verification, testing, inspection, and calibration
activities that occur in commissioning. Should the in-service date be assigned to these
components for determining their next maintenance? 7) Refer to question 3 and add our items #
4 to FAQ.
1) Documentation could be a monumental task. Although FAQ 1B allows a comprehensive set of
forms of documentation, a very large number of people are involved across this set at most
utilities. Producing a particular needle in the haystack may take longer than an auditor would
expect. Inspection forms can be structured to capture abnormal conditions, and thus normal
conditions are not recorded. Some items, like the red light monitoring a trip coil, may only be
reported by exception (i.e., “red light out, replaced bulb” but if the red light is on an operator
may not report that). 2) We presume that the SDT would expect transmission facilities to be
switched out of service if maintenance would result in those facilities being unprotected. We think
this should be stated or clarified, as there may be entities that still use differential cutoff switches
or other means of disabling protection for testing and have not considered the consequences of a
concurrent fault.
Individual
Huntis Dittmar
Lower Colorado River Authority
Yes
No
We agree with all stated intervals except for the maximum stated interval of 6 years for
Protection System Control Circuitry (Trip Coils and Auxiliary Relays) in tables 1b and 1c. What
was the intent of separating this interval out from the Protection System Control Circuitry (Trip
Circuits), which is 12 years for monitored components? Monitoring of the trip coils should be
enough to justify a maximum interval of 12 years. As stated these requirements will put an
undue financial and resource burden on utilities that have updated their protective relay systems
with state-of –the art components and monitoring. In addition to the expense and effort of
scheduling the additional maintenance, the additional validation of lockouts and auxiliary relays,
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separate from the full function testing could lead to additional human errors and accidental
tripping of circuits while testing. We believe there should be one stated activity “Protection
System Control Circuitry and have a maximum interval of 12 years for monitored systems.
Yes
Yes
We commend the drafting team for recognizing the advantages of using monitored systems and
a condition-based approach. This approach recognizes the benefits of using newer technologies
and will give utilities added incentive to update their relay systems.
Yes
Yes
The Supplementary Reference is well written and helpful in explaining the drafting teams thought
process.
Yes
The Frequently-asked Questions document is very well written and very helpful. The decision
trees are a good addition.
Conflict: Potential conflict with PRC-023 as to which PRS systems are applicable per this
standard. Comments:PRC-005-2 requires compliance for this standard for all non-radial systems
over 100 kV; while, PRC-023-1 prescribes it as below: 1. Title: Transmission Relay Loadability 2.
Number: PRC-023-1 3. Purpose: Protective relay settings shall not limit transmission loadability;
not interfere with system operators’ ability to take remedial action to protect system reliability
and; be set to reliably detect all fault conditions and protect the electrical network from these
faults. 4. Applicability: 4.1. Transmission Owners with load-responsive phase protection systems
as described in Attachment A, applied to facilities defined below: 4.1.1 Transmission lines
operated at 200 kV and above. 4.1.2 Transmission lines operated at 100 kV to 200 kV as
designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System.
4.1.3 Transformers with low voltage terminals connected at 200 kV and above. 4.1.4
Transformers with low voltage terminals connected at 100 kV to 200 kV as designated by the
Planning Coordinator as critical to the reliability of the Bulk Electric System. 4.2. Generator
Owners with load-responsive phase protection systems as described in Attachment A, applied to
facilities defined in 4.1.1 through 4.1.4. 4.3. Distribution Providers with load-responsive phase
protection systems as described in Attachment A, applied according to facilities defined in 4.1.1
through 4.1.4., provided that those facilities have bi-directional flow capabilities. 4.4. Planning
Coordinators. We believe Bulk Electric System (BES) owners’ resources would be better utilized
by focusing on relay systems as defined in the above PRC-023-1 and this would still provide high
level of reliability for the BES, since not all facilities operating between 100 – 200KV are critical
to the BES. This would not preclude any utilities from applying this standard to other facilities
operating at the lower voltage range. Why did the drafting team not use the application language
sited in the “Protection System Maintenance - A NERC Technical Reference” which is similar to
what is described above from PRC-023-1?
We commend the work done by the Standard Drafting team. In particular, the merging of
previous standards PRC-005-0, PRC-008-0, PRC-011-0, and PRC-017-0 which will help with the
efficient management of these standards.
Group
Western Area Power Administration
Brandy A. Dunn
Yes
Yes
Yes
Yes
Yes
No
No
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Group
Operations and Maintenance
Robert Casey
Yes
Yes
Yes
Yes
Yes
No
No
No conflicts known.
None.
None.
Group
Electric Market Policy
Jalal Babik
Yes
We commend the SDT for developing such a clear and well documented first draft. In general, it
provides a well reasoned and balanced view of Protection System Maintenance.
Yes
No
Recommend that all Level 1 three-month maintenance intervals be changed to a quarterly based
system where only 4 inspections are required per year. Given a 3 month maximum interval,
activities would need to be scheduled every 2 months, which would result in six inspections per
year. Our experience of four inspections per year has proven to be successful.
No
Recommend that all Level 2 three-month maintenance intervals be changed to a quarterly based
system where only 4 inspections are required per year. Given a 3 month maximum interval,
activities would need to be scheduled every 2 months, which would result in six inspections per
year. Our experience of four inspections per year has proven to be successful.
Yes
No
No
None
Regional Variance
It is our understanding that once Project 2009-17: “Interpretation of PRC-004-1 and PRC-005-1
for Y-W Electric and Tri-State” is approved, that the definition of a “Transmission Protection
System” would be included within PRC-005-2 or included within the NERC Glossary of Terms.
However, the specific protection that would be considered part of the “Transmission Protection
System” would also depend on the regional definition of the BES. We suggest that the regions
develop a supplement that provides further clarification on what constitutes a “Transmission
Protection System” given the regional definition of the BES.
The “zero tolerance” structure proposed within this standard combined with the large volume
and complexity of Protection System components requires a utilities processes and built-in grace
periods to perform to perfection. Although this is a worthy goal for our industry, this can result in
a large number of non-compliances for minor documentation issues or slightly missed
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maintenance schedules on an insignificant percentage of relays. The processing of these noncompliances can be costly in terms of resources that could be better utilized to address other
transmission reliability matters. To provide a better approach, we suggest an incremental
carryover system be permitted that would allow up to 0.5 percent of the PRC-005 maintenance
task to be carried over to the next period, provided they are random events (not repetitive). As
an example, a small percentage of our Protective System Control Trip tests on a 6-year interval
could be carried over into the next calendar year when a generator outage is rescheduled. With
this provision, these few tests could be handled without risk of a generator trip and without a
compliance consequence. These carryover tasks could be addressed through an action plan with
a defined completion date, and could be documented through a regional web portal. There are
many barriers to 100% completion at a zero tolerance level with this volume of tasks.
Group
Southern Company
Hugh Francis
Yes
No
Tables 1a and 1b require entities to verify the proper operation of voltage and current inputs to
sensing devices on a 12 year interval. The Protection System Supplementary Reference (Draft 1),
in section 15.2, describes several methods that may be used for such verification efforts. In
order to perform this type of verification the circuit in question would need to be in operation.
This verification introduces a possible unit trip due to the need to connect test equipment to live
potential and current circuits at each relay, which has the potential to trip the circuit under test.
This could result in the loss of critical transmission lines or generating units. The System
Maintenance Supplementary Reference also allows saturation tests or circuit commissioning tests
to satisfy this requirement; however, these types of tests require the circuit in question to be
removed from service. For generating plants, removing the circuit from service requires that the
station be shut down. We do not feel that the value obtained from this requirement is equal to
the risk or maintenance burden associated with it. Such testing and verification should not be
required periodically, but only if new instrument transformers, cabling or protective devices are
installed or if the instrument transformers are replaced. Table 1b: Protection System Control
Circuitry (Trip Coils and Auxiliary Relays) – Experience has shown that electrically operating
partially monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is not
warranted. This testing introduces risk from a human error perspective as well as from additional
switching and clearances required. We recommend eliminating this maintenance requirement.
Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS Systems Only) - Table 1b
includes the statement "Verification does not require actual tripping of circuit breakers or
interrupting devices." This statement should be included in Table 1a. In Table 1a – Station DC
Supply (that has as a component any type of battery), we recommend changing the maximum
maintenance interval from 3 months to 6 months as described below Verify Proper Electrolyte
Level – 3 Months The 3 months interval for verifying proper electrolyte level is excessive for
current battery designs that are properly maintained. The interval in which the electrolyte must
be replenished is affected by many factors. These include temperature, float voltage, grid
material, age of the battery, flame arrester design, frequency of equalization, and electrolyte
volume in the battery jar. Manufacturers are aware that their customers want to extend the
interval in which their batteries require water and this has lead to jar designs that have a wide
min-max band with a high volume of electrolyte to allow for extended watering intervals.
Understanding all the factors and proper maintenance will extend watering intervals. A battery
should go a year or more between watering intervals and some as many as 3 years. Being
conservative the Southern Company Substation Maintenance Standards require that we check
the electrolyte level twice yearly. Experience has shown this has worked well. We propose that
the “3 Months” interval be changed to “6 months”. • Verify proper voltage of the station battery
– 3 Months Being conservative, the Southern Company Substation Maintenance Standards
require that we check the station battery voltage twice yearly. Experience has shown this has
worked well. We propose that the “3 Months” interval be changed to “6 months”. • Verify that no
dc supply grounds are present – 3 Months Being conservative, the Southern Company Substation
Maintenance Standards require that we check for dc supply grounds twice yearly. Experience has
shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”.
Measurement of Specific Gravity – 18 Months The measurement of specific gravity and
temperature every 18 months is not necessary as a regular part of maintenance. Specific gravity
can provide information as to the health of a cell; however, taking specific gravity readings is a
messy process no matter how careful you are and will result in acid being dripped on top of the
battery jars as the hydrometer is moved from cell to cell. Should a drop of acid end up on an
external connection, it will result in corrosion and problems later. Voltage reading of cells can be
substituted for specific gravity readings under normal conditions. Specific gravity is equal to the
cell voltage minus 0.85. A cell with low voltage will have a low specific gravity. If cell voltage
becomes a problem that can not be addressed through equalization then specific gravity
readings are justified as a follow-up test. Since measurement of specific gravity could lead to
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problems and reading cell voltage is a viable alternative, we propose that it be removed from the
battery maintenance activities. Verify Cell to Cell and Terminal Connection Resistance – 18
Months Clarification is needed on the expected method for verifying cell to cell and terminal
connection resistance. This could easily be interpreted as requiring the use of an ohmic value
(impedance/conductive/resistance) test device. If this is the case then basically it eliminates the
need for the activity to “Verify that the substation battery can perform as designed by
performing a capacity test every 6-Calendar Years or performing an ohmic value test every 18
Months”, because the practical thing to do is go ahead and perform the ohmic value test while
you have your device connected to the battery. In table 1a and 1 b - Station dc supply (that has
as a component Vented Lead-Acid batteries. Verify that the Substation Battery can Perform as
Designed – 6 Calendar Years/18 Months Southern Company Transmission has approximately 570
batteries that are covered by this proposed standard. These batteries currently have ohmic value
testing performed every “4 Years” as required by the Southern Company Substation Maintenance
Standards. The “4 Years” interval has been utilized for over 10 years and has not experienced a
failure of any of the 570 batteries to perform as designed Having to perform ohmic value testing
on an “18 Months” interval will significantly increase our costs and manpower requirements with
no anticipated improvement in reliability. We propose that the “18 Months” interval for ohmic
value testing be changed to “4 Calendar Years”. This proposal also applies to verifying cell to cell
and terminal connection resistance if an ohmic value test device is required as discussed above.
In table 1a and 1b – Station dc supply (that uses a battery and charger). Verify that the Battery
Charger can Perform as Designed – 6 Calendar Years Clarification is needed on an acceptable
method for verifying that the battery charger can perform as designed by testing that the
charger will provide full rated current and will properly current limit, especially the part about
“will properly current limit”. On Table 1b – Station DC Supply (that has a component any type of
battery) we recommend changing the maximum maintenance interval from 3 months to 6
months as described below • Verify Proper Electrolyte Level – 3 Months The 3 months interval
for verifying proper electrolyte level is excessive for current battery designs that are properly
maintained. The interval in which the electrolyte must be replenished is affected by many
factors. These include temperature, float voltage, grid material, age of the battery, flame arrester
design, frequency of equalization, and electrolyte volume in the battery jar. Manufacturers are
aware that their customers want to extend the interval in which their batteries require water and
this has lead to jar designs that have a wide min-max band with a high volume of electrolyte to
allow for extended watering intervals. Understanding all the factors and proper maintenance will
extend watering intervals. A battery should go a year or more between watering intervals and
some as many as 3 years. Being conservative the Southern Company Substation Maintenance
Standards require that we check the electrolyte level twice yearly. Experience has shown this has
worked well. We propose that the “3 Months” interval be changed to “6 months”. We recommend
removing the “Detection and alarming of dc grounds” monitoring attribute. Note that this applies
to every “Station dc supply” section where it is listed. Experience has shown that there have
been no significant problems discovered via alarms that would not have been discovered by 6
month inspection cycles. We propose to add “verify no dc grounds are present” as a maintenance
activity on a 6 months inspection cycle. Experience has shown that there have been no
significant problems discovered via alarms that would not have been discovered by 6 month
inspection cycles. Table 1a, p. 7, Station dc supply, 3 month interval: need to add ‘unintentional”
to the sentence “Verify that no dc supply grounds are present.” because most dc systems have
ground detection systems which place an intentional ground on the battery. “No grounds” is not
practical and is unacceptable since most dc systems have some high resistance ground paths.
Some criteria should be established to determine the acceptable ground resistance on a dc
system. Table 1a, p. 8: For the vented, lead-acid battery, there is no basis for the 18 month
activity option (internal ohmic value measurement) in place of the 6 year performance test. The
activities for trip checks for Level 1A and Level 1B should be the same. Currently, they read:
Level 1a: “Perform a complete functional trip test that includes all sections of the Protection
System trip circuit, including all auxiliary contacts essential to proper functioning of the
Protection System. “ Level 1b: “Verify that each breaker trip coil, each auxiliary relay, and each
lockout relay is electrically operated within this time interval.” The Level 1a text is adequate for
1b also. Table 1c, p 16: Monitoring of single or parallel trip circuits is not practical where multiple
normally open contacts are in series to trip. Monitoring of the trip coils is practical and useful.
How would one monitor several normally open contacts which are in series to trip a breaker?
Table 1c, p. 15, 16, 19: The use of “continuous” under “Maximum Maintenance Interval” in Table
1c should be changed to “N/A” and the Maintenance Activity should be “NONE”. Verification of
the various monitoring (automated notification) systems is not specified anywhere in the
requirements. This, too, should be required.
No
The 3 month intervals specified for the trip coil monitoring and communication circuit testing are
too frequent. Our experience is that trip coils rarely burn open and don’t need to be checked this
often. If no monitoring currently exists, manually checking the circuit (until a time where
monitoring can be installed) may inadvertently cause a trip. This adds risk to the reliability. Thus,
requiring the trip circuits to be tested every 3 months may reduce the reliability of the BES.
Protection System Control Circuitry (Breaker Trip Coil Only) (Except for UFLS or UVLS) In order
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to reduce the risk of reducing Bulk Electric System reliability a better time interval for testing unmonitored trip coils would be 12 months. This may need to be 24 months for Nuclear Generating
units. Some allowance for a grace period (beyond the specified intervals) should be considered
for all classifications. Outage schedules are known to change unexpectedly due to unforeseen
circumstances. A grace period tolerance of +25% for specified maintenance intervals less than 12
months and of +1yr for those intervals specified as greater than 12 months is recommended.
Typically at a nuclear plant a grace period is allowed by plant procedures. This grace period is
defined as an additional 25 percent of the original schedule interval for the task. The grace
period is provided as reasonable flexibility to allow for alignment with surveillance activities and
equipment maintenance outages and to better manage the use of station resources. Some
maintenance activities will require an outage to perform the work. Refueling outages are typically
performed on an 18 month or 24 month refueling cycle. However, refueling outages do not
always fall exactly on that interval. It is possible that the duration between one outage to the
next may exceed 18 or 24 months. For activities that are required to be complete on a calendar
year cycle this should not be an issue since the outages are normally scheduled several months
prior to the end of the year. However, if the interval is a monthly interval there could be a
problem with scheduling the maintenance such that it does not impact planned maintenance
activities, surveillance requirements, and station resources. Tables 1a, 1b and 1c have several
instances where inspection and testing of DC circuits or components has a specified interval of
18 months. At nuclear generating stations, such tests on station battery banks and associated
chargers incur unacceptable risk if performed with the unit on line and a unit outage is required
for this testing. A number of nuclear plants are on two-year shutdown cycles and we request that
the 18 month intervals be changed to two (2) (calendar) year intervals to accommodate this.
Protection System Control Circuitry (Breaker Trip Coil Only) (Except for UFLS or UVLS) – Based
on past performance, a complete functional test trip every 6 years is not warranted. This
complete functional test introduces additional risk to our maintenance program, not only from a
human error perspective, but also from the additional frequency of switching and outages
required. Our experience has shown that 12 years is an appropriate maximum time interval
(rather than 6 years.)
No
Table 1b should allow self-monitored circuits that are not alarmed but are monitored and logged
by personnel daily or more often. Many plants and substations have personnel that do in person
checks of unmanned control rooms. This is the equivalent of “Protection System components
whose alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures.” For example, dc system ground potential lights and dc system
volt meters exist on most control room bench boards or exist in the digital control systems at
generating stations. These devices are monitored by operators in manned control rooms. On
Table 1b, Protection System Control Circuitry (Trip Coils and Auxiliary Relays), the monitoring
component calls for “Monitoring and alarming of continuity of trip coil(s).” Clarify that “trip
coil(s)” excludes Breaker Failure Initiate relay coil(s). On Table 1b, Protection System Control
Circuitry (Trip Coils and Auxiliary Relays) – Experience has shown that electrically operating fully
monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is not warranted.
This testing introduces risk from a human error perspective as well as from additional switching
and clearances required. We recommend eliminating this maintenance requirement from Table
1b. On Table 1c, Protection System Control Circuitry (Trip Coils and Auxiliary Relays) –
Experience has shown that electrically operating fully monitored breaker trip coils, auxiliary
relays, and lockout relays every 6 years is not warranted. This testing introduces risk from a
human error perspective as well as from additional switching and clearances required. We
recommend changing this maximum maintenance interval to 12 years. Component monitoring
attributes need to be defined for all components in table 1b and 1c. For example, the attributes
for voltage and current sensing devices could be that "Voltage and current input circuits are
monitored and alarmed". Based on past performance, the requirement to electrically operate trip
coils, auxiliary relays, and lockout relays every 6 years in Table 1b is not warranted. We
recommend complete functional testing including electrical operation of breaker trip coils,
auxiliary trip relays, and lockout relays every 12 years in tables 1b and 1c.
Yes
Yes
Section 15.3 DC Control Circuitry: Although we agree with the premise that auxiliary trip relays
and lock-out relays are similar in nature to EM relays and breakers, we believe that based on
past performance, a complete functional test trip every 6 years is not warranted. This complete
functional test introduces additional risk to our maintenance program not only from a human
error perspective but also from the additional frequency of switching and outages required. Our
experience has shown that 12 years is an appropriate maximum time interval (rather than 6
years.) The Protection System Maintenance Supplementary Reference (Draft 1), section 8.4,
states that the intervals using the term “calendar” are allowed to be completed by the end of the
applicable period, not necessarily exactly at the interval specified. The only intervals specified in
the PRC-005-2 tables are “calendar years” and “months”. We believe that the “calendar”
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description should be extended to the “months” designator also to also provide some
maintenance flexibility (i.e. if an inspection were performed March 1st and was on a three month
interval, it would not be required until the end of June). This section should remove the term
“calendar” and use “months” and “years” with an appropriate explanation of the intent of the
durations.
Yes
Part of the responses could be more correctly stated: Page 11E, “why is specific gravity testing
required?” The specific gravity measurements do not reflect accurate state of charge for leadcalcium batteries. (Float current is a better parameter for this indication)
We presently utilize a UFLS system distributed across many transmission and distribution
substations. Are the station batteries located in stations with no network transmission protection
schemes (other than UFLS) subject to the requirements of PRC-005-2? This was not addressed
in previous revisions. We presently utilize a UVLS system distributed across many transmission
and distribution substations. Are the station batteries located in stations with no network
transmission protection schemes (other than UVLS) subject to the requirements of PRC-005-2?
In the applicability section, there is no exception for smaller units and those with very low
capacity factors. Rather, those that “are part of the BES” are in the scope. We recommend that
smaller units and low capacity factor units be exempt from the requirements of this standard or
have extended maintenance intervals. Refer to the current SERC supplement for PRC-005-1.
Section II.A. of the May 29, 2008: SERC Supplement Maintenance & Testing – Protection
Systems (Transmission, Generation, UFLS, UVLS, & SPS) NERC Reliability Standards PRC-005-1,
PRC-008, PRC-011, & PRC-017. The applicability section paragraph 4.2.4 should read “are
installed” rather than “is installed”. Note 2 at the bottom of the table (1c) implies that one has to
apply voltage and inject current into the microprocessor relay to perform trip checks. Is this the
intent of the statement? If so, Note 2 should be revised to make clear the intention. We don’t
think this is necessary with microprocessor relays since they monitor inputs Why is the Violation
Severity Level Matrix not a part of this standard revision? In cases where a common dc system
exists between a generator owner and transmission owner, who is the responsible entity? We
appreciate the work that went into the implementation plan. We agree with the concept of
phasing in mandatory compliance and the timing of the implemetation. Consider defining the
Monitoring Levels once and reformatting the information contained within Tables 1a, 1b, and 1c
to regroup the information by component type rather than by Monitor Level. When considering
the various monitoring levels for the protection system components, each entity will consider
each component type apart from the others when determining the Monitor Level to apply, so this
reorganization will assist the end user to understand and apply the levels. See samples attached
as a separate document:
Individual
Daniel J. Hansen
RRI Energy
Yes
No
It is recommended to change the wording of the Maintenance Activities to the activity itself, not
the resolved state of the maintenance correctable issue (i.e. “For microprocessor relay, check for
proper operation of the A/D converters” instead of “For microprocessor relays, verify proper
functioning of the A/D converters”). The wording of the standard effectively sets the end date for
the correction of maintenance identified issues. In other words, maintenance has not taken place
until all maintenance correctible issues have been completely resolved. The wording in the
standard have set non-compliance “traps” for those performing the maintenance but have not
completed correctable issues for legitimate reasons which may not be allowed by the noexception approach of the standard. For example, rewording of the Battery Supply 3 month
activities are recommended as follows: “Check for proper electrolyte level. Check for proper
voltage. Check for dc supply grounds.” As inspection activities, any issue not corrected during the
interval should become a maintenance correctible issue. For generating stations, the judgments
to locate and remove a ground are based upon criteria not accounted for in the requirements of
this standard. An activity to locate and clear a ground requires the judgment of station
maintenance and operational management depending upon the operating conditions of the unit
and the level of the ground (solid or high-resistance). Inspections (3 month requirement
activities) although good practices, should not be standard requirements. The practice of
verifying the continuity of breaker trip circuits does not belong as an auditable NERC standard
requirement; it becomes more of a documentation requirement rather than a reliability
improvement. Otherwise, it will ultimately require the expending of resources in an unproductive
manner primarily on the development, storage, and production of excessive records for
compliance purposes. The elimination of this requirement is recommended. For Table 1a –
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Protection System Control Circuitry - rewording is suggested as follows: “Perform functional trip
tests of Protection System trip circuits, including auxiliary relays essential to the proper
functioning of the Protection System.” The requirement, as presently worded “that includes all
sections of the Protection System,” is overly prescriptive and will create non-compliances for
miniscule oversights, given the very large scope of components in protection systems that are
spread out far and wide in a system. The requirement opens the door, allowing the compliance
process itself to be punitive in nature. When pursued to the extreme under audit conditions, this
requirement will be very difficult to demonstrate on a large scale. For Table 1a – Station dc
supply: The ability of a battery charger to correctly supply equalize voltage to a battery has no
direct correlation to reliability of the BES and does not belong in this standard. The objective is
that the battery get an equalize charge when it needs it, not the maintenance of the equalize
function of a battery charger. How the battery gets equalized is not important to this standard,
especially since a battery and the equalize source are usually disconnected from the protection
system during the process. For Table 1a – Station dc supply: The use of the term “in tolerance,”
for the measurement of specific gravity, is an inconsistency in stating the standard requirements.
There are multiple activities that will necessitate the measurement of a quantity “in tolerance”
whether it is battery charger output, individual cell voltages, connection resistances, or internal
ohmic values. The suggested rewording is as follows: “Measure the specific gravity and
temperature of each cell.” For Table 1a – Station dc supply: Referring to the requirement to
“verify that the station battery can perform as designed…” very little of a generating station
battery sizing is related to BES protection. Verification of a generating station to design
conditions is outside the scope of BES protection and does not belong in this standard. Nearly all
protection system operations operate without reliance upon the battery to do so, and the
separation of the generating unit from the BES will take place within cycles, if called upon to do
so. The remainder of the battery duty cycle is outside the scope of BES protection.
No
The intervals need to be defined on a calendar quarters or calendar years, especially for intervals
listed as 3 months. The demonstration of maintenance on rolling three-month intervals will be an
onerous record keeping task, particularly when relying upon planning and tracking software that
scheduled recurring tasks on the same day of an interval. Given the magnitude of the number of
trip circuits, the requirements set an un-acceptable trap of non-compliance from a record
keeping perspective. The resources required to keep and maintain flawless records are too much
to justify the intervals. A non-compliance is the result if the breakers that happen to be in an
open state when the officially “documented” inspection is recorded and is missed by accidental
oversight on follow-up. If the requirement remains, it should be waived for any breaker that is
operated during the defined interval.
Yes
Yes
No
Yes
Reverse power relays do not belong in the list of devices within the scope of this standard;
reverse power is not used for generator protection or protection of a BES element. Aside from
the protection of reverse power for other non-BES equipment, a generator can operate
continuously as a generator, synchronous condenser, or a synchronous motor. Reverse power
relays (or reverse power elements in multi-function relays) is commonly used as a control
function for automatic shut-down purposes, which is not a protective function. Other reverse
power protection, with longer time delays, is provided for turbine protection, which is not within
the scope of the NERC Standards.
The standard was written to implement generally accepted practices, but has developed
requirements that are overly prescriptive relative to what will be required to demonstration
compliance. The standard should not assume the need to write all aspects of a maintenance
program into the standard or that maintenance programs will only consist of the standard
requirements. Protection systems of the BES have and will continue to perform very reliably with
the basic elements of a maintenance program without the need to divert resources for the
development of excessive documentation to demonstrate compliance. PRC-005-1 is the most
violated standard in the industry; not because of the lack of maintenance to protection systems,
but because the documentation requirements of the standard, given the large magnitude of
components that fall within the scope of the standard. This standard significantly increases the
administrative burden for additional documentation, without corresponding improvements to the
reliability of the BES. Recommend rewording A.4.2.5.1 as follows: “Generator Protection system
components that trip the generator circuit breakers to separate and isolate the generator from
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the BES either directly in the breaker trip coil circuit or through interposing lockout or auxiliary
tripping relays.” This document should not expand the compliance scope beyond the definition of
the BES. The generator protection systems that “trip the generator” also perform additional
control functions that extend beyond the electrical isolation of the generating unit from the BES.
These additional circuits do not protect the BES and do not belong in the scope of this document.
Recommend rewording A.4.2.5.4 as follows: “Protection systems for generator-connected station
service transformers that trip the generator circuit breakers to separate and isolate the generator
from the BES.” This document should not expand the compliance scope beyond the definition of
the BES. Related protection circuits of the transformer not involved with the electrical isolation of
the generating unit from the BES does not belong in the scope of this document. Recommend
rewording A.4.2.5.5 as follows: “Protection systems for BES elements connecting to the station
service transformers of generating stations.” This document should not expand the compliance
scope beyond the definition of the BES. The requirement incorporates radial feeds (with
dedicated breakers) into the scope of the standard that are not necessarily a part of the BES as
defined by some RRO’s. Station service transformers are not necessarily required for generating
unit operation. In some cases there are redundant sources for startup or back-up power.
Protection of these transformers does not belong in the scope of the standard if they are not a
part of the BES. The suggested rewording of R1.2 is as follows: “Identify whether each Protection
System component is addressed through time-based, condition-based, performance-based, or a
combination of these maintenance methods.” The requirement for the registered entity to list the
interval of maintenance does not belong in the standard, especially since the maximum intervals
are listed in the standard tables. The registered entity may have internal documents that
intentionally target a shorter duration than the maximum interval of Table 1a. The failure to
meeting those internally established targets can be a violation of the standard by the wording of
this requirement. Allow R4 of the standard to identify the maximum allowable intervals. In R4,
the requirement for “identification of the resolution of all maintenance correctible issues” should
be separated from the maintenance intervals; which define the maximum intervals of
maintenance activities. The requirement should be eliminated to remove the overly prescriptive
requirements of auditable documentation. If retained, a rewording of the requirement is as
follows: “Each Transmission Owner, Generator Owner, and Distribution Provider shall identify the
resolution of all issues identified and not corrected at the time the maintenance is initiated and
the protected element is returned to service.” The documented resolution of maintenance
correctible issues (if retained) should apply only to activities that are unresolved and incomplete
during the normal maintenance process. The standard should not micromanage the
documentation process by creating requirements for excessive auditable records needed to
demonstrate compliance of routine maintenance activities. In R4, the requirements for Generator
Owners which establish the durations of maximum allowable intervals should be separated from
the Transmission Owners, even if the intervals are the same. The reason is to allow for the
assignment of different Violation Risk Factors. The Violation Risk Factor for the application of a
20 MVA generating unit with an operating capacity factor of less than 5%, and connected to a
138 kV system, should not be the same as those applied to a 500kV transmission line. The
violation risks factors for these two applications are significantly different, and the ability to
recognize this is not permitted by the standard presently. Similarly, the criteria used for the
sizing of station batteries for a large generating station is very different than those used for
transmission facilities. Very little of the generating station battery sizing is related to BES
protection, and nearly all generator protection system operations occur without reliance upon the
battery. Without NERC Standard requirements, Generator Owners have their own natural
incentives to maintain batteries for the protection of the turbine generator bearings on the loss of
AC power. With the most basic requirements of an inspection and maintenance program, there is
an extremely high degree of reliability given the typical design of DC systems within a generating
station, even without documented compliance to a rigid set of standards. With very basic,
elementary maintenance (documented or not), the statistical probability for the random and
simultaneous failure of multiple battery cells to disable the protection system of a generating
station for the milliseconds of time required to separate a generating unit from the BES is
insignificant (well in excess of 1 billion to 1 across an entire calendar quarter). Violation risk
factors and the resulting penalties for non-compliance need to be realistic.
Group
Transmission Owner
Silvia Parada-Mitchell
Yes
No
Tables 1a, 1b & 1c should offer as an alternative, measuring battery float voltages and float
currents in lieu of measuring specific gravities as described in Annex A4 of IEEE Std 450-2002. b.
Inspection of CVT gaps, MOVs and gas tubes should be added to the communications equipment
time based maintenance tables. Failure of the CVT protective devices may cause failure of the
Protection System. c. Maintenance Activities for UVLS or UFLS station dc supplies shows “Verify
proper voltage of dc supply”. Does this imply that, except for voltage readings of the dc supply,
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distribution battery banks are not maintained? d. Why does the Maintenance Activities for UVLS
or UFLS relays state that verification does not require actual tripping of circuit breakers? e.
Please clarify the Maintenance Activities for Voltage and Current Sensing Devices. Must voltage,
current and their respective phase angles be measured at each discrete electromechanical relay?
No
i) Protective relays, ii) Protection Control Circuitry (Trip Circuits) and iii) Protection System
Communications Equipment and Channels should be changed from 6 calendar years to 8
calendar years. Based on FPL’s experience and Reliability Centered Maintenance (RCM) program,
FPL has established an 8 year program and has found that an aggressive 6 year program would
not substantially increase the effectiveness of a preventative maintenance program. b. Battery
visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s lead-calcium
batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in
the past. c. The maximum maintenance interval for communications equipment should be
changed from 3 months to 12 months. Based on FPL’s experience and RCM program, FPL has
established a 12 month program that is effective.
Yes
Yes
No
Yes
An alternative to measuring battery specific gravity is to measure float voltage and float current
as described in Annex A4 of IEEE Std 450-2002.
Protection System Maintenance Program (PSMP) The PSMP definition would be better defined if
the first sentence was changed to “An ongoing program by which Protection System components
are kept in working order and where malfunctioning components are restored to working order.”
b. Please clarify what is meant by “relevant” under the definition of Upkeep. Should “relevant” be
changed to “necessary”? c. The definition of Restoration would also be more explicit if changed
to “The actions to return malfunctioning components back to working order by calibration, repair
or replacement. d. Please clarify the definition of Restoration. For example, if a direct transfer
trip system has dual channels for extra security even though only one channel is required to
protect the reliability of the BES and one channel fails, must both be restored to be compliant?
e. Protection System (modification) ”Voltage and current sensing inputs to protective relays”
should be changed to “voltage and current sensors for protective relays.” Voltage and current
sensors are components that produce voltage and current inputs to protective relays. f.
“Auxiliary relays” should be changed to “auxiliary tripping relays” throughout PRC-005-2, FAQ
and the Draft Supplementary Reference. g. The word “proper” should be removed from the
standard. It is ambiguous and should be replaced with a word or words that are clear and
concise.
Individual
Greg Mason
Dynegy
Yes
No
Table 1a requires entities to "verify the continuity of of the breaker trip circuit including trip
coil..." The term "verify" needs clarification. For example, we beieve verifying red and green"
lights during routine inspection should be sufficient. On the other hand, actual testing is not
feasible and is risky to reliability.
No
The 3 month interval in Table 1a for verification of the continuity of the breaker trip circuit is only
feasible if this verification can be done by inspection versus testing (see Response to Question
2).
Yes
Yes
Yes
Suggest including operational verification (i.e. analysis of protection system operation after a
system event) as an acceptable method of verification.
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No
1. The proposed definition of Protection System needs further clarification. Suggest changing
wording around DC supply to read as follows: "..and DC control circuitry associated with
protective devices from the station DC supply". 2. Suggest revising Section 4.2 to separate time
based program as its own item under R4. 3. Change title on Table 1a to clarify level 1 monitoring
as time based.
Group
ITC Holdings
Michael Ayotte
Yes
No
• (FAQ 3C) What is the technical justification for omitting insulation testing of the wiring for DC
control, potential and current circuits between the station-yard equipment and the relay
schemes? We feel this wiring is susceptible to transients which, over time, may compromise the
insulation, and therefore should be tested. • Table 1a (Page 6) Improve wording. Suggestion:
“Verify proper functioning of the current and voltage circuits from the voltage and current
sensing devices to the protective relay inputs” • On Page 6: The red light monitors trip circuit
not only trip coil. With only one circuit going to three parallel single-pole trip coils a red light will
not detect a single open trip coil. Is a station inspection that verifies the red light is “on” an
acceptable activity? • On Page 9: The 3 month communications maintenance activities should
say that the channel needs to be checked. For example: initiate a manual checkback test of the
carrier system. • On Page 10: Not clear on level 2 monitoring attributes for protective relay
component description. As written it notes two separate requirements which are ambiguous. We
assume that all monitoring noted is required (internal self diagnosis and waveform sampling) •
On Page7: The standard should note that battery testing must include all batteries that are used
in protective relay systems (for example pilot wire batteries).
No
• Does the standard require that time or condition based maintenance programs monitor
countable events to identify significant problems in particular relay segments, and then adjust
the maintenance interval accordingly? • On page 6: Please clarify the use of “Calendar Year” Our
understanding is that if a relay is maintained on August 31, 2003 on a 6 year interval, it will not
be overdue until January 1, 2010. Is this correct? • On Page 7: What is the basis for 18 months?
We believe 2 calendar years would be more appropriate. • On Pages 6,10: What is the basis of
the 6 calendar year interval for functional trip tests? We request that this be changed to a 10
calendar year interval. We follow a 10 calendar year interval that has proven to be satisfactory.
Decreasing the interval to 6 calendar years will result in a major increase in our maintenance
expenses without a corresponding increase in reliability. • On Page 9: If it is being verified ok
every 3 months, what is the basis of the 6 calendar year interval for Communication equipment?
ITC communications systems are partially monitored and therefore required to perform this
testing every 12 years. However, ITC would like to know the basis of the 6 year interval for
informational purposes. • On pages 6, 8, 11, 13, 14 and 19: The maximum maintenance interval
“(when the associated UVLS or UFLS system is maintained)” should be shown as the actual “6
Calendar Years”. • On Page 1 of Attachment A: Please provide an example in the reference of the
proper way of adjusting the interval based on test results. • On Pages 7, 8, 12: It is our
understanding that adequate maintenance can be achieved by performing either one of the two
maintenance activities in cases where there is an “or”, is that correct? • On Page 14: For the
bottom two rows on page 14 we believe there is a typo and it should read “Level 2” not “Level
1”. • On Page 13: Do powerline carrier schemes that provide a remote alarm if a daily checkback
test fails, meet level 2 monitoring requirements? • In Table 1: What is the basis for the 6 year
interval for the battery systems? This test would be an additional test for ITC. We would prefer
to perform this additional test with the relay periodic maintenance on a 10 year interval.
Yes
• We agree with the approach. We have several issues with the details of Maintenance Issues,
Interval and Monitoring Attributes. See previous comments for Questions 2 and 3.
No
• Appendix A fixes a 4% level of “countable events”. Is this number the industry average for
countable events? Has the industry average actually been determined? The basis for the 4%
requirement noted in Paragraph 5 of Appendix A should be included in the reference document.
Also a sample calculation for adjusting the interval is needed to clarify the requirement.
Yes
• Will clarifications in the Reference Document be enforceable with the standard? For example
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page 11 of the reference document notes “Voltage & Current Sensing Device circuit input
connections to the protection system relays can be verified by comparison of known values of
other sources on live circuits or by using test currents and voltages on equipment out of service
for maintenance.” Can a maintenance program be confidently established using this or other
testing methods included in the reference document? • A condensed definition of “Condition
Based Maintenance” as described in Section 6 of the Reference document should be included in
the standard document itself.
Yes
• FAQ page 6 question 3C should be clarified in the standard document itself. What is the
technical justification for omitting insulation testing of the wiring for DC control, potential and
current circuits between the station-yard equipment and the relay schemes? We feel this wiring
is susceptible to transients which, over time, may compromise the insulation, and therefore
should be tested. • FAQ page 17 question 2A the standard should define when the first
maintenance activity is to be performed. We include our maintenance activities during
commissioning, and set the next maintenance due date based on the testing interval. • Will
clarifications in the FAQs be enforceable with the standard? Can a maintenance program be
confidently established using this or other answers included in the FAQ’s?
Comments: We are not aware of any conflicts.
Comment: We are not aware of any regional variance or business practice that should be
considered with this project.
In the Definitions of Terms, the Protection System (modification) should include control circuits
up to and including the trip coil of ground switches used in protection schemes. Footnote 2
(Maintenance correctable issue) should be included in the Definition of Terms in the body of the
standard.
Individual
Robert Waugh
Ohio Valley Electric Corp.
Yes
No
In general, all maintenance activities that are verifications of proper function imply that problems
found must be resolved within the maximum interval. For some activities, that is an
unreasonable expectation. A temporary resolution may reliably correct an adverse situation but
may not address the original verification requirement within the maximum interval. Routine
substation inspections should not fall under NERC standards. The documentation for quarterly
inspections would be oppresive. It is unreasonable to require there to be no DC grounds. All DC
grounds do not rise to the level of a reliability concern. In some cases, attempting to resolve a
relatively minor DC problem may rise to the level of negatively affecting reliability. The value of
capacity testing battery banks and chargers in the context of a protection system reliability
standard is questionable.
No
The documentation requirements for the inspection activities with three month intervals is
oppressive and should not be a part of the protection system maintenance standard.
R1.2 seems to require owners to establish there own intervals and basis. Compliance with these
requirements should be based on the intervals that are in tables 1a, 1b and 1c. R4 implies that
all maintenance correctible issues must be resolved within the Maintenance Activity Intervals. A
diligent effort to restore proper function of a system should not be penalized if it does not fall
within the prescribed maintenance interval.
Individual
Brent Ingebrigtson
E.ON U.S.
No
Capacity or AC impedance only needs to be done to determine service life and therefore periodic
testing of station DC supply does not seem necessary or prudent. If a company checks overall
battery bank voltages quarterly then periodic testing of the battery bank charger should not be
required.
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No
Generally, E.ON U.S. requests that the SDT provide the basis for the proposed changes in
maintenance time lines. E ON U.S.’s existing maintenance intervals are based on actual operating
experience. Not having been provided with the basis for the proposed intervals, the time lines
appear arbitrary. E.ON U.S. currently has an 8-year interval for combustion turbines vs. the 6year interval provided here. The E.ON U.S. interval is based on the Company’s experience with
this equipment. E.ON U.S. suggests that the SDT provide some consideration to individual
entities’ historic practices. It is difficult to track “18 months”. Maintenance intervals should be in
expressed in number of years. E ON U.S. also does not understand the basis for the 3 months
maintenance schedule on breaker trip coils. Typically, the circuit breaker closed indication is
wired through the breaker trip coil. Thus there could not be a breaker closed indication without a
good breaker trip coil. So, this test should be considered continuous monitoring which may not
even require documentation except in case of failure.
Yes
No
E.ON U.S. recommends keeping with time-based intervals (and the improvement thereof) and
staying clear of condition-based performance for the generating stations. But that is not meant
to preclude other companies from doing condition-based, if they so prefer.
Yes
With reference to Section 8.1., under additional notes is the following bullet: 5. Aggregated small
entities will naturally distribute the testing of the population of UFLS/UVLS systems and large
entities will usually maintain a portion of these systems in any given year. Additionally, if
relatively small quantities of such systems do not perform properly, it will not affect the integrity
of the overall program. This implies that incorrect performance of a “relatively small quantity” of
UFLS relays is acceptable but with the understanding that it is not optimal. E.ON U.S. agrees
with this statement in principle, in that the UFLS program is spread out across the system, and
there is not a one to one performance expectation as there is with a transmission line or
generation protection system. This calls into question the required intervals for testing of these
types of relays, and the performance expectations in a PBM program. Given the number of relays
spread out across the distribution system, the testing requirements of UFLS relays require longer
testing intervals than other bulk transmission system components. 8.2 Is this requirement
expected to be retroactive? That is, if the previous retention policy was followed to the letter, an
entity could be fully in compliance based on the previous standard, but not be in compliance if
PRC-005-2 were retroactive. 8.3 And 8.4 This discussion explains how time based maintenance
intervals were determined. The conclusion is based upon surveys of SPCTF members and their
existing practices, and seemed to arrive at a maintenance interval based upon a simple average
weighed by the size of the reporting utility. No consideration appears to have been given to
utilities who have successfully operated with longer test and calibration intervals. In section 5 of
the Supplementary Reference it is stated that “excessive maintenance can actually decrease the
reliability of the component or system.” With that in mind, some of the intervals defined in the
table seem too aggressive. With the proposed PRC-005-2, the Drafting Team has effectively
shortened the recommendation for UFLS relays from 10 years to 6 years, with reference to the
recommendations of the Protection System Maintenance Technical Reference. E.ON U.S. believes
that this is inconsistent with previous comments in Section 8.1, bullet 5 of the notes. Consistent
with the comments above and based on E ON U.S.’s internal testing, calibration and verification
experience, E.ON U.S. recommends maintenance on UFLS relays that comprise a protection
scheme distributed over the power system to be no less than 10 years for Level 1 monitoring
and no less than 15 years for Level 2 monitoring. For a PBM program, require the number of
countable events within a segment to be no more than 10%, not 4% as proposed.
No
E.ON U.S. disagrees with commissioning tests not being considered as a baseline for subsequent
maintenance activities. Commissioning tests should be counted as the initial testing in the
scheme of a maintenance program
Recently, NERC made an interpretation on PRC-005-1 which stated that battery chargers were
not to be included as part of the standard. This version of the standard seems to be in direct
conflict with that interpretation, and for the reasons stated above E.ON U.S. recommends that
battery chargers not be included in the standard. E.ON U.S. believes that capacity or AC
impedance only needs to be done to determine service life, and therefore a periodic testing of
station DC supply does not seem necessary or prudent. Regarding the “Retention of Records”,
retaining records of the latest test seems adequate. E.ON U.S. does not understand the point of
retaining records for the past two test results. This is particularly true for equipment for which
there are relatively long testing intervals, for example, 12 years. Retaining result documents
from 24 years ago seems unnecessary and impractical. With regard to NERC’s PRC-005-2
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Supplementary Reference Section 2.4 on Applicable Relays, E.ON U.S. offers the following
comments: 1. This section extends the applicable relay coverage to IEEE type # 86 and IEEE
type # 94. Some utilities define their turbine trip relay as an IEEE type #94. E.ON U.S. interprets
that the NERC scope of applicable relays is that the turbine trip relays would be excluded;
however, it would further clarify this exclusion if it were mentioned as an example in the last
sentence. 2. The Tables in proposed Standard PRC-005-2 require additional clarity. E.ON U.S.
suggests renaming tables to 1, 2 and 3 to match Level 1, 2 and 3 monitoring. The wording and
format of text is not consistent between tables. 3. The fields in the tables are incoherent. E.ON
U.S.’ interpretation is that intervals and activities for UFLS and UVLS are different than other
relay systems and components, but this is unclear. E.ON U.S. believes a separate table or
sections for UFLS and UVLS would provide more clarity. In section 7 of the Supplementary
Reference the SDT refers to the Bulk Power System instead of the Bulk Electric System. These
are not interchangeable and the SDT needs to explain the need to use the term in this case. The
phrase “support from protection equipment manufacturers” is used several times in the technical
reference (Section 8 and Section 13) yet there is no manufacturer represented on the SDT.
Rather than developing one size fits all requirements applicable to all equipment, E.ON U.S.
suggests that the SDT pursue comments from manufacturers to obtain recommendations on
what they believe is required to maintain and test their equipment.
Individual
Danny Ee
Austin Energy
Yes
No
See item # 10 Comments
No
See item # 10 Comments
Yes
No
See item # 10 Comments
Yes
Yes
Austin Energy is meticulous in adhering to the current maintenance standard and is convinced
that its current maintenance and documentation program is adequate to maintain its reliable
electric power system. Austin Energy appreciates the good intentions of the SDT but believes
that the approach taken increases complexities to the maintenance process, introduces
unwarranted workload in excessive documentation, is inflexible towards system configuration and
experience, and is over prescriptive in nature. The approach also fails to distinguish the harmful
effects of over-maintenance, increasing reliability risk due to human error and ultimately
affecting the overall performance and reliability of the system. Another concerning issue is the
addition of the breaker trip coil to the protection system definition. Our position is that the trip
coil should be part of the breaker. The protection system would be considered operating correctly
if it provided the output signal for the trip coil when expected. Hence the trip coil should be
excluded from the new protection system definition. Performance based maintenance as specified
in the attachment is extremely difficult and cumbersome to navigate. The intricate requirements
are difficult to comprehend and will entrap entities making a good faith effort to comply. We
believe this approach may become burdened with undesirable consequences. Last but not least,
Austin Energy believes that under-frequency load shedding (UFLS) and under-voltage load
shedding (UVLS) systems should not be included in the scope of this new proposal. UFLS and
UVLS are a wholly different entity as compared to the Bulk Electric System (BES). Rigidity
imposed onto distribution system equipment, operating schemes and performance is uncalled for
and overreaching.
Individual
John Alberts
Wolverine Power Supply Cooperative, Inc.
No
Wolverine Power has concern about the level of "prescription" in this standard draft. The intent
of the standards is to define what, not how. This draft gets unnecessarily preseciptive in our
opinion, particularly in the table
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No
The tables are too prescriptive - The standards should state what, not how.
No
See question 2 response
No
See question 2 response
No
See question 2 response
No
No
Individual
Willy Haffecke
City Utilities of Springfield, MO
Yes
No
CU has concern over the battery charger testing requirements. Per the charger manufacturers
recommendations there is no reason to test the chargers as proposed in PRC-005-2. It is their
opinion that the chargers are self diagnostic and do not require these tests (full load current and
current limiting tests). The charger O&M manuals do not even provide instructions for such tests
as optional. Therefore, CU takes exception to this requirement and suggests that battery
chargers be maintained and tested in accordance with manufacturer’s recommendations.
Additionally, CU is concerned with the wording in Table 1a concerning Protection system
communication equipment and channels. We are unsure what the maintenance activity actually
means. If this is an unmonitored system, how can you verify the condition of the communication
system? Is the Standard referring to local monitoring such as annunciators? Please provide
clarification.
No
CU agrees in general with many of the maximum maintenance intervals. However, we disagree
with the necessity to verify the continuity of trip coils every 3 months. We would be interested to
know what basis the committee used to arrive at all intervals. Furthermore, it is our opinion that
even if a component is unmonitored, the interval should not surpass the manufacturer’s
recommendations.
Yes
CU agrees with the approach, but, may not agree with the exact wording in the tables. For
instance, the use of the word “every” in table 1c in “Protection System components in which
every function required for correct operation of that component is continuously monitored and
verified” may be overstating the level of monitoring that would realistically enable a Protection
System to use table 1c.
No
It appears that Attachment A was written for large utilities. Some allocation needs to be made
for utilities with smaller numbers of components.
No
No
CU is unaware of any conflicts.
CU is not aware of a need for a regional variance.
As proposed, this Standard is very long and complex. Additionally,in requirement R1, bullet 1.1
ought to state “For each component used in each Protection System, include all “applicable”
maintenance activities specified in Tables 1a, 1b and 1c”. For instance, if every component has
continuous monitoring, why should the program include 1a and 1b?
Group
Pepco Holdings Inc. - Affiliates
Richard Kafka
Yes
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No
Tables 1a, 1b and 1c all require measuring specific gravity and temperature of battery cells. This
invasive test provides no information regarding battery health that cannot be obtained from cell
impedance testing. Recommend requiring cell impedance OR specific gravity & cell temperature
testing. Tables 1a, 1b and 1c all require testing the battery charger every 6 years to verify that it
can provide full rated current and will properly current limit. In order to perform this
(unnecessary) test the battery would be subjected to a deep discharge. Whatever benefits may
be derived from this test are dwarfed by the negative effect on the battery. Recommend
removing this requirement.
No
Table 1a requires verification of the continuity of the breaker trip circuit every three months in
the absence of a trip coil monitor. Recommend maintenance interval to match that for other
protection system control circuitry (6 years).
No
Monitoring and alarming of the station dc supply and detection and alarming of dc grounds are
required to qualify for Level 2 monitoring of battery / dc systems. While the presence of dc
ground may affect protection and control operations, they do not affect any of the systems for
which dc ground alarming is listed as a monitoring criteria. Recommend removing this criterion
from the battery & dc system monitoring criteria and adding it as a maintenance activity, with
frequency of testing based on presence of detection / alarming.
Yes
No
No
Item 3.B. (Page 6) claims that a small measurable quantity in 3I0 and 3V0 inputs to relays may- be evidence that the circuit is performing properly. This statement is weak at best, and
incorrect at worst. A balanced transmission system may exhibit 3I0 and 3V0 quantities that are
not measurable, and those that are measurable cannot be compared to other readings, since
CT/PT error often exceeds system imbalance. Since these inputs are verified at commissioning,
recommend that maintenance verification require ensuring that phase quantities are as expected
and that 3IO and 3VO quantities appear equal to or close to 0.
Individual
Charles J. Jensen
JEA
Yes
Generally agree; however, some suggestions for possible changes: 1) change "associated
communication systems necessary for correct operation of protective devices" to "protective
relays", 2) add a PSMP glossary defintion for an acceptable type of monitored alarm, either to
the proposed "PSMP monitor" or another definition for "PSMP monitored and alarmed." The SDT
did a good job of making the overall Protection System definition clearer.
Yes
If a communication system relies on a battery system independent of the "station battery", is
this communication system battery under the same requirements as the "station battery"?
Yes
Is it possible that for coil monitored equipment, such as LOR coils, that they were left out, of this
Table allowing for a longer maintenance interval. Certainly LOR continuous coil monitoring with
alarming to a 24 hour 7 day a week manned location, with emergency dispatch, would allow for
a longer maintenance interval for continuously monitored LORs. Suggestion here might be
alignment with continuously self-tested, monitored and alarmed microprocessor relays at 12
years.
Yes
Approach appears to be well explained. Only one are of concern and that would be delaying the
advancement of replacement of EM relay systems with microprocessor, if the PBM population
were to decrease below the 60, resulting in not meeting the sample minimum population criteria.
Falling below this 60 population sample minimum, might result in an immediate compliance
violation.
No
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Yes
The FAQ is a well written document and the team should take pride in its clarity and informative
content. One area that would be good to have further clarification, is if the SDT could provide a
current industry product or example of the "software latches or control algorithms, including trip
logic processing implemented as programming components, such as a microprocessor relay that
takes the place of (conventional) discrete componenet auxilary relays or lockout relays that do
not have to be routinely tested." Is this a microprocessor lockout relay (that does not require trip
testing?)
Regional Variance
Regional variances in the Bulk Electric System defintion as applied across regions allows for
PSMP to vary possibly even for the same region crossing tie lines. Also, accepted maintenance
practices by one region vary from accepted maintenance practices from another region. In the
case of lower kV non-redundant bus lockout protection systems, one region may allow for the
prtoection system to be taken out of service to perform maintenance, while another region may
specifically prohibit this practice (don't leave energized equipment protected by delayed clearing,
etc.)
Implementation Plan - Stongly encourage keeping the implementation plan and allow for an
extension of the implementation plan for the time required to fund, design, procure, install and
commission redundant protection systems for current non-redundant lockout systems at the
lower kV levels of the BES. Our present and past performance of LOR and auxilary relays will
support a PBM/CBM program that allows for a much longer time than the six years proposed for
EM LOR trip testing. To use a TBM for LORs of six years, may in fact, lower the reliability of the
BES due to the complete outages required, along with the detailed procedures that must be
created and rigourously followed to perform these tests without subsequent load loss on the
BES.
Group
Detroit Edison
David A Szulczewski
Yes
No
Suggest that under “Maintenance Activities” for “Protective Relays” add the following: Verify
proper functioning of the microprocessor relay external logic inputs (carrier block, etc.) We
recommend not requiring specific gravity and temperature readings for batteries. We have found
from experience that the time and difficulty to obtain specific gravity readings are not justified.
We have found that utilizing visual inspections, voltage and internal/intercell resistance readings
gives a good picture of the health of the battery. We use specific gravity readings on occasion for
troubleshooting purposes. It is recommended that the sections about verifying battery charger
performance be eliminated if there are low voltage alarms that go to a monitored location. We
recommend changing the maximum maintenance interval for DC supplies with no battery from
18 months to 3 years. If there is no battery, you do not have the risk of failure of chemical
processes and such that would require an interval as short as 18 months.
No
What is the basis for the three month interval for verifying breaker trip coil continuity? Will the
investment required to facilitate this really result in the presumed expected increased reliability?
No
Table 1b indicates that this (level 2) includes all elements of level 1 monitoring. However, level 1
is constantly referred to as unmonitored in other places.
Yes
No
Yes
Example #1 on page 21 states “A vented lead-acid battery with low voltage alarm connected to
SCADA. (level 2)”. However, Table 1b indicates that detection and alarming of dc grounds is also
required for level 2.
Suggest that the term “alarmed failures” in the table headings be changed to “alarmed
abnormalities” to better indicate that the monitored parameter may be in an abnormal state or
out of range but not necessarily failed. Does “system-connected” station service transformers
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refer to transformers connected to the BES or transformers connected to a system at any
voltage level? Is the intent of R1.1.2 that each Protection System component (specific relay at
specific location) be listed individually with its associated maintenance method and interval or
can the general component category be listed as such? Regarding R4, further clarification would
be helpful in understanding the intent of the term “resolution of all maintenance correctible
issues” as it applies to R4.1 and R4.2. Is it intended that “maintenance correctible issues” be
completed within the interval? It is recommended that each line in the tables be given a number
or letter designation to make reference to that row easier.
Individual
Greg Rowland
Duke Energy
Yes
No
Our comments are limited to activities in Table 1a. • Protective Relays – okay • Voltage and
Current Sensing Devices Inputs to Protective Relays – Proper functioning should be verified at
commissioning, and then anytime thereafter if changes are made in a PT or CT circuit. Additional
periodic checks may be warranted as suggested in Table 1A, however no additional checking
should be required where circuit configuration will inherently detect problems with a PT or CT.
For example, PTs & CTs that are monitored through EMS or microprocessor relays will be
alarmed when they are out of specification. • Protection System Control Circuitry (Breaker Trip
Coil Only) (except for UFLS or UVLS) – Need more clarity on exactly what this activity is expected
to include. In some cases we have a red light on a control panel monitoring the circuit path to
the trip coil. In locations where there is not a red light, verifying the continuity of the breaker trip
circuit including the trip coil will be complicated. There is no straightforward way to do it without
potentially impacting reliability, and we would have to consider modifying these installations to
include a red light. • Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS)
– Need more clarity on exactly what the activity is. We believe testing one output all the way to
the coil is sufficient to prove the trip path. The activity states that “all auxiliary contacts” must
be tested. We propose that all protection control circuitry should be tested at initial
commissioning, and then again if any changes are made. Ongoing routine testing is complicated
and could pose reliability challenges to the BES. As stated on page 8 of the System Maintenance
Supplementary Reference document: “Excessive maintenance can actually decrease the reliability
of the component or system. It is not unusual to cause failure of a component by removing it
from service and restoring it. The improper application of test signals may cause failure of a
component. For example, in electromechanical overcurrent relays, test currents have been
known to destroy convolution springs. In addition, maintenance usually takes the component out
of service, during which time it is not able to perform its function. Cutout switch failures, or
failure to restore switch position, commonly lead to protection failures.” • Protection System
Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only) – Need additional clarity on exactly
what the test includes. “Complete functional trip test” should not include tripping the breaker.
Proving the output of the relay should be sufficient. Systems that have all load shed on
distribution circuits should require that trip output be confirmed but should not be required
through to the trip coil due to constraints in tying distribution load. • Station dc supply (that has
as a component any type of battery) – Under the 3 month interval activities, we disagree with
the wording of the activity “Verify that no dc supply grounds are present.” The activity should
instead read “Check for dc supply grounds and if any are found, initiate action to repair.” •
Station dc supply (that has as a component any type of battery) – Under the 18 month interval
activities, what is meant by “Verify continuity and cell integrity of the entire battery”? Also what
is required to “Inspect the structural integrity of the battery rack”? The “Supplementary
Reference Document” and “Frequently asked Questions” document should be made part of the
standard to provide clarity to the requirements. • Station dc supply (that has as a component
Valve Regulated Lead-Acid batteries) – Need more clarity on exactly what is required for a
“performance or service capacity test of the entire battery bank”. The “Supplementary Reference
Document” and “Frequently asked Questions” document should be made part of the standard to
provide clarity to the requirement. • Station dc supply (that has as a component Vented LeadAcid batteries) – Need more clarity on exactly what is required for a “performance, service, or
modified performance capacity test of the entire battery bank”. The “Supplementary Reference
Document” and “Frequently asked Questions” document should be made part of the standard to
provide clarity to the requirement. • Protection system communication equipment and channels –
Need additional clarity on exactly what is required for the substation inspection. What is required
for power-line carrier systems? • UVLS and UFLS relays that comprise a protection scheme
distributed over the power system – Need more clarity regarding the meaning of “distributed
over the power system”.
No
Our comments are limited to Table 1a. More clarity is needed for many of the Maintenance
Activities before assessing whether or not the intervals are reasonable. But as a general
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comment we would like to understand the basis used to develop all of the intervals, and how
that basis compares with research done by the Electric Power Research Institute (EPRI). It is our
understanding that NERC did an industry survey of maintenance intervals and we would like to
see the results of that survey as well. Specific comments: • Protective Relays – 6 calendar years
is okay. • Voltage and Current Sensing Devices Inputs to Protective Relays – We question the
logic for a 12-year interval. Proper functioning should be verified at commissioning, and then
anytime thereafter if changes are made in a PT or CT circuit. Additional periodic checks may be
warranted as suggested in Table 1A, however no additional checking should be required where
circuit configuration will inherently detect problems with a PT or CT. For example, PTs & CTs that
are monitored through EMS or microprocessor relays will be alarmed when they are out of
specification. • Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or
UVLS) – In locations where the continuity of the circuit is not monitored (via a light in the path
or through a microprocessor relay) this would be a very complicated test, which could impact
reliability, especially if done every three months. • Protection System Control Circuitry (Trip
Circuits) (except for UFLS or UVLS) – Need clarity on exactly what the activity is to include. We
believe proving one output all the way to the trip coil is appropriate. Proving every output and
every auxiliary contact, to the trip coil would be unnecessarily invasive and could impact
reliability, even if done every 6 calendar years. • Protection System Control Circuitry (Trip
Circuits) (UFLS/UVLS Systems Only) – Interval is okay, but we disagree with tripping the
breakers – proving the output of the relay should be sufficient. Systems that have all load shed
on distribution circuits should require trip output be confirmed but should not be required
through to the trip coil due to constraints in tying distribution load. • Station dc supply (that has
as a component any type of battery) – 3 month and 18 month intervals are probably okay,
depending on what is required to “verify continuity and cell integrity of the entire battery” and
“inspect the structural integrity of the battery rack”. • Station dc supply (that has as a
component Valve Regulated Lead-Acid batteries) – 3 calendar years and 3 month intervals are
probably okay, depending on what is required for the “performance or service capacity test”. •
Station dc supply (that has as a component Vented Lead-Acid batteries) – 6 calendar year and
18 month intervals are probably okay, depending on what is required for the “performance,
service or modified performance capacity test”. • Protection system communication equipment
and channels – 3 months and 6 calendar years seem reasonable, depending upon what is
included in the substation inspection, and what is required for power-line carrier systems. • UVLS
and UFLS relays that comprise a protection scheme distributed over the power system – Can’t
comment on the 6 calendar year interval until we get more clarity regarding the meaning of
“distributed over the power system”.
No
For utilities like us with large numbers of relays it’s too complicated, which drives us back to
Table 1a.
No
For utilities like us with large numbers of relays it’s too complicated, which drives us back to
Table 1a.
Yes
We strongly believe that this document should be made a part of the standard, either as an
Attachment or worked into the requirements and tables. This will bring clarity to PRC-005 that is
needed to get away from all the past problems that were due to a lack of clarity with the
previous PRC-005 standards. Also, all the explanations and guidance lose force if they are not
part of the standard. Auditors will only be bound by the standard.
Yes
We strongly believe that this document should be made a part of the standard, either as an
Attachment or worked into the requirements and tables. This will bring clarity to PRC-005 that is
needed to get away from all the past problems that were due to a lack of clarity with the
previous PRC-005 standards. Also, all the explanations and guidance lose force if they are not
part of the standard. Auditors will only be bound by the standard.
None
Regional Variance
Regions with ISO’s and RTO’s - Where the independent system operator (ISO) is not the same
company as the entity doing testing and maintenance, the independent system operator could
prevent the entity from performing scheduled maintenance and testing due to outage request
constraints. There should be no violation in such a situation, and the maintenance and testing
just rescheduled.
• Regarding the Implementation Plan, R1 compliance should be the first day of the first calendar
quarter 18 months following applicable regulatory approvals. Entities will need this time to
change monitoring equipment and develop extensive new work practices and procedures to
assure time frames and documentation of practices comply with the wording of the revised
standard. The time frames for R2, R3 and R4 are adequate except in cases where upgrades have
to be developed and implemented in order to be able to meet the intervals (such as breaker trip
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coil verification every three months). • FAQ 2C “If I am unable to complete the maintenance as
required due to a major natural disaster, how will this effect my compliance with the standard.”
Response is the Compliance monitor will consider extenuating circumstances…We would like to
see this statement clarified as to the time frame extensions that result in non compliance or
fines. • R4 – States “each transmission owner…shall implement its PSPM, including identification
of the resolution of all maintenance correctable issues”. If the intent is to document resolution to
misoperations this is a reasonable request. If the intent is to document that a relay was found
out of calibration on a routine test, which was corrected by recalibration we need some clarity on
expectations of how that would be recorded and tracked. As written this statement is vague and
somewhat confusing since % of allowable error may vary utility to utility. • R4 doesn’t appear to
allow any time beyond the stated intervals for repairs or replacements that may take additional
time. PRC-005-2 is a maintenance and testing standard, and R4 inappropriately requires a
replacement strategy and an obsolescence strategy. Is R4 intended to apply to all equipment in
Table 1?
Individual
Bob Thomas
Illinois Municipal Electric Agency
Yes
No
The Illinois Municipal Electric Agency (IMEA) is concerned the minimum maintenance activities
may be too prescriptive for transmission subsystems that essentially operate radially. Please see
comment under Question 7. Also, IMEA supports comments submitted by Florida Municipal Power
Agency regarding applicability to UFLS systems.
No
IMEA is concerned the maximum allowable maintenance intervals may be too prescriptive for
transmission subsystems that essentially operate radially. Please see comment under Question 7.
Given the magnitude of reliability-related initiatives currently in progress, additional time is
needed to evaluate these intervals, particularly for communications equipment, dc supply, and
UFLS relays.
No
IMEA supports comments submitted by Florida Municipal Power Agency regarding use of the word
“every” in Table 1c.
No
IMEA supports comments submitted by Florida Municipal Power Agency that the process outlined
in Attachment A is biased towards larger utilities.
No
Yes
Under “Group by Type of BES Facility”, 1. (page 15) – The radial exemption in the BES definition
should be clarified to include transmission subsystems within a single municipality, where the
transmission facilities – serving only subsystem load with one transmission source - essentially
operate radially. A more practical application of the radial exemption would address smaller TOs
whose system has minimal potential to impact the BES as a whole.
Individual
Scott Barfield-McGinnis
Georgia System Operations Corporation
Yes
Yes
Yes
Yes
Yes
No
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No
Not aware of any.
None.
None.
Group
Public Service Enterprise Group Companies
Kenneth D. Brown
Yes
No
1) Table 1a – Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only).
Currently, we test our UFLS relays on a 2 year maintenance interval. We test the relays and
associated DC circuitry up to the DC lockout relays. It would require extraordinary effort to trip
the breakers directly when performing these tests. Usually, each UFLS relay will trip several
feeder breakers. This requirement states that we need to check the trip coil for each of those
breakers each time we perform relay maintenance. This will add an unreasonable amount of time
and effort to reliably switch out several 4kV or 13kV feeder every time we perform UFLS
maintenance. For UFLS and UVLS schemes, we feel the requirement for DC control testing should
not go past the lockout relay. The standard says to perform trip checks at the same time as UF
maintenance. We test the relays on a 2 year interval right now. It is unreasonable to perform
trip checks this often. The trip checks should follow a 6 year span (or longer) just like the BES
equipment. 2) Table 1a – DC supply. The 18 month inspection requires a measurement of
specific gravity and temperature. We believe that if a battery owner opts to perform an 18
month ohmic value test, this combined with the cell voltage readings and continuity tests will
give a good indication of battery health. We do not feel that the measurement of specific gravity
is required in conjunction with the tests performed above.
No
1) Table 1a – Station dc supply (that uses a battery and charger). The 6 year test requires that
the charger perform as designed. PSE&G usually applies redundant battery chargers. PSE&G
would like the drafting team to consider if it is appropriate to not require the 6 year battery
charger tests if a battery owner uses primary and backup battery chargers. PSEG believes that
the use of a redundant charger will maintain reliability at the same level or better level as
provided by testing a single charger. 2) For protection system control circuits components
(breaker trip coil only), suggest that a sub category with redundant trip coils be added with
longer maintenance interval to allow for the reliability provided by redundancy.
Yes
Figure 2 “typical generation system” shows a typical auxiliary medium voltage bus, suggest that
a line of distinction (dotted line) be added to the figure that defines the element connected to
the BES (station Aux Transformer - SAT) and equipment not associated with protection of the
SAT be shown as not part of the BES- PSMP.
Yes
1) R1 - PRC-005-1 required the protection owner to supply a “basis” for the chosen maintenance
intervals. Is it intended that the new standard will no longer require the protection owners to
provide a basis for their intervals as long as they meet (or better) the published required
intervals? 2) Compliance 1.4 Data Retention – Needs more clarity. Some items require 12 years
maximum maintenance interval. However, we may perform the same maintenance in 6 years.
The requirement for data retention is 2 maintenance intervals. In this example, does this mean
12 years or 24 years? Are we required to maintain records for the maximum maintenance
intervals allowed by the Standard or only for the two shorter maintenance intervals that we
actually use? 3) Compliance – will need some guidance on to what is required for “proper
documentation”. Generally, the relay technicians will scribe the actual test values for a given
tests requiring the application of AC voltage and current. However, as an example, when
performing DC checks (DC aux relay), the technician may simply state that the aux relay is “OK”
without stating the DC coil pickup value in volts. Is this acceptable? Another example may be
when performing battery inspections (ie verify proper voltage of station battery, verify that no
DC grounds exist, etc), the inspector may simply indicate/document that the battery is “Ok”. This
would indicate that appropriate 3 month inspections (as per table 1a) were completed and found
to be within tolerances. Is this acceptable? If specific details are required to be stored on test
media (paper test sheets, computer based data storage, etc), then please make some comments
as such. 4) Table 1a – DC supply. The 3 month inspection requires “verify that no dc supply
grounds are present”. This needs further clarification. What is the defined “limit” to determine
whether we have a DC ground? The detection methods for determining the presence of a DC
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ground will vary from indicating light balance to actual DC ammeters or voltmeters. It is
assumed that the intent of this requirement is to ensure that there are no full DC grounds (dead
shorts) in the DC terminals. Please clarify. 5) In the group by type of BES facility descriptions on
pages 15 and 16 there is discussion about generation station auxiliary transformers and
associated protection devices. It also cites examples of relays which need not be included even
though they could result in tripping of the generating station. The line of demarcation is not well
defined in the FAQs or in the standard itself. Suggest that verbiage be added that clearly defines
the element (transformer) directly connected to the BES and it’s associated protection is what is
included in the PSMP requirements, items connected at lower voltage (down stream) are not
within the PSMP requirement. 6) On page 15, the sample list of what is included in the standard,
suggest that the list be expanded to show what is not included (a relay that monitors parameters
and is used for control/ alarm but not protection); generator excitation controls that trip an
auxiliary exciter. The list of items not included in the PSMP but that could trip the unit should be
further defined and expanded.
1) R4 requires all maintenance correctable issues identified as part of a time based maintenance
plan to be resolved in that same maintenance period. This places a burden on some items (for
example, 3 month battery inspections) to achieve adequate resolution for problems that are not
an immediate threat. For example, if a battery with a somewhat out of allowable range specific
gravity is found near the end of the maintenance period, scheduling and performing the work to
replace the battery could reasonably extend somewhat beyond the end of maintenance period.
PSE&G requests that the drafting team revisit this requirement and allow flexibility for
corrections to be made within a specified reasonable timeframe when correctible issues are
identified that for practical reasons require extension for work completion beyond the end of the
current maintenance interval. 2) Section 4.2.5.5 of the standard should define provide an
example that just the transformer connected to the BES is included and specifically exclude
connected equipment beyond the LV terminals. 3) Draft implementation plan for requirements
R2, R3 & R4 discusses table 1a as basis, should also address tables 1b and 1c.
Individual
Jianmei Chai
Consumers Energy Company
Yes
No
The second sentence in Note 1 on page 20 should be changed to “A calibration failure is when
the relay is inoperable and cannot be brought within acceptable parameters.” Note 2 should be
changed to “Microprocessor relays typically are specified by manufacturers as not requiring
calibration. The integrity of the digital inputs and outputs will be verified by applying the inputs
and verifying proper response of the relay. The A/D converter must be verified by inputting test
values and determining if the relay measurements are correct.”
No
The interval for Protection System Control Circuitry (breakers trip coil) should be set at 12 years
since this is a scheme test. This test requires testing of the circuit and not just the coil. The
interval for Protection System Control Circuitry (trip circuit) should be set at 12 years since this is
a scheme test. The Protection System Control Circuitry (trip circuit) test would require tripping
off customers on radial distribution circuits which is not acceptable. The interval for a station
battery service test (lead acid) should be set at 5 years based on NFPA 70B.
In Table 1a for Station dc supply it requires verification that no dc supply grounds are present.
DC grounds are common occurrences and the activity should be to document if dc grounds are
present. Please specify how cell to cell connection resistance is measured. For station dc supply
(battery is not used) change “Verify the continuity of all circuit connections that can be affected
by wear and corrosion” to “Inspect all circuit connections that can be affected by wear and
corrosion.” Is “metered and monitored” equivalent to “alarming”? If a component failure causes
the unit to trip, what is the purpose of testing it? It will always test positive until the point of
failure and that point is identified when the unit trips. In the Facilities Section 4.2.5.4 “station
service transformer” should be changed to “unit connected auxiliary transformer” to be
consistent with Figure 2 of the Supplement Reference Document. Facilities Section 4.2.5.5 should
also include “System connected auxiliary transformers are excluded when only used for unit
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start-up.” There should be an allow variance period (grace period) for the testing intervals. The
maximum allowable time periods should be in calendar years, defined as “occurring anytime
during the calendar year.” The following statement should be added to Requirement 1.2:
“Identification at a program level is permissible if all components use the same maintenance
method.”
Individual
Vladimir Stanisic
Ontario Power Generation
Yes
Yes
Yes
Yes
Yes
No
A well prepared and useful document.
No
It was a good idea to prepare such a document.
Not aware of any
Regional Variance
Maintenance activities, and especially intervals, prescribed in NPCC Directory 3 (Maintenance
Criteria for BPS Protection) often differ from those in PRC 005 - 02. We recommend that NPCC
aligns Directory #3 with PRC 005 - 02 as much as possible. Technical justification should be
provided for any variance.
We note that Verification of Voltage and Current Sensing Device Inputs to Protective Relays is a
somewhat ambiguous activity. NERC’s audit observation team came up with a similar finding.
The supporting documents provide some clarity but in our opinion it would be helpful if the SDT
could elaborate this activity in more detail in the Table itself.
Group
Bonneville Power Administration
Denise Koehn
Yes
Yes
Yes
Yes
Will this document be a part of the standard? Are its explanations the official interpretation of
the standard?
Will this document be a part of the standard? Are its explanations the official interpretation of
the standard?
1. Tables 1a, 1b, and 1c were cumbersome to use because we found ourselves flipping back and
forth to compare the requirements for the different levels of monitoring. Also, in some cases, the
types of components were slightly different between the tables, which created confusion. We
believe that it would be much easier to decipher a single table that listed each type of
component only once and showed the requirements and maintenance intervals for the different
levels of monitoring on a single page. Even if it took an entire page for each component, it would
be very useful to see all of the options for that component without having to flip back and forth
between tables. 2. Please clarify the requirements for trip coils. Table 1a has as a component
type "breaker trip coil only", with a maximum maintenance interval of 3 months, while Table 1b
has as a component type "trip coils and auxiliary relays". Table 1b say that there are no
monitoring attributes for this component and to use the level 1 intervals, but then gives a
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maximum maintenance interval of 6 years, which doesn't agree with the 3 month interval given
in Table 1a. 3. The terminology used to describe the secondary currents and voltages provided to
the relay is confusing. Under the modified definition of a protection system, it includes the term
"voltage and current sensing inputs to protective relays", and in the tables it uses the term
"current and voltage circuit inputs". These terms, especially the use of the word input, give the
impression that the actual input circuitry of the protective relay is what is being described, but
we believe that these terms are really meant to describe the secondary currents and voltages
from the instrument transformers (or other devices). BPA suggests revising the terminology to
describe the secondary currents and voltages. For example, in the maintenance activities section
of the tables, you could say, "Verify that the secondary current and voltages provided to the
relay are correct". 4. There is no mention to what the thresholds are when performing these
maintenance activities or what corrective actions must take place and by when they need to be
carried out. Is this something we should expect to see soon? 5. The need to measure the
cell/unit internal ohmic value every 18 months can be argued. BPA’s Substation Maintenance
crew performs these measurements once every 24 months and with the Operators monthly
inspections, we have been able to effectively catch any problems before a severe event/failure.
6. Communications: It is not clear specifically what equipment is included in "communications".
The test interval of 12 years in table 1b is too long to verify continued proper operation of
transfer trip tone equipment. Monitoring the presence of the channel does not provide any
indication of whether the equipment can initiate a trip. Consequently, a required minimum
interval of 12 calendar years is too long and does not do anything to verify proper
communications support of the relay scheme. A shorter interval of 6 years, such as that in table
1a makes more sense from a functionality standpoint.
Individual
James H. Sorrels, Jr.
AEP
Yes
No
In the process of performing maintenance, some protection systems may need to be taken out of
service on in-service equipment (bus differential protection for example) where redundant
protection systems do not exist. This action seems counter to NERC recommendations,
presenting a scenario for expanding outages during a simultaneous fault. Would the
implementation plan include time for the additions of redundant protection systems? Comments
expanded in question 10 response.
No
The availability to perform maintenance of many protection systems is dictated by the load or
customer that is connected. Many of these industrial customers, who are outside the jurisdiction
of NERC requirements, operate 24X7 and see the outages required for maintenance as a
nuisance and a loss of revenue. How can the owner be held non- compliant for not meeting the
intervals when they may not control the timing? Comments expanded in question 10 response.
No
How would the failure of a SCADA system affect the ability to take advantage of monitoring?
Yes
Although helpful in understanding and clarifying intent, the requirements of a standard should be
clearly written so that multiple, lengthy supporting documents are not needed. These supporting
documents do not get recorded into the registry as part of the standard and may or may not be
used by auditors during compliance audits which could lead to different interpretations.
Yes
Although helpful in understanding and clarifying intent, the requirements of a standard should be
clearly written so that multiple, lengthy supporting documents are not needed. These supporting
documents do not get recorded into the registry as part of the standard and may or may not be
used by auditors during compliance audits which could lead to different interpretations.
No known conflicts.
No none regional or business practice variances known.
Monitoring and tracking the activities prescribed in the standard seem too complex to manage at
a level needed for auditable compliance. The activities prescribed seem to lean toward
conventional protection systems and do not take into account newer special technology devices
(High Voltage DC, Static Var Compensator and Phase Shifting transformer controls) and how
there are to included. R1 1.2 Does the draft standard require a basis for an entities’ defined time
based maintenance intervals or can an entity just move directly to the intervals prescribed and
use the standard as its basis? R4. This requirement seems to refer to failed equipment and its’
reporting. This corrective maintenance activity is outside of the interpreted preventative
maintenance theme of the standard and adds another layer of complexity in compliance data
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retention. It also implies that a failed piece of equipment or segment could remain failed for the
entire maintenance interval. Tables 1a & 1b. Station dc supply (that has as a component any
type of battery) Interval: 18 months This requirement incorporates specific gravity testing
(where applicable). Although (where applicable) is not defined, it seems it refers to all nonsealed batteries. For sealed batteries, a more frequent internal ohmic test is prescribed. The
same 18 month requirement incorporates ohmic testing which is essentially equivalent to specific
gravity. Specific gravity and measure of internal temperature are invasive tests which subject
personnel to handling acid and subject the battery to damage. If the logic for sealed batteries is
to do more frequent ohmic testing why not allow more frequent ohmic testing as a substitute for
specific gravity? We would suggest ohmic testing every 6 months with any questionable results
rechecked using specific gravity. This eliminates excessive intervention into all cells and gives a
validity check on the ohmic testing. For Ni-Cad the performance service test has no option (6
year intervals). Typically, the Ni-Cad can yield a low voltage indication; however testing the cells
in pairs allows testing and finding bad cells. Why not offer a more frequent ohmic test for the NiCads? Facilities 4.2.1 and R1 ‘…. applied on, or are designed to provide protection for the BES.’
This may be in conflict with Regional Entity (RE) BES definitions. There needs to a clear
understanding of what is included and what is not without regional differences. There should be
no responsibilities or requirements of the RE. BES also takes on different meanings depending
upon which of the many standards it is applied. Data Retention 1.4 Data retention for two
intervals could mean that records would need to be kept for 24 years. This seems impractical.
Could audit evidence be used in lieu of actual data for long intervals? Tables: Where the interval
is in months, the term ‘calendar’ months should be used for clarification. Table 1a ‘….verify the
continuity of the breaker trip coil…..’ The SDT assumed that Trip Coil Monitoring (TCM) could be
accomplished by verifying/inspecting red lights. This may be true in most cases, but there are
designs that do not incorporate this type of TCM and the breaker would have to be exercised
every 3 months if not operated by natural events unless the scheme gets replaced. This seems
counter productive to the reliability of the BES. The implementation plan does not take the time
required for upgraded systems into consideration. Table 1a DC Supply, 3 month interval ‘Verify
no dc supply grounds are present.’ Does this mean that you are non-compliant if you have a DC
ground? This also needs to be clarified as to the amount of acceptable ground that could be
present. Table 1a PS communications equipment channels 3 month interval: Do the activities
imply that only alarms be verified and that no channel ‘playback’ be performed? If SPR relay or
similar auxiliary relay is excluded as a protective relay, then do we not have to verify its tripping
contact as part of the DC system? Table 1a The exclusion of UVLS/UFLS from certain activities is
confusing. Does trip coil monitoring not have to be performed on these systems? Tables: Since
PT and CT devices themselves are not included in the PS definition, then the word ‘devices’
should be removed from the type of component column describing inputs to the relay. Table 1a.
Even though an entity may be on time-based intervals, would a natural occurring fault event
reset the maintenance clock for the protection segment involved? Assessment of Impact of
Proposed Modification to the Definition of Protection System: Reclosing and certain auxiliary
relays have been excluded from protection system definition. This new definition would have an
impact on other PRC standards that use this term in its requirements, specifically the
misoperations investigation and reporting standards. These other standards, as written today,
are not clearly written as to the application and assumptions as to what is included in a
protection system. Trip coil Monitoring: If the trip coil is actually part of the DC circuitry, then
why is there a differing (shorter) interval for this series connected element?
Individual
Jason Shaver
American Transmission Company
Yes
No
The Standard should focus on identifying the types of components to be tested but should not
identify the specific maintenance activities that must be performed. Entities should be allowed
the flexibility to develop and implement the appropriate maintenance activities necessary for
each identified component. ATC is also concerned with the expressed identification of
maintenance intervals. We do not believe that the standard should identify specific maintenance
intervals but that it should require entities to identify their maintenance intervals appropriate for
their system. If the team continues to pursue specific maintenance intervals it will be
establishing the industries practices. Specific Concern: The standard identifies that entities
should perform complete functional testing as part of its maintenance activities, but we are
concerned that this could lead to reduced levels of reliability, because it requires entities to
remove elements from service and then requires entities to perform tests that are inherently
prone to human errors. We believe that the perceived benefits do not match the anticipated
costs or improve system reliability.
No
ATC is concerned that the proposed standard would result in entities being required to use
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outdated testing techniques and or practices. We believe that the standard should identify the
“what” and not the “how”. The identification of specific testing techniques and/or practices would
likely result in entities being prevented from implementing improved techniques and/or practices.
(The standard would have to be updated and receive FERC approval before entities could
test/implement improved testing techniques and/or practices.) And example of the standard
directing the how is with station batteries. The “specific gravity” test, proposed in the standard,
is being used less or not at all by some registered entities because a more accurate method that
is less intrusive and provides more accurate results has been developed. (This standard would
basically require entities to go backwards in testing practices.) This standard should not prevent
the use of improved techniques and/or practices.
No
ATC does not believe that there is a relay, on the market today, that has the ability to fully
monitor itself as described in Table 1c. We believe that Table 1c should be deleted. (Table 1b
could cover any device that has the ability to fully monitor if such a device is developed in the
future.) ATC does not believe that NERC Reliability Standards should be used as an enticement
for manufacturers to develop specific devices. Under the “General Description” in Table 1c, there
is a reporting requirement identifying a 1 hour window. (“… must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to the location where action can be taken.”)
ATC believes that the team needs to define if this action is a phone call or physically verify the
maintenance correctable issue which is occurring.
No
ATC agrees with this approach but is concerned that Attachment A does not contain enough
language to support an entity that implements this practice. This attachment needs to clearly
state that following your performance-based maintenance practices satisfies an entity’s
compliance obligations. Entities should not be subject to non-compliance over disagreements
with their performance-based maintenance methodology.
No
No
Overall, the FAQ’s are helpful. Explanations for questions dealing with the maintenance activities
(e.g., battery testing) indicate an attempt to line up the requirement with IEEE standards. While
commendable to attempt alignment with the industry, it is further justification that maintenance
activities should not be included in the standard. Over the long term, technology or IEEE
standards could change making the compliance standard inconsistent.
Order 672 says that standards should be clear and unambiguous This proposed standard is very
complex. While the standard allows entities to select the appropriate maintenance strategy (time
based, performance based or conditioned based) for their system the amount of data and
tracking required to demonstrate compliance will be overwhelming.
Business Practice
Jointly-owned facilities should be a component of this standard. Comments: ATC shares services
at Substations; consider dividing the services, i.e. batteries and PTs.
General Comment: The requirements section of the standard seems acceptable. NOTE: Why does
R1.3 identify the inclusion of batteries? We believe that this should be part of the definition. We
believe that the team needs to define the term “condition-based”. Does the Protection System
definition in PRC-005-2 or interpretation of the standard and the tables line up with other NERC
Standards? The table formats (1a through 1b) are confusing and should be reconsidered. We
found is difficult to relate one table to another. (No consistency in the Type of components)
Individual
Edward Davis
Entergy Services, Inc
Yes
Yes
No
A 3 month interval activity is likely to drive an entity to perform that activity every 2 months in a
zero tolerance, 100% completion, mandatory compliance environment. There should be an
allowance for a grace period on monthly designated activities, for instance a one month grace
period, unless the intention is to have the activity performed more frequently than indicated.
Additional guidance is needed on the monthly interval designations. Is it okay, for instance, to do
all four tasks (3 month interval) at one time? Instinctively the answer should be "no", but if
following the "calendar year" allowance, then maybe it is. Are we non-compliant on a 3 month
interval task if we go one single day over the due date? Instinctively the answer should be "no",
but some additional guidance should be provided. For example, the standard might be more
understandable if it indicated that if the interval is "four per year" (or 3 month interval), then it
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is allowed to perform these tasks no less than 45 days apart from each other as long as four are
done within a calendar year, etc. We believe the 3 month trip coil task activity could actually
shorten the life of the trip coil, introduce unpredictable trip coil failures, and increase the risk of
an in-service failure of the trip coil if the verification is done by tripping the breaker each time.
Increasing the risk of failure is counter-productive the intent of the standard.
Yes
Yes
No
Regarding Section 2.3, Applicability of New Protection System Maintenance Standards, there
needs to be clarification and examples of applicable relaying associated with the language: “…
and that are applied on, or are designed to provide protection for the BES.” For example, is the
application of reverse power schemes and directional overcurrent schemes considered applicable
when considering the impact to the protection of the BES? We agree with the application of the
term “calendar” in the PRC-005-2 Protection — System Maintenance Supplementary Reference
document. There should be enough flexibility in interval assignments to allow for annual
maintenance planning, scheduling and implementation.
Yes
It would be beneficial to also include an explanation or definition of the term “calendar year” in
the standard. It is not readily apparent in the draft standard, especially in light of the new
maximum interval requirements, that a task can be performed anytime between 1/1 and 12/31.
Although addressed in the FAQ and Supplement, the terms “Upkeep” and “Restoration” are
referenced in the definitions section of the standard but are not used anywhere else in the
document, or with regard to routine activities. They should be eliminated from the standard
unless there are upkeep or restoration requirements.
Individual
W. Guttormson
Saskatchewan Power Corporation
Yes
Saskatchewan would like clarification of what the expectations and rationale are for including
Restoration in the PSMP. The other terms listed under the PSMP definition represent what we
would consider as typical relay maintenance activities. We would typically consider Restoration as
an Operational activity. The existing NERC standards seem to treat this an Operator concern
addressed in PRC-001 R2.1 and R2.2 (The Operator shall take corrective action as soon as
possible). If Restoration is included in PRC-005 doesn't PRC-001 have to be modified as well to
remove these references? Saskatchewan would also like clarification on the term upkeep. Is the
standard prescriptive and mandate the application of the latest firmware upgrades within a
defined period, or is it flexible and can upgrades be applied as the utility deems necessary?
Yes
Yes
Yes
No
Saskatchewan agrees with the approach, but requires clarification in the definition of segment.
The definition uses a population of 60 or more individual components but in the establishment of
a PSMP, it only asks for a population of 30 or more. Which number will be used to define the
segment?
Yes
The supplementary reference document is useful information if properly explained and justified.
Are the suggestions in the reference document to become part of the standard, or simply
recommendations of best practice from industry and serve as a document to reduce the number
of interpretations requested?
Yes
The FAQ section is beneficial, but would suggest reviewing it to determine if it can be integrated
within the reference document.
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Saskatchewan recommends that the PC's and RC's designate what equipment is applied to
protect the BES and should be included in the protection maintenance program. It is questionable
whether the facility owners or Distribution Providers will know. What are the impacts on the BES
from the protection systems identifed in Facilities 4.2.5 and the FAQ? For example there is an
impact on the BES from generator under-frequency protection not being properly coordinated,
but assuming it is and if it is not maintained isn't the impact to the unit itself? Inadvertent
energization protection also seems to be an impact to the unit itself not the BES? The standard
should be concerned with protection systems that impact the BES not equipment protection that
has localized impacts however important they may be. Change Facilities 4.2.2 to “Protection
System components used for under-frequency load-shedding systems which are installed to
prevent system under-frequency collapse for BES reliability.” The reference to ERO is
unnecessary and inappropriate.
Group
FirstEnergy
Sam Ciccone
Yes
Although we agree with the change in the title of the standard, as well as the proposed definition
of "Protection System Maintenance Program", we feel that the definition could be clarified. With
regard to "Restoration", which at present is described as "The actions to restore proper operation
of malfunctioning components", it may be helpful to add examples of acceptable actions to
restore operations, such as calibration, repair, replacement, etc.
No
In general we agree with the maintenance activities, except for the specific gravity and
temperature testing included in the "Station dc Supply (that has as a component any type of
battery)" of the tables 1a and 1b. We only perform this testing at nuclear facilities for insurance
requirements. In transmission substation applications it has been eliminated due to the
variability of results due to recharging/equalizing, water addition, temperature correction
requirements, etc. In the Supplementary reference, section 15.4 Batteries and DC Supplies, third
paragraph, the SDT indicates these tests are recommended in IEEE 450-2002 to ensure that
there are no open circuits in the battery string. This is essentially a continuity check of the
battery string. In the fourth paragraph, the SDT states that "…"continuity" was introduced into
the standard to allow the owner to choose how to verify continuity of a battery set by various
methods, and not to limit the owner to the two methods recommended in the IEEE standards."
The SDT in Table 1a, the Maintenance Activity "Verify continuity and cell integrity of the entire
battery", and in Table 1b, the Maintenance Activity "Verify electrical continuity of the entire
battery". Based on the information in the Supplementary reference, the owner has to choose a
method to verify continuity and the measurement of specific gravity and cell temperatures could
be the selected method, however it should not be a required maintenance activity as shown in
Tables 1a and 1b.
No
Although we agree with the proposed maintenance intervals, there may be extenuating
circumstances beyond an entity’s control that could delay maintenance on a particular protection
system. We ask the SDT to consider adding a footnote to these intervals that allows a grace
period of up to three months when outages necessary for maintenance must be delayed due to
unusual system conditions or other issues where an outage would be detrimental to the entity's
system.
Yes
Yes
Although we agree with the parameters of the proposed PBM, we have the following comments:
1. We question the inclusion of misoperations in countable events as described in footnote 4.
Since standard PRC-004 already requires analysis and mitigation of Protection System
Misoperations through a Corrective Action Plan, entities should not be required to repeat this
analysis and mitigation in PRC-005. We ask that the SDT clarify the requirements to allow a tie
between PRC-005 and PRC-004 so as to assure work is not duplicated. 2. We are not receptive
to using this methodology to develop intervals due to the detailed tracking and analysis that will
be required to establish maximum intervals. The approach may suit other utilities and thus, we
are not opposed to the methodology being contained within the standard.
Yes
1. Sec. 2.3 (pg. 4) – This section appears to be discussing the purpose of the standard and not
the applicability. We suggest changing the title of Sec. 2.3 to "Purpose of New Protection System
Maintenance Standard." Also, in Sec. 2.3 it states: "The applicability language has been changed
from the original PRC-005: '... affecting the reliability of the Bulk Electric System (BES) ...' To
the present language: '... and that are applied on, or are designed to provide protection for the
BES.' However, the posted Draft 1 of PRC-005-2 still has the original Purpose statement. Is the
SDT planning to revise the Purpose statement as discussed in Sec. 2.3 of the Ref. document? It
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appears that this statement is included in the applicability section 4.2.1 but believe it is more
appropriate as a general purpose statement applying to the whole standard. 2. Sec. 2.4 (pg. 4) –
Remove the extra word "that" from the second sentence of this section. 3. In the Supplementary
reference, section 15.4 Batteries and DC Supplies, third paragraph, the SDT indicates these tests
are recommended in IEEE 450-2002 to ensure that there are no open circuits in the battery
string. This is essentially a continuity check of the battery string. In the fourth paragraph, the
SDT states that "..."continuity" was introduced into the standard to allow the owner to choose
how to verify continuity of a battery set by various methods, and not to limit the owner to the
two methods recommended in the IEEE standards." The SDT in Table 1a, the Maintenance
Activity "Verify continuity and cell integrity of the entire battery", and in Table 1b, the
Maintenance Activity "Verify electrical continuity of the entire battery". Based on the information
in the Supplementary reference, the owner has to choose a method to verify continuity and the
measurement of specific gravity and cell temperatures could be the selected method, however it
should not be a required maintenance activity as shown in Tables 1a and 1b.
Yes
Pg. 17 (What forms of evidence are acceptable) – Although Measures are not yet developed and
posted with the standard, we wanted to point out that the SDT should consider adding these
acceptable forms of evidence in the measures of the standard.
1. BES reclosing schemes were recently questioned in a PRC-005-1 interpretation but there is no
mention of reclosing schemes in the draft standard. This interpretation should be integrated into
the requirements of PRC-005-2. 2. Lack of Exception Process - The standard as written does not
reflect the fact that any one group, such as a TO performing maintenance on a BES, does not
have full control over when an outage can be taken to perform maintenance activities. Especially
regarding functional testing, where the equipment needs to be exercised resulting in some BES
components being de-energized, it can be very difficult in certain parts of the T&D system to
obtain the necessary outage to complete these tasks. Even with proper planning, changes in
system conditions and unforeseen equipment problems in other areas can impact the ability to
schedule an equipment outage appropriately. Accordingly, a TO can be penalized for not
completing prescribed maintenance within prescribed limits due to factors outside of their
control. This type of scenario has already been experienced where maintenance activities are
scheduled upwards of a year in advance, and then inclement weather or system conditions
outside of a TO’s service territory (e.g. unanticipated generating unit shutdown) prevent the
work from taking place. The standard should provide some specific guidance to allow relief for
such situations, or that properly incents or even requires independent system operators (ISOs)
and other outside groups to also ensure maintenance is completed within prescribed intervals. If
a TO properly considers factors such as weather (not scheduling critical outage during middle of
summer), resource commitment, schedule (the requested outage window is at least one year
before maximum interval is met), time of day (performing work during after hours period when
load is down) etc. then if outages are still denied, that the TO is not penalized for being out of
compliance as maximum intervals are exceeded. This suggested "exception process" should
provide requirements for all parties involved, both those performing the maintenance as well as
those controlling and overseeing the system. There should be required documentation to prove
that the parties on both sides made proper efforts to complete the required maintenance, as well
as discuss conflict resolution. 3. With regard to the phrase "including identification of the
resolution of all maintenance correctible issues" in Req. R4, we feel that this requirement should
be a subset of R4 since it is part of the implementation of the PSMP. We suggest removing the
phrase from the main requirement of R4 and creating a new 4.3 as follows: "4.3. For all
maintenance programs, identify resolutions for all encountered maintenance correctible issues
and take corrective action within a time period suitable for maintaining reliability of the affected
protection system." 4. With regard to the proposed modification of "Protection System", we
suggest adding the word "devices" after "voltage and current sensing". This would also match
what appears to be the SDT’s intended wording as shown in the Supplementary Reference
Document sec. 2.2. Also, we suggest modifications to the proposed definition to add clarity to the
types of communications system protection and the voltage and current sensing devices. The
following is our suggestion for wording of the definition: "Protective relays, communication
systems used in communications aided (or pilot) protection, voltage and current sensing devices
and their secondary circuits to protective relays, station DC supply, and DC control circuitry from
the station DC supply through the trip coil(s) of the circuit breakers or other interrupting
devices." 5. Protection System Communication Equipment and Channels - Some power line
carrier equipment has automatic testing and remote alarming and some that does not. For other
relay communication schemes (e.g., tone transfer trip ckts), if the circuit travels over our private
communications network (fiber or microwave radio), the communication equipment is remotely
monitored/alarmed. In other cases it is not remote monitored. We ask for clarification as follows:
As part of our maintenance program, we check that signal level, reflected power, and data error
rate are all within tolerance at the interface between the end equipment and the communication
link. Our question is: Does this meet the intent of the proposed requirements in PRC-005-2 for
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maintenance activities for Protection System Communication Equipment and Channels? Or do the
requirements ask for something beyond this? 6. We suggest combining 4.2.2, 4.2.3 and 4.2.4 to
read as a new 4.2.2 "Protection System components which are installed as a underfrequency
load shedding, underfrequency generation shedding, under voltage load shedding or Special
Protection System for BES reliability."
Individual
Alice Murdock
Xcel Energy
Yes
No
Regarding battery chargers, does the SDT propose that OEM-type tests be performed to validate
the rated full current output and current limiting capabilities? It has been proposed that simply
turning off the charger and allowing the batteries to drain for a period of several hours, then
returning the charger to service, will validate these items. It is not clear that an auditor would
come to the same conclusion, since it appears open to interpretation. Please modify to make this
clear. If an entity has an over-sized battery charger, they can (and should) only test to the max
capacity of the battery bank. Suggest changing “full rated current” to “designed charging rate”.
No
Within the tables, several components related to UFLS/UVLS systems have an interval of “when
the associated UVLS or UFLS system is maintained.” Yet, there is no maximum interval
established for a UVLS or UFLS system. We feel this item should be clarified. If the intent of the
SDT is to tie the testing to when the UFLS/UVLS relays are maintained, so that all components
are tested at the same time, then this should be made clear. One possible resolution would be to
change the interval to read: “when the associated UVLS/UFLS relays are maintained”.
Yes
Yes
Yes
The information in the supplementary reference document is very helpful and valuable. Yet, it is
not clear how the document would be managed/revised, nor what role it plays in compliance
monitoring. There needs to be a clear understanding if everything in the document is required for
compliance, e.g. criteria for monitored systems, etc. Additionally, we feel that evidence should be
addressed within the supplementary reference document.
Yes
The Frequently-asked Questions seem to act as interpretations to the standard. What roll will
they play in determining compliance? On table 1b (page 11) the UFLS and UVLS maintenance
activities indicate that tripping of the interrupting device is not required, but it uses the term
‘functional trip test’. The FAQ indicates that a ‘functional trip test’ does require tripping the
interrupting device. This conflicts with what is in the table and should be corrected in the FAQ to
reflect that no trip is required.
Please clarify if the following are subject to PRC-005-2 requirements: 1) a battery that is in a
station where the only BES element is a UFLS scheme 2) batteries used only to support
communication elements (microwave houses)
Group
NERC Standards Review Subcommittte
Carol Gerou
Yes
N/A
No
A. In the tables, the term “verification” should be switched with “check”. B. The verification
activities include testing for “specific gravity” in batteries. Since “impedance testing” will give you
the same results or similar results; revise the tables to reflect this, as well. C. Another question
deals with the table title verbiage. Table 1a and 1c are labeled as Protection Systems, while
Table 1b is Protection System Components. One could interpret table 1c as saying that if any one
component of the protection system in question is not in compliance with level 3 monitoring
stipulations, then every component must be degraded to level 2 monitoring as so forth. This
needs to be clarified. D. Some activities, such as complete functional testing, could lead to
reduced levels of reliability, because [1] it requires removing elements of the transmission
system from service and [2] it requires performing tests that are inherently prone to human
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errors. The MRO NSRS does not believe the perceived benefits justify the anticipated costs. E. In
the tables, under Table 1a and Protection system communications equipment and channels, a
technical justification should be provided to show that performance and quality channel testing
would result in the reduction of regional disturbances and blackouts. Quality and performance
testing is subjective. Subjective tests are inherently poor compliance measures. The
requirements to measure, document, store, and prove channel quality data is a poor use of
limited compliance resources. F. In the tables, under Table 1a and Station DC supply (and
anywhere else), equalize (battery) voltages should be eliminated. Equalizing battery voltages
reduces battery life and do not provide a significant gain in overall system reliability to offset the
loss of battery life. G. In the tables, under Table 1a and Station DC supply (and anywhere else),
delete the reference to measuring the fluid temperature of “each cell”. A technical basis should
be demonstrated that shows why individual cell fluid temperature measurement would reduce the
occurrence of regional disturbances. If fluid temperature measurement remains in the standard,
a single fluid temperature measurement per battery bank should be sufficient to demonstrate
that the battery bank was performing within normal parameters. The compliance burden to add
fluid temperature measurements for each cell is unwarranted and reduces compliance personnel
resources that could be utilized on more important reliability activities.
No
A. It looks like for unmonitored systems, breaker trip coils are to be checked for continuity every
3 months. There is no mention of auxiliary relays. In the partially monitored and fully monitored
sections, trip coils and auxiliary relays are lumped in the same category at 6 calendar years
each. What happened to the aux relays in the unmonitored section? Also, note that the term
"trip coils" is used, not "breaker trip coils" in the type of component category. B. The
maintenance interval for Protection System Control Circuitry (Trip coils and Auxiliary relays) is 6
years, but the interval for relay output contacts is 12 years when these components are partially
monitored. It seems that these things all have a similar reliability. If commissioning tests are
done diligently, the trip DC availability is continuously monitored and the trip coil itself is
continuously monitored, no functional tests should be needed. The only thing that would be done
at PM time would be to ensure that the alarming method is still functional.
Yes
A. The MRO NSRS agrees with this approach; however, I think most entities will not see the
advantage of condition-based maintenance until they can resolve any gaps in data retention. If
an entity was retaining a set of maintenance records but failed to include all the needed
information as specified in this standard so they would need to adjust their maintenance
procedure to collect all information and then they would need to wait for the entire retention
period until they could start using the extended maintenance interval. If an entity had a collateral
set of records which verified the information that lacked in the original maintenance record then
could the entity start using the extended maintenance interval? For example, an entity has
records showing that they have maintained a voltage or current transformer within the
prescribed maintenance interval listed in level 1 monitoring (which is a maximum 12 year
maintenance interval). Could this same entity go to level 3 monitoring (which is a continuous
maintenance interval) immediately if it can query their SCADA and produce detailed records
indicating the accuracy of the PT or CT for the maintenance records already retained? B. For
lockout relays, if commissioning tests are done diligently, the trip DC availability is continuously
monitored and the trip coil itself is continuously monitored, is it necessary to operate these
relays for functional testing? For breaker failure lockout relays, re-verifying the operation of the
coil and all the contacts could mean taking multiple breakers and line terminals out of service at
the same time. Functional trip tests could cause unintentional tripping of equipment, cause
equipment damage and interruption of service to customers. It's hard to see how the reliability
of the BES is significantly improved by doing this test. The MRO NSRS feels the risk of adverse
impact could be greatly reduced by a longer interval such as 12 years. C. In table 1c, the word
“continuous or continuously monitored” is used. Please clarify the “within 1 hour” time frame
takes into account that there may be a communication outage (failover) that will prevent an
entity to “continuously” monitor a device.
No
A. The MRO NSRS is concerned that this approach could lead to non-compliance if the company
follows this process and a Compliance Auditor disagrees with the method that was used. An
applicable entity should be protected if they follow the standard appropriately. There should be
some assurance of a grace period for mitigation if this selected approach was not accepted. B.
Please provide the basis for having at least 60, then taking 30 (50%) for testing/maintenance.
This may give an unfair advantage to larger companies rather than being fair across the board.
This places an undue burden on smaller companies by having to team up with other asset
owners.
No
N/A
No
Overall, the FAQ’s are helpful toward understand what the SDT was thinking. Explanations for
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questions dealing with the maintenance activities (e.g., battery testing) indicate an attempt to
line up the requirement with IEEE standards. While it is commendable to attempt alignment
reliability standards with other industry standards, it also begs the question of why requirements
that are already covered by other standards should be repeated in reliability standards. In
addition, if the other standards are changed, then they could become inconsistent with or
contradictory to the reliability standard.
Conflict: Order 672 says that standards should be clear and unambiguous.
A. In the applicability section 4.2.5.5, change the statement to say, “Protection systems for BES
connected station-service transformers for generators that are part of the BES.” B. In the
applicability section 4.2.5, change the statement to replace “are part of” with “directly connected
to”. The “are part of” will be left to interpretation. Please indicate the added reliability benefit by
collecting this in Table 1a Page 9 protection system communication equipment and channels. C.
If a breaker failure relay is also being used for sync-check, is it required to verify the voltage
inputs since they are used for a closing function and not a tripping function? It is understood that
the current inputs would have to be verified since these are used for breaker failure tripping. D.
Please clarify requirement R1-1.1, does one have to individually list out each Protection System
and its associated maintenance activities or can the PSMP be a generalized procedure that
covers each of the components in all of a utility's Protection Systems? E. All references to
breakers should be eliminated; thus, eliminate breaker trip coils. Breakers are primarily
mechanical in nature and should be excluded similar to mechanical relay systems such as sudden
pressure relays. F. Clarify that trip coils checks or tests can be verified through alternate means
other than physically tripping the coil or potentially requiring system outages to physically trip a
coil. Alternate tests could consist of checking self monitoring relays, continuity lights, etc. Trip
coil tests could require transmission line outages which can be denied by regulatory authorities
due to system conditions beyond an entity’s control. Significant delays of months or longer could
occur to obtain a transmission line outage. Further, potentially requiring transmission line
outages for trip coil test could harm BES reliability by increase the number of force transmission
line outages due to testing. System reliability could be significantly negatively impacted anytime
testing on trip circuits is performed due to human errors causing outages or regional
disturbances. G. One item R1.3 (inclusion of batteries) was questioned as why this was
specifically called out. It should be part of the definition. H. Define the term “condition-based”. I.
The format of the tables is poor with 17 line items addressed in each. It is difficult to relate one
table to another because they are not consistent with regard to the type of components. For
example table 1a references of components a “breaker trip coil (only)” and the 1b references
“trip coils and auxiliary relays”. J. R1.1 please add “… as they apply to the applicable entity”. As
stated now, all three tables must be accomplished. K. Please add the words “time based
maintenance methods” to table 1a for clarity in the heading. L. Table 1b under general
description, last sentence the word “elements” should be replaced with “maintenance activities”
which will provide exactly what is intended. M. Table 1b, if maintenance activities for level 2
monitoring include level 1 maintenance activities, then redundant activities in table 2 that are
contained in table 1 should be removed (the same for table 3 to table 2 to table 1). N. If an
entity maintenances a protective relay such that it is included in level 2 monitoring (a Condition
Based Maintenance program) and this relay is considered to have a maximum interval of 12
years, does the entity need to also perform the maintenance activities for level 1 monitoring
since the table 1b header indicates, “General Description: Protection System components whose
alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elements of level 1 monitoring with additional
monitoring attributes as listed below for the individual type of component?”
Group
Platte River Power Authority Maintenance Group
Deborah Schaneman
Yes
No
Minimum maintenance activites should be based on categorization of relays and defined
maintenance actions system by system using historical and definitively known data entity by
entity. By establishing specific minimum maintenance activities you risk entites changing
currently effective maintenance programs to programs that match minimum maintenance
activities to meet requirements in the Standard which could be less effective for their system.
No
Electro-mechanical relays are historically out of tolerance well before the 6 year maximum
allowable maintenance intervals defined witin table 1a.
Yes
Yes
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Yes
It isn't clear in the Supplementary Reference Document why lock-out relays (86) are included as
a component of Protection Systems that require a 6 year maximum interval. Historically we
haven't experienced any failures with lock-out relays and feel the risk of causing a system
reliabiliy issue by removing it from service and restroing it far out weghts the benefits of testing
it. What, if any evidence, i.e. equipment failure, does the standard drafting team use to mandate
routine testing of 86 devices? Are we fixing something that isn't broke here? The FERC order
directed NERC to submit a modification to PRC-005-1 that includes a requirement that
maintenance and testing of a protection system be carried out within a maximum allowable
interval that is appropriate to the type of the protection system and its impact on the reliability
of the BPS. It would seem more appropriate to allow each entity to set their own maximum
allowable interval based on studies and historical data of their specific protection system and
impact on the reliability of the BPS opposed to a blanket approach that covers all systems
regardless of their size or system confirguration.
No
Individual
Martin Bauer
US Buereau of Reclamation
No
The alteration of the program to include testing as a component does not add value to system
reliability. The existing requirement can only be completed with procedures that some of the
elements listed under the program. The proposed program is far too restrictive in the manner in
which it requires specific actions and thereby excludes others. The program element for
monitoring is listed; however, the monitoring is intended to be used through an electronic
subsystem and does not allow for observations by experienced technical staff. Testing is listed;
however, the definition is limited to the application of signals and precludes other procedures.
Further, the definition of Protection System proposed is a nested definition which tends to
expand the number of devices covered (any device that has voltage and current sensing inputs)
irrespective of their impact on the BPS.
No
2. The basis for developing the maintenance intervals was adequately explained. It is understood
that FERC would like uniform intervals; the intervals do not recognize the tremendous variation
in installation and equipment and possibly manufacturer recommendation. Point in fact is the
interval for listed for electromechanical relays. Some of these relays must be calibrated every
year or three years on the outside. Relays that have a history of stable performance based on
consistently good test results. The intervals for battery maintenance are not reasonable. The
capacity testing at 3 years is higher than the 5 year which battery manufactures require.
No
The definition of Protection System components does not add clarity. The standard proposes
including stations service transformers for generation facilities, however, the protection system
definition does not include those elements. The inclusion of station service transformers would
only be appropriate if the protection associated with the transformer results in the tripping of a
transmission element.
No
The condition based monitoring only provides for a very narrow process and excludes sound
judgment in determining maintenance intervals. As long as the registered entity establishes
parameters by which variation in the prescribed maintenance intervals are determined, justified
variation should be allowed.
No
The parameters established can only be implemented with documentation that defined in the
document but is not readily available.
No
6. The document will require revisions. Performance based maintenance is establishing a strategy
to achieve a desired performance. The document limits strategy to statistical analysis of failure
rates. The document assumes a modern protection system with a high level of monitoring.
Facilities which barely qualify would not have high end monitoring installed. The document also
refers to “exercising a circuit breaker through t relay tripping circuits using remote control
capabilities via data communication.” This repeated several times throughout the document as a
means of increasing the TBM. This function, if indeed used, would require maintenance. This
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function is very dangerous and could introduce a cyber vulnerability.
No
The significance of this issue is not relfected in the period of time needed to review the
documents. The supplement has many good ideas; however, the concept is going further than
needed for establishing consistent maintenance intervals.
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Consideration of Comments on Draft Standard Version 1 Protection System
Maintenance and Testing — Project 2007-17
The Protection System Maintenance and Testing SDT thanks all commenters who submitted
comments on PRC-005-2 — Protection System Maintenance standard. This standard was
posted for a 45-day public comment period from July 24, 2009 through September 8, 2009.
Stakeholders were asked to provide feedback on the Standard through a special electronic
comment form. There were 57 sets of comments, including comments from more than 130
different people from over 75 companies representing all of the 10 Industry Segments as
shown in the table on the following pages.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
The SDT proposed to change the name of the draft standard from “Protection System
Maintenance and Testing” to “Protection System Maintenance”, and to include testing as one
component of “Protection System Maintenance Program”, which will be a defined term. The
majority of stakeholders agreed with both the change in the name of the draft standard and
with the definition of Protection System Maintenance Program. Only two respondents
disagreed and their comments were addressed. Hence, the draft standard will now be
referred to as “Protection System Maintenance.”
Stakeholders generally disagreed with the minimum maintenance activities as well as the
maximum allowable intervals included in Tables 1a, 1b, and 1c in the draft standard. As a
result, the SDT made extensive changes to the standard and tables regarding the
maintenance activities, and made minor changes relative to the associated maintenance
intervals.
A majority of the respondents agreed with the general approaches regarding conditionbased and performance based maintenance programs but provided suggestions on
improving the clarity of the provisions within the tables and expressed concerns about
perceived administrative issues in establishing the programs. The SDT responded by
revising the tables to improve clarity and addressing the administrative concerns in its
responses to comments.
Stakeholders expressed appreciation for the “Supplementary Reference Document” and the
“Frequently-asked Questions” (FAQs) document. In its responses to the comments, the SDT
explained the relationship between the Standard and the two documents. Additionally, the
SDT addressed many of the comments in Questions 1-5 by developing additional FAQ
content, and referring the respondents to the FAQs document.
Most stakeholders were unaware of any conflicts between the proposed standard and any
business practices; however, a few commented that conflicts possibly existed with existing
business practices or with other organizations such as the Nuclear Regulatory Commission.
The SDT provided clarifying explanations to illustrate that conflicts are not actually present.
Stakeholders made numerous comments and suggestions resulting in substantial changes to
the draft Standard, the Supplemental Reference Document, the FAQs, and minor changes to
the draft Implementation Plan.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Index to Questions, Comments, and Responses
1.
The SDT proposes to change the name of the draft standard from “Protection System
Maintenance and Testing” to “Protection System Maintenance”, and to include testing
as one component of “Protection System Maintenance Program”, which will be a
defined term. Do you agree? If not, please explain in the comment area. ................ 11
2.
Within Table 1a, Table 1b, and Table 1c, the draft standard establishes specific
minimum maintenance activities for the various types of devices defined within the
definition of “Protection System”. Do you agree with these minimum maintenance
activities? If not, please explain in the comment area. ........................................... 18
3.
Within Table 1a, the draft standard establishes maximum allowable maintenance
intervals for the various types of devices defined within the definition of “Protection
System”, where nothing is known about the in-service condition of the devices. Do you
agree with these intervals? If not, please explain in the comment area. ................... 58
4.
Within Tables 1b and 1c, the draft standard establishes parameters for condition-based
maintenance, where the condition of the devices is known by means of monitoring
within the substation or plant and the condition is reported. Do you agree with this
approach? If not, please explain in the comment area. ........................................... 84
5.
Within PRC-005 Attachment A, the draft standard establishes parameters for
performance-based maintenance, where the historical performance of the devices is
known and analyzed to support adjustment of the maximum intervals. Do you agree
with this approach? If not, please explain in the comment area. .............................. 94
6.
The SDT has provided a “Supplementary Reference Document” to provide supporting
discussion for the Requirements within the standard. Do you have any comments on
the Supplementary Reference Document? Please explain in the comment area. ...... 102
7.
The SDT has provided a “Frequently-asked Questions” document to address anticipated
questions relative to the standard. Do you have any comments on the FAQ? Please
explain in the comment area. ............................................................................ 115
8.
If you are aware of any conflicts between the proposed standard and any regulatory
function, rule, order, tariff, rate schedule, legislative requirement, or agreement please
identify the conflict here. .................................................................................. 129
9.
If you are aware of the need for a regional variance or business practice that we should
consider with this project, please identify it here. ................................................ 135
10. If you have any other comments on this standard that you have not already provided in
response to the prior questions, please provide them here.................................... 140
June 3, 2010
2
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Group
Joe Spencer - SERC
staff
Additional Member
3
4
5
6
7
8
9
SERC Protection and Controls Sub-committee
(PCS)
Additional Organization
Ameren Services Co.
SERC
1, 3, 5
2. Rick Conner
E.ON Services Inc.
SERC
1, 3, 5, 6
3. Charles Fink
Entergy
SERC
1, 3, 5, 6
4. Phil Winston
Georgia Power Co.
SERC
1, 3, 5
5. Steve Waldrep
Georgia Power Co.
SERC
1, 3, 5
6. Jay Farrington
PowerSouth Energy Coop.
SERC
1, 3, 5, 6
7. Jerry Blackley
Progress Energy Carolinas
SERC
1, 3, 5, 6
8. Marion Frick
South Carolina Electric and Gas Co. SERC
1, 3, 5, 6
9. Bridget Coffman
South Carolina Public Service Auth. SERC
1, 3, 5, 6
10. George Pitts
TVA
SERC
1, 9, 3, 5
11. Ron Broocks
Va.Electric and Power Co.
SERC
1, 3, 5
12. Joe Spencer
SERC Reliability Corp
SERC
10
10
X
Region Segment Selection
1. Paul Nauert
June 3, 2010
2
3
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
2.
Group
Rick Shackleford
Green Country Energy LLC
2
3
4
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Danny Parish
SPP
5
2. Ron Zane
SPP
5
3. Dennis Bradley
SPP
5
4. Mike Anderson
SPP
5
5. Greg Froehling
SPP
5
3.
Group
Guy Zito
Additional Member
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1. Ralph Rufrano
New York Power Authority
NPCC 5
2. Alan Adamson
New York State Reliability Council, LLC
NPCC 10
3. Gregory Campoli
New York Independent System Operator
NPCC 2
4. Roger Champagne
Hydro-Quebec TransEnergie
NPCC 2
5. Kurtis Chong
Independent Electricity System Operator
NPCC 2
6. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
7. Manuel Couto
National Grid
NPCC 1
8. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
9. Brian D. Evans-Mongeon Utility Services
NPCC 8
10. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
11. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
12. Kathleen Goodman
ISO - New England
NPCC 2
13. David Kiguel
Hydro One Networks Inc.
NPCC 1
14. Michael R. Lombardi
Northeast Utilities
NPCC 1
15. Greg Mason
Dynegy Generation
NPCC 5
16. Bruce Metruck
New York Power Authority
NPCC 6
17. Chris Orzel
FPL Energy/NextEra Energy
NPCC 5
18. Robert Pellegrini
The United Illuminating Company
NPCC 1
June 3, 2010
X
4
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
19. Michael Schiavone
National Grid
20. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
21. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
22. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
23. Randy MacDonald
New Brunswick System Operator
NPCC 2
4.
Group
Jalal Babik
2
3
4
5
6
7
8
9
NPCC 1
Electric Market Policy
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Louis Slade
SERC
2. Mike Garton
6
NPCC 5
3. John Loftis
Electric Transmission
SERC
1
4. Ron Broocks
Electric Transmission
SERC
1
5.
Group
Richard Kafka
Pepco Holdings Inc. - Affiliates
Additional Member Additional Organization Region Segment Selection
1. Carlton Bradshaw
Atlantic City Electric
RFC
1
2. Ken Lehberger
Atlantic City Electric
RFC
1
3. Randal Coleman
Delmarva Power & Light
RFC
1
4. Guy Eberwein
Delmarva Power & Light
RFC
1
5. Walt Blackwell
Potomac Electric Power Co RFC
1
6.
Group
David A Szulczewski
Detroit Edison
X
X
X
Additional Member Additional Organization Region Segment Selection
1. David A Szulczewski Detroit Edison
RFC
2. Raju J Vengalil
RFC
June 3, 2010
Detroit Edison
5
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
7.
Group
Kenneth D. Brown
Public Service Enterprise Group Companies
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Scott Slickers
PSEG Power Connecticut NPCC
2. Clint Bogan
PSEG Fossil LLC
ERCOT 5
3. James Hebson
PSEG ER&T LLC
RFC
6
4. James Hubertus
PSE&G
RFC
1, 3
8.
Group
Denise Koehn
Additional Member
5
Bonneville Power Administration
Additional Organization
Region Segment Selection
1. Dean Bender
SPC Technical Svcs
2. Mason Bibles
Sub Maint and HV Engineering WECC 1
3. Laura Demory
PSC Technical Svcs
9.
Group
Sam Ciccone
WECC 1
WECC 1
FirstEnergy
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hohlbaugh
FE
RFC
2. Jim Kinney
FE
RFC
3. Eric Schock
FE
RFC
4. Allen Morinec
FE
RFC
5. Ken Dresner
FE
RFC
6. Bill Duge
FE
RFC
7. Art Buanno
FE
RFC
8. Brian Orians
FE
RFC
9. Jim Detweiler
FE
RFC
10. Ken Bunting
FE
RFC
10.
Group
Carol Gerou
Additional Member
June 3, 2010
MRO NERC Standards Review Subcommittee
Additional Organization
X
Region Segment Selection
6
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
1. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
2. Neal Balu
WPS Corporation
MRO
3, 4, 5, 6
3. Terry Bilke
Midwest ISO Inc.
MRO
2
4. Ken Goldsmith
Alliant Energy
MRO
4
5. Jodi Jenson
Western Area Power Administration MRO
1, 6
6. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
7. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
8. Alice Murdock
Xcel Energy
MRO
1, 3, 5, 6
9. Scott Nickels
Rochester Public Utilties
MRO
4
10. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
11. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
11.
Group
Deborah Schaneman
Additional Member
Platte River Power Authority Maintenance
Group
Additional Organization
2
3
4
5
X
X
X
7
8
9
Region Segment Selection
1. Scott Rowley
Platte River Power Authority WECC 7
2. Gary Whittenberg
Platte River Power Authority WECC 7
12.
Individual
James Starling
SCE&G
X
X
X
13.
Individual
Rick Koch
Nebraska Public Power District
X
X
X
14.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
15.
Individual
Kristina Loudermilk
ENOSERV
16.
Individual
Wade Davis
Otter Tail Power
17.
Individual
Alison Mackellar
Exelon Generation Company, LLC - Exelon
Nuclear
June 3, 2010
6
X
X
X
X
X
7
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
18.
Individual
Benjamin Church
NextEra Energy Resources
19.
Individual
Scott Berry
Indiana Municipal Power Agency
20.
Individual
John E. Emrich
Indianapolis Power & Light Co.
X
21.
Individual
Glenn Hargrave
CPS Energy
X
22.
Individual
Darryl Curtis
Oncor Electric Delivery
X
23.
Individual
Sandra Shaffer
PacifiCorp
X
24.
Individual
Armin Klusman
CenterPoint Energy
X
25.
Individual
Howard Gugel
Progress Energy
26.
Individual
John Moraski
BGE
27.
Individual
Dale Fredrickson
Wisconsin Electric
28.
Individual
Frank Gaffney
Florida Municipal Power Agency, and its
Member Cities as follows: New Smyrna
Beach; City of Vero Beach; and Lakeland
Electric
X
29.
Individual
Russell C Hardison
TVA
X
30.
Individual
Kirit Shah
Ameren
X
31.
Individual
Huntis Dittmar
Lower Colorado River Authority
X
32.
Individual
Brandy A. Dunn
Western Area Power Administration
X
June 3, 2010
2
3
4
5
6
7
8
9
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
8
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
33.
Individual
Robert Casey
Operations and Maintenance
X
34.
Individual
Hugh Francis
Southern Company
X
35.
Individual
Daniel J. Hansen
RRI Energy
36.
Individual
Silvia Parada-Mitchell
Transmission Owner
37.
Individual
Greg Mason
Dynegy
38.
Individual
Michael Ayotte
ITC Holdings
X
39.
Individual
Robert Waugh
Ohio Valley Electric Corp.
X
40.
Individual
Brent Ingebrigtson
E.ON U.S.
X
41.
Individual
Danny Ee
Austin Energy
X
42.
Individual
John Alberts
Wolverine Power Supply Cooperative, Inc.
43.
Individual
Willy Haffecke
44.
Individual
45.
2
3
4
X
5
7
8
9
X
X
X
X
X
X
X
X
X
X
X
City Utilities of Springfield, MO
X
X
X
Charles J. Jensen
JEA
X
X
X
Individual
Greg Rowland
Duke Energy
X
X
X
46.
Individual
Bob Thomas
Illinois Municipal Electric Agency
47.
Individual
Scott Barfield-McGinnis
Georgia System Operations Corporation
X
X
48.
Individual
Jianmei Chai
Consumers Energy Company
X
X
49.
Individual
Vladimir Stanisic
Ontario Power Generation
June 3, 2010
6
X
X
X
X
X
X
9
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
5
6
X
X
X
X
X
X
X
50.
Individual
James H. Sorrels, Jr.
AEP
X
51.
Individual
Jason Shaver
American Transmission Company
X
52.
Individual
Edward Davis
Entergy Services, Inc
X
X
53.
Individual
W. Guttormson
Saskatchewan Power Corporation
X
X
54.
Individual
Alice Murdock
Xcel Energy
X
X
55.
Individual
Martin Bauer
US Bureau of Reclamation
June 3, 2010
4
X
7
8
9
X
10
10
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
1. The SDT proposes to change the name of the draft standard from “Protection System Maintenance and Testing”
to “Protection System Maintenance”, and to include testing as one component of “Protection System
Maintenance Program”, which will be a defined term. Do you agree? If not, please explain in the comment
area.
Summary Consideration: The majority of the respondents agreed with both the change in the name of the draft standard
and with the definition of Protection System Maintenance Program. Some comments were offered, most of which were
answered by explanation of the rationale of the SDT.
Organization
Yes or No
US Bureau of Reclamation
No
Question 1 Comment
1. The alteration of the program to include testing as a component does not add value to system reliability.
The existing requirement can only be completed with procedures that some of the elements listed under
the program. The proposed program is far too restrictive in the manner in which it requires specific
actions and thereby excludes others.
2. The program element for monitoring is listed; however, the monitoring is intended to be used through an
electronic subsystem and does not allow for observations by experienced technical staff.
3. Testing is listed; however, the definition is limited to the application of signals and precludes other
procedures.
4. Further, the definition of Protection System proposed is a nested definition which tends to expand the
number of devices covered (any device that has voltage and current sensing inputs) irrespective of their
impact on the BPS.
Response: The SDT thanks you for your comments.
1. Maintenance includes a number of actions, one of which is testing; inspections, etc are also part of maintenance. One option is to separately
identify each type of activity, another is to combine the types of activities within the overall Maintenance activity and address the specific activity
type where relevant. As for including some activities and excluding others, the listed activities are contemplated as minimum activities and do not
preclude an entity from performing additional activities.
2. If a facility is attended, the observation of locally-alarmed conditions by on-site personnel, within the time intervals expressed in the monitoring
attributes, can satisfy these requirements. Adequate documentation should be available that the facility is indeed attended, and that the on-site
personnel observe the related items. See FAQ V-1-D (page 30)
3. Nothing is precluded; minimum activities are specified, and entities may use additional approaches.
4. This concern is addressed by the applicability of the standard, where the applicability is limited to “Protection Systems that are applied on, or are
June 3, 2010
11
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 1 Comment
designed to provide protection for the BES”.
Wolverine Power Supply
Cooperative, Inc.
No
Wolverine Power has concern about the level of "prescription" in this standard draft. The intent of the
standards is to define what, not how. This draft gets unnecessarily prescriptive in our opinion, particularly in
the table
Response: The SDT thanks you for your comments. The SDT believes that the level of prescription within the standard is necessary to satisfy the
guidance in FERC Order 693, and also to address observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC005-1 is excessively general. FERC Order 672 also specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined
the minimum activities necessary to implement an effective PSMP.
AEP
Yes
American Transmission
Company
Yes
Austin Energy
Yes
Bonneville Power Administration
Yes
City Utilities of Springfield, MO
Yes
Consumers Energy Company
Yes
CPS Energy
Yes
Detroit Edison
Yes
Duke Energy
Yes
Dynegy
Yes
ENOSERV
Yes
Entergy Services, Inc
Yes
June 3, 2010
12
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Florida Municipal Power Agency,
and its Member Cities
Yes
Georgia System Operations
Corporation
Yes
Green Country Energy LLC
Yes
Illinois Municipal Electric Agency
Yes
Indiana Municipal Power Agency
Yes
Indianapolis Power & Light Co.
Yes
ITC Holdings
Yes
Lower Colorado River Authority
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NextEra Energy Resources
Yes
Northeast Power Coordinating
Council
Yes
Ohio Valley Electric Corp.
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
June 3, 2010
Question 1 Comment
13
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Otter Tail Power
Yes
PacifiCorp
Yes
Pepco Holdings Inc.
Yes
Platte River Power Authority
Maintenance Group
Yes
Progress Energy
Yes
Public Service Enterprise Group
Companies
Yes
RRI Energy
Yes
Southern Company
Yes
Transmission Owner
Yes
TVA
Yes
Western Area Power
Administration
Yes
Wisconsin Electric
Yes
Xcel Energy
Yes
FirstEnergy
Yes
June 3, 2010
Question 1 Comment
Although we agree with the change in the title of the standard, as well as the proposed definition of
"Protection System Maintenance Program", we feel that the definition could be clarified. With regard to
"Restoration", which at present is described as "The actions to restore proper operation of malfunctioning
components", it may be helpful to add examples of acceptable actions to restore operations, such as
calibration, repair, replacement, etc.
14
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 1 Comment
Response: The SDT appreciates your support and comments. An FAQ document is included that addresses your comment related to an example of
acceptable operations to restore operations. See FAQ II-2-B. (page 5)
JEA
Yes
Generally agree; however, some suggestions for possible changes:
1) change "associated communication systems necessary for correct operation of protective devices" to
"protective relays",
2) add a PSMP glossary definition for an acceptable type of monitored alarm, either to the proposed "PSMP
monitor" or another definition for "PSMP monitored and alarmed." The SDT did a good job of making the
overall Protection System definition clearer.
Response: The SDT appreciates your support and comments.
1) “Protective relays” is too specific a term here; it excludes applications such as logic-based direct transfer trip that provides protective functions.
2) The SDT disagrees that the proposed definition is necessary. Guidance on this issue is included in the FAQ. See FAQ V-1-A (page 28)
MRO NERC Standards Review
Subcommittee
Yes
N/A
Exelon Generation Company,
LLC
Yes
None
Saskatchewan Power
Corporation
Yes
Saskatchewan would like clarification of what the expectations and rationale are for including Restoration in
the PSMP. The other terms listed under the PSMP definition represent what we would consider as typical
relay maintenance activities. We would typically consider Restoration as an Operational activity. The existing
NERC standards seem to treat this as an Operator concern addressed in PRC-001 R2.1 and R2.2 (The
Operator shall take corrective action as soon as possible). If Restoration is included in PRC-005 doesn't
PRC-001 have to be modified as well to remove these references? Saskatchewan would also like
clarification on the term upkeep. Is the standard prescriptive and mandate the application of the latest
firmware upgrades within a defined period, or is it flexible and can upgrades be applied as the utility deems
necessary?
Response FAQ II-2-B (page 5) explains that restoration is the “corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction” and provides extensive discussion contrasting “restoration” in this context from
“restoration” in a system operations context. Examples are also discussed. Note that the word, ‘restoration’ is capitalized in the definition, but this
capitalization is for consistent format by capitalizing the first letter of each word in each bulleted phrase – the word was not capitalized to show that
June 3, 2010
15
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 1 Comment
the term is using the approved definition of ‘Restoration.’
SCE&G
Yes
The SDT is to be commended for developing a clear and well documented draft. Overall it provides a
balanced view of Protection System Maintenance, and good justification for its maximum intervals.
Response: The SDT appreciates your support.
Ameren
Yes
1. We commend the SDT for developing such a clear and well documented first draft. It generally provides a
well reasoned and balanced view of Protection System Maintenance, and good justification for its maximum
intervals. Our existing M&T Program has and continues to yield a very reliable BES with mostly similar
intervals, though some are longer and others shorter. We strongly support the almost all of the applicability
revision, which clarifies the boundary of NERC maintenance and testing oversight.
2. We question the addition of UFLS station DC Supply, auxiliary relays, and Generating facility systemconnected station service transformers. Have these components been a significant source of problems
leading to cascading outages?
3. The SDT also modifies the Protection System definition, mostly clarifying the boundaries. We generally
agree except that we recommend adding “fault” before “interrupting devices”.
Response:
1. The SDT appreciates your support and comments.
2. The standard is not focused only on causes of “cascading outages”; it is focused on “Protection Systems that are applied on, or are designed to
provide protection for the BES” and on maintenance of the UFLS systems. The components addressed in the comment are all part of the BES, or the
UFLS. As for the DC supply to the UFLS, it is a component that is necessary for the UFLS to function properly. FAQ II-4-D (page 11) discusses what
auxiliary tripping relays are actually included, and FAQ III-2-A (page 20) provides a discussion of station service (auxiliary) transformers and their
inclusion in this standard.
3. The “Interrupting devices” is a term that addresses the actions of UFLS, UVLS, and SPS, as well as the actions to clear faults.
Electric Market Policy
Yes
We commend the SDT for developing such a clear and well documented first draft. In general, it provides a
well reasoned and balanced view of Protection System Maintenance.
Response: The SDT appreciates your support.
SERC (PCS)
June 3, 2010
Yes
We commend the SDT for developing such a clear and well documented first draft. It generally provides a
well reasoned and balanced view of Protection System Maintenance, and good justification for its maximum
16
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 1 Comment
intervals.
Response: The SDT appreciates your support
AECI
Yes
Puget Sound Energy
Yes
June 3, 2010
17
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
2. Within Table 1a, Table 1b, and Table 1c, the draft standard establishes specific minimum maintenance activities
for the various types of devices defined within the definition of “Protection System”. Do you agree with these
minimum maintenance activities? If not, please explain in the comment area.
Summary Consideration: Most of the respondents disagreed with the minimum maintenance activities to some degree or
another. The disagreement ranged over the full spectrum of activities specified in the Tables, resulting in numerous changes to
the standard in response to comments.
Organization
Yes or No
ITC Holdings
No
Question 2 Comment
1. (FAQ 3C) What is the technical justification for omitting insulation testing of the wiring for DC control,
potential and current circuits between the station-yard equipment and the relay schemes? We feel this
wiring is susceptible to transients which, over time, may compromise the insulation, and therefore should
be tested.
2. 2. Table 1a (Page 6) Improve wording. Suggestion: “Verify proper functioning of the current and voltage
circuits from the voltage and current sensing devices to the protective relay inputs”
3. On Page 6: The red light monitors trip circuit not only trip coil. With only one circuit going to three parallel
single-pole trip coils a red light will not detect a single open trip coil. Is a station inspection that verifies
the red light is “on” an acceptable activity?
4. On Page 9: The 3 month communications maintenance activities should say that the channel needs to be
checked. For example: initiate a manual checkback test of the carrier system.
5. On Page 10: Not clear on level 2 monitoring attributes for protective relay component description. As
written it notes two separate requirements which are ambiguous. We assume that all monitoring noted is
required (internal self diagnosis and waveform sampling)?
6. On Page7: The standard should note that battery testing must include all batteries that are used in
protective relay systems (for example pilot wire batteries).
Response: The SDT thanks you for your comments.
1. The SDT does not believe that insulation testing needs to be included within the minimum required maintenance activities; the SDT is not aware of a
body of evidence that suggests that these tests should be included as a requirement. The proposed standard does not prevent an entity from
including such tests in its program if its experience indicates that such testing is needed.
2. The SDT has modified the standard in consideration of your suggestion and the suggestions of others as shown:
June 3, 2010
18
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
Verify proper functioning of the current and voltage circuit signals necessary for Protection System operation from the voltage and current sensing devices to
the protective relays.
3. The SDT has modified the standard to remove the requirement cited in this comment as shown below:
4. The SDT has modified the standard in consideration of your suggestion as shown below:
Verify that the Protection System communications system is functional.
See FAQ II-6-B for suggestions related to methodology.
5. Yes. For level 2 monitoring, all attributes must be satisfied. The SDT has modified the standard to clarify as shown below:
Includes:
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures.
•
Input voltage or current waveform sampling three or more times per power cycle
•
Conversion of samples to numeric values for measurement calculations by microprocessor electronics that are also performing self diagnosis and
alarming.
6. The proper functioning of such batteries will be addressed by the verification and monitoring of the communications system, and by addressing
maintenance correctable issues related to the communications system.
Green Country Energy LLC
No
1) Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) also The maintenance
activity causes excessive breaker operation, and the intrusive nature increases the risk of subsequent
misoperations on operating units. System configuration of many plants will require an extensive interruption of
total plant production to complete the test.
2) Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS systems only) The maintenance activity
causes excessive breaker operation, and the intrusive nature increases the risk of subsequent misoperations
on operating units. System configuration of many plants will require an extensive interruption of total plant
production to complete the test.
Response: The SDT thanks you for your comments.
1. The overall Protection System Control Circuitry can be addressed in segments, as long as all portions are verified or tested as required.
Depending on the arrangement of the DC control circuit, it may be necessary to only trip the breaker itself once. See FAQ II-4-E. (page 11)
2. The overall Protection System Control Circuitry can be addressed in segments, as long as all portions are verified or tested as required.
June 3, 2010
19
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
Depending on the arrangement of the DC control circuit, it may be necessary to only trip the breaker itself once. See FAQ II-4-E. (page 11)
Public Service Enterprise Group
Companies
No
1) Table 1a Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only). Currently, we test
our UFLS relays on a 2 year maintenance interval. We test the relays and associated DC circuitry up to the
DC lockout relays. It would require extraordinary effort to trip the breakers directly when performing these
tests. Usually, each UFLS relay will trip several feeder breakers. This requirement states that we need to
check the trip coil for each of those breakers each time we perform relay maintenance. This will add an
unreasonable amount of time and effort to reliably switch out several 4kV or 13kV feeders every time we
perform UFLS maintenance. For UFLS and UVLS schemes, we feel the requirement for DC control testing
should not go past the lockout relay. The standard says to perform trip checks at the same time as UF
maintenance. We test the relays on a 2 year interval right now. It is unreasonable to perform trip checks this
often. The trip checks should follow a 6 year span (or longer) just like the BES equipment.
2) Table 1a DC supply. The 18 month inspection requires a measurement of specific gravity and
temperature. We believe that if a battery owner opts to perform an 18 month ohmic value test, this combined
with the cell voltage readings and continuity tests will give a good indication of battery health. We do not feel
that the measurement of specific gravity is required in conjunction with the tests performed above.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment as shown below:
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits, including all electromechanical trip and
auxiliary contacts essential to proper functioning of the Protection System, except that verification does not require actual tripping of circuit breakers or
interrupting devices.
See FAQ II-8-D (page 19) for a discussion on this.
2. The SDT has modified the standard in consideration of your comment and this has been deleted.
Wisconsin Electric
No
1. Page 7 Station DC Supply (Batteries): The activity to verify proper electrolyte level should only apply to
unstaffed (unmanned) stations; checking battery electrolyte levels is routinely done in generating stations,
which are staffed with personnel continuously (24 x 7). In addition, the three activities listed here with a 3
month interval for batteries (electrolyte, voltage, grounds) should NOT require documentation for compliance
purposes. It should be sufficient that these routine and recurring activities (every 3 months) are identified in
the Maintenance Plan. Otherwise the administrative burden to provide documentation will become excessive
and counterproductive to assuring BES reliability.
2. Page 7 Station DC Supply (Batteries): The 18 month interval includes an activity to verify the battery
charger equalize voltage. This activity is normally done only when the bank is load tested. Therefore the
June 3, 2010
20
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
activity to verify equalize voltage of a charger should have a 6 year interval along with the other battery
charger activities to verify full rated current and current-limiting.
3. Page 9 Communications Equipment: Similar to #1 above, the activity to verify monitoring and alarms
should NOT require documentation in order to demonstrate compliance. Having these routine 3 month
activities in the Maintenance Plan is sufficient. This needs to be clarified in the standard. Also, this
requirement should be re-worded to refer to generating stations also, not just substations.
4. Page 11 Station DC Supply (Batteries): Like #1 above, the similar requirement in Table 1b for verifying
battery electrolyte levels should be revised to indicate that documentation is NOT required.
5. Page 6 Prot System Control Circuitry: Like #1 above, the 3 month activity to verify continuity of breaker
trip circuits is fine, but there should be no requirement to document the readings or observations; it is
sufficient that this activity be addressed in the Maintenance Plan, especially for staffed generating stations.
6. Page 6 Prot System Control Circuitry: For the 6 year activity to "perform a functional trip test...": is this a
requirement to actually trip the circuit breaker ? If yes, this should be stated clearly in the Maintenance
Activity description.
7. We are concerned that the Maintenance Activities are not appropriate for certain equipment. The RFC
definition of Bulk Electric System includes any protection equipment that can trip a BES facility independent of
voltage level. As an LSE, this includes distribution-level equipment that was not designed to the same level of
redundancy as Transmission equipment. Complying with the requirements for control circuitry functional
testing and current sensing device testing will actually decrease system reliability since this often cannot be
accomplished without requiring outages to major distribution system components and/or temporarily breaking
protection circuits. We propose that this type of testing on distribution systems which fall under the definition
of BES Protection Systems should be addressed separately from the rest of the BES Protection Systems in
this standard. The intervals and/or maintenance activities should reflect the differences in how these
distribution protection systems are designed and operated.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment. The revised standard requires the responsible entity to “check” the
following every 3 calendar months:
• Electrolyte level (excluding valve-regulated lead acid batteries)
• Station dc supply voltage
• Unintentional grounds
2. The SDT has modified the standard in consideration of your comments regarding DC supply and the reference to “equalize voltages” has been
June 3, 2010
21
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
removed
3. The word “substation” has been removed from this requirement. Documentation of completion of required maintenance activities will likely be
necessary to demonstrate compliance.
4. The SDT has modified the standard in consideration of your comments to require checking of electrolyte levels, instead of verification.
Documentation of completion of required maintenance activities will likely be necessary to demonstrate compliance.
5. The SDT has modified the standard to remove the requirement cited in your comment.
6. Yes. The intent here is that the entire dc control circuit, including the breaker trip coil, be exercised. This was changed to read as follows:
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits, including all electromechanical trip and
auxiliary contacts essential to proper functioning of the Protection System.
7. As established in 4.2.1, this standard applies to all Protection Systems that are “Protection Systems that are applied on, or are designed to provide
protection for the BES”.
Exelon Generation Company,
LLC
No
1. Minimum maintenance activities should be on a yearly multiplier verses a monthly multiplier. Nuclear
generating stations are typically on an 18-month or 24-month refueling cycle. The draft standard does not
take into consideration a nuclear generators refueling cycle. Specifically, most Boiling Water Reactors
(BWRs) are on a 24-month refueling cycle and may run continuously between refueling outages. Performing
maintenance on-line puts the generating unit at risk without any commensurate increase in reliability to the
bulk electric system.
2. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's
refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing
of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing
programs.
3. Activities that begin with "verify" should be modified to "Validate…are/is within acceptable limits. Initiate
corrective actions as required." For example, some levels of DC grounds are acceptable based on circuit
design and component installation. Troubleshooting or ground isolation may increase the risk to the system
depending on ground magnitude and conditions.
4. Please provide clarification on "verify that no dc supply grounds are present" most stations have some level
of ground current. Should this be interpreted to be a measure of resistance or current values? Suggest
rewording to say "Check and record unintentional battery grounds"
5. "Verify Station Battery Chargers provides the correct float and equalize voltage" should be deleted.
Equalizing a battery is a maintenance function and should only be performed as needed. Suggest rewording
June 3, 2010
22
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
to say "Check and record charger output current and voltage."
6. Activities associated with Battery Charger performance should be deleted. The ability of the Battery
Charger to maintain the battery at full charge state is verified by checking proper "float voltage." The ability to
provide full rated current only affects the ability to recharge a battery AFTER an event has occurred.
7. In Table 1a does the requirement to "verify proper electrolyte level" refer to all batteries or only a sampling?
Current practice is to use the "pilot cell" as the monitoring cell as this cell is usually the least healthy of the
battery bank from a specific gravity and/or voltage standpoint. If the pilot cell continues to degrade then the
other batteries will be monitored more often. Suggest rewording to "Check electrolyte level."
8. In Table 1a the 18-month requirement to measure that the specific gravity and temperature of each cell is
within tolerance is "where applicable" what does "where applicable" mean?
9. For the Station dc supply (battery is not used) 18-month interval should this be interpreted that it is just the
battery charger with no attached battery? Or a dc supply system that does not contain a battery?
10. Table 1a Station dc supply 18-month interval to verify cell-to-cell and terminal connection resistance is
within "tolerance" should be revised to say "tolerance or acceptable limits."
11. Table 1a Station dc supply (that has as a component valve regulated lead-acid batteries) should provide
an additional optional activity for "Total replacement of battery at an interval of four (4) years" in lieu of not
conducting performance or service capacity test at maximum maintenance interval.
Response: The SDT thanks you for your comments.
1. The activities that are on an interval less than one calendar year are all “inspection” type activities, rather than “testing” activities. The SDT
requests more specificity as to your concerns.
2. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8.4 of the Supplementary Reference Document
(page 13) and FAQ IV-2-D (page 23) for a discussion on this issue.
3. The SDT has modified the standard and Frequently Asked Questions document (See FAQ II-5-I, page 15) in consideration of your comments about
dc grounds.
4. The SDT has modified the standard and Frequently Asked Questions document (See FAQ II-5-I, page 15) in consideration of your comments about
June 3, 2010
23
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
no dc supply grounds being present. The language in the standard was changed to: Check for unintentional grounds
5. The SDT has modified the standard in consideration of your comments – the phrase, “equalize voltages,” was deleted
6. The performance of the battery charger is critical to the performance of the protection system. The SDT has modified the standard to simplify the
requirements related to maintenance of the battery charger.
7. The SDT has modified the standard in consideration of your comments. The Maintenance Activity related to electrolyte level of batteries has been
changed from “verify proper” to “check” electrolyte levels. This Maintenance Activity refers to every individual cell in a non-VLRA station battery,
similar to recommendations in the relevant IEEE Standards.
8. The SDT has modified the standard in consideration of your comments. The requirement to measure that the specific gravity and temperature of
each cell is within tolerance is "where applicable" has been deleted.
9. The FAQ II-5-A (page 12) addresses your question concerning “Station dc supply (battery is not used)” by explaining that “a Station dc supply where
a battery is not used” is a situation where another energy storage technology besides a battery is used prevent loss of the station dc supply when ac
power to the station dc supply is lost.
10. The SDT has modified the standard in consideration of your comments regarding cell-to-cell and terminal connection resistance – the phrase,
“within tolerance” was deleted – and the requirement was subdivided to clarify that the entity must “verify battery terminal connection resistance and
verify battery cell-to-cell connection resistance.”
11. The SDT believes that the maintenance activities specified in Table 1a for VRLA batteries are necessary to assure that the station battery will
perform reliably and that replacement of the battery every four years in lieu of such testing would not provide such assurance. The SDT is providing
the option of either capacity testing (every three years) or measuring individual cell/unit ohmic values (every three months) and trending the test
results against the station battery’s baseline to allow entities to choose which of these activities best address their facilities. Total replacement of a
VRLA battery with a properly-performing new battery, 3 calendar years after installation of the original battery, is in compliance with Table 1a of this
standard. See FAQ IV-2-A (page 22) & IV-2-B (page 23) for a discussion about commissioning tests and how they relate to establishing a baseline.
US Bureau of Reclamation
No
1. The basis for developing the maintenance intervals was adequately explained. It is understood that FERC
would like uniform intervals; the intervals do not recognize the tremendous variation in installation and
equipment and possibly manufacturer recommendation. Point in fact is the interval for listed for
electromechanical relays. Some of these relays must be calibrated every year or three years on the outside.
Relays that have a history of stable performance based on consistently good test results.
2. The intervals for battery maintenance are not reasonable. The capacity testing at 3 years is higher than
the 5 year which battery manufactures require.
Response: The SDT thanks you for your comments.
1. The proposed standard does not prevent an entity from including such tests in their program if their experience has indicated that such testing is
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
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Question 2 Comment
needed.
2. The 3-year capacity test is specifically for Valve Regulated Lead-Acid batteries (VRLA); Vented Lead-Acid batteries require a 6-year capacity test.
Due to the failure mode and designed service life of Valve Regulated Lead-Acid (VRLA) batteries compared to a Vented Lead-Acid batteries, the SDT
believes that extending capacity testing of a VRLA battery beyond the maximum maintenance interval of 3 calendar years in Table 1a cannot be
justified regardless of what the battery manufacturers recommend.
MRO NERC Standards Review
Subcommittee
No
A. In the tables, the term “verification” should be switched with “check”.
B. The verification activities include testing for “specific gravity” in batteries. Since “impedance testing” will
give you the same results or similar results; revise the tables to reflect this, as well.
C. Another question deals with the table title verbiage. Table 1a and 1c are labeled as Protection Systems,
while Table 1b is Protection System Components. One could interpret table 1c as saying that if any one
component of the protection system in question is not in compliance with level 3 monitoring stipulations, then
every component must be degraded to level 2 monitoring as so forth. This needs to be clarified.
D. Some activities, such as complete functional testing, could lead to reduced levels of reliability, because [1]
it requires removing elements of the transmission system from service and [2] it requires performing tests that
are inherently prone to human errors. The MRO NSRS does not believe the perceived benefits justify the
anticipated costs.
E. In the tables, under Table 1a and Protection system communications equipment and channels, a technical
justification should be provided to show that performance and quality channel testing would result in the
reduction of regional disturbances and blackouts. Quality and performance testing is subjective. Subjective
tests are inherently poor compliance measures. The requirements to measure, document, store, and prove
channel quality data is a poor use of limited compliance resources.
F. In the tables, under Table 1a and Station DC supply (and anywhere else), equalize (battery) voltages
should be eliminated. Equalizing battery voltages reduces battery life and do not provide a significant gain in
overall system reliability to offset the loss of battery life.
G. In the tables, under Table 1a and Station DC supply (and anywhere else), delete the reference to
measuring the fluid temperature of “each cell”. A technical basis should be demonstrated that shows why
individual cell fluid temperature measurement would reduce the occurrence of regional disturbances. If fluid
temperature measurement remains in the standard, a single fluid temperature measurement per battery bank
should be sufficient to demonstrate that the battery bank was performing within normal parameters. The
compliance burden to add fluid temperature measurements for each cell is unwarranted and reduces
compliance personnel resources that could be utilized on more important reliability activities.
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Response: The SDT thanks you for your comments.
A. The SDT has modified the tables in consideration of your comments regarding “verification” vs. “checking”.
B. The SDT has modified the standard in consideration of your comments – the term, “specific gravity” is not used in the revised standard
C. The SDT has modified Tables 1a and 1c in consideration of your comments. The subheading of Table 1a and 1c were modified, replacing,
“Systems” with “System Components.”
D. To minimize system impact of such maintenance and possible errors, the maintenance necessarily should be scheduled at a time that minimizes the
risks.
E. Many utilities have long history that emphasizes that maintenance of communications systems is critical to assuring the proper performance of
these systems. The intervals were determined based on the experiences of SDT and NERC System Protection and Task Force members. Additionally,
this standard is not focused only on avoiding regional disturbances or blackouts, but instead on overall Protection System reliability. See
Supplementary Reference Document, Section 15.5 (page 23) and FAQ II-6-D (page 17).
F. The SDT has modified the standard in consideration of your comments. The requirement to “equalize battery voltages” was removed from the
revised standard.
G. The SDT has modified the standard in consideration of your comments and all references to measuring “temperature” have been removed from the
revised standard.
CenterPoint Energy
No
a. CenterPoint Energy believes the approach taken by the SDT is overly prescriptive and too complex to be
practically implemented. The inflexible minimum “maintenance activities” approach fails to recognize the
harmful effects of over-maintenance and precludes the ability of entities to tailor their maintenance program
based on their configurations and operating experience. In particular, the loss of maintenance flexibility
embodied in this approach would have perverse consequences for entities with redundant systems. Entities
with redundant systems have less need for maintenance of individual components (due to redundancy) yet
have twice the maintenance requirements under the minimum “maintenance activities” approach. For
example, Table 1A calls for performing a specific gravity test on “each cell” of vented lead-acid batteries.
CenterPoint Energy believes such a requirement is dubious for entities that do not have redundant batteries,
and absurd for entities that do. CenterPoint Energy has installed redundant batteries in most locations and
has had an excellent operating history with batteries by using a combination of internal resistance testing and
specific gravity testing of a single “pilot cell”. This practice, combined with DC system alarming capability, has
worked well.
b. CenterPoint Energy is opposed to approving a standard that imposes unnecessary burden and reliability
risk by imposing an overly prescriptive approach that in many cases would “fix” non-existent problems. To
clarify this last point, CenterPoint Energy is not asserting that maintenance problems do not exist. However,
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requiring all entities to modify their practices to conform to the inflexible approach embodied in this proposal,
regardless of how existing practices are working, is not an appropriate solution. Among other things,
requiring entities to modify practices that are working well to conform to the rigid requirements proposed
herein carries the downside risk that the revised practices, made solely to comply with the rigid requirements,
degrade reliability performance.
c. Arguably, an entity could possibly return to its existing practices, if those practices are working well, by
navigating through the complex set of options and supporting documentation that the SDT has crafted in this
proposal. However, most entities have an army of substation technicians with various ranges of experience
to perform maintenance on protection systems and other substation components. It is unrealistic to expect
most entities making a good faith effort to comply with this proposal to have a full understanding throughout
the entire organization of all the nuances crafted into this complex proposal.
d. For the reasons outlined above, CenterPoint Energy does not agree with the proposal to specify minimum
maintenance activities. However, if the majority of industry commenters agree with the SDT’s proposal,
CenterPoint Energy has concerns about some of the proposed tasks. For Protection System control circuitry
(trip circuits), Table 1A calls for performing a complete functional trip test. The “Frequently-asked Questions”
document states that this “may be an overall test that verifies the operation of the entire trip scheme at once,
or it may be several tests of the various portions that make up the entire trip scheme”. Such a requirement
creates its own set of reliability risks, especially when monitoring already mitigates risks. CenterPoint Energy
is concerned with this standard promoting an overall functional trip test for transmission protection systems.
This type of testing can negatively impact reliability with the outages that are required and by exposing the
electric system to incorrect tripping. CenterPoint Energy views overall functional trip testing as a
commissioning task, not a preventive maintenance task. CenterPoint Energy performs such testing on new
stations and whenever expansion or modification of existing stations dictates such testing. Overall,
CenterPoint Energy recommends minimizing, to the extent possible, maintenance activities that disturb the
protection system; that is, placing the protection system in an abnormal state in order to perform a test.
e. For Protection System control circuitry (breaker trip coils only), Table 1A calls for verifying the continuity of
the trip circuit every 3 months. CenterPoint Energy is not sure what would be the expected task to meet this
requirement (it is not addressed in the “Frequently-asked Questions” document).
Response: The SDT thanks you for your comments.
a) The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. Regardless of the level of redundancy provided, all components addressed by this
standard must be maintained in accordance with the requirements of the standard. The SDT has therefore defined the minimum activities necessary to
implement an effective PSMP. The SDT has modified the standard in consideration of your comments concerning performing a specific gravity test
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
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and the revised standard does not require a specific gravity test.
b) ) The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The opportunities in R3 provide additional flexibilities for entities which desire
them.
c) For those entities which wish the least complex approach, a pure time-based program, using R1, R2, and R4, with Table 1a provides the simplest
approach to meeting this standard.
d) The SDT believes that functional trip testing is a key component of an effective PSMP.
e) See the Supplemental Reference Document, Section 15.3 (page 22) for a discussion on this topic.
NextEra Energy Resources
No
a. Tables 1a, 1b & 1c should offer as an alternative, measuring battery float voltages and float currents in lieu
of measuring specific gravities as described in Annex A4 of IEEE Std 450-2002.
b. Inspection of CVT gaps, MOVs and gas tubes should be added to the communications equipment time
based maintenance tables. Failure of the CVT protective devices may cause failure of the Protection System.
c. Maintenance Activities for UVLS or UFLS station dc supplies shows “Verify proper voltage of dc supply”.
Does this imply that, except for voltage readings of the dc supply, distribution battery banks are not
maintained?
d. Why does the Maintenance Activities for UVLS or UFLS relays state that verification does not require
actual tripping of circuit breakers?
e. Please clarify the Maintenance Activities for Voltage and Current Sensing Devices. Must voltage, current
and their respective phase angles be measured at each discrete electromechanical relay?
f. NextEra Energy concurs with other entities comments concerning this question: This entity believes the
approach taken by the SDT is overly prescriptive and too complex to be practically implemented. The
inflexible “minimum maintenance activities” approach fails to recognize the harmful effects of overmaintenance and precludes the ability of entities to tailor their maintenance program based on their
configurations and operating experience. In particular, the loss of maintenance flexibility embodied in this
approach would have perverse consequences for entities with redundant systems. Entities with redundant
systems have less need for maintenance of individual components (due to redundancy) yet have twice the
maintenance requirements under the “minimum maintenance activities” approach. For example, Table 1A
calls for performing a specific gravity test on “each cell” of lead acid batteries. Our company believes such a
requirement is dubious for entities that do not have redundant batteries, and absurd for entities that do. We
have installed redundant batteries in most locations and have had an excellent operating history with batteries
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by using a combination of internal resistance testing and specific gravity testing of a single “pilot cell”. This
practice, combined with DC system alarming capability, has worked well. We are opposed to approving a
standard that imposes unnecessary burden and reliability risk by imposing an overly prescriptive approach
that in many cases would “fix” non-existent problems. To clarify this last point, we are not asserting that
maintenance problems do not exist. However, requiring all entities to modify their practices to conform to the
inflexible approach embodied in this proposal, regardless of how existing practices are working, is not an
appropriate solution. Among other things, requiring entities to modify practices that are working well to
conform to the rigid requirements proposed herein carries the downside risk that the revised practices, made
solely to comply with the rigid requirements, degrade reliability performance. Arguably, an entity could
possibly return to its existing practices, if those practices are working well, by navigating through the complex
set of options and supporting documentation that the SDT has crafted in this proposal. However, like many
entities, we have an army of substation technicians with various ranges of experience to perform maintenance
on protective systems and other substation components. It is unrealistic to expect most entities making a
good faith effort to comply with this proposal to have a full understanding throughout the entire organization of
all the nuances crafted into this complex proposal. For the reasons outlined above, we do not agree with the
proposal to specify minimum maintenance activities. However, if the majority of industry commenters agree
with the SDT’s proposal, we have concerns about some of the proposed minimum tasks. For Protection
System control circuitry (trip circuits), Table 1A calls for performing a complete functional trip test. The
“Frequently-asked Questions” document states that this “may be an overall test that verifies the operation of
the entire trip scheme at once, or it may be several tests of the various portions that make up the entire trip
scheme”. Such a requirement creates its own set of reliability risks, especially when monitoring already
mitigates risks. We are concerned with this standard promoting an overall functional trip test for transmission
Protection Systems. This type of testing can negatively impact reliability with the outages that are required
and by exposing the electric system to incorrect tripping. Our company views overall functional trip testing as
a commissioning task, not a preventive maintenance task. We perform such testing on new stations and
whenever expansion or modification of existing stations dictates such testing.
Response: The SDT thanks you for your comments.
a. The SDT has modified the standard in consideration of your comments. All references to measuring specific gravities have been removed from the
revised standard – and for Table 1a for station dc supply, the language was revised to require, “Verify float voltage of battery charger.”
b. Power line carrier channels are made up of many components that must be maintained on a periodic basis. This standard indicates that adequate
maintenance and testing must be done to keep the performance of the channel at a level that meets the requirements of the relay system. The
determination of specific maintenance activities is the responsibility of the Entity.
c. This standard limits the maintenance requirements of distribution system batteries to those used for UVLS and UFLS and constrains those
requirements to verification of proper voltage. If “distribution system” batteries are used for any other BES Protection System applications, they must
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be maintained according to the other requirements of this standard.
d. The SDT believes that the UFLS scheme is predominantly based within the distribution sector. As such, there are many circuit interrupting devices
that will be operating for any given under-frequency event that require tripping for that event. A failure in the tripping-action of a single distribution
breaker will be far less significant than, for example, any single Transmission Protection System failure such as a failure of a Bus Differential Lock-Out
Relay. While many failures of these distribution breakers could add up to be significant, distribution breakers are operated often on just fault clearing
duty and therefore the distribution circuit breakers are operated at least as frequently as any requirements that might have appeared in the standard.
e. The requirement is that the proper voltage, current, and phase angle must be delivered to each respective relay. The standard does not prescribe
methodology. See FAQ II-3-A (page 8) for further discussion.
f. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. Regardless of the level of redundancy provided, all components addressed by this
standard must be maintained in accordance with the requirements of the standard. The SDT has therefore defined the minimum activities necessary to
implement an effective PSMP. The SDT has modified the standard in consideration of your comments concerning specific gravity testing.
E.ON U.S.
No
1. Capacity or AC impedance only needs to be done to determine service life and therefore periodic testing of
station DC supply does not seem necessary or prudent.
2. If a company checks overall battery bank voltages quarterly then periodic testing of the battery bank
charger should not be required.
Response: The SDT thanks you for your comments.
1. Capacity or Internal Ohmic testing must be periodically performed at the Maximum Maintenance Intervals in Table 1 to verify that a lead acid
battery can perform as designed. Periodic testing to ensure that a battery can perform as designed is necessary to ensure that a battery is capable
of being a dc source to the station dc loads when required. If a battery fails to perform as designed during test before its designed service life is
reached it must be replaced regardless of how many years of service are left on its warranty or its engineered service life.
2. Proper functioning of the battery charger is critical to proper performance of the DC supply. The SDT has modified the standard to simplify the
battery charger maintenance requirements.
City Utilities of Springfield, MO
June 3, 2010
No
1. CU has concern over the battery charger testing requirements. Per the charger manufacturers
recommendations there is no reason to test the chargers as proposed in PRC-005-2. It is their opinion
that the chargers are self diagnostic and do not require these tests (full load current and current limiting
tests). The charger O&M manuals do not even provide instructions for such tests as optional. Therefore,
CU takes exception to this requirement and suggests that battery chargers be maintained and tested in
accordance with manufacturer’s recommendations.
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2. Additionally, CU is concerned with the wording in Table 1a concerning Protection system communication
equipment and channels. We are unsure what the maintenance activity actually means. If this is an
unmonitored system, how can you verify the condition of the communication system? Is the standard
referring to local monitoring such as enunciators? Please provide clarification.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comments. If the battery charger is self diagnostic, it may qualify for Table 1b or Table
1c.
2. FAQ II-6-A (page 16) provides an extensive discussion about various methods to test communications systems.
Florida Municipal Power Agency,
and its Member Cities
No
1. FMPA does not believe that maintenance of each UFLS / UFLS systems are as important as
maintenance of BES protection systems. The fundamental reason is that delayed or uncleared faults on
the BES can cause system “instability, uncontrolled separation, and cascading outages”; therefore, BES
protection systems are very important; however, if a small percentage of UFLS / UVLS relays mis-operate
as a result of a frequency or voltage event, the impact of the mis-operation is much smaller, if even
measurable. As a result, FMPA believes that the emphasis of the maintenance activities ought to be
placed on those systems that can have the most impact on what the standards are all about, as Section
215(a)(4) of the Federal Power Act says, “avoiding instability, uncontrolled separation, and cascading
outages”. As a result, FMPA believes that full functional testing, while important for BES protection
systems, is not necessary for UFLS and UVLS systems (Table 1a, page 6 and Table 1b, page 11).
Because most UFLS / UVLS are on radial distribution feeders, such testing will cause outages to
customers fed on radial distribution circuits and transmission lines without sufficient cause, in other words,
the maintenance itself will reduce the reliability the customer experiences. In addition, distribution tripping
circuits are more regularly exercised by distribution faults than are transmission tripping circuits; therefore,
full functional testing of distribution tripping circuits is far less valuable than testing trip circuits of
transmission elements which are exercised less frequently due to actual system events.
2. FMPA is confused with the wording of Table 1a, page 6, row 3 that talks about breaker trip coils. In the
“Type of Component” column, the subject says “Breaker Trip Coils Only (except for UFLS or UVLS)”, yet
the maintenance activity described states “Verify the continuity of the breaker trip circuit including trip
coil”. These two statements are inconsistent because the first statement limits the applicability to just the
trip coil and the second statement goes beyond the trip coil. And, FMPA believes the second statement
should only apply to the trip coil, e.g., the second statement should say: “Verify the continuity of the trip
coil”. In addition, the parenthetical is confusing, is it meant to say that the continuity of the trip coil only
needs to be verified when the breaker operates during the 3 month interval, or that the intended continuity
check is from the relay contacts through the trip coil, and not from the relay contacts back to the
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batteries?
3. FMPA is also confused concerning station DC supply testing. There are multiple rows in Table 1a
concerning various types of testing for various types of batteries and chargers that do not exclude UVLS
and UFLS, yet on page 8, on the bottom row, the row is exclusive to UVLS and UFLS yet overlaps other
rows discussing station DC supply testing. Is it intended that the other rows that are silent as to what they
apply to exclude UVLS and UFLS? FMPA believes that should be the case. The same comment applies
to Table 1b.
4. FMPA also has concern over the battery charger testing requirements. Per the charger manufacturers
recommendations there is no reason to test the chargers as proposed in PRC-005-2. It is their opinion
that the chargers are self diagnostic and do not require these tests (full load current and current limiting
tests). The charger O&M manuals do not even provide instructions for such tests as optional. Therefore,
FMPA takes exception to this requirement and suggests that battery chargers be maintained and tested in
accordance with manufacturer’s recommendations
Response: The SDT thanks you for your comments.
1. The SDT believes that UFLS and UVLS maintenance needs to be prescriptive for the following reasons:
a. PRC-008-0 and PRC-011-0 today require maintenance of UFLS and UVLS equipment.
b. FERC Order 693 directs NERC to develop maximum allowable intervals for UFLS and UVLS equipment, and recommends combining PRC-0051, PRC-008-0, PRC-011-0, and PRC-017-0.
The objectives are not constrained to limiting “instability, uncontrolled separation, and cascading outages”, but instead address overall Protection
System reliability. The standard has, however, been modified to remove the requirement that the breakers actually be tripped for UFLS and UVLS
functional trip testing.
2. The SDT has modified the standard to remove the requirement cited in your comments.
3. The SDT has modified the standard to clarify that the only DC Supply requirement relevant to UVLS and UFLS is to verify the DC supply voltage in
consideration of your comments.
4. The SDT has modified the standard in consideration of your comments. If the battery charger is self diagnostic, it may qualify for Table 1b or
Table 1c.
Indiana Municipal Power Agency
June 3, 2010
No
IMPA does not agree with the battery charger testing requirements. Per the battery charger manual, the
manufacturer sets the current limit at the factory, and it only needs to be adjusted if a lower current limit is
desired. The manufacturer gives directions on how to lower the current limiter, and the directions seem to be
for this purpose only (not for the sole purpose of performing a current limiter test). The manufacturer also
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does not give directions on how to perform a full load current test and does not give any recommendation to
the user that such test is needed. IMPA believes that both of these maintenance items are not needed to
maintain the battery charger and that only the manufacturer's recommendations on maintenance and testing
need to be followed.
Response: The SDT thanks you for your comments. The performance of the battery charger is critical to the performance of the protection system.
The SDT has modified the standard to simplify the requirements related to maintenance of the battery charger.
FirstEnergy
No
In general we agree with the maintenance activities, except for the specific gravity and temperature testing
included in the "Station dc Supply (that has as a component any type of battery)" of the tables 1a and 1b. We
only perform this testing at nuclear facilities for insurance requirements. In transmission substation
applications it has been eliminated due to the variability of results due to recharging/equalizing, water
addition, temperature correction requirements, etc. In the Supplementary reference, section 15.4 Batteries
and DC Supplies, third paragraph, the SDT indicates these tests are recommended in IEEE 450-2002 to
ensure that there are no open circuits in the battery string. This is essentially a continuity check of the battery
string. In the fourth paragraph, the SDT states that "continuity" was introduced into the standard to allow the
owner to choose how to verify continuity of a battery set by various methods, and not to limit the owner to the
two methods recommended in the IEEE standards."The SDT in Table 1a, the Maintenance Activity "Verify
continuity and cell integrity of the entire battery", and in Table 1b, the Maintenance Activity "Verify electrical
continuity of the entire battery". Based on the information in the Supplementary reference, the owner has to
choose a method to verify continuity and the measurement of specific gravity and cell temperatures could be
the selected method, however it should not be a required maintenance activity as shown in Tables 1a and 1b.
Response: The SDT thanks you for your comments and has modified the standard in consideration of your comments. All references to specific
gravity and temperature testing have been removed from the revised standard.
Ohio Valley Electric Corp.
No
1. In general, all maintenance activities that are verifications of proper function imply that problems found
must be resolved within the maximum interval. For some activities, that is an unreasonable expectation.
A temporary resolution may reliably correct an adverse situation but may not address the original
verification requirement within the maximum interval.
2. Routine substation inspections should not fall under NERC standards. The documentation for quarterly
inspections would be oppressive. It is unreasonable to require there to be no DC grounds. All DC
grounds do not rise to the level of a reliability concern. In some cases, attempting to resolve a relatively
minor DC problem may rise to the level of negatively affecting reliability.
3. The value of capacity testing battery banks and chargers in the context of a protection system reliability
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standard is questionable.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard to clarify that corrective actions must be initiated, but intentionally does not identify when they need to be
completed, largely for the reasons you cite. See FAQ II-2-I (page 7) for a discussion on this.
2. The SDT believes that certain verification activities must be performed on a periodic basis via visual inspection. The standard and Frequently
Asked Questions document (See FAQ II-5-I, page 15) have been modified in consideration of your comment concerning locating and removal of a dc
ground. References to dc grounds have been revised to “unintentional dc grounds.”
3. The SDT believes that the ability of the battery to provide required tripping current is CRITICAL to the reliability of the Protection System; else, the
Protection System is unable to react properly when required. Similarly, the SDT believes that the ability of the charger to properly charge the battery is
critical to sustain the battery capability.
AEP
No
In the process of performing maintenance, some protection systems may need to be taken out of service on
in-service equipment (bus differential protection for example) where redundant protection systems do not
exist. This action seems counter to NERC recommendations, presenting a scenario for expanding outages
during a simultaneous fault. Would the implementation plan include time for the additions of redundant
protection systems? Comments expanded in question 10 response.
Response: The SDT thanks you for your comments. To minimize system impact of maintenance, the maintenance necessarily should be scheduled at
a time that minimizes the risks. The implementation plan addresses the development of acceptable PSMPs.
RRI Energy
June 3, 2010
No
1. It is recommended to change the wording of the Maintenance Activities to the activity itself, not the resolved
state of the maintenance correctable issue (i.e. “For microprocessor relay, check for proper operation of the
A/D converters” instead of “For microprocessor relays, verify proper functioning of the A/D converters”). The
wording of the standard effectively sets the end date for the correction of maintenance identified issues. In
other words, maintenance has not taken place until all maintenance correctible issues have been completely
resolved. The wording in the standard have set non-compliance “traps” for those performing the maintenance
but have not completed correctable issues for legitimate reasons which may not be allowed by the noexception approach of the standard. For example, rewording of the Battery Supply 3 month activities are
recommended as follows: “Check for proper electrolyte level. Check for proper voltage. Check for dc supply
grounds.” As inspection activities, any issue not corrected during the interval should become a maintenance
correctible issue. For generating stations, the judgments to locate and remove a ground are based upon
criteria not accounted for in the requirements of this standard. An activity to locate and clear a ground
requires the judgment of station maintenance and operational management depending upon the operating
conditions of the unit and the level of the ground (solid or high-resistance).Inspections (3 month requirement
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activities) although good practices, should not be standard requirements.
2. The practice of verifying the continuity of breaker trip circuits does not belong as an auditable NERC
standard requirement; it becomes more of a documentation requirement rather than a reliability improvement.
Otherwise, it will ultimately require the expending of resources in an unproductive manner primarily on the
development, storage, and production of excessive records for compliance purposes. The elimination of this
requirement is recommended.
3. For Table 1a Protection System Control Circuitry - rewording is suggested as follows: “Perform functional
trip tests of Protection System trip circuits, including auxiliary relays essential to the proper functioning of the
Protection System.” The requirement, as presently worded “that includes all sections of the Protection
System,” is overly prescriptive and will create non-compliances for miniscule oversights, given the very large
scope of components in protection systems that are spread out far and wide in a system. The requirement
opens the door, allowing the compliance process itself to be punitive in nature. When pursued to the extreme
under audit conditions, this requirement will be very difficult to demonstrate on a large scale.
4. For Table 1a Station dc supply: The ability of a battery charger to correctly supply equalize voltage to a
battery has no direct correlation to reliability of the BES and does not belong in this standard. The objective is
that the battery get an equalize charge when it needs it, not the maintenance of the equalize function of a
battery charger. How the battery gets equalized is not important to this standard, especially since a battery
and the equalize source are usually disconnected from the protection system during the process.
5. For Table 1a Station dc supply: The use of the term “in tolerance,” for the measurement of specific gravity,
is an inconsistency in stating the standard requirements. There are multiple activities that will necessitate the
measurement of a quantity “in tolerance” whether it is battery charger output, individual cell voltages,
connection resistances, or internal ohmic values. The suggested rewording is as follows: “Measure the
specific gravity and temperature of each cell.”
6. For Table 1a Station dc supply: Referring to the requirement to “verify that the station battery can perform
as designed” very little of a generating station battery sizing is related to BES protection. Verification of a
generating station to design conditions is outside the scope of BES protection and does not belong in this
standard. Nearly all protection system operations operate without reliance upon the battery to do so, and the
separation of the generating unit from the BES will take place within cycles, if called upon to do so. The
remainder of the battery duty cycle is outside the scope of BES protection.
Response: The SDT thanks you for your comments.
The station dc supply 3 month activities section of table 1a has been reworded in consideration of your comment as shown below:
Check:
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Question 2 Comment
•
Electrolyte level (excluding valve-regulated lead acid batteries)
•
Station dc supply voltage
•
For unintentional grounds
Also FAQ II-5-I (page 15) has been modified in consideration of your comment concerning location and removal of dc grounds on a generating
station. The following was added to the FAQs:
In most cases, the first ground that appears on a battery pole is not a problem. It is the unintentional ground that appears on the opposite pole that
becomes problematic. Even then many systems are designed to operate favorably under some unintentional DC ground situations. It is up to the owner
of the Protection System to determine if corrective actions are needed on unintentional DC grounds. The standard merely requires that a check be made
for the existence of Unintentional DC Grounds. Obviously a “check-off” of some sort will have to be devised to demonstrate that a check is routinely
done for Unintentional DC Grounds.
Additionally, the Maintenance Activities in Table 1a, Table 1b, and Table 1c have been generally revised as you suggest, to present the activity rather
that the resolved state.
2. The SDT has modified the standard to clarify that this requirement is actually monitoring the trip coil. The SDT believes that verification of breaker
trip coil continuity is a vital component of the Protection System performance, and that they must be maintained as specified in the Standard.
3. The SDT believes that proper functioning of all trip circuit paths is a vital component of the Protection System performance, and that they must be
maintained as specified in the Standard.
4. The SDT has modified the standard in consideration of your comment and the requirement to equalize voltages has been removed from the revised
standard
5. The SDT has modified the standard in consideration of your comment and the comments from others, the reference to measuring specific gravity
and temperature has been removed
6. Thank you for your comments concerning verification that the station battery can perform as designed. Although the SDT agrees with you that
very little of a generation station battery sizing is related to BES protection, the majority of a generation station battery duty cycle is for safely
operating the station when the other elements of a station dc supply are unavailable and that some Protection System operations can operate
using the other elements of the station dc supply besides the station battery. The SDT believes that the station dc supply is such an integral part
of the Protection System of a generating station that, at a minimum, it must be maintained using the Maintenance Activities and Maximum
Maintenance Intervals of Table 1. It is important to note that the station battery must still be able to perform its vital Protection System functions
even if it is simultaneously supplying dc for its myriad of other applications. The required activities include “verify that the station battery can
perform as designed.”
Indianapolis Power & Light Co.
June 3, 2010
No
1. Many preventive maintenance programs have testing tolerances which are tighter than the manufacturer’s
tolerances. This practice is used to force an action prior to falling outside of the manufacture’s tolerances and
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accounts for slight variations in test equipment and environment. Maintenance correctable issues should not
be reportable unless the test failure falls outside of the manufacturer’s published tolerances.
2. In tables 1a through 1c the “Type of Component” columns in each table do not have consistent listings from
one 1a to 1b to 1c. The type of component should be identified consistently in each table. By doing so this
would eliminate confusion in moving from one table to the other.
3. The maintenance activities for some types of components specifies how (i.e. Test and calibrate the relays.
with simulated electrical inputs) while other maintenance activities do not specify how. The maintenance
activities should either all be specific or all be generic.
4. For Station dc Supply (that has as a component any type of battery) the maintenance activity of “verify that
no dc supply grounds are present” there is a problem of tolerance. It is impossible to have “no dc supply
grounds present”. There has to be some tolerance given here such as a voltage measurement from each
battery terminal to ground +- 15 volts of nominal for example.
5. For the type of component of “Protection System Control Circuitry (trip circuits) (UFLS/UVLS Systems
only), the maintenance activity requires a complete functional trip test” of the Protection System. This
suggests that a breaker trip test is required at each maintenance interval. This requires tripping breakers that
supply customers. It is impossible to trip each individual distribution feeder without forcing an outage on
some customers as when there are no other usable circuits to tie the load off to. A failure to trip of a single
distribution circuit in the overall scheme of a UVLS or UFLS scheme would have little effect on the BES. Trip
testing BES breakers and verifying correct operation of breaker auxiliary contacts could become very difficult
to accomplish since opening a breaker on a line might adversely affect the BES. ISOs may prohibit such an
activity at any time. Allowances should be made for BES circuit breakers that can not be operated for such
reasons if documented sufficiently.
Response: The SDT thanks you for your comments.
1. The tolerances, per Note 1 to Table 1a, Table 1b, and Table 1c, are defined by the entity according to their application considerations as related to
the component. The standard has been revised to exclude minor issues that can be corrected during the on-site maintenance activities from
“maintenance correctible issues”.
2. The variations in the “Type of Component” are a result of the varying maintenance activities that are necessary as there are higher levels of
component monitoring. If the “Type of Component” was made consistent among all three tables, there would be additional confusion, because
many of the “Types of Component” in Tables 1b and 1c would indicate that no maintenance activities are required.
3. Generic activity descriptions have been used except where specific activities are necessary.
4. The standard and Frequently Asked Questions document (See FAQ II-5-I, page 15) have been modified in consideration of your comment regarding
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dc grounds. References to dc grounds have been revised to “unintentional dc grounds.”
5. We agree. The minimum activities have been revised in the standard to not require tripping of the breakers for this table entry.
Platte River Power Authority
Maintenance Group
No
Minimum maintenance activities should be based on categorization of relays and defined maintenance
actions system by system using historical and definitively known data entity by entity. By establishing specific
minimum maintenance activities you risk entities changing currently effective maintenance programs to
programs that match minimum maintenance activities to meet requirements in the standard which could be
less effective for their system.
Response: The SDT thanks you for your comments. As for including some activities and excluding others, the listed activities are contemplated as
minimum activities and do not preclude an entity from performing additional activities. Your use of historical and definitively known data may be
applicable to a Performance-Based maintenance program (R3) for some of your activities.
PacifiCorp
No
No comment.
Duke Energy
No
Our comments are limited to activities in Table 1a.
1. ” Protective Relays “ okay
2. ” Voltage and Current Sensing Devices Inputs to Protective Relays “ Proper functioning should be verified
at commissioning, and then anytime thereafter if changes are made in a PT or CT circuit. Additional periodic
checks may be warranted as suggested in Table 1A; however no additional checking should be required
where circuit configuration will inherently detect problems with a PT or CT. For example, PTs & CTs that are
monitored through EMS or microprocessor relays will be alarmed when they are out of specification.
3. “Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS) “Need more
clarity on exactly what this activity is expected to include. In some cases we have a red light on a control
panel monitoring the circuit path to the trip coil. In locations where there is not a red light, verifying the
continuity of the breaker trip circuit including the trip coil will be complicated. There is no straightforward way
to do it without potentially impacting reliability, and we would have to consider modifying these installations to
include a red light.
4.” Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) “Need more clarity on
exactly what the activity is. We believe testing one output all the way to the coil is sufficient to prove the trip
path. The activity states that “all auxiliary contacts” must be tested. We propose that all protection control
circuitry should be tested at initial commissioning, and then again if any changes are made. Ongoing routine
testing is complicated and could pose reliability challenges to the BES. As stated on page 8 of the System
Maintenance Supplementary Reference document: “Excessive maintenance can actually decrease the
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reliability of the component or system. It is not unusual to cause failure of a component by removing it from
service and restoring it. The improper application of test signals may cause failure of a component. For
example, in electromechanical over current relays, test currents have been known to destroy convolution
springs. In addition, maintenance usually takes the component out of service, during which time it is not able
to perform its function. Cutout switch failures, or failure to restore switch position, commonly lead to protection
failures.
5.” Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only) Need additional clarity on
exactly what the test includes. “Complete functional trip test” should not include tripping the breaker.
Proving the output of the relay should be sufficient. Systems that have all load shed on distribution circuits
should require that trip output be confirmed but should not be required through to the trip coil due to
constraints in tying distribution load.
6. Station dc supply (that has as a component any type of battery) Under the 3 month interval activities, we
disagree with the wording of the activity Verify that no dc supply grounds are present. The activity should
instead read “Check for dc supply grounds and if any are found, initiate action to repair.
7. Station dc supply (that has as a component any type of battery) Under the 18 month interval activities, what
is meant by “Verify continuity and cell integrity of the entire battery”? Also what is required to “Inspect the
structural integrity of the battery rack”? The “Supplementary Reference Document” and “Frequently asked
Questions” document should be made part of the standard to provide clarity to the requirements.
8. Station dc supply (that has as a component Valve Regulated Lead-Acid batteries) Need more clarity on
exactly what is required for a “performance or service capacity test of the entire battery bank”. The
“Supplementary Reference Document” and “Frequently asked Questions” document should be made part of
the standard to provide clarity to the requirement.
9. Station dc supply (that has as a component Vented Lead-Acid batteries) Need more clarity on exactly what
is required for a “performance, service, or modified performance capacity test of the entire battery bank”. The
“Supplementary Reference Document” and “Frequently asked Questions” document should be made part of
the standard to provide clarity to the requirement.
10.” Protection system communication equipment and channels Need additional clarity on exactly what is
required for the substation inspection. What is required for power-line carrier systems?
11. UVLS and UFLS relays that comprise a protection scheme distributed over the power system Need more
clarity regarding the meaning of “distributed over the power system”.
Response: The SDT thanks you for your comments.
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1. Thank you.
2. Your example describes attributes applicable to Table 1c, and which would not require periodic maintenance. If monitoring, as you’ve described,
is not present, periodic verification is necessary as described in Table 1a.
3. You are correct. This area of each of the Tables has been extensively revised in response to comments. FAQ II-4-C (page 10) explains that this
“may be via targeted maintenance activities or by documented operation of these devices for other purposes such as fault clearing” and Section
15.3 of the Supplementary Reference (page 22) provides discussion on this.
4. If only one path is tested, this provides no assurance that other paths will perform properly. The cited reference on Page 8 of the Supplementary
Reference Document is focused on effective maintenance intervals, not on performing maintenances. There are methods of performing functional
testing without injecting damaging test currents.
5. The requirement has been modified to provide more clarity, and has been modified to remove the requirement to actually trip the breaker.
6. The SDT has modified the standard in consideration of your comment – it now reads, “Check for unintentional grounds.”
7. The SDT has modified the standard in consideration of your comment on cell integrity of the entire battery. Also, the Protection System
Maintenance Frequently Asked Questions document (FAQ II-5-H, page 15) that accompanied the standard for this comment period addresses your
question about the battery rack in Station dc Supply section. According to the NERC Standard Development Procedure, a standard is to contain
only the prescriptive requirements; supporting discussion is to be in a separate document.
8. Methodologies regarding performance and service capacity tests for VLRA batteries are explained in detail in various available references.
According to the NERC Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to
be in a separate document.
9. Your comment is in the nature of a “how to”, not a requirement, and therefore the SDT believes it belongs in the supporting discussion. According
to the NERC Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to be in a
separate document.
10. FAQ II-6-A (page 16) presents a variety of methods to maintain Protection System communication equipment.
11. This refers to the common practice of applying UFLS on the distribution system, with each UFLS individually tripping a relatively low value of load.
Therefore, the program is implemented via a large number of relays, and the failure of any individual relay to perform properly will have a minimal
effect on the effectiveness of the UFLS program. There are some UVLS systems that are applied similarly.
Progress Energy
No
Progress Energy does not agree with the activity “Verify that the battery charger can perform as designed by
testing that the charger will provide full rated current and will properly current-limit.” We are unclear how this
test should be performed.
Response: The SDT thanks you for your comments. The SDT has modified the standard in consideration of your comment. The component
description was changed to: Station dc supply (which do not use a station battery) And the maintenance activity was changed to: Verify that the dc
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supply can perform as designed when the ac power from the grid is not present.
Xcel Energy
No
Regarding battery chargers, does the SDT propose that OEM-type tests be performed to validate the rated
full current output and current limiting capabilities? It has been proposed that simply turning off the charger
and allowing the batteries to drain for a period of several hours, then returning the charger to service will
validate these items. It is not clear that an auditor would come to the same conclusion, since it appears open
to interpretation. Please modify to make this clear. If an entity has an over-sized battery charger, they can
(and should) only test to the max capacity of the battery bank. Suggest changing “full rated current” to
“designed charging rate”.
Response: The SDT thanks you for your comments. The SDT has modified the standard in consideration of your comment. The component description
was changed to: Station dc supply (which do not use a station battery) And the maintenance activity was changed to: Verify that the dc supply can perform as
designed when the ac power from the grid is not present.
Austin Energy
No
See item # 10 Comments
No
Station DC supply - (Maintenance Activity) As a company we do not think that measuring specific gravity and
temperature of each cell is necessary. There is a better test that we use with the Bite Impedance Test. We
have had good success with the impedance test for determining the batteries condition. See article
(Impedance Testing Is The Coming Thing For Substation Battery Maintenance)written in Transmission &
Distribution 11/1991 by Richard Kelleher, Test & Maintenance Specialist, Northeast Utilities.
Response: See #10 Response
Otter Tail Power
Response: The SDT thanks you for your comments regarding DC supply. Changes have been made to the standard in consideration of your
comments. The requirement to measure specific gravity and temperature of each cell has been deleted.
Detroit Edison
No
1. Suggest that under “Maintenance Activities” for “Protective Relays” add the following: Verify proper
functioning of the microprocessor relay external logic inputs (carrier block, etc.)
2. We recommend not requiring specific gravity and temperature readings for batteries. We have found from
experience that the time and difficulty to obtain specific gravity readings are not justified. We have found that
utilizing visual inspections, voltage and internal/intercell resistance readings gives a good picture of the health
of the battery. We use specific gravity readings on occasion for troubleshooting purposes.
3. It is recommended that the sections about verifying battery charger performance be eliminated if there are
low voltage alarms that go to a monitored location.
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4. We recommend changing the maximum maintenance interval for DC supplies with no battery from 18
months to 3 years. If there is no battery, you do not have the risk of failure of chemical processes and such
that would require an interval as short as 18 months.
Response: Thank you for your comments
1. The SDT has modified the standard in consideration of your comment. The revised activity reads as follows: For microprocessor relays, check the
relay inputs and outputs that are essential to proper functioning of the Protection System
2. Thank you for your comments regarding DC supply. The SDT has modified the standard in consideration of your comment. The requirement to
measure specific gravity and temperature of each cell has been deleted.
3. Changes have been made to the standard in consideration of your comments regarding verifying battery charger performance. The only
requirement relative to battery chargers in the latest draft of the standard (see Table 1a, pg 14) is to verify the float voltage.
4. The SDT disagrees; the 18-month interval includes several items that can be verified only by physical inspection; that are independent of chemical
processes, and that affect the ability of the dc supply to perform properly.
SCE&G
No
1. Table 1a Level 1 Monitoring has a requirement to “Verify the continuity of the breaker trip circuit including
trip coil” at least every 3 months. This is interpreted to be applicable to both the low-side generator output
breaker and the high-side breaker for the GSU. The generator output breaker has 3 separate trip coils (one
for each pole) that are connected in a parallel configuration and there is no means available to verify
continuity of each of these coils INDIVIDUALLY in this arrangement. Is the intent of this requirement to have
each trip signal parallel leg verified every three months even though the trip contacts are normally open
(these circuits are functionally checked during LOR Functional Verification)?
2. Also, is the Red Indication Light (RIL), which includes the trip coil in the power circuit, adequate for
verification (note that the breaker does not include the parallel legs that contain the tripping sensor contacts)?
3. Also, more clarification is needed on the section “Verify proper functioning of the current and voltage circuit
inputs from the voltage and current sensing devices to the protective relays” under “Voltage and Current
Sensing Devices Inputs to Protective Relays.” How would this be done if no redundancy is available for crosschecking voltage and current sources?
4. In certain situations, “verify proper functioning” is not clear enough. Documentation of verification consistent
with the entities procedures should be adequate to indicate compliance.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard to remove the requirement cited in your comment.
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2. The SDT has modified the standard to remove the requirement cited in your comment.
3. The Supplementary Reference Document, Section 15.2 (page 21) and FAQ II-3 (page 8) provides several discussions on this item.
4. Documentation of verification consistent with your procedures is sufficient to “verify proper functioning”
Dynegy
No
Table 1a requires entities to "verify the continuity of the breaker trip circuit including trip coil..." The term
"verify" needs clarification. For example, we believe verifying red and green" lights during routine inspection
should be sufficient. On the other hand, actual testing is not feasible and is risky to reliability.
Response: The SDT thanks you for your comment, and has modified the standard to remove the requirement cited in your comment.
Nebraska Public Power District
No
1. Table 1a, for Protective Relays identifies the following Maintenance Activities: Test and calibrate the relays
(other than microprocessor relays) with simulated electrical inputs. Verify proper functioning of the relay trip
outputs. What is the difference between these two requirements? They appear to be practically equivalent.
2. Tables 1a & 1b, for Station DC supply identify the following Maintenance Activity: Measure that specific
gravity and temperature of each cell is within tolerance (where applicable). What is the advantage of testing
the SG in every cell compared to using a pilot cell as representative sample of the entire bank? NPPD has
not experienced any problems using a pilot cell compared to testing every individual cell. Typically, if the SG
is low the cell voltage will be low, which is detected by the voltage test. This seems to be an excessive
requirement and does increase personnel exposure to hazardous fluid. What unique information is provided
by this test that other tests do not provide?
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment. The activity to “verify proper functioning of the relay trip outputs was
changed to: Verify that settings are as specified.
2. The SDT thanks you for your comments regarding DC supply and has made changes to the standard in consideration of your comments. The
requirement to measure specific gravity and temperature of each cell has been deleted.
ENOSERV
No
1. Table 1A, protective relays for 6 calendar years, Testing and calibrating the relays other than
microprocessors relays with simulated electrical inputs... does that mean that micro processor relays do not
need to be checked?
2. Verify proper function of the relay trip outputs... Does this involve both electro AND micro processors?
Then when mentioning the verifying microprocessor relays, does that include the trip output.
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Response: The SDT thanks you for your comments.
1. Yes. The SDT has modified the standard for clarity. The maintenance activities for microprocessor relays were changed to read as follows:
For microprocessor relays, check the relay inputs and outputs that are essential to proper functioning of the Protection System.
For microprocessor relays, verify acceptable measurement of power system input values.
2. Yes. The SDT has modified the standard for clarity. The language for microprocessor relays was changed as noted in response to your first
comment; the following modification addresses all protective relays: Verify that settings are as specified.
Southern Company
No
1. Tables 1a and 1b require entities to verify the proper operation of voltage and current inputs to sensing
devices on a 12 year interval. The Protection System Supplementary Reference (Draft 1), in section 15.2,
describes several methods that may be used for such verification efforts. In order to perform this type of
verification the circuit in question would need to be in operation. This verification introduces a possible unit trip
due to the need to connect test equipment to live potential and current circuits at each relay, which has the
potential to trip the circuit under test. This could result in the loss of critical transmission lines or generating
units. The System Maintenance Supplementary Reference also allows saturation tests or circuit
commissioning tests to satisfy this requirement; however, these types of tests require the circuit in question to
be removed from service. For generating plants, removing the circuit from service requires that the station be
shut down. We do not feel that the value obtained from this requirement is equal to the risk or maintenance
burden associated with it. Such testing and verification should not be required periodically, but only if new
instrument transformers, cabling or protective devices are installed or if the instrument transformers are
replaced.
2. Table 1b: Protection System Control Circuitry (Trip Coils and Auxiliary Relays) “ Experience has shown
that electrically operating partially monitored breaker trip coils, auxiliary relays, and lockout relays every 6
years is not warranted. This testing introduces risk from a human error perspective as well as from additional
switching and clearances required. We recommend eliminating this maintenance requirement.
3. Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS Systems Only) - Table 1b includes the
statement "Verification does not require actual tripping of circuit breakers or interrupting devices." This
statement should be included in Table 1a.
4. In Table 1a “Station DC Supply (that has as a component any type of battery), we recommend changing
the maximum maintenance interval from 3 months to 6 months as described below.
5. “Verify Proper Electrolyte Level “3 Months - The 3 months interval for verifying proper electrolyte level is
excessive for current battery designs that are properly maintained. The interval in which the electrolyte must
be replenished is affected by many factors. These include temperature, float voltage, grid material, age of the
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battery, flame arrester design, frequency of equalization, and electrolyte volume in the battery jar.
Manufacturers are aware that their customers want to extend the interval in which their batteries require water
and this has lead to jar designs that have a wide min-max band with a high volume of electrolyte to allow for
extended watering intervals. Understanding all the factors and proper maintenance will extend watering
intervals. A battery should go a year or more between watering intervals and some as many as 3 years.
Being conservative the Southern Company Substation Maintenance Standards require that we check the
electrolyte level twice yearly. Experience has shown this has worked well. We propose that the “3 Months”
interval be changed to “6 months”.
6.”Verify proper voltage of the station battery “3 Months - Being conservative, the Southern Company
Substation Maintenance Standards require that we check the station battery voltage twice yearly. Experience
has shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”.
7.” Verify that no dc supply grounds are present “3 Months Being conservative, the Southern Company
Substation Maintenance Standards require that we check for dc supply grounds twice yearly. Experience has
shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”.
8. Measurement of Specific Gravity 18 Months- The measurement of specific gravity and temperature every
18 months is not necessary as a regular part of maintenance. Specific gravity can provide information as to
the health of a cell; however, taking specific gravity readings is a messy process no matter how careful you
are and will result in acid being dripped on top of the battery jars as the hydrometer is moved from cell to cell.
Should a drop of acid end up on an external connection, it will result in corrosion and problems later. Voltage
reading of cells can be substituted for specific gravity readings under normal conditions. Specific gravity is
equal to the cell voltage minus 0.85. A cell with low voltage will have a low specific gravity. If cell voltage
becomes a problem that cannot be addressed through equalization then specific gravity readings are justified
as a follow-up test. Since measurement of specific gravity could lead to problems and reading cell voltage is
a viable alternative, we propose that it be removed from the battery maintenance activities.
9. Verify Cell to Cell and Terminal Connection Resistance 18 Months - Clarification is needed on the expected
method for verifying cell to cell and terminal connection resistance. This could easily be interpreted as
requiring the use of an ohmic value (impedance/conductive/resistance) test device. If this is the case then
basically it eliminates the need for the activity to “Verify that the substation battery can perform as designed
by performing a capacity test every 6-Calendar Years or performing an ohmic value test every 18 Months”,
because the practical thing to do is go ahead and perform the ohmic value test while you have your device
connected to the battery.
10. In table 1a and 1 b - Station dc supply (that has as a component -Vented Lead-Acid batteries). Verify that
the Substation Battery can Perform as Designed 6 Calendar Years/18 Months - Southern Company
Transmission has approximately 570 batteries that are covered by this proposed standard. These batteries
currently have ohmic value testing performed every “4 Years” as required by the Southern Company
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Substation Maintenance Standards. The “4 Years” interval has been utilized for over 10 years and has not
experienced a failure of any of the 570 batteries to perform as designed Having to perform ohmic value
testing on an “18 Months” interval will significantly increase our costs and manpower requirements with no
anticipated improvement in reliability. We propose that the “18 Months” interval for ohmic value testing be
changed to “4 Calendar Years”. This proposal also applies to verifying cell to cell and terminal connection
resistance if an ohmic value test device is required as discussed above.
11. In table 1a and 1b Station dc supply (that uses a battery and charger). Verify that the Battery Charger can
Perform as Designed 6 Calendar Years - Clarification is needed on an acceptable method for verifying that
the battery charger can perform as designed by testing that the charger will provide full rated current and will
properly current limit, especially the part about “will properly current limit”.
12. On Table 1b Station DC Supply (that has a component any type of battery) we recommend changing the
maximum maintenance interval from 3 months to 6 months as described below “ Verify Proper Electrolyte
Level “ 3 Months - The 3 months interval for verifying proper electrolyte level is excessive for current battery
designs that are properly maintained. The interval in which the electrolyte must be replenished is affected by
many factors. These include temperature, float voltage, grid material, age of the battery, flame arrester
design, frequency of equalization, and electrolyte volume in the battery jar. Manufacturers are aware that
their customers want to extend the interval in which their batteries require water and this has lead to jar
designs that have a wide min-max band with a high volume of electrolyte to allow for extended watering
intervals. Understanding all the factors and proper maintenance will extend watering intervals. A battery
should go a year or more between watering intervals and some as many as 3 years. Being conservative the
Southern Company Substation Maintenance Standards require that we check the electrolyte level twice
yearly. Experience has shown this has worked well. We propose that the “3 Months” interval be changed to
“6 months”.
13. We recommend removing the “Detection and alarming of dc grounds” monitoring attribute. Note that this
applies to every “Station dc supply” section where it is listed. .Experience has shown that there have been no
significant problems discovered via alarms that would not have been discovered by 6 month inspection
cycles. We propose to add “verify no dc grounds are present” as a maintenance activity on a 6 months
inspection cycle. Experience has shown that there have been no significant problems discovered via alarms
that would not have been discovered by 6 month inspection cycles.
14. Table 1a, p. 7, Station dc supply, 3 month interval: need to add “unintentional” to the sentence “Verify
that no dc supply grounds are present.” Because most dc systems have ground detection systems which
place an intentional ground on the battery. “No grounds” is not practical and is unacceptable since most dc
systems have some high resistance ground paths. Some criteria should be established to determine the
acceptable ground resistance on a dc system.
15. Table 1a, p. 8: For the vented, lead-acid battery, there is no basis for the 18 month activity option
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(internal ohmic value measurement) in place of the 6 year performance test.
16. The activities for trip checks for Level 1A and Level 1B should be the same. Currently, they read: Level
1a: Perform a complete functional trip test that includes all sections of the Protection System trip circuit,
including all auxiliary contacts essential to proper functioning of the Protection System. Level 1b: Verify that
each breaker trip coil, each auxiliary relay, and each lockout relay is electrically operated within this time
interval. The Level 1a text is adequate for 1b also.
17. Table 1c, p 16: Monitoring of single or parallel trip circuits is not practical where multiple normally open
contacts are in series to trip. Monitoring of the trip coils is practical and useful. How would one monitor
several normally open contacts which are in series to trip a breaker?
18. Table 1c, p. 15, 16, 19: The use of “continuous” under “Maximum Maintenance Interval” in Table 1c
should be changed to “N/A” and the Maintenance Activity should be “NONE”.
19. Verification of the various monitoring (automated notification) systems is not specified anywhere in the
requirements. This, too, should be required.
Response: The SDT thanks you for your comments.
1. The SDT believes that proper functioning of the sensing devices is a vital component of the Protection System performance, and that they must be
maintained as specified in the Standard. To minimize system impact of such maintenance and possible errors, the maintenance necessarily should be
scheduled at a time that minimizes the risks.
2. The SDT believes that proper functioning of the Protection System Control Circuitry is a vital component of the Protection System performance and
those must be maintained as specified in the standard. To minimize system impact of such maintenance and possible errors, the maintenance
necessarily should be scheduled at a time that minimizes the risks
3. The SDT has modified the standard in consideration of your comment. The following was added to Table 1a:
Type of Component - Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS Systems Only)
Maximum Maintenance Interval - 6 Calendar Years
Maintenance Activity - Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits, including all
electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System, except .that verification does not require actual
tripping of circuit breakers or interrupting devices.
4. Please see responses 5, 6 and 7 (below) for discussion regarding your concern about extending the Maximum Maintenance Intervals for an extra 3
months on activities related the station dc supply.
5. The SDT agrees that a healthy modern lead acid battery can go for extended periods of time beyond 3 months without requiring watering. However,
checking cell electrolyte level not only indicates the need for battery watering, it is an indication of an individual cell’s health and needs to remain at
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the Maximum Maintenance Interval of 3 months. To avoid the confusion that the Maintenance Activity listed in Table 1 was to water the battery at the
specified 3 month interval, the Drafting Team has changed the wording of the Maintenance Activity from “verify proper” to “check” electrolyte level.
6. Thank you for your comment to extend the Maximum Maintenance Interval for checking the station dc supply voltage. The SDT believes that
extending the Maximum Maintenance Interval beyond that listed in Table 1 would compromise the performance of the station dc supply.
7. Due to the consequences of unintentional grounds to the station dc control system, the SDT feels that extension of the Maintenance Intervals
beyond the 3 month interval is not prudent. See FAQ IV-2-F (Page 23).
8. Changes have been made to the standard in consideration of your comments regarding specific gravity testing, and the revised standard does not
include a requirement to perform this maintenance activity.
9. Thank you for your comments concerning performance of ohmic measurement at the same time that connection resistance is measured. As you
suggested, these two measurements could be taken at the same time to meet the requirements of their respective Maintenance Activities.
10. Thank you for your comments concerning evaluating internal ohmic values and measurement of battery connection resistance for Vented Lead-Acid
(VLA) batteries. As noted in your comment an owner has two different Maintenance Activities with associated different Maximum Maintenance Intervals
to choose from in verifying that the VLA station battery can perform as designed.
FAQ II-5-F (page 14) and II-5-G (page 14) provides an explanation of why there are two different intervals for these Maintenance Activities is given.
Because trending is an important element of ohmic measurement evaluation, the SDT believes that extending the Maximum Maintenance Interval listed
in Table 1 for evaluating internal ohmic values to four years as suggested would not provide the necessary information for proper evaluation of the
ability of the station battery to perform as designed.
Concerning verifying cell to cell and terminal connection resistance as part of inspecting the battery, various technical references on Lead-Acid
battery maintenance talk about how and why this Maintenance Activity should be performed at the Maximum Maintenance Interval listed in Table 1.
The SDT believes that to extend this inspection activity for the connections of a Lead-Acid battery beyond the Maximum Maintenance Interval would
compromise the performance of the station dc supply.
11. The SDT has modified the standard in consideration of your comment regarding battery charger performance. The only remaining maintenance
activity relevant to the battery charger is to verify the float voltage.
12. The SDT agrees that a healthy modern lead acid battery can go for extended periods of time beyond 3 months without requiring watering.
However, checking cell electrolyte level not only indicates the need for battery watering, it is an indication of an individual cell’s health and needs to
remain at the Maximum Maintenance Interval of 3 months. To avoid the confusion that the Maintenance Activity listed in table 1 was to water the
battery at the specified 3 month interval, the Drafting Team has changed the wording of the Maintenance Activity from “verify proper” to “check”
electrolyte level.
13. Thank you for your comments concerning the monitoring attribute for unintentional dc grounds on the station dc supply. Due to the consequences
of unintentional grounds to the station dc control system (see FAQ II-5-I, page 15), the SDT feels that monitoring for them is an important part of an
effective condition based maintenance program and should be an option available for those who want to perform condition based maintenance. Also
because the threat to the dc system and the BES that unintentional dc grounds create, the SDT feels that extension of the Maintenance Intervals for
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checking for unintentional dc grounds beyond the 3 month interval is not prudent. See FAQ IV-2-F (page 23).
14. The SDT has modified the standard in consideration of your comment regarding dc grounds – the word, “unintentional” was added as proposed.
15. The SDT thanks you for your comment concerning ohmic value measurements. The FAQ II-5-F (page14) includes an explanation for the basis of
this activity. The SDT believes that this Maintenance Activity is a viable alternative that a Vented Lead-Acid battery owner can perform at the Maximum
Maintenance Interval of Table 1 in place of conducting a performance, modified performance or service capacity test.
16. For Table 1b, much of the DC control circuit is, by definition, being monitored; therefore, the only requirement is that the electromechanical devices
be exercised.
17. With the detail provided in your comment, it appears to the SDT that you would not be able to use Table 1c in this example.
18. “Continuous” is intended to clarify that the maintenance is being performed continuously via the monitoring system and the Activities portion of
the table is intended to state those activities that are being performed by the monitoring system.
19. This verification is established within the “General Description” at the top of Table 1c as generic criteria to use this table.
Transmission Owner
No
a. Tables 1a, 1b & 1c should offer as an alternative, measuring battery float voltages and float currents in lieu
of measuring specific gravities as described in Annex A4 of IEEE Std 450-2002.
b. Inspection of CVT gaps, MOVs and gas tubes should be added to the communications equipment time
based maintenance tables. Failure of the CVT protective devices may cause failure of the Protection System.
c. Maintenance Activities for UVLS or UFLS station dc supplies shows “Verify proper voltage of dc supply”.
Does this imply that, except for voltage readings of the dc supply, distribution battery banks are not
maintained?
d. Why does the Maintenance Activities for UVLS or UFLS relays state that verification does not require
actual tripping of circuit breakers?
e. Please clarify the Maintenance Activities for Voltage and Current Sensing Devices. Must voltage, current
and their respective phase angles be measured at each discrete electromechanical relay?
Response: The SDT thanks you for your comments.
a. The SDT has modified the standard in consideration of your comment regarding dc supply. All references to measuring specific gravities have been
removed from the revised standard – and for Table 1a for station dc supply, the language was revised to require, “Verify float voltage of battery
charger.”
b. Power line carrier channels are made up of many components that must be maintained on a periodic basis. This standard indicates that adequate
maintenance and testing must be done to keep the performance of the channel at a level that meets the requirements of the relay system. The
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determination of specific maintenance activities is the responsibility of the Entity.
c. This standard limits the maintenance requirements of distribution system batteries to those used for UVLS and UFLS and constrains those
requirements to verification of proper voltage. If “distribution system” batteries are used for any other BES Protection System applications, they must
be maintained according to the other requirements of this standard.
d. The SDT believes that the UFLS scheme is predominantly based within the distribution sector. As such, there are many circuit interrupting devices
that will be operating for any given under-frequency event that requires tripping for that event. A failure in the tripping-action of a single distribution
breaker will be far less significant than, for example, any single Transmission Protection System failure such as a failure of a Bus Differential Lock-Out
Relay. While many failures of these distribution breakers could add up to be significant, it is also believed that distribution breakers are operated often
on just fault clearing duty and therefore the distribution circuit breakers are operated at least as frequently as any requirements that might have
appeared in the standard.
e. Not exactly. The requirement is that the entity must verify that proper voltage, current, and phase angle is delivered to the relays. The standard does
not prescribe methodology. See FAQ II-3-A (page 8) and the Supplementary Reference Document, Section 15.2 (page 21) for a discussion on this
topic.
Pepco Holdings Inc.
No
1. Tables 1a, 1b and 1c all require measuring specific gravity and temperature of battery cells. This invasive
test provides no information regarding battery health that cannot be obtained from cell impedance testing.
Recommend requiring cell impedance OR specific gravity & cell temperature testing.
2. Tables 1a, 1b and 1c all require testing the battery charger every 6 years to verify that it can provide full
rated current and will properly current limit. In order to perform this (unnecessary) test the battery would be
subjected to a deep discharge. Whatever benefits may be derived from this test are dwarfed by the negative
effect on the battery. Recommend removing this requirement.
Response: The SDT thanks you for your comments.
1. The SDT has made changes in consideration of your comments regarding measuring of specific gravity and temperature of battery cells and
removed this maintenance activity from the revised standard.
2. The SDT has modified the standard in consideration of your comments regarding battery charger performance. All maintenance activities relating to
the battery charger were removed except for verification of the float voltage.
Illinois Municipal Electric Agency
No
1. The Illinois Municipal Electric Agency (IMEA) is concerned the minimum maintenance activities may be too
prescriptive for transmission subsystems that essentially operate radially.
2. Please see comment under Question 7.
3. Also, IMEA supports comments submitted by Florida Municipal Power Agency regarding applicability to
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UFLS systems.
Response: The SDT thanks you for your comments.
1. This standard applies Protection Systems that that are applied on, or are designed to provide protection for the BES. The SDT believes that the level
of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address observations from the Compliance
Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also specifies that NERC Standards should
be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to implement an effective PSMP.
2. Please see our response to your comments under Question 7.
3. The SDT has responded to the FMPA comments regarding UFLS systems.
Consumers Energy Company
No
1. The second sentence in Note 1 on page 20 should be changed to “A calibration failure is when the relay is
inoperable and cannot be brought within acceptable parameters.”
2. Note 2 should be changed to “Microprocessor relays typically are specified by manufacturers as not
requiring calibration. The integrity of the digital inputs and outputs will be verified by applying the inputs and
verifying proper response of the relay. The A/D converter must be verified by inputting test values and
determining if the relay measurements are correct.”
Response: The SDT thanks you for your comments.
1. The standard establishes a calibration failure to be any condition where the relay is found to be out of tolerance, whether or not it can be restored
to acceptable parameters. The condition described is a calibration failure that is also a “maintenance correctable issue” as established in
revisions to R4 and the resulting footnote, and requires more extensive action to resolve.
2. Note 2 has been removed and the relevant requirements added to the Tables themselves. There are methods, other than inputting test values, to
verify the A/D converter.
American Transmission
Company
No
1. The Standard should focus on identifying the types of components to be tested but should not identify the
specific maintenance activities that must be performed. Entities should be allowed the flexibility to develop
and implement the appropriate maintenance activities necessary for each identified component.
2. ATC is also concerned with the expressed identification of maintenance intervals. We do not believe that
the standard should identify specific maintenance intervals but that it should require entities to identify their
maintenance intervals appropriate for their system. If the team continues to pursue specific maintenance
intervals it will be establishing the industries practices.
3. Specific Concern: The standard identifies that entities should perform complete functional testing as part of
its maintenance activities, but we are concerned that this could lead to reduced levels of reliability, because it
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requires entities to remove elements from service and then requires entities to perform tests that are
inherently prone to human errors. We believe that the perceived benefits do not match the anticipated costs
or improve system reliability.
Response: The SDT thanks you for your comments. As you are probably aware, protection systems have contributed to most major events, indicating
a need to provide greater “defense in depth” to the body of standards. While many facility owners do have effective protective system maintenance
programs, some do not – which puts the grid at risk.
1. Specific activities are defined where necessary to implement an effective PSMP, and has provided for flexibility where there are multiple methods
that will be effective.
2. FERC Order 693 expressly directs NERC to develop maximum maintenance intervals.
3. The SDT believes that complete functional testing is a vital component of the Protection System performance, and must be performed as specified
in the standard. To minimize system impact of such maintenance and possible errors, the maintenance necessarily should be scheduled at a time
that minimizes the risks.
Wolverine Power Supply
Cooperative, Inc.
No
The tables are too prescriptive - The standards should state what, not how.
Response: The SDT thanks you for your comments. The SDT believes that the level of prescription within the standard is necessary to satisfy the
guidance in FERC Order 693, and also to address observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC005-1 is excessively general. FERC Order 672 also specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined
the minimum activities necessary to implement an effective PSMP.
Northeast Power Coordinating
Council
No
1. We agree there is a need for minimum maintenance activities; however, the standard does not clearly
define the differences between Table 1a, 1b, and 1c. It is recommended that the drafting team develop
definitions for the equipment listed in these tables. For example, Table 1a equipment consists of mechanical
and solid state equipment without monitoring capability, Table 1b consists of mechanical and solid state
equipment with monitoring capability, and Table 1c consists of equipment capable of self monitoring.
2. In addition, all battery, charger and power supply maintenance activities should be removed from Table 1a,
1b, and 1c, and summarized in a separate Table (i.e. Table 2). Tables 1a and 1b for 'Station dc supply (that
has as a component any type of battery) and Table 1c for 'Station dc Supply (any battery technology) for an
18 Month 'Maximum Maintenance Interval' identifies the need to 'Measure that the specific gravity and
temperature of each cell is within tolerance (where applicable).'
3. Following industry best practices, we would recommend using the MBRITE diagnostic test. MBRITE
testing provides more information than a specific gravity test while reducing the risk of injury to testing
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personnel.
4. In Table 1a, the Type of Component “Protection system communications equipment and channels.” has a 3
month “Maximum Maintenance Interval”. Clarification needs to be provided as to how an unmonitored (do not
have self-monitoring alarms) will be tested.
5. Table 1a refers to “Unmonitored Protection Systems”. The “6 Calendar Years” “Maximum Maintenance
Interval” “Maintenance Activities” is excessive.
Response: The SDT thanks you for your comments.
1. The component differences between Table 1a, Table 1b, and Table 1c are described in the header to the Tables and in the specific monitoring
attributes for the specific component types. Please see the decision trees near the end of the FAQ document (pages 33-37).
2. The SDT believes that the Station DC Supply component should be addressed with the other components, and has simplified the Tables in
consideration of your comments.
3. The DC Supply component has been modified, and no longer specifically requires specific gravity testing.
4. See FAQ II-6-B (page 16) for a discussion of a number of methods to test the communications systems.
5. Your comment is unclear, and the SDT is unsure how to respond. The SDT believes that the level of prescription within the standard is necessary
to satisfy the guidance in FERC Order 693, and also to address observations from the Compliance Monitoring entities (the Regional Entities and
NERC) that PRC-005-1 is excessively general. FERC Order 672 also specifies that NERC Standards should be clear and unambiguous. The SDT
has therefore defined the minimum activities and maximum intervals necessary to implement an effective PSMP. Some entities may feel that they
need to maintain Protection System components more frequently.
Lower Colorado River Authority
No
We agree with all stated intervals except for the maximum stated interval of 6 years for Protection System
Control Circuitry (Trip Coils and Auxiliary Relays) in tables 1b and 1c. What was the intent of separating this
interval out from the Protection System Control Circuitry (Trip Circuits), which is 12 years for monitored
components? Monitoring of the trip coils should be enough to justify a maximum interval of 12 years. As
stated these requirements will put an undue financial and resource burden on utilities that have updated their
protective relay systems with state-of “the art components and monitoring. In addition to the expense and
effort of scheduling the additional maintenance, the additional validation of lockouts and auxiliary relays,
separate from the full function testing could lead to additional human errors and accidental tripping of circuits
while testing. We believe there should be one stated activity “Protection System Control Circuitry and have a
maximum interval of 12 years for monitored systems.
Response: The SDT thanks you for your comments.
Monitoring of the coil of these devices does not assure that the device will mechanically operate properly. Electromechanical devices such as lockout
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relays and auxiliary relays must be exercised periodically to assure proper operation. The monitoring systems cannot perform this. See
Supplementary Reference Document Section 15.3 (page 22).
Ameren
No
We agree with the vast majority of them, listed below are our few concerns, questions, and pleas for
clarification.
1) We disagree with doing specific gravity and temperature of every cell in the 18 month test because the
other tests being done are already comprehensive.
2) FAQ 3B p 29 digital relay A/D verification should include simply comparing digital relay displayed metered
values to another metered source.
3) FAQ 3A p6 Change “prove that” to “verify”. For single CT or VT, this can be challenging and some
measure of reasonableness in determining an expected value comparable to the measured value must be
acceptable.
4) FAQ 1B p17 Combining evidence forms of “Process documentation or plans” and “Data” or “screen shots”
shows compliance. Please add an example or verbiage to clarify that a field technician’s (or operator)
recorded check-off combined with a company’s process is sufficient evidence. Otherwise documentation
alone could consume considerable field personnel time.
5) FAQ p2 Add FAQ to clarify “verify settings”. If EM relays are included, explain that minor tap or time dial
differences of the order of relay tolerances are acceptable. For digital relays state that software compare
functions are a sufficient means to “verify settings.”
6) Omit Table 1b row 3 because row 4 actually applies to Monitoring Level 2 Trip Circuits. Row 3 already
appears in Table 1a, and repeating it in Table 1b is confusing.
7) FAQ 4D p 7 then defines auxiliary relays as device 86 and 94. Does device number nomenclature or
function determine and restrict inclusion?
8) Please state that “a location where action can be taken for alarmed failures” would include a dispatch
center or control room. From there the custodial authority would be called out to take action.
9) Please explain the expansion from station battery to station DC supply, specifically the addition of the
charger, an AC to DC device.
10. The charger load test up to its current limiter would add a significant amount of work with little known
benefit.
11. Have charger problems been a significant cause of cascading outages?
12) We oppose your expansion of Station DC Supply to UFLS (the last row on page 8.) PRC-008-0 is
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restricted to UFLS equipment. UFLS is often applied in distribution substations to trip feeders directly serving
load. Your scope expansion has the potential to greatly increase the number of substation DC Supplies
covered by NERC standards. ,. While we agree that UFLS is BES applicable, and those substations are
included in our overall maintenance program, this expansion to NERC scrutiny is not warranted. Have there
been UF events in which a material amount of load was not shed because of DC problems? UFLS is spread
out amongst many distribution stations, and even if a couple did fail to trip in an underfrequency event, it
would have little effect.
13) FAQ 2 p 17 expands the scope at Generating Facilities so that system connected station auxiliary
transformers would be included. We oppose this expansion as these are radially served loads, and they often
do not result in generation loss. Even if they did, the BES can readily tolerate the loss of a single generator.
Response: The SDT thanks you for your comments.
1. All references to specific gravity and temperature testing have been removed from the revised standard.
2. The FAQ has been revised and reorganized in response to many industry comments; see FAQ II-3 (all subsections – pages 8-10) for a discussion of
this topic.
3. The FAQ has been revised and reorganized in response to many industry comments; see FAQ II-3 (all subsections – pages 8-10) for a discussion of
this topic.
4. The FAQ has been revised and reorganized in response to many industry comments; see FAQ IV-1-B (page 21)
5. See FAQ II-2-D & II-2-E(pages 6-7).
6. Table 1a and Table 1b each stand alone; use the table that is relevant to the level of monitoring that is implemented.
7. The SDT modified the FAQ to remove references to the IEEE device numbers (page 11) except when essential to respond to the question.
Regardless of how the device is described by internal entity nomenclature, the function of the device determines whether it is included within the
standard.
8. Your suggestion is properly considered as an example. See FAQ V-1-A (page 28).
9. The SDT believes that the charger is an integral portion of the Station DC supply; thus it has been added. The SDT has modified the standard to
simplify the requirements related to maintenance of the battery charger.
10. The SDT modified the standard in consideration of your comment. All maintenance activities pertaining to battery chargers have been removed
except verification of the float voltage.
11. The standard addresses overall Protection System reliability, not only those issues that may cause cascading outages.
12. The SDT believes that verification of the DC supply voltage to the UFLS is not burdensome. The SDT has modified the standard to clarify that the
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only DC Supply requirement relevant to UFLS is to verify the DC supply voltage.
13. Station service transformers are essential to starting the plant during grid recovery. The FAQ clarifies why these elements are included. The
standard addresses overall Protection System reliability, not only those issues that may cause extreme outages.
Manitoba Hydro
No
1. What documentation or evidence is required to prove that the Protection System Control Circuitry has been
maintained every three months, if just a visual inspection of the breaker control trip circuit RED panel light has
been completed, to verify continuity of breaker trip coil?
2. How do we handle breakers with dual trip coils and only one RED light for trip coil continuity?
3. What do the terms DISTRIBUTED and CENTRALIZED with respect to UFLS mean?
4. In Table 1C under the heading "Maximum Maintenance Interval” some of the entries are stated as being
"Continuous". In the case of other maintenance activities the descriptor for Maintenance Interval indentifies
the maximum period of time that may elapse before action must be taken. "Continuous" implies continuous
action; however, in reality continuous monitoring enables no maintenance action to be taken until such time
as trends indicate the need to do so. Therefore we recommend that where the maintenance interval is stated
as "Continuous" it should be changed to read "Never" or "Not Applicable".
5. The Table 1A requirement of 3 months for Protection System Control Circuitry (Breaker Trip Coil Only)
(except for UFLS or UVLS) should be omitted as it is not realistic. Recommend following the Table 1B
requirement of 6 years (Trip testing) for this. Does 27 undervoltage monitoring of this circuit qualify as self
monitoring?
Response: The SDT thanks you for your comments.
1. The requirement to which you refer has been removed. See FAQ IV-1-B (page 21) for a general discussion of documentation.
2. The SDT has modified the standard to remove the requirement cited in your comment.
3. See FAQ II-7-C (page 18) and FAQ II-8-E (page 19A).
4. Continuous” is intended to clarify that the maintenance is being performed continuously via the monitoring system and the Activities portion of the
table is intended to state those activities that are being performed by the monitoring system.
5. The SDT has removed this requirement.
CPS Energy
No
While I agree for the most part, there are some activities that are unclear.
1. Specifically, the testing of voltage and current sensing devices, some of the trip coil testing, and some of
the communications testing. If the trip coil is now going to be included in the definition of the protective
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system, is the testing defined adequate?
2. The testing of the voltage and current sensing devices is not entirely clear.
Response: The SDT thanks you for your comments.
1. The listed activities are contemplated as minimum activities and do not preclude an entity from performing additional activities.
2. See the Supplementary Reference Document, Section 15.2 (page 21) and FAQ II-3-A (page 19) for a discussion of this topic.
AECI
No
1. Tables 1a and 1b Station DC Supply: Requirement is to measure specific gravity and temperature of
every cell. We believe that this test is unnecessary if voltage and internal resistance are measured. This
test should only be required if other tests indicate a problem, or if the voltage and internal resistance tests
are not performed.
2. Tables 1a and 1b Station DC Supply (Valve Regulated Lead-Acid Batteries): Will a limited discharge test
be acceptable as a “performance or service capacity test” or is full discharge required? We believe a full
discharge test will decrease battery life and suggest that only a limited discharge test be performed.
3. Tables 1a and 1b Station DC Supply (Vented Lead-Acid Batteries): What is the definition of “modified
performance capacity test?”
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment concerning station dc supply and has removed the requirement to measure
specific gravity and temperature of every cell.
2. The SDT does not feel that conducting a performance or service capacity test at the intervals prescribed in the standard will cause any appreciable
decrease in battery life over the service life of the battery. The Protection System owner is responsible for maintaining a station dc supply that can
perform as designed and conducting a performance or service capacity test will verify that a VRLA battery will satisfy the design requirements (battery
duty cycle) of the dc system that a limited discharge test might not verify. If you are concerned that such a test may have implications on battery life,
the standard provides an option to instead measure and trend internal cell/unit ohmic values on a 3-month interval.
3. How to conduct a modified performance test for Vented Lead-Acid Batteries is explained in detail in various available reference books. For Vented
Lead-Acid Batteries, it is a capacity test where the discharge rate(s) are modified to cover every portion of the battery’s duty cycle.
Puget Sound Energy
June 3, 2010
No
For all tables, PSE agrees with the majority of the minimum maintenance activities established. However, the
Station DC supply maintenance activities raise concern. The requirement to test that the charger will provide
full rated current versus output seems to be excessive. In many cases the charger is rated far in excess of
the output needed to perform its function. Also PSE is not aware of a known industry test for these and it is
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not an IEEE recommended standard. Finally, PSE is unclear whether this test would diminish the charger.
Response: The SDT thanks you for your comments. The SDT modified the standard in consideration of your comment regarding battery chargers.
The maintenance activities for battery chargers have been modified to remove all activities except for verification of the float voltage.
SERC (PCS)
Yes
We agree with the majority of the activities. Below is an example where clarification is needed.
1. “Verify proper functioning of the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays” under “Voltage and Current Sensing Devices Inputs to Protective Relays.”
How would this be done if no redundancy is available for cross-checking voltage and current sources?
2. In certain situations, “verify proper functioning” is not clear enough. Documentation of verification consistent
with the entities procedures should be adequate to indicate compliance.
Response: The SDT thanks you for your comments.
1. The standard is prescribing what needs to be done, not how. Please refer to the Supplementary Reference Document Section 15.2 (page 21) and
FAQ II-3-A (page 19) for examples and additional discussion.
2. Documentation of verification consistent with your procedures is sufficient to “verify proper functioning”
TVA
Yes
Add clarifying statement from Table 1b for Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS
Systems Only) to the same section in Table 1a. Statement is “(Verification does not require actual tripping of
circuit breakers or interrupting devices.)"
Response: Thank you for your comment. The SDT has modified the standard in consideration of your comment. The following was added to Table 1a:
Type of Component - Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS Systems Only)
Maximum Maintenance Interval - 6 Calendar Years
Maintenance Activity - Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits, including all
electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System, except .that verification does not require actual
tripping of circuit breakers or interrupting devices.
JEA
Yes
If a communication system relies on a battery system independent of the "station battery", is this
communication system battery under the same requirements as the "station battery"?
Response: Thank you for your comment. The proper functioning of such batteries will be addressed by the verification and monitoring of the
communications system, and by addressing maintenance correctable issues related to maintenance of communication systems. See FAQ II-5-K (page
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Yes or No
Question 2 Comment
15).
Bonneville Power Administration
Yes
Electric Market Policy
Yes
Entergy Services, Inc
Yes
Georgia System Operations
Corporation
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
Saskatchewan Power
Corporation
Yes
Western Area Power
Administration
Yes
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
3. Within Table 1a, the draft standard establishes maximum allowable maintenance intervals for the various types
of devices defined within the definition of “Protection System”, where nothing is known about the in-service
condition of the devices. Do you agree with these intervals? If not, please explain in the comment area.
Summary Consideration: Most respondents disagreed with the specified maximum allowable intervals to some degree or
another. The disagreements ranged over the full spectrum of activities specified in the Tables, and often corresponded to the
disagreements related to the activities. The intervals within Table 1a were reconsidered (with minor changes – eliminating the
3-month control circuit activity) by the SDT when responding to the comments.
Organization
Yes or No
Green Country Energy LLC
No
Question 3 Comment
1) Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) also The maintenance
activity causes excessive breaker operation, and the intrusive nature increases the risk of subsequent
Misoperations on operating units. System configuration of many plants will require an extensive interruption of
total plant production to complete the test.
2) Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS systems only) The maintenance activity
causes excessive breaker operation, and the intrusive nature increases the risk of subsequent Misoperations
on operating units. System configuration of many plants will require an extensive interruption of total plant
production to complete the test.
Response: The SDT thanks you for your comments.
1. The overall Protection System Control Circuitry can be addressed in segments, as long as all portions are verified or tested as required. Depending
on the arrangement of the DC control circuit, it may be necessary to only trip the breaker itself once. See FAQ II-4-E (page 11).
2. The overall Protection System Control Circuitry can be addressed in segments, as long as all portions are verified or tested as required. Depending
on the arrangement of the DC control circuit, it may be necessary to only trip the breaker itself once. See FAQ II-4-E (page 11).
Public Service Enterprise Group
Companies
No
1) Table 1a Station dc supply (that uses a battery and charger). The 6 year test requires that the charger
perform as designed. PSE&G usually applies redundant battery chargers. PSE&G would like the drafting
team to consider if it is appropriate to not require the 6 year battery charger tests if a battery owner uses
primary and backup battery chargers. PSEG believes that the use of a redundant charger will maintain
reliability at the same level or better level as provided by testing a single charger.
2) For protection system control circuits components (breaker trip coil only), suggest that a sub category with
redundant trip coils be added with longer maintenance interval to allow for the reliability provided by
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Organization
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Question 3 Comment
redundancy.
Response: The SDT thanks you for your comments.
1. The performance of the battery charger is critical to the performance of the protection system. The SDT has modified the standard to simplify the
requirements related to maintenance of the battery charger. If condition-based maintenance is applied in accordance with Table 1b, the battery alarms
could automatically (or manually) switch to the redundant charger. Redundancy may also provide more flexibility in addressing issues discovered
during maintenance.
2. Even with redundant equipment, it is essential that all equipment be tested according to the requirements of this standard to ensure proper function
and to support the reliability advantages presented by redundancy. The requirements related to this subject have been extensively modified.
Ameren
No
1) The “zero tolerance” structure proposed combined with the large volume and complexity of Protection
System components forces an entity to shorten their intervals well below maximum. We instead propose a
calendar increment grace period in which a small percentage of carryover components would be tracked and
addressed. For example, up to 10% of all breaker trip coils subject to the 3 month “verify breaker trip coil
continuity” could carry over into the first month of the next period. And for example, up to 5% of an entity’s
communication channel 6 year verifications could carryover into the next year. These carryover components
would be addressed with high priority in that next calendar increment. There are many barriers to 100%
completion or zero tolerance. Barriers include sheer volume, obtaining outages, resource availability,
coordination, and documentation (over ten thousand components in our utility alone; taking a BES outage to
permit maintenance can incur a greater reliability risk than delaying the maintenance; emergent issues such
as major storms impact resource availability; coordination with interconnected neighbors, their resources and
maintenance timing; record keeping errors or oversights; etc. )
2) Alternatively, components with intervals less than a year should be stated in terms of the number of times
annually it should be performed, rather than a short duration interval. The expectation is that they would be
roughly equally spaced throughout the year; for example quarterly instead of 3 months. Comment 1 grace
period would still apply to components with maximum intervals of 1 year or greater.
3) Some of our maintenance intervals are shorter than maximum. Please confirm that documentation is only
to be kept for two of the entity’s intervals, not two of the maximum interval.
4) Please add standard language or FAQ near 2D on p 18 that an entity can validly use an interval with %
tolerance to achieve maintenance goals, as long as the applicable maximum interval is honored.
Response: The SDT thanks you for your comments.
1. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals
would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace
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Organization
Yes or No
Question 3 Comment
period” would not conform to this directive.
2. Simply stating the number of times annually that these devices must be maintained, with a tacit expectation that the maintenance be spaced
throughout the year, does not ensure that they will be tested thusly. To achieve the periodicity of the testing, it is essential that the requirement
specify such periodicity. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the
established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and
allowing for a “grace period” would not conform to this directive.
3. The data retention has been modified in consideration of your comments. The revised language reads as follows:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation of the two most recent performances of each
distinct maintenance activity for the Protection System components, or to the previous on-site audit date, whichever is longer.
4. You may define your program within the parameters expressed within the standard as long as you adhere both to your program and to the Standard.
Exelon Generation Company,
LLC
No
1. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's
refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing
of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing
programs.
2. Table 1a page 6 regarding the 3 Month "Protection System Control Circuitry (Breaker Trip Coil Only)
(except for UFLS or UVLS)" states that the maintenance activity shall verify the continuity of the breaker trip
circuit including the trip coil. There is unclear guidance on how this activity is to be performed, particular on
generator output breakers. Does this activity imply actual trip testing of the breaker itself? If so, performing
this type of activity with the generator on-line puts the unit at risk without any commensurate increase in
reliability to the bulk electric system. If this is the case it is requested that this particular test is extended from
3 months to 24 months to align with nuclear generating units refueling cycle. If not, and this activity is simply
verification of continuity by means of light indication; then please clarify in Table 1a.
Response: The SDT thanks you for your comments.
1. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document
for a discussion on this issue.
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Yes or No
Question 3 Comment
2. The SDT has removed this requirement.
Entergy Services, Inc
No
1. A 3 month interval activity is likely to drive an entity to perform that activity every 2 months in a zero
tolerance, 100% completion, mandatory compliance environment. There should be an allowance for a grace
period on monthly designated activities, for instance a one month grace period, unless the intention is to have
the activity performed more frequently than indicated. Additional guidance is needed on the monthly interval
designations. Is it okay, for instance, to do all four tasks (3 month interval) at one time? Instinctively the
answer should be "no", but if following the "calendar year" allowance, then maybe it is. Are we non-compliant
on a 3 month interval task if we go one single day over the due date? Instinctively the answer should be "no",
but some additional guidance should be provided. For example, the standard might be more understandable if
it indicated that if the interval is "four per year" (or 3 month interval), then it is allowed to perform these tasks
no less than 45 days apart from each other as long as four are done within a calendar year, etc.
2. We believe the 3 month trip coil task activity could actually shorten the life of the trip coil, introduce
unpredictable trip coil failures, and increase the risk of an in-service failure of the trip coil if the verification is
done by tripping the breaker each time. Increasing the risk of failure is counter-productive the intent of the
standard.
Response: The SDT thanks you for your comments.
1. The standard specifies MAXIMUM allowable intervals for the various activities; entities must manage their program however they see fit to adhere to
those intervals. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established
intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for
a “grace period” would not conform to this directive.
2. The SDT has removed this requirement.
MRO NERC Standards Review
Subcommittee
No
A. It looks like for unmonitored systems, breaker trip coils are to be checked for continuity every 3 months.
There is no mention of auxiliary relays. In the partially monitored and fully monitored sections, trip coils and
auxiliary relays are lumped in the same category at 6 calendar years each. What happened to the aux relays
in the unmonitored section? Also, note that the term "trip coils" is used, not "breaker trip coils" in the type of
component category.
B. The maintenance interval for Protection System Control Circuitry (Trip coils and Auxiliary relays) is 6 years,
but the interval for relay output contacts is 12 years when these components are partially monitored. It seems
that these things all have a similar reliability. If commissioning tests are done diligently, the trip DC availability
is continuously monitored and the trip coil itself is continuously monitored, no functional tests should be
needed. The only thing that would be done at PM time would be to ensure that the alarming method is still
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Organization
Yes or No
Question 3 Comment
functional.
Response: The SDT thanks you for your comments.
A. The SDT has removed this requirement.
B. In your discussion (with continuous monitoring of the trip dc and trip coil), you have effectively established most of the monitoring to move to either
Table 1b or even Table 1c. You are encouraged to carefully review the Monitoring Attributes for these higher levels of monitoring; if you satisfy the
attributes, you may be able to further minimize hands-on maintenance.
NextEra Energy Resources
No
a. (i) Protective relays, (ii) Protection Control Circuitry (Trip Circuits) and (iii) Protection System
Communications Equipment and Channels should be changed from 6 calendar years to 8 calendar years.
Based on FPL Group’s experience and Reliability Centered Maintenance (RCM) program, FPL Group has
established an 8 year program and has found that an aggressive 6 year program would not substantially
increase the effectiveness of a preventative maintenance program.
b. Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s lead-calcium
batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past.
c. The maximum maintenance interval for communications equipment should be changed from 3 months to
12 months. Based on FPL Group’s experience and RCM program, FPL Group has established a 12 month
program that is effective.
d. Additionally, NextEra Energy concurs with other entities comments concerning this question: Imposing
inflexible maximum interval requirements has the same basic problems as imposing inflexible minimum task
requirements. The inflexible “maximum interval” approach fails to recognize the harmful effects of overmaintenance and precludes the ability of entities to tailor their maintenance program based on their
configurations and operating experience. The maximum interval approach also has same perverse
consequences for entities with redundant systems as the minimum interval approach.
e. Furthermore, the rigid maximum interval approach embodied herein does not sufficiently take into
consideration common natural disaster situations. Several of the preventive maintenance tasks proposed in
this standard have a maximum interval of 3 months, which is problematic under normal circumstances and
unworkable when routine maintenance activities have a much lower priority than emergency repair and
restoration. An interval as short as this does not provide a sufficient maintenance scheduling horizon to
complete the tasks. The SDT could attempt to address this shortfall by modifying the draft to account for
natural disaster situations. For example, the FERC-approved NERC reliability standard FAC-003 for
Vegetation Management does include such allowances for natural disasters, such as tornados and
hurricanes. However, even if that specific problem is addressed, the fundamental problems created by an
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Yes or No
Question 3 Comment
overly prescriptive maximum interval approach remains.
Response: The SDT thanks you for your comments.
a. The SDT believes that the 6-year maximum allowable intervals, to which you refer, are appropriate. The intervals within the standard are based on
the experience of the SDT and of the NERC System Protection and Control Task Force (SPCTF). The SPCTF also validated these intervals via an
informal survey that represented about 2/3 of the net-energy-for-load within NERC, and by comparison to IEEE surveys. See Supplementary Reference
Document Section 8 (page 9). An entity may implement a Performance Based maintenance program if they wish to apply their experience.
b. The SDT agrees that a healthy modern lead acid battery can go for extended periods of time beyond 3 months without requiring watering. However,
checking cell electrolyte level not only indicates the need for battery watering, it is an indication of an individual cell’s health and needs to remain at
the Maximum Maintenance Interval of 3 months. To avoid the confusion that the Maintenance Activity listed in Table 1 was to water the battery at the
specified 3 month interval, the Drafting Team has changed the wording of the Maintenance Activity from “verify proper” to “check” electrolyte level.
c. The 3 month interval is for inspection of unmonitored equipment. The SDT felt that this is appropriate for carrier channels or for leased audio
channels that have a chance of failure and would result in an overtrip or failure to trip if ignored. It is possible to extend the interval for performance
based systems if the entity has applicable data.
d. FERC Order 693 directs that NERC establish maximum allowable intervals. For entities that wish to establish a performance-based maintenance
program using experience, the standard DOES allow for that.
e. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to implement an
effective PSMP.
CenterPoint Energy
No
a. See CenterPoint Energy’s comments made in response to question 2. Imposing inflexible maximum
interval requirements has the same basic problems as imposing inflexible minimum task requirements. The
inflexible “maximum interval” approach fails to recognize the harmful effects of over-maintenance and
precludes the ability of entities to tailor their maintenance program based on their configurations and
operating experience. The maximum interval approach also has same perverse consequences for entities
with redundant systems as the minimum interval approach.
b. Furthermore, the rigid maximum interval approach embodied herein does not sufficiently take into
consideration common natural disaster situations. Several of the preventive maintenance tasks proposed in
this standard have a maximum interval of 3 months, which is problematic under normal circumstances and
unworkable when routine maintenance activities have a much lower priority than emergency repair and
restoration. An interval as short as this does not provide a sufficient maintenance scheduling horizon to
complete the tasks. The SDT could attempt to address this shortfall by modifying the draft to account for
natural disaster situations. For example, the FERC-approved NERC reliability standard FAC-003 for
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Organization
Yes or No
Question 3 Comment
Vegetation Management does include such allowances for natural disasters, such as tornados and
hurricanes. However, even if that specific problem is addressed, the fundamental problems created by an
overly prescriptive maximum interval approach remains.
Response: The SDT thanks you for your comments.
a. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to implement an
effective PSMP.
b. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document
(page 9) for a discussion on this issue.
FirstEnergy
No
Although we agree with the proposed maintenance intervals, there may be extenuating circumstances beyond
an entity’s control that could delay maintenance on a particular protection system. We ask the SDT to
consider adding a footnote to these intervals that allows a grace period of up to three months when outages
necessary for maintenance must be delayed due to unusual system conditions or other issues where an
outage would be detrimental to the entity's system.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may
need to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. Specifically,
for generation facilities, there would seem to be numerous opportunities within the 6-year or longer intervals to perform the required maintenance
during a scheduled plant outage, and maintenance with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection
than anything else; the SDT believes that this maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be
used to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed
that NERC establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8
of the Supplementary Reference Document (page 9) for a discussion on this issue.
American Transmission
Company
June 3, 2010
No
1. ATC is concerned that the proposed standard would result in entities being required to use outdated
testing techniques and or practices. We believe that the standard should identify the “what” and not the
“how”. The identification of specific testing techniques and/or practices would likely result in entities being
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Yes or No
Question 3 Comment
prevented from implementing improved techniques and/or practices. (The standard would have to be
updated and receive FERC approval before entities could test/implement improved testing techniques
and/or practices.)
2. An example of the standard directing the how is with station batteries. The “specific gravity” test,
proposed in the standard, is being used less or not at all by some registered entities because a more
accurate method that is less intrusive and provides more accurate results has been developed. (This
standard would basically require entities to go backwards in testing practices.)This standard should not
prevent the use of improved techniques and/or practices.
Response: The SDT thanks you for your comments.
1. In consideration for your concern, the Drafting Team has revised Table 1 to identify more of what is required for the station dc supply activities and
eliminated most of the “how to do it”.
2. All references to specific gravity and temperature testing have been removed from the revised standard.
City Utilities of Springfield, MO
No
CU agrees in general with many of the maximum maintenance intervals. However, we disagree with the
necessity to verify the continuity of trip coils every 3 months. We would be interested to know what basis the
committee used to arrive at all intervals. Furthermore, it is our opinion that even if a component is
unmonitored, the interval should not surpass the manufacturer’s recommendations.
Response: The SDT thanks you for your comments and has removed this requirement.
ITC Holdings
No
1. Does the standard require that time or condition based maintenance programs monitor countable events to
identify significant problems in particular relay segments, and then adjust the maintenance interval
accordingly?
2. On page 6: Please clarify the use of “Calendar Year” Our understanding is that if a relay is maintained on
August 31, 2003 on a 6 year interval, it will not be overdue until January 1, 2010. Is this correct??
3. On Page 7: What is the basis for 18 months? We believe 2 calendar years would be more appropriate.
4. On Pages 6, 10: What is the basis of the 6 calendar year interval for functional trip tests? We request that
this be changed to a 10 calendar year interval. We follow a 10 calendar year interval that has proven to be
satisfactory. Decreasing the interval to 6 calendar years will result in a major increase in our maintenance
expenses without a corresponding increase in reliability.
5. On Page 9: If it is being verified ok every 3 months, what is the basis of the 6 calendar year interval for
Communication equipment? ITC communications systems are partially monitored and therefore required to
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Yes or No
Question 3 Comment
perform this testing every 12 years. However, ITC would like to know the basis of the 6 year interval for
informational purposes.
6. On pages 6, 8, 11, 13, 14 and 19: The maximum maintenance interval (when the associated UVLS or
UFLS system is maintained) should be shown as the actual “6 Calendar Years”.?
7. On Page 1 of Attachment A: Please provide an example in the reference of the proper way of adjusting the
interval based on test results.
8. On Pages 7, 8, 12: It is our understanding that adequate maintenance can be achieved by performing
either one of the two maintenance activities in cases where there is an “or”, is that correct?
9. On Page 14: For the bottom two rows on page 14 we believe there is a typo and it should read “Level 2”
not “Level 1”.
10. On Page 13: Do power line carrier schemes that provide a remote alarm if a daily check back test fails,
meet level 2 monitoring requirements?
11. In Table 1: What is the basis for the 6 year interval for the battery systems? This test would be an
additional test for ITC. We would prefer to perform this additional test with the relay periodic maintenance on
a 10 year interval.
Response: The SDT thanks you for your comments.
1. No, the standard does not require that countable events be analyzed for determination of intervals in time-based or condition-based maintenance
programs. However, excessive poor operation may trigger additional activities as part of a corrective action plan per PRC-004 in response to
Misoperations.
2. Your understanding is incorrect. A maintenance activity last completed in 2003 on a 6-year interval would next need to be maintained sometime in
2009. (See Supplementary Reference Document Section 8.4, page 13)
3. The SDT believes that 18-month is the appropriate interval, based on common industry practice.
4. The SDT believes that 6-years is the appropriate interval, based on common industry practice. For entities that wish to establish a performancebased maintenance program using experience, the standard DOES allow for that.
5. The 6 year interval is mostly driven by the needs of power line carrier channels and the use of analog auxiliary tuning components in the
communications systems. The relay communications systems intervals were based on the experiences of SDT and NERC System Protection
Committee Task Force members.
6. The SDT has modified the standard in consideration of your comment to include the specific intervals for the various components related to
UFLS/UVLS, with the exception of the dc supply. The maintenance for the dc supply for UFLS/UVLS was left related to the maintenance of the
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Yes or No
Question 3 Comment
UVLS/UFLS system because the SDT believed that this activity should be tied to the specific intervals needed for the relays.
7. See FAQ IV-3-H (page 26).
8. You are correct in your statement that the Maintenance Activity of verifying that the station battery can perform as designed can be met by
completing either of the two activities listed in Table 1 in the prescribed Maximum Maintenance Interval.
9. Thank you. You are correct; these table entries have been modified accordingly.
10. Yes. A remote alarm daily auto-check back as you describe satisfies the Level 2 monitoring attributes for channel performance in a power line
carrier system.
11. The SDT believes that extending the Maximum Maintenance Interval for station batteries beyond that listed in Table 1 would degrade the Protection
System by not detecting compromises to the performance of the station dc supply during the extended interval.
Platte River Power Authority
Maintenance Group
No
Electro-mechanical relays are historically out of tolerance well before the 6 year maximum allowable
maintenance intervals defined within table 1a.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may
need to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals.
Florida Municipal Power Agency,
and its Member Cities
No
1. FMPA agrees in general with many of the maximum maintenance intervals; however we have been unable
to determine what basis was used to arrive at the time based intervals provided in the tables. Further
explanation would be appreciated
2. FMPA is concerned with the use of the term “continuous” in Table 1c. As stated, it would seem that, on loss
of communications that would communicate the alarm, thereby causing a loss of “continuous” monitoring and
alarming, the entity who invested in a reliability improving monitoring system would be found non-compliant
with an infinitesimal maintenance period required for “continuous” monitoring. Therefore, FMPA recommends
using “not applicable” or some other term in this column.
Response: The SDT thanks you for your comments.
1. The intervals within the standard are based on the experience of the SDT and of the NERC System Protection and Control Task Force (SPCTF). The
SPCTF also validated these intervals via an informal survey that represented about 2/3 of the net-energy-for-load within NERC, and by comparison to
IEEE surveys. See Supplementary Reference Document Section 8 (page 9).
2. The SDT believes that the maintenance is indeed being done “continuously”. If the alarming method is not functional, you’ve fundamentally
dropped back to Level 1 or Level 2 monitoring, depending on the component.
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Yes or No
E.ON U.S.
No
Question 3 Comment
1. Generally, E.ON U.S. requests that the SDT provide the basis for the proposed changes in maintenance
time lines. E ON U.S.’s existing maintenance intervals are based on actual operating experience. Not having
been provided with the basis for the proposed intervals, the time lines appear arbitrary. E.ON U.S. currently
has an 8-year interval for combustion turbines vs. the 6-year interval provided here. The E.ON U.S. interval is
based on the Company’s experience with this equipment. E.ON U.S. suggests that the SDT provide some
consideration to individual entities historic practices.
2. It is difficult to track “18 months”. Maintenance intervals should be in expressed in number of years.
3. E ON U.S. also does not understand the basis for the 3 months maintenance schedule on breaker trip
coils. Typically, the circuit breaker closed indication is wired through the breaker trip coil. Thus there could
not be a breaker closed indication without a good breaker trip coil. So, this test should be considered
continuous monitoring which may not even require documentation except in case of failure.
Response: The SDT thanks you for your comments.
1. See Supplementary Reference Document, Section 8 (page 9). An entity’s historical practices and results can be used to establish a performancebased maintenance program as described within the standard.
2. The SDT believes that the 18-month interval is appropriate. If you wish, you may do these activities more frequently to aid in your maintenance
tracking, as long as you adhere to the requirements within the standard.
3. If this indication is local (for example, a lamp), 3-month inspections of the lamp state are necessary to satisfy the requirement. If the indication is an
alarm to a location such as a control room, control center, etc, this may satisfy for either Level 2 or Level 3 monitoring as you suggest.
Transmission Owner
No
a. i) Protective relays, ii) Protection Control Circuitry (Trip Circuits) and iii) Protection System Communications
Equipment and Channels should be changed from 6 calendar years to 8 calendar years. Based on FPL’s
experience and Reliability Centered Maintenance (RCM) program, FPL has established an 8 year program
and has found that an aggressive 6 year program would not substantially increase the effectiveness of a
preventative maintenance program.
b. Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s lead-calcium
batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past.
c. The maximum maintenance interval for communications equipment should be changed from 3 months to
12 months. Based on FPL’s experience and RCM program, FPL has established a 12 month program that is
effective.
Response: The SDT thanks you for your comments.
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a. The SDT believes that the 6-year interval is appropriate. An entity may implement a Performance Based maintenance program if they wish to apply
their experience.
b. The SDT agrees that a healthy modern lead acid battery can go for extended periods of time beyond 3 months without requiring watering. However,
checking cell electrolyte level not only indicates the need for battery watering, it is an indication of an individual cell’s health and needs to remain at
the Maximum Maintenance Interval of 3 months. To avoid the confusion that the Maintenance Activity listed in Table 1 was to water the battery at the
specified 3 month interval, the Drafting Team has changed the wording of the Maintenance Activity from “verify proper” to “check” electrolyte level.
c. The 3 month interval is for inspection of unmonitored equipment. The SDT felt that this is appropriate for carrier channels or for leased audio
channels that have a chance of failure and would result in an overtrip or failure to trip if ignored. It is possible to extend the interval for performance
based systems if the entity has applicable data.
Illinois Municipal Electric Agency
No
1. IMEA is concerned the maximum allowable maintenance intervals may be too prescriptive for transmission
subsystems that essentially operate radially.
2. Please see comment under Question 7.
3. Given the magnitude of reliability-related initiatives currently in progress, additional time is needed to
evaluate these intervals, particularly for communications equipment, dc supply, and UFLS relays.
Response: The SDT thanks you for your comments.
1. The intervals are established for Protection Systems on BES components. If you believe that some of your system components are not BES that is
an issue relative to your region’s BES definition.
2. See response to comment under Question 7.
3. An Implementation Plan is provided to allow systematic implementation of these intervals. If you are concerned about the time available to develop
comments on posted drafts, be advised that the posting period is determined according to the NERC Reliability Standards Development Process. The
SDT is providing the maximum comment time available.
PacifiCorp
No
No comment.
Duke Energy
No
1. Our comments are limited to Table 1a. More clarity is needed for many of the Maintenance Activities
before assessing whether or not the intervals are reasonable. But as a general comment we would like to
understand the basis used to develop all of the intervals, and how that basis compares with research done by
the Electric Power Research Institute (EPRI). It is our understanding that NERC did an industry survey of
maintenance intervals and we would like to see the results of that survey as well.
Specific comments:
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2. Protective Relays 6 calendar years is okay.
3. Voltage and Current Sensing Devices Inputs to Protective Relays We question the logic for a 12-year
interval. Proper functioning should be verified at commissioning, and then anytime thereafter if changes are
made in a PT or CT circuit. Additional periodic checks may be warranted as suggested in Table 1A, however
no additional checking should be required where circuit configuration will inherently detect problems with a PT
or CT. For example, PTs & CTs that are monitored through EMS or microprocessor relays will be alarmed
when they are out of specification.
4. Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS) In locations where
the continuity of the circuit is not monitored (via a light in the path or through a microprocessor relay) this
would be a very complicated test, which could impact reliability, especially if done every three months.
5. Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) Need clarity on exactly what
the activity is to include. We believe proving one output all the way to the trip coil is appropriate. Proving
every output and every auxiliary contact, to the trip coil would be unnecessarily invasive and could impact
reliability, even if done every 6 calendar years.
6. Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only) Interval is okay, but we
disagree with tripping the breakers proving the output of the relay should be sufficient. Systems that have all
load shed on distribution circuits should require trip output be confirmed but should not be required through to
the trip coil due to constraints in tying distribution load.
7. Station dc supply (that has as a component any type of battery) 3 month and 18 month intervals are
probably okay, depending on what is required to “verify continuity and cell integrity of the entire battery” and
“inspect the structural integrity of the battery rack”.
8. Station dc supply (that has as a component Valve Regulated Lead-Acid batteries) 3 calendar years and 3
month intervals are probably okay, depending on what is required for the “performance or service capacity
test”.
9. Station dc supply (that has as a component Vented Lead-Acid batteries) 6 calendar year and 18 month
intervals are probably okay, depending on what is required for the “performance, service or modified
performance capacity test”.
10. Protection system communication equipment and channels 3 months and 6 calendar years seem
reasonable, depending upon what is included in the substation inspection, and what is required for power-line
carrier systems.
11. UVLS and UFLS relays that comprise a protection scheme distributed over the power system Can’t
comment on the 6 calendar year interval until we get more clarity regarding the meaning of “distributed over
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the power system”.
Response: The SDT thanks you for your comments.
1. See Supplementary Reference Document, Section 8 (page 9).
2. The SDT thanks you for your support.
3. For unmonitored systems, the SDT believes that the interval specified in Table 1a is appropriate. If alarming is available for anomalies, you may be
able to use Table 1c with continuous monitoring.
4. Table 1a has been modified to remove the activities to which you refer.
5. See Supplementary Reference Document, Section 15.3 (page 22).
6. The requirements relating to Protection System Control Circuitry for UFLS/UVLS only do not require tripping of the breaker.
7. Thank you for agreeing with the Maximum Maintenance intervals associated with the Maintenance Activities. The SDT has modified the standard
concerning the requirement to verify cell integrity (See FAQ II-5-C, page 12), and continuity (See FAQ II-5-D, page 13) and inspecting for the structural
integrity of the battery rack (See FAQ II-5-H, page 15).
8. How to conduct a performance and service capacity test for Valve Regulated Lead-Acid batteries are explained in detail in various available
reference books. One of the options available to the Protection System owner who is responsible for maintaining a station dc supply that can perform
as designed is to conduct a performance or service capacity test within the Maximum Maintenance Interval of Table 1 that will verify that a VRLA
battery will satisfy the design requirements (battery duty cycle) of the dc system.
9. How to conduct a performance service or modified performance capacity test for Vented Lead-Acid Batteries is explained in detail in various
available reference books.
10. These intervals are for power line carrier channels as well as other types of communications channels.
11. See FAQ II-7-C (page 19).
Electric Market Policy
No
Recommend that all Level 1 three-month maintenance intervals be changed to a quarterly based system
where only 4 inspections are required per year. Given a 3 month maximum interval, activities would need to
be scheduled every 2 months, which would result in six inspections per year. Our experience of four
inspections per year has proven to be successful.
Response: The SDT thanks you for your comments. The SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of
the maintenance activities. “Once per calendar quarter” would allow up to a 6-month practical interval, which would not maintain this periodicity. This
DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
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SERC (PCS)
No
Question 3 Comment
Recommend that all Level 1 three-month maintenance intervals be changed from 3 months to quarterly.
Given a 3 month maximum interval an entity would need to schedule these tasks every 2 months. This would
result in six inspections per year. In the experience of many of our utilities, four inspections per year have
proven to be successful.
Response: The SDT thanks you for your comments. The SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of
the maintenance activities. “Once per calendar quarter” would allow up to a 6-month practical interval, which would not maintain this periodicity. This
DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
Indianapolis Power & Light Co.
No
See comments in number 2 above.
Response: The SDT thanks you for your comments. See response to comments in Question 2.
Austin Energy
No
See item # 10 Comments
Response: The SDT thanks you for your comments. See Question #10 Response
Wolverine Power Supply
Cooperative, Inc.
No
See question 2 response
Response: The SDT thanks you for your comments. See Question #2 Response
SCE&G
No
Several maximum maintenance intervals are 3 months. Since this is an absolute maximum period, entities
would need to schedule on a 2 month basis to assure the 3 month maximum is met, i.e., 6 times per year.
We recommend that 3 month periods be increased to 4 months which allows scheduling every 3 months.
Other methods of achieving the same result are to state periodic requirements of quarterly or 4 times per
year.
Response: The SDT thanks you for your comments. The SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of
the maintenance activities. “Once per calendar quarter” or “four times per year” would allow up to a 6-month practical interval, which would not
maintain this periodicity. This DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
Wisconsin Electric
June 3, 2010
No
Similar to comments in #7 above: It is our practice on distribution-level protection systems to utilize a 6 year
interval plus/minus 1 year to accommodate potential scheduling conflicts. This is consistent with other LSE's
relay testing practices as well. Thus the potential 7 year maintenance interval would be a violation of the draft
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requirements. The maintenance intervals in this standard should be increased accordingly for distribution
protection system equipment.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may
need to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. Specifically,
for generation facilities, there would seem to be numerous opportunities within the 6-year or longer intervals to perform the required maintenance
during a scheduled plant outage, and maintenance with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection
than anything else; the SDT believes that this maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be
used to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed
that NERC establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8
of the Supplementary Reference Document for a discussion on this issue.
Pepco Holdings Inc.
No
Table 1a requires verification of the continuity of the breaker trip circuit every three months in the absence of
a trip coil monitor. Recommend maintenance interval to match that for other protection system control
circuitry (6 years).
Response: The SDT thanks you for your comments. The SDT has modified the standard to remove the requirement to which you refer.
Nebraska Public Power District
No
Table 1a, for Station DC supply (that has as a component - Valve Regulated Lead-Acid batteries) establishes
a Maximum Maintenance Interval of 3 Calendar Years for the following Maintenance Activity: Verify that the
station battery can perform as designed by conducting a performance or service capacity test of the entire
battery bank. What is the basis for this interval? NPPD’s experience indicates that a 5 Year interval is
adequate, especially during the early service life of the battery bank, with increasing frequency as the bank
ages.
Response: Thank you for your comment concerning the Maximum Maintenance Interval for Valve Regulated Lead-Acid batteries (VRLA). Due to the
failure mode and designed service life of VRLA batteries compared to a Vented Lead-Acid batteries, the SDT believes that extending capacity testing of
a VRLA battery beyond the maximum maintenance interval of 3 calendar years in Table 1 cannot be justified regardless of what the battery
manufacturers of VRLA batteries recommend. This is especially true in the later periods of service life beyond 3 calendar years as noted by many
utilities requiring total replacement of their VRLA batteries after 4 years of service. It appears that your practices are actually addressing Vented Lead
Acid batteries, rather than Valve Regulated Lead-Acid batteries.
Dynegy
No
The 3 month interval in Table 1a for verification of the continuity of the breaker trip circuit is only feasible if this
verification can be done by inspection versus testing (see Response to Question 2).
Response: The SDT thanks you for your comment and has removed the requirement.
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Southern Company
No
Question 3 Comment
1. The 3 month intervals specified for the trip coil monitoring and communication circuit testing are too
frequent. Our experience is that trip coils rarely burn open and don’t need to be checked this often. If no
monitoring currently exists, manually checking the circuit (until a time where monitoring can be installed) may
inadvertently cause a trip. This adds risk to the reliability. Thus, requiring the trip circuits to be tested every 3
months may reduce the reliability of the BES.
2. Protection System Control Circuitry (Breaker Trip Coil Only) (Except for UFLS or UVLS) In order to reduce
the risk of reducing Bulk Electric System reliability a better time interval for testing un-monitored trip coils
would be 12 months. This may need to be 24 months for Nuclear Generating units.
3. Some allowance for a grace period (beyond the specified intervals) should be considered for all
classifications. Outage schedules are known to change unexpectedly due to unforeseen circumstances. A
grace period tolerance of +25% for specified maintenance intervals less than 12 months and of +1yr for those
intervals specified as greater than 12 months is recommended. Typically at a nuclear plant a grace period is
allowed by plant procedures. This grace period is defined as an additional 25 percent of the original schedule
interval for the task. The grace period is provided as reasonable flexibility to allow for alignment with
surveillance activities and equipment maintenance outages and to better manage the use of station
resources. Some maintenance activities will require an outage to perform the work. Refueling outages are
typically performed on an 18 month or 24 month refueling cycle. However, refueling outages do not always fall
exactly on that interval. It is possible that the duration between one outage to the next may exceed 18 or 24
months. For activities that are required to be complete on a calendar year cycle this should not be an issue
since the outages are normally scheduled several months prior to the end of the year. However, if the interval
is a monthly interval there could be a problem with scheduling the maintenance such that it does not impact
planned maintenance activities, surveillance requirements, and station resources.
4. Tables 1a, 1b and 1c have several instances where inspection and testing of DC circuits or components
has a specified interval of 18 months. At nuclear generating stations, such tests on station battery banks and
associated chargers incur unacceptable risk if performed with the unit on line and a unit outage is required for
this testing. A number of nuclear plants are on two-year shutdown cycles and we request that the 18 month
intervals be changed to two (2) (calendar) year intervals to accommodate this.
5. Protection System Control Circuitry (Breaker Trip Coil Only) (Except for UFLS or UVLS) Based on past
performance, a complete functional test trip every 6 years is not warranted. This complete functional test
introduces additional risk to our maintenance program, not only from a human error perspective, but also from
the additional frequency of switching and outages required. Our experience has shown that 12 years is an
appropriate maximum time interval (rather than 6 years.)
Response: The SDT thanks you for your comments.
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1. The SDT believes that such maintenance of the communications will primarily be performed by inspection monitoring lamps and so forth. The trip
coil requirements to which you refer have been removed.
2. This activity is primarily inspection-based, involving no invasive testing. The stated intervals seem appropriate.
3. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 (page 9) of the Supplementary Reference
Document for a discussion on this issue.
4. All Maintenance Activities listed in Tables 1a, 1b, and 1c related to the station dc supply that have a Maximum Maintenance Interval shorter than two
(2) (calendar) years are necessary inspection, checking or verification activities routinely performed on the station dc supply with it in service and
without posing an unacceptable risk. The Drafting team feels that to extend these activities beyond their Maximum Maintenance Intervals listed in
Table 1 would jeopardize the station dc supply.
5. The SDT believes that the 6-year interval for this activity is appropriate. If you experience supports a longer interval, the standard permits you to
utilize Performance-Based maintenance.
AEP
No
The availability to perform maintenance of many protection systems is dictated by the load or customer that is
connected. Many of these industrial customers, who are outside the jurisdiction of NERC requirements,
operate 24X7 and see the outages required for maintenance as a nuisance and a loss of revenue. How can
the owner be held non-compliant for not meeting the intervals when they may not control the timing?
Comments expanded in question 10 responses.
Response: The SDT thanks you for your comments. This non-compliance would be addressed via contract law; these contracts are described in the
Statement of Compliance Registry.
US Bureau of Reclamation
No
The definition of Protection System components does not add clarity. The standard proposes including
stations service transformers for generation facilities, however, the protection system definition does not
include those elements. The inclusion of station service transformers would only be appropriate if the
protection associated with the transformer results in the tripping of a transmission element.
Response: The SDT thanks you for your comments. The applicability to station service transformers emphasizes the impact of those components on
the operability of the associated generator. They are not themselves Protection System components; however, maintenance of the Protection System
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components on those system elements is required per the Standard. See FAQ III-2-A (page 20).
Ohio Valley Electric Corp.
No
The documentation requirements for the inspection activities with three month intervals are oppressive and
should not be a part of the protection system maintenance standard.
Response: The SDT thanks you for your comments. The SDT disagrees; it is left to the entity to adopt effective methods to document these activities.
CPS Energy
No
1. The first problem that I have is the 3 Months for the Protection system communications equipment and
channels component. My main concern with this interval is that it is so extremely short and I am concerned
that there may not be any rational behind it. What studies, surveys, or statistical data were used to determine
that 3 months is necessary to protect the reliability of the BES? It doesn't make sense that a communications
signal needs to be checked every 3 months but the protective relay that utilizes that scheme needs to be
checked at most only every 6 years.
2. What concerns me the most with the 3 month interval for my company is with on-off power line carrier DCB
schemes? We only have these schemes on tie lines, and it can be difficult to implement a checkback system
with another utility who might utilize different carrier equipment. This type of scheme is also intended to be
inherently insecure and is frequently more or less tested with faults in the system. The SPCTF should do
surveys to determine what is presently done with these type of systems or provide some other rationale for
the communication requirements. It is not totally clear from the documents, but it appears that the only way to
avoid the 3 month check for an on-off power-line carried DCB scheme is to have an automated check back
scheme. Is this correct? Or is alarming from the carrier equipment adequate?
3. My second problem is with the 6 year maximum maintenance interval for the breaker trip coil in tables 1b
and 1c. By having to verify that each breaker trip coil is electrically operated, you might as well perform a
functional test to test the protection system control circuitry. Electrically operating the trip coil tests the
breaker as much as it test the actual trip coil. Also, if you have a primary and secondary trip coil, is it really
necessary to test this often? What studies or statistical data were used to determine that testing the breaker
trip coils every 6 years is necessary to protect the reliability of the BES?
4. My third problem is with the intervals requirements for the UVLS/UFLS systems. Other than testing and
calibration of electromechanical UVLS/UFLS, most other tests probably should require at most 10 years for
these types of systems. These systems don't require the performance level of most other systems as stated
in the supplementary reference. The testing and calibration of electromechanical UFLS should possibly be
even shorter than the 6 year requirement due to problems with drift with these type of relays. What studies,
surveys, or statistical data were used to determine the intervals in related to UFLS/UVLS.?
Response: The SDT thanks you for your comments.
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1. The 3 month intervals are for unmonitored equipment and are based on experience of the relaying industry represented by the SDT, the SPCTF and
review of IEEE PSRC work. Relay communications using power line carrier or leased audio tone circuits are prone to channel failures and are proven
to be less reliable than protective relays.
2. The automated check back systems are common ways to verify the integrity of the relay communication channel. It would only be moved to Level 2
if the check back test is monitored remotely and the tests are run daily. Without check back equipment, it will be necessary to have personnel at both
ends and manually initiate a signal and verify that the remote equipment operates.
3. In the experience of the SDT and the NERC SPCTF, the 6-year interval is appropriate. The SPCTF also conducted an informal survey of entities
representing approximately 2/3 of the NERC net-energy-for-load and a review of IEEE surveys to validate these intervals. See the Supplementary
Reference Document, Section 8 (page 9).
4. In the experience of the SDT and the NERC SPCTF, the 6-year interval is appropriate. The SPCTF also conducted an informal survey of entities
representing approximately 2/3 of the NERC net-energy-for-load and a review of IEEE surveys to validate these intervals. See the Supplementary
Reference Document, Section 8 (page 9). The maintenance of the other Protection System components associated with UFLS/UVLS is specifically
stated to correspond with the intervals for the relays themselves.
Consumers Energy Company
No
1. The interval for Protection System Control Circuitry (breakers trip coil) should be set at 12 years since this
is a scheme test. This test requires testing of the circuit and not just the coil.
2. The interval for Protection System Control Circuitry (trip circuit) should be set at 12 years since this is a
scheme test. The Protection System Control Circuitry (trip circuit) test would require tripping off customers on
radial distribution circuits which is not acceptable.
3. The interval for a station battery service test (lead acid) should be set at 5 years based on NFPA 70B.
Response: The SDT thanks you for your comments.
1. The SDT believes that the intervals indicated in the standard are appropriate. The standard allows the use of Performance-Based maintenance if
your experience supports it.
2. The SDT believes that the intervals indicated in the standard are appropriate. The standard allows the use of Performance-Based maintenance if
your experience supports it. The standard applies only to Protection Systems on BES components as established by your regional BES definition.
3. NFPA 70B is a recommended practice which is voluntary, and is not a standard that establishes any requirements that must be measurable. NERC
standard PRC-005 requirements are loosely aligned with some of the NFPA standards. However, the Maximum Maintenance Intervals required in PRC005-2 were established to be measurable and enforceable. If an owner chooses to perform the Maintenance Activities outlined in Table 1 of the
standard at a lesser interval the owner is free to do so.
RRI Energy
June 3, 2010
No
1. The intervals need to be defined on a calendar quarters or calendar years, especially for intervals listed as
3 months. The demonstration of maintenance on rolling three-month intervals will be an onerous record
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keeping task, particularly when relying upon planning and tracking software that scheduled recurring tasks on
the same day of an interval.
2. Given the magnitude of the number of trip circuits, the requirements set an un-acceptable trap of noncompliance from a record keeping perspective. The resources required to keep and maintain flawless
records are too much to justify the intervals. A non-compliance is the result if the breakers that happen to be
in an open state when the officially “documented” inspection is recorded and is missed by accidental oversight
on follow-up. If the requirement remains, it should be waived for any breaker that is operated during the
defined interval.
Response: The SDT thanks you for your comments.
1. The SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of the maintenance activities. “Once per calendar
quarter” or “four times per year” would allow up to a 6-month practical interval, which would not maintain this periodicity. This DOES permit entities
to use four inspections per year provided that they carefully manage their maintenance activities.
2. The dc control circuit maintenance to which you refer has been removed from the standards. The SDT disagrees that the record keeping is
excessively burdensome; it is left to the entity to adopt effective methods to document these activities.
Progress Energy
No
The rational for microprocessor-based relay intervals is examined, but all others are strictly based on industry
weighted average of survey results. We believe the team should use a more empirical, documented
approach to determining these intervals, as many companies have longer intervals that they currently have
documented for their basis. If these have been accepted as satisfactory in previous audits, why should they
be required to change just to meet an arbitrary number?
Response: The SDT thanks you for your comments. The standard permits entities to use Performance-based maintenance if they have documented
experience which supports doing so.
Northeast Power Coordinating
Council
No
1. We question whether any maintenance activity should be as long as 12 years. Considering the rate of
change in personnel and technology, the working group should reduce the time period by redefining the
requirement if necessary, or eliminate the standard requirement.
2. In addition, the DC components have too many tests at confusing intervals. Confusion will make it difficult
to implement or follow the exact method used.
Response: The SDT thanks you for your comments.
1. In the experience of the SDT and the NERC SPCTF, the intervals within the standard are appropriate. The SPCTF also conducted an informal survey
of entities representing approximately 2/3 of the NERC net-energy-for-load and a review of IEEE surveys to validate these intervals. (See
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Question 3 Comment
Supplementary Reference Document, Section 8.4, page 13)
2. The SDT has modified the standard in consideration of your comments and simplified the maintenance activities associated with dc supplies.
Detroit Edison
No
What is the basis for the three month interval for verifying breaker trip coil continuity? Will the investment
required to facilitate this really result in the presumed expected increased reliability?
Response: The SDT thanks you for your comments and has removed the requirement.
Manitoba Hydro
No
1. When we have redundant digital relay system that would fall under Level 1c category with a 12 year
maintenance cycle, but the Protection System Control Circuitry is non-monitored so it falls under Level 1a,
with a 6 year maintenance cycle. We will have to complete relay maintenance and trip testing every 12 years
and trip testing only every 6 years, therefore we must complete trip testing twice as often as we are doing the
maintenance. We feel that relay maintenance and trip testing should be completed at the same frequency.
2. The Protection System Control Circuitry (Breaker Trip Coil) checks every three months is too excessive.
These circuits are checked during trip testing of the Protection scheme, at the 6 or 12 year interval.
3. If we have a redundant digital relay system, using a IEC61850 communication from the relay to a common
breaker aux trip relay, what level does this system fall under?
Response: The SDT thanks you for your comments.
1. Whether relay systems are redundant are immaterial in determining appropriate maintenance intervals. The SDT believes that the intervals
established in the standard are appropriate. The Tables have been revised extensively; the SDT invites you to review the revised Tables to determine
how they affect your system.
2. The requirement to which you refer has been removed from the Table.
3. Whether relay systems are redundant are immaterial in determining appropriate maintenance intervals. You will need to evaluate all components to
determine applicable maintenance activities; the digital relays MAY fall under Table 1c, but other components may fall under any of the Tables.
Xcel Energy
June 3, 2010
No
Within the tables, several components related to UFLS/UVLS systems have an interval of “when the
associated UVLS or UFLS system is maintained.” Yet, there is no maximum interval established for a UVLS
or UFLS system. We feel this item should be clarified. If the intent of the SDT is to tie the testing to when the
UFLS/UVLS relays are maintained, so that all components are tested at the same time, then this should be
made clear. One possible resolution would be to change the interval to read: “when the associated
UVLS/UFLS relays are maintained”.
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Question 3 Comment
Response: The SDT thanks you for your comments. The interval for the UVLS or UFLS system relays is established within Table 1a, Table 1b, and
Table 1c. The intent of the SDT is to facilitate concurrent maintenance of all components associated with these systems at a common location.
AECI
No
1. Comments: Table 1a 3 months for protection system coil check out seems extreme. Should be at least 1
year.
2. Same as comment 4 for the communication checkout on page 9.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard to remove the requirement to which you refer.
2. See response to your question 4 comment on communication checkout.
Puget Sound Energy
Yes
PSE appreciates the explanation of calendar provided in the supplementary reference on page 14. Further
clarity would be gained by an example that is not at the end of a calendar year. For example if a relay was
maintained June 15, 2008, would it be due for maintenance again no later than June 30, 2014 or December
31, 2014.
Response: The SDT thanks you for your comments. For your example, the maintenance would have to be completed within 2014.
Bonneville Power Administration
Yes
ENOSERV
Yes
Georgia System Operations
Corporation
Yes
Lower Colorado River Authority
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
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Organization
Yes or No
Otter Tail Power
Yes
Saskatchewan Power
Corporation
Yes
TVA
Yes
Western Area Power
Administration
Yes
June 3, 2010
Question 3 Comment
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
4. Within Tables 1b and 1c, the draft standard establishes parameters for condition-based maintenance, where
the condition of the devices is known by means of monitoring within the substation or plant and the condition
is reported. Do you agree with this approach? If not, please explain in the comment area.
Summary Consideration: Most respondents agreed with the general approach regarding condition-based maintenance, many
of them with questions and/or comments. Many of the comments requested clarification of any of a variety of specific
provisions within Tables 1b and 1c, and revisions were made to the Tables to present the information more clearly. The
activities for control circuits and for dc supply were considerably re-worked.
Organization
Yes or No
Green Country Energy LLC
Exelon Generation Company,
LLC
Question 4 Comment
No Preference at this time.
No
1. Please provide more clarification on what constitutes "partially monitoring." For example, is a computer
auxiliary contact alarm count as partial monitoring? Would a common alarm between relays meet the
definition of partial monitoring?
2. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's
refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing
of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing
programs.
3. Table 1b Station dc supply (that has as a component valve regulated lead-acid batteries) should provide an
additional optional activity for "Total replacement of battery at an interval of four (4) years.
4. There seems to be a disconnect between the monitoring attribute and maintenance activity. For example,
the monitoring attribute "Monitoring and alarming of the station dc supply voltage/detection and alarming of dc
grounds" has the maintenance activity "verify that the station battery can perform as designed by conducting
a performance or service capacity test of the entire batter bank. (3 calendar years) or “ Verify that the station
battery can perform as designed by evaluating the measure cell/unit internal ohmic values to station battery
baseline (3 months)." The maintenance activity does not support the monitoring attribute.
5. If an entity has implemented Table 1b and/ or Table 1c, is there an acceptable length of time that the
monitoring equipment can be out of service without falling back to Table 1a requirements?
Response: The SDT thanks you for your comments.
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Organization
Yes or No
Question 4 Comment
1. A common alarm would meet the definition of partially monitored. See FAQ V-3-A (page 38).
2. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities
more frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance
with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this
maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and
that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance
intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document
(page 9) for a discussion on this issue.
3. The SDT believes that total replacement of a VRLA battery set at an interval of four (4) years in lieu of not conducting a capacity test at the maximum
maintenance interval of 3 calendar years, or evaluating the measured cell/unit internal ohmic values to the station battery’s baseline at the maximum
maintenance interval of 3 months would put the owner of the battery set out of compliance with the standard. The SDT believes the three calendar
year Maximum Maintenance Interval for conducting a capacity test (listed in Table 1) cannot be exceeded. If an owner does a total replacement of the
battery within a three calendar year interval from initial installation of a VRLA battery set, the owner will be compliant with the standard. Extending the
time that a VRLA goes beyond the Maximum Maintenance Interval in Table 1 without verification that it can perform as designed is not adequate to
insure that the station battery will perform reliably.
4. The monitoring attributes describe “what you know of the component via the monitoring”, while the activities describe what must be done relative to
the “things you don’t know”. Therefore, it’s expected that the attributes and activities will be dissimilar.
5. The equipment used to monitor the alarms must be returned to service within the shortest Table 1a interval of the monitored components. For
example, if monitoring is used to defer the 3-month Table 1a maintenance activity related to Protection System Control Circuitry, the monitoring
function must be returned to service within 3 months. This has been added to Table 1b and Table 1c as a requirement.
American Transmission
Company
No
1. ATC does not believe that there is a relay, on the market today, that has the ability to fully monitor itself as
described in Table 1c. We believe that Table 1c should be deleted. (Table 1b could cover any device that
has the ability to fully monitor if such a device is developed in the future.) ATC does not believe that NERC
Reliability Standards should be used as an enticement for manufacturers to develop specific devices.
2. Under the “General Description” in Table 1c, there is a reporting requirement identifying a 1 hour window.
(“must be reported within 1 hour or less of the maintenance-correctable issue occurring, to the location where
action can be taken.”) ATC believes that the team needs to define if this action is a phone call or physically
verify the maintenance correctable issue which is occurring.
Response: The SDT thanks you for your comments.
1. Your observation may be accurate at the present time and is not limited to protective relays. The standard was developed with future improvements
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Organization
Yes or No
Question 4 Comment
in technology and practices in mind.
2. This reporting requirement is intended to be by whatever means is available, to a location where resolution of the maintenance-correctable issue
can be initiated.
Duke Energy
No
For utilities like us with large numbers of relays it’s too complicated, which drives us back to Table 1a.
Response: The SDT thanks you for your comments. The standard was written with enough flexibility to allow entities to make the best business
decision for their situation. Some entities may decide that Table 1a is the best fit for their situation.
AEP
No
How would the failure of a SCADA system affect the ability to take advantage of monitoring?
Response: The SDT thanks you for your comments.
It doesn’t, as long as the SCADA system is returned to service within the shortest Table 1a interval of the monitored components. For example, if
monitoring is used to defer the 3 month Table 1a maintenance activity related to Protection System Control Circuitry, the monitoring function must be
returned to service within 3 months. This has been added to Table 1b and Table 1c as a required attribute for the associated type of protection system
component.
Illinois Municipal Electric Agency
No
IMEA supports comments submitted by Florida Municipal Power Agency regarding use of the word “every” in
Table 1c.
Response: The SDT thanks you for your comments. See response to FMPA.
Pepco Holdings Inc.
No
Monitoring and alarming of the station dc supply and detection and alarming of dc grounds are required to
qualify for Level 2 monitoring of battery / dc systems. While the presence of dc ground may affect protection
and control operations, they do not affect any of the systems for which dc ground alarming is listed as a
monitoring criteria. Recommend removing this criterion from the battery & dc system monitoring criteria and
adding it as a maintenance activity, with frequency of testing based on presence of detection / alarming.
Response: The SDT thanks you for your comments. The dc ground alarm may identify a maintenance correctable issue, which must be resolved
according to Requirement R4. The SDT believes that dc ground detection is usually a part of battery maintenance; this is sometimes even included in
the battery charger.
Electric Market Policy
June 3, 2010
No
Recommend that all Level 2 three-month maintenance intervals be changed to a quarterly based system
where only 4 inspections are required per year. Given a 3 month maximum interval, activities would need to
be scheduled every 2 months, which would result in six inspections per year. Our experience of four
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Organization
Yes or No
Question 4 Comment
inspections per year has proven to be successful.
Response: Thank you for your comments .SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of the
maintenance activities. “Once per calendar quarter” or “four times per year” would allow up to a 6-month practical interval, which would not maintain
this periodicity. This DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
SERC (PCS)
No
Recommend that all Level 2 three-month maintenance intervals be changed from 3 months to quarterly.
Given a 3 month maximum interval an entity would need to schedule these tasks every 2 months. This would
result in six inspections per year. In the experience of many of our utilities, four inspections per year have
proven to be successful.
Response: The SDT thanks you for your comments. SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of the
maintenance activities. “Once per calendar quarter” or “four times per year” would allow up to a 6-month practical interval, which would not maintain
this periodicity. This DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
Wolverine Power Supply
Cooperative, Inc.
No
See question 2 response
Response: The SDT thanks you for your comments. See Question 2 response.
SCE&G
No
Several maximum maintenance intervals are 3 months. Since this is an absolute maximum period, entities
would need to schedule on a 2 month basis to assure the 3 month maximum is met, i.e., 6 times per year.
We recommend that 3 month periods be increased to 4 months which allows scheduling every 3 months. An
alternate method of achieving the same result is to state periodic requirements of quarterly or 4 times per
year.
Response: The SDT thanks you for your comments. SDT believes that the “3 Calendar Month” interval is necessary to maintain the periodicity of the
maintenance activities. “Once per calendar quarter” or “four times per year” would allow up to a 6-month practical interval, which would not maintain
this periodicity. This DOES permit entities to use four inspections per year provided that they carefully manage their maintenance activities.
Detroit Edison
No
Table 1b indicates that this (level 2) includes all elements of level 1 monitoring. However, level 1 is constantly
referred to as unmonitored in other places.
Response: The SDT thanks you for your comments and modified Table 1b to address your comment by removing this reference from the header of the
table.
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Organization
Yes or No
Southern Company
No
Question 4 Comment
1. Table 1b should allow self-monitored circuits that are not alarmed but are monitored and logged by
personnel daily or more often. Many plants and substations have personnel that do in person checks of
unmanned control rooms. This is the equivalent of “Protection System components whose alarms are
automatically provided daily (or more frequently) to a location where action can be taken for alarmed failures.”
For example, dc system ground potential lights and dc system volt meters exist on most control room bench
boards or exist in the digital control systems at generating stations. These devices are monitored by
operators in manned control rooms.
2. On Table 1b, Protection System Control Circuitry (Trip Coils and Auxiliary Relays), the monitoring
component calls for “Monitoring and alarming of continuity of trip coil(s).” Clarify that “trip coil(s)” excludes
Breaker Failure Initiate relay coil(s).
3. On Table 1b, Protection System Control Circuitry (Trip Coils and Auxiliary Relays) Experience has shown
that electrically operating fully monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is
not warranted. This testing introduces risk from a human error perspective as well as from additional
switching and clearances required. We recommend eliminating this maintenance requirement from Table
1b.
4. On Table 1c, Protection System Control Circuitry (Trip Coils and Auxiliary Relays) Experience has shown
that electrically operating fully monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is
not warranted. This testing introduces risk from a human error perspective as well as from additional
switching and clearances required. We recommend changing this maximum maintenance interval to 12
years.
5. Component monitoring attributes need to be defined for all components in table 1b and 1c. For example,
the attributes for voltage and current sensing devices could be that "Voltage and current input circuits are
monitored and alarmed".
6. Based on past performance, the requirement to electrically operate trip coils, auxiliary relays, and lockout
relays every 6 years in Table 1b is not warranted. We recommend complete functional testing including
electrical operation of breaker trip coils, auxiliary trip relays, and lockout relays every 12 years in tables 1b
and 1c.
Response: Thank you for your response.
1. The SDT modified the Table 1b header to address your comment by adding “condition or” to the General Description. See FAQ V-1-D (page 30).
2. The SDT has modified the standard to clarify that this monitoring addresses monitoring of the trip circuit(s), rather than the trip coil(s).
3. The SDT believes that it is important that these mechanical devices be periodically (physically) exercised to assure that they will operate properly.
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Organization
Yes or No
Question 4 Comment
4. The SDT believes that the intervals in the table are appropriate. The standard allows entities to utilize Performance-Based maintenance if they have
appropriate documented experience.
5. The tables have been modified to address this issue, except where no relevant monitoring attributes exist.
6. The SDT believes that the intervals in the table are appropriate. The standard allows entities to utilize Performance-Based maintenance if they have
appropriate documented experience.
US Bureau of Reclamation
No
The condition based monitoring only provides for a very narrow process and excludes sound judgment in
determining maintenance intervals. As long as the registered entity establishes parameters by which
variation in the prescribed maintenance intervals are determined, justified variation should be allowed.
Response: The SDT thanks you for your comments. The SDT, in accordance with FERC Order 693, has prescribed maximum allowable maintenance
intervals for unmonitored Protection System components (Table 1a), partially-monitored Protection System components (Table 1b), and fullymonitored Protection System components (Table 1c). For further discussion pertaining to intervals see Supplementary Reference Document, Section
8 (page 9). To allow an entity to use their discretion to extend these intervals, absent adoption of the criteria established for performance-based
maintenance, would be contrary to the direction established by FERC. For further discussion pertaining to performance based maintenance see
Supplementary Reference Section 9.
Austin Energy
Yes
Bonneville Power Administration
Yes
CPS Energy
Yes
Dynegy
Yes
E.ON U.S.
Yes
ENOSERV
Yes
Entergy Services, Inc
Yes
FirstEnergy
Yes
Georgia System Operations
Yes
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Organization
Yes or No
Question 4 Comment
Corporation
Indianapolis Power & Light Co.
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NextEra Energy Resources
Yes
Northeast Power Coordinating
Council
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
Otter Tail Power
Yes
PacifiCorp
Yes
Platte River Power Authority
Maintenance Group
Yes
RRI Energy
Yes
Saskatchewan Power
Corporation
Yes
Transmission Owner
Yes
TVA
Yes
June 3, 2010
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Organization
Yes or No
Western Area Power
Administration
Yes
Wisconsin Electric
Yes
Xcel Energy
Yes
MRO NERC Standards Review
Subcommittee
Yes
Question 4 Comment
A. The MRO NSRS agrees with this approach; however, I think most entities will not see the advantage of
condition-based maintenance until they can resolve any gaps in data retention. If an entity was retaining a set
of maintenance records but failed to include all the needed information as specified in this standard so they
would need to adjust their maintenance procedure to collect all information and then they would need to wait
for the entire retention period until they could start using the extended maintenance interval. If an entity had a
collateral set of records which verified the information that lacked in the original maintenance record then
could the entity start using the extended maintenance interval? For example, an entity has records showing
that they have maintained a voltage or current transformer within the prescribed maintenance interval listed in
level 1 monitoring (which is a maximum 12 year maintenance interval). Could this same entity go to level 3
monitoring (which is a continuous maintenance interval) immediately if it can query their SCADA and produce
detailed records indicating the accuracy of the PT or CT for the maintenance records already retained?
B. For lockout relays, if commissioning tests are done diligently, the trip DC availability is continuously
monitored and the trip coil itself is continuously monitored, is it necessary to operate these relays for
functional testing? For breaker failure lockout relays, re-verifying the operation of the coil and all the contacts
could mean taking multiple breakers and line terminals out of service at the same time. Functional trip tests
could cause unintentional tripping of equipment, cause equipment damage and interruption of service to
customers. It's hard to see how the reliability of the BES is significantly improved by doing this test. The
MRO NSRS feels the risk of adverse impact could be greatly reduced by a longer interval such as 12 years.
C. In table 1c, the word “continuous or continuously monitored” is used. Please clarify the “within 1 hour” time
frame takes into account that there may be a communication outage (failover) that will prevent an entity to
“continuously” monitor a device.
Response: The SDT thanks you for your comments.
A. It appears to the SDT that this comment actually is addressing performance-based maintenance, rather than condition-based maintenance. If the
entity has all the necessary records to support immediate moving to a specific level of maintenance, or to performance-based maintenance, there
should be no barrier to such an action.
B. The SDT is not aware of any monitoring system that can verify that these mechanical devices can indeed physically operate properly; thus the
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Organization
Yes or No
Question 4 Comment
interval is established at 6 years. (See Supplementary Reference Document Section 15.4, page 23.)
C. “Continuous monitoring” is an attribute of the Protection System component to produce an indication of state or status; the 1-hour constraint refers
to the communication method used to monitor the indications. The equipment used to monitor the alarms must be returned to service within the
shortest Table 1a interval of the monitored components. For example, if monitoring is used to defer the 3 month Table 1a maintenance activity related to
Protection System Control Circuitry, the monitoring function must be returned to service within 3 months. This has been added to Table 1b and Table 1c
as a required attribute for the associated type of protection system component.
City Utilities of Springfield, MO
Yes
CU agrees with the approach, but, may not agree with the exact wording in the tables. For instance, the use
of the word “every” in table 1c in “Protection System components in which every function required for correct
operation of that component is continuously monitored and verified” may be overstating the level of monitoring
that would realistically enable a Protection System to use table 1c.
Response: The SDT thanks you for your comments. Table 1c establishes that, with the monitoring attributes specified, periodic maintenance may not
be necessary at all. In order to facilitate this, the constraint, “every function required for correct operation of that component is continuously
monitored and verified” must be met. If a component cannot meet this constraint, it must be addressed within either Table 1b or Table 1a, as
appropriate.
Florida Municipal Power Agency,
and its Member Cities
Yes
FMPA agrees with the approach, but, may not agree with the exact wording in the tables. For instance, the
use of the word “every” in table 1c in “Protection System components in which every function required for
correct operation of that component is continuously monitored and verified” may be overstating the level of
monitoring that would realistically enable a Protection System to use table 1c.
Response: The SDT thanks you for your comments. Table 1c establishes that, with the monitoring attributes specified, periodic maintenance may not
be necessary at all. In order to facilitate this, the constraint, “every function required for correct operation of that component is continuously
monitored and verified” must be met. If a component cannot meet this constraint, it must be addressed within either Table 1b or Table 1a, as
appropriate.
JEA
Yes
Is it possible that for coil monitored equipment, such as LOR coils, that they were left out, of this Table
allowing for a longer maintenance interval. Certainly LOR continuous coil monitoring with alarming to a 24
hour 7 day a week manned location, with emergency dispatch, would allow for a longer maintenance interval
for continuously monitored LORs. Suggestion here might be alignment with continuously self-tested,
monitored and alarmed microprocessor relays at 12 years.
Response: The SDT thanks you for your comments. Monitoring of the coil of these devices does not assure that the device will mechanically operate
properly; thus the interval for verification of proper physical operation is established at 6 years similarly to Table 1a and Table 1b. (See Supplementary
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Organization
Yes or No
Question 4 Comment
Reference Document, Section 15.4, page 23.)
ITC Holdings
Yes
We agree with the approach. We have several issues with the details of Maintenance Issues, Interval and
Monitoring Attributes. See previous comments for Questions 2 and 3.
Response: The SDT thanks you for your comments. See response to your comments in Questions 2 and 3.
Ameren
Yes
We agree with the condition-based approach. Our comments in 3 above apply to Tables 1b and 1c as well.
We note that Table 1b Station dc supply intervals are the same as Table 1a. Why doesn’t the monitoring
cause 1b intervals to be longer than 1a?
Response: The SDT thanks you for your comments. The standard (specifically Table 1b) has been modified in consideration of your comment.
Lower Colorado River Authority
Yes
We commend the drafting team for recognizing the advantages of using monitored systems and a conditionbased approach. This approach recognizes the benefits of using newer technologies and will give utilities
added incentive to update their relay systems.
Response: The SDT thanks you for your support.
Puget Sound Energy
June 3, 2010
Yes
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5. Within PRC-005 Attachment A, the draft standard establishes parameters for performance-based maintenance,
where the historical performance of the devices is known and analyzed to support adjustment of the maximum
intervals. Do you agree with this approach? If not, please explain in the comment area.
Summary Consideration: Many of the respondents agreed with this approach, but comments indicated concern about
perceived administrative difficulties in establishing performance-based maintenance programs. The SDT responded to these
concerns by noting that associated administrative program development is one of the considerations that an entity must
address when contemplating use of such a program.
Organization
Yes or No
Green Country Energy LLC
MRO NERC Standards Review
Subcommittee
Question 5 Comment
N/A does not apply
No
A. The MRO NSRS is concerned that this approach could lead to non-compliance if the company follows this
process and a Compliance Auditor disagrees with the method that was used. An applicable entity should be
protected if they follow the standard appropriately. There should be some assurance of a grace period for
mitigation if this selected approach was not accepted.
B. Please provide the basis for having at least 60, then taking 30 (50%) for testing/maintenance. This may
give an unfair advantage to larger companies rather than being fair across the board. This places an undue
burden on smaller companies by having to team up with other asset owners.
Response: The SDT thanks you for your comments.
A. See Attachment A of standard. The entity has three years to get performance to an acceptable level (under 4% countable events) or get on the
appropriate time-based interval.
B. The requirement for having 60 and testing 30 is based on having a statistically significant number of devices. Please see Section 9.1 (page 16) of
the Supplementary Reference Document for a discussion of the statistical basis. The standard allows smaller entities to share data in order to support
their ability to utilize performance-based maintenance.
CenterPoint Energy
June 3, 2010
No
a. CenterPoint Energy lauds the SDT for recognizing that strict imposition of the maximum interval approach
creates problems which the SDT attempts to correct by allowing performance-based adjustments.
CenterPoint Energy believes the majority of industry commenters will agree with CenterPoint Energy’s
assessment that the maximum interval approach is problematic and should be dropped from the proposal.
However, if the majority of industry commenters agree with the SDT’s approach, then a performance-based
option to correct the problems introduced by the maximum interval requirements should remain.
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Organization
Yes or No
Question 5 Comment
b. CenterPoint Energy answered “No” to question 5 because CenterPoint Energy believes the arduous path of
creating a new set of problems with a rigid approach (maximum interval requirements) and then introducing a
complex set of auditable requirements to provide an option (performance-based maintenance) to mitigate the
harm of the rigid approach is ill-advised and fraught with pitfalls. Stated otherwise, using performance-based
adjustments to correct inappropriate maximum intervals would not be necessary if the inappropriate maximum
intervals were not imposed. CenterPoint Energy believes a better approach is to avoid introducing the new
set of problems that then have to be mitigated by not imposing problematic maximum intervals.
c. Followed to its logical conclusion, using performance-based adjustments to correct inappropriate maximum
intervals is a contorted way of arriving at the philosophy embodied in the current set of standards in which
entities determine the maximum intervals appropriate for their circumstances and performance. CenterPoint
Energy’s concern is that the contortions needed to arrive at the same point, in addition to being unnecessary,
will be difficult for most entities to navigate. An entity making a good faith effort to comply with the
performance-based adjustments will have to navigate through the complexities and nuances of the approach,
as illustrated by the extensive set of documents the SDT has provided in an attempt to explain all the
requirements and nuances. As an entity attempts to manage this hurdle, the entity will likely have to deal with
the reality that the granularity of performance metrics do not exist in most cases to justify to an auditor the
rationale for the adjustments to the inappropriate maximum intervals. For example, CenterPoint Energy has
asserted that it has had good battery performance using existing practices. However, the assertion is
anecdotal. CenterPoint Energy cannot recall any instances where it had a relay misoperation due to battery
failure in over twenty five years. CenterPoint Energy does not attempt to keep performance metrics on events
that historically occur less than four times a century and CenterPoint Energy believes most entities will be in
the same situation.
d. If an entity is somehow able to overcome these hurdles, the entity will almost certainly encounter
skepticism for what will be viewed as an exception to the default requirement embodied in the standard. Even
if an entity can overcome likely skepticism in an audit, the entity will be in a severely disadvantaged situation if
a protection system component for which the maintenance interval has been adjusted, based on the entity’s
good faith effort and reasoned judgment, nevertheless is a contributing factor in a major reliability event
investigation, regardless of whether the maintenance interval adjustment contributed to the failure. No matter
what maintenance intervals are used, protection system components could fail. If the maintenance interval
has been adjusted and if failure occurs, it will likely be unknown whether the interval adjustment was in fact a
contributing factor or whether the failure would have occurred anyway.
e. Faced with this dilemma, in addition to all the other hurdles to overcome in attempting to adjust an
inappropriate maximum interval, the reality is that most entities will accept the inappropriate maximum interval
and over-maintain their protection system components, and introduce a new set of reliability risks from such
over-maintenance. For these reasons, CenterPoint Energy advises against creating a new set of problem by
imposing rigid maximum intervals and then attempting to correct the problems through a performance-based
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Organization
Yes or No
Question 5 Comment
mechanism that in actual practice would likely be illusory.
Response: The SDT thanks you for your comments.
a. FERC order 693 requires that NERC establish maximum time intervals. The criteria for performance-based maintenance are established for entities
that wish to establish other intervals based on concise stated criteria.
b. FERC order 693 requires that NERC establish maximum time intervals. The SDT believes that the established intervals are appropriate. The criteria
for performance-based maintenance are established for entities that wish to establish other intervals based on concise stated criteria.
c. Entities are not required to use PBM, but instead may elect to simply use the intervals established in Table 1a, Table 1b, and/or Table 1c. However, if
an entity keeps the necessary metrics to conform to Attachment 1, it may find opportunities within PBM; however, the SDT has established that
maintenance of station batteries must be performed within a time-based maintenance program.
d. The standard established maximum intervals, minimum maintenance activities, and, for PBM, minimum requirements (and performance). If an entity
is concerned about whether these intervals will yield acceptable performance, it may perform more maintenance, more frequently, than established
within the standard.
e. FERC order 693 requires that NERC establish maximum time intervals. The criteria for performance-based maintenance are established for entities
that wish to establish other intervals based on concise stated criteria, but entities are not required to use PBM.
ITC Holdings
No
Appendix A fixes a 4% level of “countable events”. Is this number the industry average for countable events?
Has the industry average actually been determined? The basis for the 4% requirement noted in Paragraph 5
of Appendix A should be included in the reference document. Also a sample calculation for adjusting the
interval is needed to clarify the requirement.
Response: The SDT thanks you for your comments. We used failure and calibration data from some of the utilities on the drafting team to determine
the 4% level; this value is also determined such that a single countable event on the 30 unit minimum test sample established via the statistical
analysis described in Section 9 of the Supplementary Reference Document (page 15) does not exceed the threshold. See FAQ IV-3-D thru IV-3-F
(pages 25-26) which discusses types of Misoperations and correcting segment performance.
American Transmission
Company
No
ATC agrees with this approach but is concerned that Attachment A does not contain enough language to
support an entity that implements this practice. This attachment needs to clearly state that following your
performance-based maintenance practices satisfies an entity’s compliance obligations. Entities should not be
subject to non-compliance over disagreements with their performance-based maintenance methodology.
Response: The SDT thanks you for your comments. The SDT believes Attachment A does contain enough language to support PBM, and this
language is further supported by technical guidance from Section 9 of the Supplementary Reference Document (page 15). Additionally, R3 of the
standard specifically provides that an entity that follows the requirements detailed in Attachment A is indeed in compliance. The SDT will consider any
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Question 5 Comment
suggested improvements.
E.ON U.S.
No
E.ON U.S. recommends keeping with time-based intervals (and the improvement thereof) and staying clear of
condition-based performance for the generating stations. But that is not meant to preclude other companies
from doing condition-based, if they so prefer.
Response: The SDT thanks you for your comments.
Indianapolis Power & Light Co.
No
Establishing historical performance and keeping the documentation up to date makes this almost useless
Response: The SDT thanks you for your comments. Entities are not required to use PBM.
Florida Municipal Power Agency,
and its Member Cities
No
FMPA believes that the documented process outlined in Attachment A; "Criteria for Performance Based
Protection System Maintenance Program" is biased towards larger entities. The requirement that the
minimum population of 60 individual components of a particular segment is required to make a component
applicable to this program automatically eliminates most of the small or medium sized entities. Further the
need to first test a minimum of 30 individual components in any segment reinforces the same size limitation.
FMPA suggests that the Performance-Based Protection System Maintenance Program allow for regional
shared databases applicable towards meeting the establishment and testing criteria of similar individual
components. This practice will allow for the inclusion of entities of all sizes. This will also provide a greater
format for the discussion of lessons learned and improvements to the testing database on a regional basis.
Response: The SDT thanks you for your comments. The requirement for having 60 and testing 30 is based on having a statistically significant number
of devices. Please see Section 9.1 of the Supplementary Reference Document (page 16) for a discussion of the statistical basis. The standard allows
smaller entities to share data in order to support their ability to utilize performance-based maintenance. See footnote 4 of Attachment A.
Duke Energy
No
For utilities like us with large numbers of relays it’s too complicated, which drives us back to Table 1a.
Response: The SDT thanks you for your comments. Entities are not required to use PBM.
Illinois Municipal Electric Agency
No
IMEA supports comments submitted by Florida Municipal Power Agency that the process outlined in
Attachment A is biased towards larger utilities.
Response: The SDT thanks you for your comments. The requirement for having 60 and testing 30 is based on having a statistically significant number
of devices. Please see Section 9.1 of the Supplementary Reference Document (page 16) for a discussion of the statistical basis. The standard allows
smaller entities to share data in order to support their ability to utilize performance-based maintenance. See footnote 4 of Attachment A.
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Organization
Yes or No
City Utilities of Springfield, MO
No
Question 5 Comment
It appears that Attachment A was written for large utilities. Some allocation needs to be made for utilities with
smaller numbers of components.
Response: The SDT thanks you for your comments. The requirement for having 60 and testing 30 is based on having a statistically significant number
of devices. Please see Section 9.1 of the Supplementary Reference Document (page 16) for a discussion of the statistical basis. The standard allows
smaller entities to share data in order to support their ability to utilize performance-based maintenance. See footnote 4 of Attachment A.
Saskatchewan Power
Corporation
No
Saskatchewan agrees with the approach, but requires clarification in the definition of segment. The definition
uses a population of 60 or more individual components but in the establishment of a PSMP, it only asks for a
population of 30 or more. Which number will be used to define the segment?
Response: The SDT thanks you for your comments. The requirement is that a minimum population of 60 units be present, and that at least 30 units be
tested on time-based maintenance (Table 1a) prior to moving to PBM. A minimum of 30 units tested is also used for ongoing analysis of the PBM
performance, as specified in Attachment A. Please see Section 9.1 of the Supplementary Reference Document (page 16) for a discussion of the
statistical basis.
Austin Energy
No
See item # 10 Comments
No
See question 2 response
Response: See item #10 response.
Wolverine Power Supply
Cooperative, Inc.
Response: See question 2 response.
Northeast Power Coordinating
Council
No
The concept is acceptable, but the requirements to follow in Appendix A seem to be a deterrent from
attempting to use this process. Is the term “common factors” meant to take into account variables at locations
that can affect the components” performance (lightning, water damage, humidity, heat, cold)”
Response: The SDT thanks you for your comments. The SDT has attempted to make Attachment A as straight forward as possible. The term
“common factors” does mean common variables that are expected to affect performance of the component such as lightning, water damage, humidity,
heat and cold. The term also means common variables such as design, manufacture, performance history, etc that are expected to affect performance
of the component.
US Bureau of Reclamation
June 3, 2010
No
The parameters established can only be implemented with documentation that defined in the document but is
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Question 5 Comment
not readily available.
Response: Before utilizing a PBM for their Protection Systems, an entity must develop the supporting documentation via application of a time-based
program (using the Table 1a intervals) in accordance with Attachment A.
CPS Energy
Yes
Detroit Edison
Yes
Dynegy
Yes
Electric Market Policy
Yes
ENOSERV
Yes
Entergy Services, Inc
Yes
Georgia System Operations
Corporation
Yes
Lower Colorado River Authority
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NextEra Energy Resources
Yes
Oncor Electric Delivery
Yes
Ontario Power Generation
Yes
Operations and Maintenance
Yes
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Organization
Yes or No
PacifiCorp
Yes
Pepco Holdings Inc.
Yes
Platte River Power Authority
Maintenance Group
Yes
RRI Energy
Yes
SCE&G
Yes
SERC (PCS)
Yes
Southern Company
Yes
Transmission Owner
Yes
Western Area Power
Administration
Yes
Wisconsin Electric
Yes
Xcel Energy
Yes
FirstEnergy
Yes
Question 5 Comment
Although we agree with the parameters of the proposed PBM, we have the following comments:
1. We question the inclusion of Misoperations in countable events as described in footnote 4. Since standard
PRC-004 already requires analysis and mitigation of Protection System Misoperations through a Corrective
Action Plan, entities should not be required to repeat this analysis and mitigation in PRC-005. We ask that the
SDT clarify the requirements to allow a tie between PRC-005 and PRC-004 so as to assure work is not
duplicated.
2. We are not receptive to using this methodology to develop intervals due to the detailed tracking and
analysis that will be required to establish maximum intervals. The approach may suit other utilities and thus,
we are not opposed to the methodology being contained within the standard.
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Question 5 Comment
Response: The SDT thanks you for your comments.
1. PRC-004 should be used to handle reporting of the Misoperation and its corrective action. However, the misoperation should be included as a
countable event required for PBM analysis. The documentation of correction of problems per PRC-004 should also suffice to address resolution of the
corresponding maintenance-correctable issue for PRC-005.
2. Entities are not required to use PBM.
JEA
Yes
Approach appears to be well explained. Only one are of concern and that would be delaying the
advancement of replacement of EM relay systems with microprocessor, if the PBM population were to
decrease below the 60, resulting in not meeting the sample minimum population criteria. Falling below this 60
population sample minimum, might result in an immediate compliance violation.
Response: The SDT thanks you for your comments. The standard is not meant to delay replacement of relays. An entity should do an annual analysis
of it segment size and countable events. As the segment population approaches 60, the entity should transition back to a time-based program per
Table 1a, Table 1b, or 1c, as appropriate, and assure that the remaining components are maintained accordingly.
Exelon Generation Company,
LLC
Yes
None
TVA
Yes
Should allow inclusion of dc systems as well.
Response: The SDT thanks you for your comments. A Station DC supply that does not include batteries may be fit into a PBM. See Section 15 of the
Supplementary Reference Document (page 21) (and FAQ IV-3-G, page 26) for a discussion of why station batteries cannot be included in a PBM.
Ameren
Yes
While we agree with the approach, batteries should be allowed, not excluded.
Response: The SDT thanks you for your comments. See Section 15 of the Supplementary Reference Document (page 21) (and FAQ IV-3-G, page 26)
for a discussion of why station batteries cannot be included in a PBM.
Puget Sound Energy
June 3, 2010
Yes
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6. The SDT has provided a “Supplementary Reference Document” to provide supporting discussion for the
Requirements within the standard. Do you have any comments on the Supplementary Reference Document?
Please explain in the comment area.
Summary Consideration: In general, respondents expressed appreciation for the additional technical discussion included
within this document. The SDT responded to many comments by explaining the relationship between the Standard and the
Reference Document. Several respondents suggested that elements of the extensive discussion be contained within the
standard itself, which is contrary to the guidance within the paradigm for NERC Standards.
Organization
Yes or No
Bonneville Power Administration
Question 6 Comment
Will this document be a part of the standard? Are its explanations the official interpretation of the standard?
Response: The FAQ and the Supplementary Reference Document are provided as references to present detailed discussions about determination of
maintenance intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT
believes that these documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes
that these documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority.
It is the drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference
document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the
Standards Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future
revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the
standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
American Transmission
Company
No
City Utilities of Springfield, MO
No
Detroit Edison
No
Electric Market Policy
No
ENOSERV
No
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Organization
Yes or No
Florida Municipal Power Agency,
and its Member Cities
No
Georgia System Operations
Corporation
No
Illinois Municipal Electric Agency
No
Indianapolis Power & Light Co.
No
JEA
No
Manitoba Hydro
No
Nebraska Public Power District
No
NextEra Energy Resources
No
Northeast Power Coordinating
Council
No
Operations and Maintenance
No
Pepco Holdings Inc.
No
RRI Energy
No
SCE&G
No
SERC (PCS)
No
Transmission Owner
No
TVA
No
June 3, 2010
Question 6 Comment
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Organization
Yes or No
Western Area Power
Administration
No
Wolverine Power Supply
Cooperative, Inc.
No
US Bureau of Reclamation
No
Question 6 Comment
The document will require revisions.
1. Performance based maintenance is establishing a strategy to achieve a desired performance. The document
limits strategy to statistical analysis of failure rates.
2. The document assumes a modern protection system with a high level of monitoring. Facilities which barely
qualify would not have high end monitoring installed.
3. The document also refers to “exercising a circuit breaker through t relay tripping circuits using remote control
capabilities via data communication.” This repeated several times throughout the document as a means of
increasing the TBM. This function, if indeed used, would require maintenance. This function is very dangerous
and could introduce a cyber vulnerability.
Response: The SDT thanks you for your comments.
1. As you say, PBM is an option to achieve a desired performance. The result should be a documented acceptable level of performance, and statistical
analysis of failure rates is required as a minimum method to achieve this level of performance.
2. The standard addresses all generations of equipment with varying levels of monitoring capability, and establishes requirements which address the
equipment with no monitoring capability, as well as facilitating effective use of monitoring capabilities of the equipment that DOES have those
capabilities.
3. Exercising a circuit breaker through the relay tripping circuits via a remote communication method is an available option to those entities that wish to
use it to satisfy maintenance intervals established in the standard, not to increase them; this is presented as an example of how entities may be able to
use remotely performed activities to minimize maintenance requiring station visits. If an entity is concerned about risks presented from remote
maintenance activities, they are not required to use such methods. Issues relating to cyber security are outside the scope of this Standard.
Ontario Power Generation
No
A well prepared and useful document.
Response: The SDT thanks you for your support.
MRO NERC Standards Review
June 3, 2010
No
N/A
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Organization
Yes or No
Question 6 Comment
Subcommittee
Exelon Generation Company,
LLC
No
None
Entergy Services, Inc
No
1. Regarding Section 2.3, Applicability of New Protection System Maintenance Standards, there needs to be
clarification and examples of applicable relaying associated with the language: and that are applied on, or are
designed to provide protection for the BES. For example, is the application of reverse power schemes and
directional overcurrent schemes considered applicable when considering the impact to the protection of the
BES?
2. We agree with the application of the term “calendar” in the PRC-005-2 Protection System Maintenance
Supplementary Reference document. There should be enough flexibility in interval assignments to allow for
annual maintenance planning, scheduling and implementation.
Response: The SDT thanks you for your comments.
1. Please refer to Clause 4 (Applicability) of the standard itself, and to the FAQ document (FAQ III – 2 – A, page 20), for further information on this. It
appears that this comment is focused on generation plants; Clause 4.2.5.1 of the draft standard states, “Protection system components that act to trip
the generator either directly or via generator lockout or auxiliary tripping relays.” This Applicability clause would have to be applied to the specific
instance of concern.
2. The SDT thanks you for your comments.
PacifiCorp
No
Very helpful.
Response: The SDT thanks you for your comments.
Austin Energy
Yes
Ameren
Yes
1) We disagree with the page 22 statement that batteries cannot be a unique population segment of a PBM.
2) What role does the Supplement play in Compliance Monitoring and Enforcement?
Response: The SDT thanks you for your comments.
1. Thank you for your comment concerning your disagreement with the standard Drafting Team that batteries cannot be a unique population segment of
a PBM. In FAQ IV-3-G (page 26) and the Supplementary Reference Document (See Section 15.4, page 23), the Drafting team states why batteries are
excluded from PBM. The Drafting Team still believes, that for the reasons stated in the FAQ, that batteries cannot be a unique population segment of a
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PBM. There was much debate on this topic in the standard drafting process. It is well known that like batteries will behave differently for even slight
variations of outside influences such as temperature, station load, battery charger action, number of duty cycles and even time spent on inventory shelf
before first charge. The manufacturers’ literature all state that you must control outside influences to attain a level of satisfactory performance. To prove
this level of satisfactory performance (and possibly to help detect poor performance from outside influences) you must conduct certain routine tests.
Routine tests are included within the Standard’s tables of maintenance activities.
2. The FAQ and the Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document.
In order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the Standards
Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future revisions to
PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the standard,
and the Standards Committee will have to remain convinced of their accuracy and relevance.
FirstEnergy
Yes
1. Sec. 2.3 (pg. 4) This section appears to be discussing the purpose of the standard and not the applicability.
We suggest changing the title of Sec. 2.3 to "Purpose of New Protection System Maintenance Standard."
Also, in Sec. 2.3 it states: "The applicability language has been changed from the original PRC-005: '... affecting
the reliability of the Bulk Electric System (BES) ...' To the present language: '... and that are applied on, or are
designed to provide protection for the BES.' However, the posted Draft 1 of PRC-005-2 still has the original
Purpose statement. Is the SDT planning to revise the Purpose statement as discussed in Sec. 2.3 of the Ref.
document? It appears that this statement is included in the applicability section 4.2.1 but believe it is more
appropriate as a general purpose statement applying to the whole standard.
2. Sec. 2.4 (pg. 4) Remove the extra word "that" from the second sentence of this section.
3. In the Supplementary reference, section 15.4 Batteries and DC Supplies, third paragraph, the SDT indicates
these tests are recommended in IEEE 450-2002 to ensure that there are no open circuits in the battery string.
This is essentially a continuity check of the battery string. In the fourth paragraph, the SDT states that
"..."continuity" was introduced into the standard to allow the owner to choose how to verify continuity of a battery
set by various methods, and not to limit the owner to the two methods recommended in the IEEE standards."
4. The SDT in Table 1a, the Maintenance Activity "Verify continuity and cell integrity of the entire battery", and in
Table 1b, the Maintenance Activity "Verify electrical continuity of the entire battery". Based on the information in
the Supplementary reference, the owner has to choose a method to verify continuity and the measurement of
specific gravity and cell temperatures could be the selected method, however it should not be a required
maintenance activity as shown in Tables 1a and 1b.
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Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments.
1. This clause of the document DOES specifically discuss the Applicability clause of the Standard; PRC-005-2 Section 4.2.1 states “Protection Systems
that are applied on, or are designed to provide protection for the BES.”
2. The Supplementary Reference Document has been changed in consideration of your comment – the extra “that” has been removed.
3. The standard and FAQ (See FAQ II-5-D, page 13) have been modified in consideration of your comments concerning checking continuity using specific
gravity.
4. Table 1a and Table 1b of the draft standard have been modified to remove requirements relating to measurement of cell temperature and specific
gravity.
CPS Energy
Yes
Adds to the confusion with the standard, FAQ, and Supplemental. The three documents at times describe
things a little differently.
Response: The SDT thanks you for your comments and is aligning the associated documents with changes to the standard.
AEP
Yes
Although helpful in understanding and clarifying intent, the requirements of a standard should be clearly written
so that multiple, lengthy supporting documents are not needed. These supporting documents do not get
recorded into the registry as part of the standard and may or may not be used by auditors during compliance
audits which could lead to different interpretations.
Response: The SDT thanks you for your comments. The FAQ and Supplementary Reference Document are provided as references to present detailed
discussions about determination of maintenance intervals and other useful information regarding establishment of a maintenance program, and do not
have statutory effect. The SDT believes that these documents provide potentially useful information to the entity in developing and sustaining an
effective PRC-005 program, and hopes that these documents will be useful to the entity in establishing support of their program when it is reviewed by
the Compliance Enforcement Authority. It is the drafting team's intent that these documents be posted with the standard when approved similarly to the
CIP FAQ and the PRC-023 reference document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo
industry comment and review, and the Standards Committee must be convinced through that process that the documents align with the standard and are
relevant to the standard. With future revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and
industry comment to remain posted with the standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
CenterPoint Energy
June 3, 2010
Yes
CenterPoint Energy believes the need for an extensive “Supplementary Reference Document”, in addition to 13
pages of tables and an attachment in the standard itself, illustrates that the proposal is too prescriptive and
complex for most entities to practically implement. CenterPoint Energy would prefer the SDT leave the existing
requirements substantially intact or, if most industry commenters prefer the SDT’s approach, that the SDT
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Question 6 Comment
attempt to simplify it.
Response: The SDT thanks you for your comments. The NERC Standard Development Procedure establishes that the standard prescribe requirements,
but avoid “how to” or “why” discussions. The SDT, in accordance with FERC Order 693, has prescribed maximum allowable maintenance intervals for
various Protection System Components, has provided opportunities for entities to use advanced technologies to perform physical maintenance less
frequently, and to use analytical techniques to customize their intervals. At its simplest, an entity could implement a pure time-based program utilizing
Table 1a, and much of the additional explanation in the Supplementary Reference Document would not be needed by that entity.
Public Service Enterprise Group
Companies
Yes
Figure 2 “typical generation system” shows a typical auxiliary medium voltage bus, suggest that a line of
distinction (dotted line) be added to the figure that defines the element connected to the BES (station Aux
Transformer - SAT) and equipment not associated with protection of the SAT be shown as not part of the BESPSMP.
Response: The SDT thanks you for your comments. The figures are provided to help describe the components of the Protection System, and are not
intended to fully describe the boundaries of the BES, the definition of which may vary by Region.
Wisconsin Electric
Yes
How much authority or weight will this document have with Compliance staff? If potential violations of the
standard requirements are alleged by Compliance staff, can this document be cited by an entity when the
document provides clarifying information on the requirements?
Response: The SDT thanks you for your comments. This document is not part of the standard, but is intended to provide the rationale of the SDT, as
well as guidance about how the various requirements might be met. The explanations are not an “official” interpretation of the standard, but may be
useful to determine how to implement various facets of the standard.
Green Country Energy LLC
Yes
Huge help to us!
Response: Thank you for your support.
Platte River Power Authority
Maintenance Group
Yes
1. It isn't clear in the Supplementary Reference Document why lock-out relays (86) are included as a component
of Protection Systems that require a 6 year maximum interval. Historically we haven't experienced any failures
with lock-out relays and feel the risk of causing a system reliability issue by removing it from service and
restoring it far outweighs the benefits of testing it. What, if any evidence, i.e. equipment failure, does the
standard drafting team use to mandate routine testing of 86 devices? Are we fixing something that isn't broke
here?
2. The FERC order directed NERC to submit a modification to PRC-005-1 that includes a requirement that
maintenance and testing of a protection system be carried out within a maximum allowable interval that is
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Organization
Yes or No
Question 6 Comment
appropriate to the type of the protection system and its impact on the reliability of the BPS. It would seem more
appropriate to allow each entity to set their own maximum allowable interval based on studies and historical data
of their specific protection system and impact on the reliability of the BPS opposed to a blanket approach that
covers all systems regardless of their size or system configuration.
Response: The SDT thanks you for your comments.
1. There are events in the industry that point to a failure of an electro-mechanical 86 device failing, and these devices are essential to proper functioning
of the Protection System. PBM principles can be utilized to extend maintenance intervals. (See Supplementary Reference Document, Section 9, page 15.)
2. FERC Order 693 directed that NERC establish maximum maintenance intervals, which does not provide the latitude to continue to allow entities to set
their own intervals. The SDT has, however, added the ability of an entity to follow PBM principles, as you describe, thus adjusting the time intervals
between required hands-on maintenance activity to reflect an entity’s experience.
Progress Energy
Yes
Progress Energy is concerned that separating this document from the standard may lead to issues down the
road. If the desire is to consolidate and clarify existing standards, then the two documents should be merged.
Otherwise the reference document may get lost from the standard, or might get changed without due process, or
might not even be recognized by FERC.
Response: The SDT thanks you for your comments. The FAQ and Supplementary Reference Document are provided as references to present detailed
discussions about determination of maintenance intervals and other useful information regarding establishment of a maintenance program, and do not
have statutory effect. The SDT believes that these documents provide potentially useful information to the entity in developing and sustaining an
effective PRC-005 program, and hopes that these documents will be useful to the entity in establishing support of their program when it is reviewed by
the Compliance Enforcement Authority. It is the drafting team's intent that these documents be posted with the standard when approved similarly to the
CIP FAQ and the PRC-023 reference document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo
industry comment and review, and the Standards Committee must be convinced through that process that the documents align with the standard and are
relevant to the standard. With future revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and
industry comment to remain posted with the standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
Southern Company
Yes
1.Section 15.3 DC Control Circuitry: Although we agree with the premise that auxiliary trip relays and lock-out
relays are similar in nature to EM relays and breakers, we believe that based on past performance, a complete
functional test trip every 6 years is not warranted. This complete functional test introduces additional risk to our
maintenance program not only from a human error perspective but also from the additional frequency of
switching and outages required. Our experience has shown that 12 years is an appropriate maximum time
interval (rather than 6 years.)
2. The Protection System Maintenance Supplementary Reference (Draft 1), section 8.4, states that the intervals
using the term “calendar” are allowed to be completed by the end of the applicable period, not necessarily
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Question 6 Comment
exactly at the interval specified. The only intervals specified in the PRC-005-2 tables are “calendar years” and
“months”. We believe that the “calendar” description should be extended to the “months” designator also to also
provide some maintenance flexibility (i.e. if an inspection were performed March 1st and was on a three month
interval, it would not be required until the end of June). This section should remove the term “calendar” and use
“months” and “years” with an appropriate explanation of the intent of the durations.
Response: The SDT thanks you for your comments.
1. The SDT believes that the intervals within the standard are appropriate. The standard permits the use of Performance-Based maintenance if an entity
has documented experience that supports longer intervals.
2. The standard was modified to append “Calendar” in front of “Months” in the Tables in consideration of your comment.
Dynegy
Yes
Suggest including operational verification (i.e. analysis of protection system operation after a system event) as
an acceptable method of verification.
Response: The SDT thanks you for your comments. Verification through analysis of events is an acceptable method of verification. Section 11 of the
Supplementary Reference Document (page 18) speaks to this topic.
Oncor Electric Delivery
Yes
The “Supplementary Reference Document” provides good technical justification for the various approaches to a
maintenance program (Time Based, Performance Based, and Condition Based) or combinations of these
programs that an owner of a Protection System can follow.
Response: The SDT thanks you for your support.
Xcel Energy
Yes
The information in the supplementary reference document is very helpful and valuable. Yet, it is not clear how
the document would be managed/revised, nor what role it plays in compliance monitoring. There needs to be a
clear understanding if everything in the document is required for compliance, e.g. criteria for monitored systems,
etc.
Additionally, we feel that evidence should be addressed within the supplementary reference document.
Response: The SDT thanks you for your support. The FAQ and Supplementary Reference Document are provided as references to present detailed
discussions about determination of maintenance intervals and other useful information regarding establishment of a maintenance program, and do not
have statutory effect. The SDT believes that these documents provide potentially useful information to the entity in developing and sustaining an
effective PRC-005 program, and hopes that these documents will be useful to the entity in establishing support of their program when it is reviewed by
the Compliance Enforcement Authority. It is the drafting team's intent that these documents be posted with the standard when approved similarly to the
CIP FAQ and the PRC-023 reference document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo
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Question 6 Comment
industry comment and review, and the Standards Committee must be convinced through that process that the documents align with the standard and are
relevant to the standard. With future revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and
industry comment to remain posted with the standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
The Supplementary Reference Document and FAQ have been updated to include a discussion pertaining to evidence for compliance.
Saskatchewan Power
Corporation
Yes
The supplementary reference document is useful information if properly explained and justified. Are the
suggestions in the reference document to become part of the standard, or simply recommendations of best
practice from industry and serve as a document to reduce the number of interpretations requested?
Response: The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of
maintenance intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT
believes that these documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes
that these documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority.
It is the drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference
document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the
Standards Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future
revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the
standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
Lower Colorado River Authority
Yes
The Supplementary Reference is well written and helpful in explaining the drafting teams thought process.
Response: The SDT thanks you for your support.
Duke Energy
Yes
We strongly believe that this document should be made a part of the standard, either as an Attachment or
worked into the requirements and tables. This will bring clarity to PRC-005 that is needed to get away from all
the past problems that were due to a lack of clarity with the previous PRC-005 standards. Also, all the
explanations and guidance lose force if they are not part of the standard. Auditors will only be bound by the
standard.
Response: The SDT thanks you for your comments. The NERC Standard Development Procedure establishes that the standard prescribe requirements,
but avoid “how to” or “why” discussions. The SDT, in accordance with FERC Order 693, has prescribed maximum allowable maintenance intervals for
various Protection System Components, has provided opportunities for entities to use advanced technologies to perform physical maintenance less
frequently, and to use analytical techniques to customize their intervals. At its simplest, an entity could implement a pure time-based program utilizing
Table 1a, and much of the additional explanation in the Supplementary Reference Document would not be needed by that entity.
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Organization
Yes or No
ITC Holdings
Yes
Question 6 Comment
1. Will clarifications in the Reference Document be enforceable with the standard?
2. For example page 11 of the reference document notes “Voltage & Current Sensing Device circuit input
connections to the protection system relays can be verified by comparison of known values of other sources on
live circuits or by using test currents and voltages on equipment out of service for maintenance.” Can a
maintenance program be confidently established using this or other testing methods included in the reference
document?
3. A condensed definition of “Condition Based Maintenance” as described in Section 6 of the Reference
document should be included in the standard document itself.
Response: The SDT thanks you for your comments.
1. The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document.
In order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the Standards
Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future revisions
to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the
standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
2. The NERC Standard Development Procedure establishes that the standard prescribe requirements, but avoid “how to” or “why” discussions.
3. Condition Based Maintenance is not intended to be a defined term; however, a discussion of the attributes of condition-based maintenance is
captured within the header of Table 1b and Table 1c of the Standard.
E.ON U.S.
June 3, 2010
Yes
1. With reference to Section 8.1., under additional notes is the following bullet:5. Aggregated small entities will
naturally distribute the testing of the population of UFLS/UVLS systems and large entities will usually maintain a
portion of these systems in any given year. Additionally, if relatively small quantities of such systems do not
perform properly, it will not affect the integrity of the overall program. This implies that incorrect performance of a
“relatively small quantity” of UFLS relays is acceptable but with the understanding that it is not optimal. E.ON
U.S. agrees with this statement in principle, in that the UFLS program is spread out across the system, and
there is not a one to one performance expectation as there is with a transmission line or generation protection
system. This calls into question the required intervals for testing of these types of relays, and the performance
expectations in a PBM program. Given the number of relays spread out across the distribution system, the
testing requirements of UFLS relays require longer testing intervals than other bulk transmission system
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Organization
Yes or No
Question 6 Comment
components.
2. 8.2 Is this requirement expected to be retroactive? That is, if the previous retention policy was followed to
the letter, an entity could be fully in compliance based on the previous standard, but not be in compliance if
PRC-005-2 were retroactive.
3. 8.3 And 8.4 This discussion explains how time based maintenance intervals were determined. The
conclusion is based upon surveys of SPCTF members and their existing practices, and seemed to arrive at a
maintenance interval based upon a simple average weighed by the size of the reporting utility. No
consideration appears to have been given to utilities who have successfully operated with longer test and
calibration intervals. In section 5 of the Supplementary Reference it is stated that “excessive maintenance can
actually decrease the reliability of the component or system.” With that in mind, some of the intervals defined in
the table seem too aggressive.
4. With the proposed PRC-005-2, the Drafting Team has effectively shortened the recommendation for UFLS
relays from 10 years to 6 years, with reference to the recommendations of the Protection System Maintenance
Technical Reference. E.ON U.S. believes that this is inconsistent with previous comments in Section 8.1, bullet
5 of the notes.
5. Consistent with the comments above and based on E ON U.S.’s internal testing, calibration and verification
experience, E.ON U.S. recommends maintenance on UFLS relays that comprise a protection scheme
distributed over the power system to be no less than 10 years for Level 1 monitoring and no less than 15 years
for Level 2 monitoring. For a PBM program, require the number of countable events within a segment to be no
more than 10%, not 4% as proposed.
Response: The SDT thanks you for your comments.
1. The SDT believes that the intervals specified in the standard are appropriate.
2. The new standard will be effective according to the dates established within the standard. The Implementation Plan posted with the standard
establishes a path for entities to migrate from their current practices and schedules to those imposed in this standard when approved.
3. Entities that have successful experience with equipment at intervals beyond the Standard’s tables can utilize the Standard’s PBM option.
4. The SDT believes that the intervals specified in the standard are appropriate, and disagrees that the intervals are inconsistent with the cited clause of
the Supplementary Reference Document.
5. Allowing the countable events to be increased to 10% would clearly allow an entity to increase its time interval between testing if there was a failure of
less than 10% of the testing segment. However, SDT contends that would be an unacceptably high rate of mal-performing Protection System
components, and would be detrimental to system reliability. The acceptable failure rate needs to balance between a goal of ultimate reliability and what
could be reasonably expected of a well-performing component population.
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Organization
Yes or No
AECI
No
Puget Sound Energy
Yes
Question 6 Comment
PSE appreciates this document as it provides a lot of further clarity. However, we wonder how this document
might be used during an audit. What is the formal process for the supplementation reference document to be
changed? How will entities be notified?
Response: The SDT thanks you for your support. This document is not part of the standard, but is intended to provide the rationale of the SDT, as well
as guidance about how the various requirements might be met. The explanations are not an “official” interpretation of the standard, but may be useful to
determine how to implement various facets of the standard. The FAQ and Supplementary Reference Document are provided as references to present
detailed discussions about determination of maintenance intervals and other useful information regarding establishment of a maintenance program, and
do not have statutory effect. The SDT believes that these documents provide potentially useful information to the entity in developing and sustaining an
effective PRC-005 program, and hopes that these documents will be useful to the entity in establishing support of their program when it is reviewed by
the Compliance Enforcement Authority. It is the drafting team's intent that these documents be posted with the standard when approved similarly to the
CIP FAQ and the PRC-023 reference document. In order that these documents are initially posted with PRC-005-2 when approved, they must undergo
industry comment and review, and the Standards Committee must be convinced through that process that the documents align with the standard and are
relevant to the standard. With future revisions to PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and
industry comment to remain posted with the standard, and the Standards Committee will have to remain convinced of their accuracy and relevance.
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7. The SDT has provided a “Frequently-asked Questions” document to address anticipated questions relative to
the standard. Do you have any comments on the FAQ? Please explain in the comment area.
Summary Consideration: In general, respondents expressed appreciation for the additional technical discussion included
within this document. The SDT responded to many comments by explaining the relationship between the standard and the FAQ.
Several respondents suggested that elements of the extensive discussion be contained within the standard itself, which is
contrary to the guidance within the paradigm for NERC Standards. Additionally, many of the comments in Questions 1-5 were
addressed by developing additional FAQ content and referring the respondents to the revised FAQ.
Organization
SCE&G
Yes or No
Question 7 Comment
1. The FAQ should be expanded to address the issues raised above with verification of trip circuits as to what is
an acceptable method meeting the intent of the standard.
2.
We also suggest changing “prove” to “verify” on FAQ 3a to be consistent with the wording of the
requirement.
3. Also, for a single bus with one set of bus potential transformers, how does one verify proper functioning of
the potentials? Is a reasonableness criterion adequate?
Response: The SDT thanks you for your comments.
1. The SDT agrees. The FAQ has been modified to address your concerns. (See FAQ II-4-E, page 11.)
2. The SDT agrees. The FAQ has been modified to address your concerns. (See FAQ II-3-A, page 8.)
3. The entity must verify that the protective devices are receiving the expected potential from the potential transformers or equivalent. If the potentials,
both magnitude and phase angle, can be determined to be reasonable, that would suffice. (See FAQ II-3-A, page 8.)
Bonneville Power Administration
Will this document be a part of the standard? Are its explanations the official interpretation of the standard?
Response: The SDT thanks you for your comments.
The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document.
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Organization
Yes or No
City Utilities of Springfield, MO
No
Dynegy
No
Electric Market Policy
No
ENOSERV
No
Florida Municipal Power Agency,
and its Member Cities
No
Georgia System Operations
Corporation
No
Green Country Energy LLC
No
Indianapolis Power & Light Co.
No
Operations and Maintenance
No
Platte River Power Authority
Maintenance Group
No
TVA
No
US Bureau of Reclamation
No
Western Area Power
Administration
No
Wisconsin Electric
No
Wolverine Power Supply
Cooperative, Inc.
No
June 3, 2010
Question 7 Comment
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Organization
Yes or No
E.ON U.S.
No
Question 7 Comment
E.ON U.S. disagrees with commissioning tests not being considered as a baseline for subsequent maintenance
activities. Commissioning tests should be counted as the initial testing in the scheme of a maintenance program
Response: The SDT thanks you for your comments.
As long as the requirements of the standard are met by the commissioning tests, they can “start the clock” for future maintenance testing. The FAQ has
been reworded to clarify this point. (The revised FAQ is IV-2-B, page 23.)
Ontario Power Generation
No
It was a good idea to prepare such a document.
Response: The SDT thanks you for your support.
Pepco Holdings Inc.
No
Item 3.B. (Page 6) claims that a small measurable quantity in 3I0 and 3V0 inputs to relays -may- be evidence that
the circuit is performing properly. This statement is weak at best, and incorrect at worst. A balanced
transmission system may exhibit 3I0 and 3V0 quantities that are not measurable, and those that are measurable
cannot be compared to other readings, since CT/PT error often exceeds system imbalance. Since these inputs
are verified at commissioning, recommend that maintenance verification require ensuring that phase quantities
are as expected and that 3IO and 3VO quantities appear equal to or close to 0.
Response: The SDT thanks you for your comments.
The SDT agrees; See FAQ II-3-B, page 9.
Exelon Generation Company,
LLC
No
None
MRO NERC Standards Review
Subcommittee
No
Overall, the FAQ’s are helpful toward understand what the SDT was thinking. Explanations for questions dealing
with the maintenance activities (e.g., battery testing) indicate an attempt to line up the requirement with IEEE
standards. While it is commendable to attempt alignment reliability standards with other industry standards, it
also begs the question of why requirements that are already covered by other standards should be repeated in
reliability standards. In addition, if the other standards are changed, then they could become inconsistent with or
contradictory to the reliability standard.
Response: The SDT thanks you for your support. The IEEE standards are voluntary standards, and do not establish any requirements, and also are not
measurable. PRC-005 standard requirements are loosely aligned with the IEEE standards and any future minor changes to those IEEE standards would
not significantly alter the correlation between PRC-005 standard requirements for batteries and the IEEE recommendations.
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Organization
Yes or No
American Transmission
Company
No
Question 7 Comment
Overall, the FAQ’s are helpful. Explanations for questions dealing with the maintenance activities (e.g., battery
testing) indicate an attempt to line up the requirement with IEEE standards. While commendable to attempt
alignment with the industry, it is further justification that maintenance activities should not be included in the
standard. Over the long term, technology or IEEE standards could change making the compliance standard
inconsistent.
Response: The SDT thanks you for your support. The IEEE standards are voluntary standards, and do not establish any requirements, and also are not
measurable. PRC-005 standard requirements are loosely aligned with the IEEE standards and any future minor changes to those IEEE standards would
not significantly alter the correlation between PRC-005 standard requirements for batteries and the IEEE recommendations.
PacifiCorp
No
Very helpful.
Response: Thank you for your support.
Austin Energy
Yes
Entergy Services, Inc
Yes
Manitoba Hydro
Yes
Public Service Enterprise Group
Companies
Yes
1) R1 - PRC-005-1 required the protection owner to supply a “basis” for the chosen maintenance intervals. Is it
intended that the new standard will no longer require the protection owners to provide a basis for their intervals
as long as they meet (or better) the published required intervals?
2) Compliance 1.4 Data Retention Needs more clarity. Some items require 12 years maximum maintenance
interval. However, we may perform the same maintenance in 6 years. The requirement for data retention is 2
maintenance intervals. In this example, does this mean 12 years or 24 years? Are we required to maintain
records for the maximum maintenance intervals allowed by the standard or only for the two shorter maintenance
intervals that we actually use?
3) Compliance will need some guidance on to what is required for “proper documentation”. Generally, the relay
technicians will scribe the actual test values for a given tests requiring the application of AC voltage and current.
However, as an example, when performing DC checks (DC aux relay), the technician may simply state that the
aux relay is “OK” without stating the DC coil pickup value in volts. Is this acceptable? Another example may be
when performing battery inspections (i.e., verify proper voltage of station battery, verify that no DC grounds exist,
etc), the inspector may simply indicate/document that the battery is “Ok”. This would indicate that appropriate 3
month inspections (as per table 1a) were completed and found to be within tolerances. Is this acceptable? If
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Organization
Yes or No
Question 7 Comment
specific details are required to be stored on test media (paper test sheets, computer based data storage, etc),
then please make some comments as such.
4) Table 1a DC supply. The 3 month inspection requires “verify that no dc supply grounds are present”. This
needs further clarification. What is the defined “limit” to determine whether we have a DC ground? The detection
methods for determining the presence of a DC ground will vary from indicating light balance to actual DC
ammeters or voltmeters. It is assumed that the intent of this requirement is to ensure that there are no full DC
grounds (dead shorts) in the DC terminals. Please clarify.
5) In the group by type of BES facility descriptions on pages 15 and 16 there is discussion about generation
station auxiliary transformers and associated protection devices. It also cites examples of relays which need not
be included even though they could result in tripping of the generating station. The line of demarcation is not well
defined in the FAQs or in the standard itself. Suggest that verbiage be added that clearly defines the element
(transformer) directly connected to the BES and its associated protection is what is included in the PSMP
requirements, items connected at lower voltage (down stream) are not within the PSMP requirement.
6) On page 15, the sample list of what is included in the standard, suggest that the list be expanded to show what
is not included (a relay that monitors parameters and is used for control/ alarm but not protection); generator
excitation controls that trip an auxiliary exciter. The list of items not included in the PSMP but that could trip the
unit should be further defined and expanded.
Response: The SDT thanks you for your comments.
1. The SDT agrees that no basis is required for level 1 monitoring as detailed in Table 1a. Monitoring attributes will be required to meet Table 1b and
Table 1c requirements. A performance based program will require further documentation; see Attachment A of the standard.
2. The SDT has modified the Data Retention area of the standard to clarify this.
3. The SDT will consider acceptable forms of evidence when developing the Measures. See the FAQ IV-1-B, page 21. Also, see Section 15.6 (page 24) of
the Supplementary Reference Document for a discussion of “evidence”.
4. Table 1a has been modified to address this, and an FAQ (FAQ II-5-I, page 15) has been added to clarify this. The revised language in the standard reads:
Check for unintentional grounds.
5. The SDT agrees; the FAQ has been modified to address your concerns see FAQ III-2-A, page 20.
6. The definition of Protection System states that “Protective relays, associated communication systems necessary for correct operation of protective
devices, voltage and current sensing inputs to protective relays, station DC supply, and DC control circuitry from the station DC supply through the trip
coil(s) of the circuit breakers or other interrupting devices.” Controls and alarms are excluded per the definition.
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Organization
Yes or No
Ameren
Yes
Question 7 Comment
1) We don’t think an Executive Summary is needed.
2) Please include the Supplement’s explanation of A/D verification method from Supplement page 9.
3) What role does the FAQ play in Compliance Monitoring and Enforcement?
4) Refer to question 2 and add our items # 2, 3, 4, 5, 7, and 11 to FAQ.
5) Please add FAQ that provides the NERC Compliance Registry Criteria for Generating Facilities, to clarify
applicability to >20MVA direct BES connection, aggregate >75MVA etc.
6) FAQ 2A p17 states that commissioning is construction, not maintenance. It seems like you’re ignoring the
significant verification, testing, inspection, and calibration activities that occur in commissioning. Should the inservice date be assigned to these components for determining their next maintenance?
7) Refer to question 3 and add our items # 4 to FAQ.
Response: The SDT thanks you for your comments.
1. The SDT thanks you for your input.
2. The SDT agrees; this information was already present in FAQ V-3-B (page 38).
3. The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that
these documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference
document.
4. The SDT agrees; see our response to your comment on Question 2.
5. The NERC Compliance Registry Criteria and Regional BES definitions are themselves requirements upon entities, and need not be explained within the
PRC-005 FAQ.
6. As long as the requirements of the standard are met by the commissioning tests, they can “start the clock” for future maintenance testing. See FAQ
IV-2-B (page 23).
7. The SDT agrees; see our response to your comment on Question 3.
NextEra Energy Resources
June 3, 2010
Yes
a. NextEra Energy believes the need for an extensive “Supplementary Reference Document”, in addition to 13
pages of tables and an attachment in the standard itself, illustrates that the proposal is too prescriptive and
complex for most entities to practically implement. NextEra Energy would prefer the SDT leave the existing
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Organization
Yes or No
Question 7 Comment
requirements substantially intact or, if most industry commenters prefer the SDT’s approach, that the SDT
attempt to simplify it.7. The SDT has provided a “Frequently-asked Questions” document to address anticipated
questions relative to the standard. Do you have any comments on the FAQ? Please explain in the comment
area. 1 Yes 0 No
Comments:
a. An alternative to measuring battery specific gravity is to measure float voltage and float current as described in
Annex A4 of IEEE Std 450-2002.
b. FAQ Page 17 (#1B): It is outside the jurisdiction of the standards development team to determine acceptable
forms of evidence. This should be decided by the Regional Entities.
c. FAQ Page 15 (#1A): This question should not have been included since it is addressing the definition of BES,
which is currently being addressed by another NERC Group.
d. FAQ Page 15 (#2): Although the FAQ is not enforceable, the answer provided may be interpreted as
enforceable. This should be included in the standard and not in the FAQ.
Response: The SDT thanks you for your comments.
The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities and maximum intervals
necessary to implement an effective PSMP.
a. The SDT has modified the standard in consideration of your comment by removing the maintenance activity of measuring specific gravity.
b. Other commenters have requested assistance in determining applicable evidence. The SDT has provided guidance that agrees with entities’ experience
regarding effective evidence during actual audits. See FAQ IV-1-B, page 21 and Supplementary Reference Document, Section 15.6, page 24.
c. Including the definition of the BES in the FAQ is helpful to some entities, and addresses common questions from other commenters; the FAQ states
that the RRO’s may have additional criteria.
d. The FAQ is intended to present examples of applicable devices, and is not intended to be all-inclusive. The requirements are established by the standard
definition of Protection System and the section 4 (“Applicability”).
CPS Energy
Yes
Adds to the confusion with the standard, FAQ, and Supplemental. The three documents at times describe things
a little differently.
Response: The SDT thanks you for your comments, however in the future please be more specific and identify the actual discrepancies so we can
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Organization
Yes or No
Question 7 Comment
improve the documents.
AEP
Yes
Although helpful in understanding and clarifying intent, the requirements of a standard should be clearly written
so that multiple, lengthy supporting documents are not needed. These supporting documents do not get
recorded into the registry as part of the standard and may or may not be used by auditors during compliance
audits which could lead to different interpretations.
Response: The SDT thanks you for your comments. The SDT believes that providing additional references helps clarify the requirements in the standard.
The SDT must address the directives of FERC orders 672 and 693 without being too prescriptive within the standard itself. According to the NERC
Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to be in a separate document.
Transmission Owner
Yes
An alternative to measuring battery specific gravity is to measure float voltage and float current as described in
Annex A4 of IEEE Std 450-2002.
Response: The SDT has modified the standard in consideration of your comment by removing the maintenance activity of measuring specific gravity.
SERC (PCS)
Yes
Change “prove” to “verify” on FAQ 3a (under Voltage and Current Sensing Devise Inputs to Protective Relays) to
be consistent with the wording of the requirement.
Response: The SDT thanks you for your comments. See FAQ II-3-A (page 8) – the word, “prove” was replaced with “verify” as proposed.
Detroit Edison
Yes
Example #1 on page 21 states “A vented lead-acid battery with low voltage alarm connected to SCADA. (level
2)”. However, Table 1b indicates that detection and alarming of dc grounds is also required for level 2.
Response: The SDT thanks you for your comments. The cited example is intended to show a mixture of Level 1 and Level 2 monitored components.
Those components not equipped with Level 2 monitoring must be maintained in accordance with Table 1a. Also, see the Decision Tree at the end of the
FAQ, addressing DC Supply monitoring levels.
ITC Holdings
Yes
1. FAQ page 6 question 3C should be clarified in the standard document itself. What is the technical justification
for omitting insulation testing of the wiring for DC control, potential and current circuits between the station-yard
equipment and the relay schemes? We feel this wiring is susceptible to transients which, over time, may
compromise the insulation, and therefore should be tested.
2. FAQ page 17 question 2A the standard should define when the first maintenance activity is to be performed.
We include our maintenance activities during commissioning, and set the next maintenance due date based on
the testing interval.
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Organization
Yes or No
Question 7 Comment
3. Will clarifications in the FAQs be enforceable with the standard? Can a maintenance program be confidently
established using this or other answers included in the FAQ’s?
Response: The SDT thanks you for your comments.
1. The SDT does not believe that insulation testing needs to be included within the minimum required maintenance activities; the SDT is not aware of a
body of evidence that suggests that these tests should be included as a requirement. The proposed standard does not prevent an entity from including
such tests in its program if their experience has indicated that such testing is needed. Furthermore, requirements for checking for proper current and
voltage at the relays and checking for DC grounds, provides some assurance of cable insulation integrity.
2. As long as the requirements of the standard are met by the commissioning tests, they can “start the clock” for future maintenance testing. See FAQ IV2-B, page 23.
3. The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority.
Nebraska Public Power District
Yes
On page 17, the answers to questions 2B and 2C indicate that there is no allowance or provision to exceed the
Maximum Maintenance Interval under any circumstances, except that natural disasters or other events of force
majeure will receive special consideration when determining sanctions. The rigidity of this performance
requirement could conceivably require equipment to be tested even though it is out of service in order to remain
compliant, adding unnecessary cost and waste to the PSMP of the regulated entities. We believe that a
prescriptive process for deferring testing and maintenance beyond the stated interval would be beneficial to allow
the necessary flexibility to manage the PSMP effectively.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may
need to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. The SDT is
concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals would thus not be
measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace period” would not
conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a discussion on this issue.
Should maintenance be due on equipment that is out-of service for a protracted period, the required maintenance should only be necessary before the
equipment is returned to service. However, you may encounter compliance challenges if you did not complete the maintenance during the scheduled
period, and should be prepared to document the out-of-service period and the subsequent maintenance.
Southern Company
June 3, 2010
Yes
Part of the responses could be more correctly stated: Page 11E, “why is specific gravity testing required” The
specific gravity measurements do not reflect accurate state of charge for lead-calcium batteries. (Float current is
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Organization
Yes or No
Question 7 Comment
a better parameter for this indication)
Response: The SDT thanks you for your comments concerning specific gravity being required. The SDT has modified the standard by removing the
requirement for specific gravity testing.
FirstEnergy
Yes
Pg. 17 (What forms of evidence are acceptable) Although Measures are not yet developed and posted with the
standard, we wanted to point out that the SDT should consider adding these acceptable forms of evidence in the
measures of the standard.
Response: The SDT thanks you for your comments. The SDT will consider identifying acceptable forms of evidence when developing the Measures.
Progress Energy
Yes
Progress Energy is unclear how a new/revised standard can have a 30 page FAQ document associated with it. If
questions need to be addressed, the answers should be incorporated into the existing standard. During this
stage of the draft, all questions should be addressed, not left to the side in an “interpretation” paper.
Response: The SDT thanks you for your comments. The SDT believes that providing additional references helps clarify the requirements in the standard.
The SDT must address the directives of FERC orders 672 and 693 without being too prescriptive within the standard itself. According to the NERC
Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to be in a separate document.
RRI Energy
Yes
Reverse power relays do not belong in the list of devices within the scope of this standard; reverse power is not
used for generator protection or protection of a BES element. Aside from the protection of reverse power for
other non-BES equipment, a generator can operate continuously as a generator, synchronous condenser, or a
synchronous motor. Reverse power relays (or reverse power elements in multi-function relays) is commonly
used as a control function for automatic shut-down purposes, which is not a protective function. Other reverse
power protection, with longer time delays, is provided for turbine protection, which is not within the scope of the
NERC Standards.
Response: The SDT thanks you for your comments. For some power plants, the reverse power relays trip the generation output breaker(s) and thus are in
scope per section 4.2.5.1 of the standard. The list of devices provides examples which may or may not be in scope of the standard depending upon how
they applied.
CenterPoint Energy
Yes
See CenterPoint Energy’s response to question 6. The need for an FAQ document in addition to an extensive
“Supplementary Reference Document” further illustrates the complexity and impracticality of the proposed
standard revisions.
Response: The SDT thanks you for your comments. See the response to your comments on Question 6.
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Organization
Yes or No
Question 7 Comment
The SDT believes that providing additional references helps clarify the requirements in the standard. The SDT must address the directives of FERC
orders 672 and 693 without being too prescriptive within the standard itself. According to the NERC Standard Development Procedure, a standard is to
contain only the prescriptive requirements; supporting discussion is to be in a separate document.
Oncor Electric Delivery
Yes
The FAQ document is an excellent resource document for Protection System Owners to understand why the
maintenance activities listed in the proposed standard were chosen.
Response: The SDT thanks you for your support.
JEA
Yes
The FAQ is a well written document and the team should take pride in its clarity and informative content. One
area that would be good to have further clarification, is if the SDT could provide a current industry product or
example of the "software latches or control algorithms, including trip logic processing implemented as
programming components, such as a microprocessor relay that takes the place of (conventional) discrete
component auxiliary relays or lockout relays that do not have to be routinely tested." Is this a microprocessor
lockout relay (that does not require trip testing?)
Response: The SDT thanks you for your support. The description indeed does reflect a microprocessor relay with imbedded lockout relay functions that
does not require trip testing for the lockout function. However, the breaker trip coil would still need to be tested as otherwise required in the standard.
Because of the NERC Antitrust Policy, the SDT is unable to provide commercial examples.
Northeast Power Coordinating
Council
Yes
The FAQ is helpful in answering many of the obvious questions.
Response: The SDT thanks you for your support.
Saskatchewan Power
Corporation
Yes
The FAQ section is beneficial, but would suggest reviewing it to determine if it can be integrated within the
reference document.
Response: The SDT thanks you for your support. The SDT will, to the degree possible, integrate material from the FAQ into the Supplementary Reference
Document. The SDT additionally believes that there is value in the FAQ that presents the material as questions and answers.
Lower Colorado River Authority
Yes
The Frequently-asked Questions document is very well written and very helpful. The decision trees are a good
addition.
Response: The SDT thanks you for your support.
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Organization
Yes or No
Xcel Energy
Yes
Question 7 Comment
1. The Frequently-asked Questions seem to act as interpretations to the standard. What roll will they play in
determining compliance?
2. On table 1b (page 11) the UFLS and UVLS maintenance activities indicate that tripping of the interrupting
device is not required, but it uses the term “functional trip test”. The FAQ indicates that a “functional trip test”
does require tripping the interrupting device. This conflicts with what is in the table and should be corrected in the
FAQ to reflect that no trip is required.
Response: The SDT thanks you for your comments.
1. The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document.
2. The SDT agrees with your comment. See FAQ II-4-E, page 11.
Illinois Municipal Electric Agency
Yes
Under “Group by Type of BES Facility”, 1. (page 15) “The radial exemption in the BES definition should be
clarified to include transmission subsystems within a single municipality, where the transmission facilities serving
only subsystem load with one transmission source - essentially operate radially. A more practical application of
the radial exemption would address smaller TOs whose system has minimal potential to impact the BES as a
whole.
Response: The SDT thanks you for your comments. The BES is a NERC and Regional defined term, and is outside the scope of this drafting team.
Requests for clarification regarding the BES definition should be referred to your Regional Entity. It isn’t clear to the SDT whether the example you
request is appropriate or accurate.
Duke Energy
Yes
We strongly believe that this document should be made a part of the standard, either as an Attachment or
worked into the requirements and tables. This will bring clarity to PRC-005 that is needed to get away from all
the past problems that were due to a lack of clarity with the previous PRC-005 standards. Also, all the
explanations and guidance lose force if they are not part of the standard. Auditors will only be bound by the
standard.
Response: The SDT thanks you for your comments. The SDT must address the directives of FERC orders 672 and 693 without being too prescriptive
within the standard itself. The SDT feels that providing additional references helps clarify the requirements in the standard and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. According
to the NERC Standard Development Procedure, a standard is to contain only the prescriptive requirements; supporting discussion is to be in a separate
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Organization
Yes or No
Question 7 Comment
document.
AECI
Yes
Group by Type of Maintenance Program:
2. Time-Based Protection System Maintenance (TBM) Programs
A. What does this Maintenance standard say about commissioning?
Commissioning tests are regarded as a construction activity, not a maintenance activity.
COMMENT 1: If we understand the question and answer correctly, we disagree. We believe that the standard
should accept commissioning as the first date for the maintenance testing if the commissioning tests correspond
to the Standard’s TBM testing procedures. Otherwise, maintenance tests on a new substation will be required to
be completed (again) based on the Implementation Plan guidelines for PRC-005-02.
Group by Type of Maintenance Program:
2. Time-Based Protection System Maintenance (TBM) Programs
C. If I am unable to complete the maintenance as required due to a major natural disaster (hurricane,
earthquake, etc.), how will this affect my compliance with this standard.
The NERC Sanction Guidelines provide that the Compliance Monitor will consider extenuating circumstances
when considering any sanctions.
COMMENT 2: We feel that guidelines should be provided for “extenuating circumstances”, specifically
addressing natural disasters.
Response: The SDT thanks you for your comments.
The FAQ will be reworded to clarify that commission tests can be used to establish initial performance of maintenance as long as the requirements
Tables 1a, 1b, & 1c are fulfilled. See FAQ IV-2-B, page 23.
The SDT believes that “extenuating circumstances” are addressed by the NERC Sanction Guidelines, and are therefore a discretionary issue between the
entity and the Compliance Enforcement Authority. Because of the variability in natural disasters and their potential impact on Protection System
maintenance programs, it does not seem practical to develop measurable requirements addressing this issue in the context of this standard. Additionally,
FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive.
Please refer to Section 8 (page 9) of the Supplementary Reference Document for a discussion on this issue.
Puget Sound Energy
June 3, 2010
Yes
PSE appreciates this document as it provides a lot of further clarity. PSE hopes this document will be updated
through by comments and questions provided during the development process. We wonder how this document
might be used in an audit as well. What is the formal process for the supplementation reference document to be
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Organization
Yes or No
Question 7 Comment
changed? How will entities be notified?
Response: Thank you for your support.
The FAQ and Supplementary Reference Document are provided as references to present detailed discussions about determination of maintenance
intervals and other useful information regarding establishment of a maintenance program, and do not have statutory effect. The SDT believes that these
documents provide potentially useful information to the entity in developing and sustaining an effective PRC-005 program, and hopes that these
documents will be useful to the entity in establishing support of their program when it is reviewed by the Compliance Enforcement Authority. It is the
drafting team's intent that these documents be posted with the standard when approved similarly to the CIP FAQ and the PRC-023 reference document. In
order that these documents are initially posted with PRC-005-2 when approved, they must undergo industry comment and review, and the Standards
Committee must be convinced through that process that the documents align with the standard and are relevant to the standard. With future revisions to
PRC-005, the FAQ and Supplemental Reference Document will have to undergo SDT review and industry comment to remain posted with the standard,
and the Standards Committee will have to remain convinced of their accuracy and relevance.
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8. If you are aware of any conflicts between the proposed standard and any regulatory function, rule, order,
tariff, rate schedule, legislative requirement, or agreement please identify the conflict here.
Summary Consideration: Most respondents were unaware of any conflicts. Some felt that conflicts existed with existing
business or Regional practices, or with other organizations such as the Nuclear Regulatory Commission. The SDT provided
clarifying explanations to illustrate that conflicts are not actually present.
Organization
ITC Holdings
Question 8 Comment
Comments: We are not aware of any conflicts.
Response: The SDT thanks you for your comments.
MRO NERC Standards Review
Subcommittee
Conflict: Order 672 says that standards should be clear and unambiguous.
Response: The SDT thanks you for your comments. The SDT must address the directives of FERC orders 672 and 693 without being too prescriptive
within the standard itself. The SDT believes that providing additional references helps clarify the requirements in the standard. Also, the SDT believes
that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address observations from the
Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general.
Lower Colorado River Authority
Conflict: Potential conflict with PRC-023 as to which PRS systems are applicable per this standard.
Comments: PRC-005-2 requires compliance for this standard for all non-radial systems over 100 kV; while, PRC-023-1
prescribes it as below: 1. Title: Transmission Relay Loadability2. Number: PRC-023-13. Purpose: Protective relay settings shall
not limit transmission loadability; not interfere with system operators’ ability to take remedial action to protect system reliability
and; be set to reliably detect all fault conditions and protect the electrical network from these faults.4. Applicability: 4.1.
Transmission Owners with load-responsive phase protection systems as described in Attachment A, applied to facilities defined
below:4.1.1 Transmission lines operated at 200 kV and above.4.1.2 Transmission lines operated at 100 kV to 200 kV as
designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System.4.1.3 Transformers with low
voltage terminals connected at 200 kV and above.4.1.4 Transformers with low voltage terminals connected at 100 kV to 200 kV
as designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System.4.2. Generator Owners with
load-responsive phase protection systems as described in Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.4.3.
Distribution Providers with load-responsive phase protection systems as described in Attachment A, applied according to
facilities defined in 4.1.1 through 4.1.4., provided that those facilities have bi-directional flow capabilities.4.4. Planning
Coordinators.
We believe Bulk Electric System (BES) owners resources would be better utilized by focusing on relay systems as defined in
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Organization
Question 8 Comment
the above PRC-023-1 and this would still provide high level of reliability for the BES, since not all facilities operating between
100 200KV are critical to the BES. This would not preclude any utilities from applying this standard to other facilities operating
at the lower voltage range. Why did the drafting team not use the application language sited in the “Protection System
Maintenance - A NERC Technical Reference” which is similar to what is described above from PRC-023-1?
Response: The SDT thanks you for your comments. The Energy Policy Act of 2005, as well as various FERC orders and the NERC Standards
Development Process requires that reliability standards should be applicable to the BES (or, in the case of the Energy Policy Act, the BPS, which is
almost synonymous). In the case of PRC-023-1, cited in the comment, that SDT as well as the NERC Staff was required to carefully explain why this
standard was not specifically applicable to the BES, but instead to a subset of the BES. The 2007-17 SDT has determined that a similar rationale cannot
be effectively determined for PRC-005-2, and thus specified that it should be applicable to the BES. It is noted that this applicability is similar to the
applicability for PRC-005-1.
Exelon Generation Company, LLC
Conflict
1. Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission (NRC). Each licensee
operates in accordance with plant specific Technical Specifications (TSs) issued by the NRC. TS allow for a 25% grace period
may be applied to TS Surveillance Requirements (SRs). Referencing NRC issued NUREGs for Standard Issued Technical
Specifications (NUREG-143 through NUREG-1434) Section 3.0, "Surveillance Requirement (SR) Applicability, SR 3.02 states
the following:" The specified Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval
specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of
the Frequency is met."
2. Battery Charger Testing
2a. All conditions (grounds, voltages etc) should be compared to "acceptable limits" as specified in nuclear station design basis
documents, industry standards or vendor data.
2b. IEEE 450 does not use the word "proper" as utilized in Table 1a (e.g., "record voltage of each cell v/s verify proper voltage
of each individual cell.")
3. The NRC Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness of maintenance to ensure reliable
operation of equipment within the scope of the Rule. Adjustments are made to the PM (preventative maintenance) program
based on equipment performance. The Maintenance Rule program should provide an acceptable level of reliability and
availability for equipment within its scope.
Comments:
4. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's refueling schedule
and emergent conditions that would prevent the safe isolation of equipment and/or testing of function. "Grace" periods align
with currently implemented nuclear generator's maintenance and testing programs.
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Organization
Question 8 Comment
5. The 3-month maximum interval should be extended to include a grace period to ensure that a 25% grace period is included
to align with current nuclear templates that implement NRC TS SRs are documented in the response to Question 8.
Response: The SDT thanks you for your comments.
1. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with
shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance
can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the
established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and
allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a
discussion on this issue.
2a. The SDT agrees that each entity establishes its own “acceptable limits”. In this case, “acceptable limits” would seem to be determined in the
materials cited, and would apply for PRC-005-2.
2b. The SDT agrees. The SDT modified the standard to address your concerns. The revised maintenance activity now reads: Inspect cell condition of
individual battery cells where cells are visible, or measure battery cell/unit internal ohmic values where cells are not visible.
3. The entity must satisfy all applicable requirements (in this case, NERC PRC-005-2 and the NRC 10 CFR 50.65) as they apply to common equipment.
Since the NRC requires monitoring of the effectiveness of the program, you must do so even if this isn’t in the NERC standard.
4. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with
shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance
can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the
established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and
allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a
discussion on this issue.
5. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be
numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with
shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance
can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the
established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and
allowing for a “grace period” would not conform to this directive. Please refer to Section 8 (page 9) of the Supplementary Reference Document for a
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Organization
Question 8 Comment
discussion on this issue.
City Utilities of Springfield, MO
CU is unaware of any conflicts.
Response: The SDT thanks you for your comments.
Florida Municipal Power Agency,
and its Member Cities
FMPA is not aware of any conflicts
Response: The SDT thanks you for your comments.
Green Country Energy LLC
It would be beneficial to include some administrative (man hour) and cost estimates to comply with this and any future
proposed standards so if major budget impacts could be addressed.
Response: The SDT thanks you for your comments. The SDT is unable to assess the costs of any specific entity to comply with this standard, as the SDT
is not aware of the degree to which that entity’s current program would satisfy the requirements of this standard. Additionally, “man-hours” would vary
widely with the size of the entity.
Operations and Maintenance
No conflicts known.
AEP
No known conflicts.
Duke Energy
None
Electric Market Policy
None
Nebraska Public Power District
None
PacifiCorp
None known.
SERC (PCS)
None known.
Ontario Power Generation
Not aware of any
Georgia System Operations
Not aware of any.
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Organization
Question 8 Comment
Corporation
American Transmission Company
Order 672 says that standards should be clear and unambiguous. This proposed standard is very complex. While the standard
allows entities to select the appropriate maintenance strategy (time based, performance based or conditioned based) for their
system the amount of data and tracking required to demonstrate compliance will be overwhelming.
Response: The SDT thanks you for your comments. At its simplest, using time-based maintenance and Table 1a, the documentation requirements should
not be vastly different than those to prove compliance to PRC-005-1 for a strong compliance program. If more advanced strategies are used,
documentation requirements to demonstrate compliance may very well increase.
The SDT believes that it has clearly and unambiguously defined the minimum activities and maximum intervals necessary to implement an effective
PSMP, and presented advanced strategies for those entities who wish to utilize them.
Indianapolis Power & Light Co.
Performing some of the maintenance activities may cause conflict with regional ISOs and their safe operation of the BES
Response: The SDT thanks you for your comments. To minimize system impact of such maintenance, the maintenance necessarily should be scheduled
at a time that minimizes the risks.
Northeast Power Coordinating
Council
Yes--NPCC Directory #3, NPCC Key Facility Maintenance Tables. All areas must implement changes at the same time.
Response: The SDT thanks you for your comments. PRC-005-2 is a NERC standard and as such it will have its own implementation plan. PRC-005-2
when implemented will be an ERO-wide standard which establishes minimum requirements; to the degree that these requirements are more stringent
than those currently imposed by any individual Regional Entity, the NERC requirements will govern. Any individual Regional Entity can establish MORE
stringent requirements.
Puget Sound Energy
PRC-STD-005
PRC-005-2 requires a Protection System Maintenance Program (PSMP) while PRC-STD-005 requires a Transmission
Maintenance and Inspection Plan (TMIP). Historically the requirements of PRC-005-1 and PRC-STD-005 folded nicely into one
consistent plan. Could the maximum intervals identified in PRC-005-2 be expected or audited against under PRC-STD-005
where it does not indicated that much specificity? PRC-STD-005 requires maintenance of lines and breakers over and above
what PRC-005-2 the expectations relative to breakers should align.
Response: The SDT thanks you for your comments. An entity can be audited to both NERC Reliability Standards and to Regional Standards, provided
that both are mandatory and enforceable. Where applicable, Regional Standards will have more stringent requirements. As for intervals, where different
intervals apply to the same piece of equipment, the more stringent intervals apply. Also, the NERC intervals would apply only to the equipment
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Organization
Question 8 Comment
associated with those intervals within the NERC Standard. If the Regional requirements address equipment not addressed within the NERC Standard,
only the Regional requirements are relevant.
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Consideration of Comments on draft of PRC-005-2 — Project 2007-17
9. If you are aware of the need for a regional variance or business practice that we should consider with this
project, please identify it here.
Summary Consideration: A number of respondents suggested that the standard should allow “grace periods” to defer
maintenance because of a variety of expected difficulties in completing the required activities within the established intervals.
The SDT consistently responded that a “grace period” would be contrary to a measurable standard, and that entities should
manage their programs to assure that the required activities are completed on schedule.
Organization
TVA
Regional Variance or
Business Practice
Business Practice
Question 9 Comment
Allow for deferrals to coordinate with generator outages.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may need
to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. Specifically, for
generation facilities, there would seem to be numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a
scheduled plant outage, and maintenance with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything
else; the SDT believes that this maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a
de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish
maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary
Reference Document (page 9) for a discussion on this issue.
Exelon Generation Company,
LLC
Business Practice
Business Practice: Nuclear Electric Insurance Limited (NEIL) variance allowance.
Response: The SDT thanks you for your comments. The SDT considered this issue when developing the intervals, and realizes that some entities may need
to perform certain maintenance activities more frequently to assure that the activities are performed within the required intervals. Specifically, for
generation facilities, there would seem to be numerous opportunities within the 6-year or longer intervals to perform the required maintenance during a
scheduled plant outage, and maintenance with shorter intervals can be characterized as non-intrusive maintenance, more of an inspection than anything
else; the SDT believes that this maintenance can be done on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a
de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish
maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the Supplementary
Reference Document (page 9) for a discussion on this issue.
ITC Holdings
June 3, 2010
Comment: We are not aware of any regional variance or business practice that should be considered
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Organization
Regional Variance or
Business Practice
Question 9 Comment
with this project.
Response: The SDT thanks you for your comment.
Green Country Energy LLC
Business Practice
Contractual commitments existing prior to NERC stds make it difficult to comply with some of the
maintenance activities.
Response: The SDT thanks you for your comment. Existing contracts may need to be adjusted to accommodate compliance to NERC standards.
City Utilities of Springfield, MO
CU is not aware of a need for a regional variance.
Response: The SDT thanks you for your comment.
Florida Municipal Power Agency,
and its Member Cities
FMPA is not aware of a need for a regional variance
Response: The SDT thanks you for your comment.
Electric Market Policy
Regional Variance
1. It is our understanding that once Project 2009-17: “Interpretation of PRC-004-1 and PRC-005-1 for
Y-W Electric and Tri-State” is approved, that the definition of a “Transmission Protection System”
would be included within PRC-005-2 or included within the NERC Glossary of Terms. However, the
specific protection that would be considered part of the “Transmission Protection System” would also
depend on the regional definition of the BES.
2. We suggest that the regions develop a supplement that provides further clarification on what
constitutes a “Transmission Protection System” given the regional definition of the BES.
Response: The SDT thanks you for your comments.
1. The 2009-17 interpretation addresses PRC-005-1. The SDT will monitor this interpretation to determine if any changes need to be made to PRC-005-2 in
response to this interpretation. In general, a definition cannot be established via the Interpretation process, but only through the comprehensive Standards
Development process.
2. You should present this concern to your region.
SERC (PCS)
June 3, 2010
Regional Variance
1, It is our understanding that once Project 2009-17: “Interpretation of PRC-004-1 and PRC-005-1 for
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Organization
Regional Variance or
Business Practice
Question 9 Comment
Y-W Electric and Tri-State” is approved, that the definition of a “Transmission Protection System”
would be included within PRC-005-2 or included within the NERC Glossary of Terms. However, the
specific protection that would be considered part of the “Transmission Protection System” would also
depend on the regional definition of the BES.
2. We suggest that the regions develop a supplement that provides further clarification on what
constitutes a “Transmission Protection System” given the regional definition of the BES.
Response: The SDT thanks you for your comments.
1. The 2009-17 interpretation addresses PRC-005-1. The SDT will monitor this interpretation to determine if any changes need to be made to PRC-005-2 in
response to this interpretation. In general, a definition cannot be established via the Interpretation process, but only through the comprehensive Standards
Development process.
2. You should present this concern to your region.
American Transmission
Company
Business Practice
Jointly-owned facilities should be a component of this standard. Comments: ATC shares services at
Substations; consider dividing the services, i.e. batteries and PTs.
Response: The SDT thanks you for your comments. This is a registration issue and it’s not within the scope of the SDT. If a company owns a facility that
meets the applicability section as described in this standard then it is responsible for the maintenance activities as described in this standard.
Ontario Power Generation
Regional Variance
Maintenance activities, and especially intervals, prescribed in NPCC Directory 3 (Maintenance Criteria
for BPS Protection) often differ from those in PRC 005 - 02. We recommend that NPCC aligns
Directory #3 with PRC 005 - 02 as much as possible. Technical justification should be provided for
any variance.
Response: The SDT thanks you for your comments. Any Regional Entity may develop its own requirements, as long as they are not less stringent than the
NERC requirements.
The SDT suggests that the commenter communicate with the NPCC regional staff regarding this concern.
AEP
No none regional or business practice variances known.
Nebraska Public Power District
None
PacifiCorp
None known.
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Organization
Regional Variance or
Business Practice
Question 9 Comment
Georgia System Operations
Corporation
None.
Operations and Maintenance
None.
Northeast Power Coordinating
Council
Not aware of any regional variance or business practice.
Response: The SDT thanks you for your comment.
JEA
Regional Variance
Regional variances in the Bulk Electric System definition as applied across regions allows for PSMP
to vary possibly even for the same region crossing tie lines. Also, accepted maintenance practices by
one region vary from accepted maintenance practices from another region. In the case of lower kV
non-redundant bus lockout protection systems, one region may allow for the protection system to be
taken out of service to perform maintenance, while another region may specifically prohibit this
practice (don't leave energized equipment protected by delayed clearing, etc.)
Response: The SDT thanks you for your comment.
Duke Energy
Regional Variance
Regions with ISO’s and RTO’s - Where the independent system operator (ISO) is not the same
company as the entity doing testing and maintenance, the independent system operator could prevent
the entity from performing scheduled maintenance and testing due to outage request constraints.
There should be no violation in such a situation, and the maintenance and testing just rescheduled.
Response: The SDT thanks you for your comments.
The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. The SDT is concerned that a “grace period”, if permitted, would be used
to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC
establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 (page 9) of the
Supplementary Reference Document for a discussion on this issue.
Wisconsin Electric
June 3, 2010
Regional Variance
See above Question 2, Item 7: There needs to be some recognition that Protection System's applied
on distribution-voltage systems may be included in a regional definition of a BES Protection System.
These systems are not designed or operated in the same way as Transmission or Generation
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Organization
Regional Variance or
Business Practice
Question 9 Comment
Protection Systems. Therefore, it is reasonable that these systems be subject to less rigorous
requirements.
Response: The SDT thanks you for your comments. See our response above to Question #2, item 7.
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10.If you have any other comments on this standard that you have not already provided in response to the prior
questions, please provide them here.
Summary Consideration: This question generated numerous comments and many respondents repeated comments offered
earlier in the document. Several of the respondents objected to the establishment of maximum allowable intervals at all, and
suggested that it should be left to the entities to establish their own intervals; the SDT explained that this would be directly
contrary to FERC directives related to the four current standards which are being addressed within this project. Additional
technical comments covered the full spectrum of the material in the standard and associated reference documents, and resulted
in extensive changes to the standard and in changes to both the Supplementary Reference (mostly to correct inconsistencies)
and to the FAQ (including addition of many additional topics). There was also concern about the documentation necessary to
demonstrate compliance.
Organization
Ameren
Question 10 Comment
1) Documentation could be a monumental task. Although FAQ 1B allows a comprehensive set of forms of documentation, a very
large number of people are involved across this set at most utilities. Producing a particular needle in the haystack may take
longer than an auditor would expect. Inspection forms can be structured to capture abnormal conditions, and thus normal
conditions are not recorded. Some items, like the red light monitoring a trip coil, may only be reported by exception (i.e., “red light
out, replaced bulb” but if the red light is on an operator may not report that).
2) We presume that the SDT would expect transmission facilities to be switched out of service if maintenance would result in
those facilities being unprotected. We think this should be stated or clarified, as there may be entities that still use differential
cutoff switches or other means of disabling protection for testing and have not considered the consequences of a concurrent fault.
Response: The SDT thanks you for your comments.
1. Much of your concern can be addressed within your program by careful design of your maintenance tracking forms and systems. In your example of a
red light, your maintenance can include documentation forms that require completion of either of multiple choices (e.g., OK, Not OK with resolution, etc).
2. This consideration relates to general planning, design, and operational issues, and is outside the scope of this standard. Various other NERC standards
apply.
Public Service Enterprise Group
Companies
June 3, 2010
1) R4 requires all maintenance correctable issues identified as part of a time based maintenance plan to be resolved in that same
maintenance period. This places a burden on some items (for example, 3 month battery inspections) to achieve adequate
resolution for problems that are not an immediate threat. For example, if a battery with a somewhat out of allowable range
specific gravity is found near the end of the maintenance period, scheduling and performing the work to replace the battery could
reasonably extend somewhat beyond the end of maintenance period. PSE&G requests that the drafting team revisit this
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Question 10 Comment
requirement and allow flexibility for corrections to be made within a specified reasonable timeframe when correctible issues are
identified that for practical reasons require extension for work completion beyond the end of the current maintenance interval.
2) Section 4.2.5.5 of the standard should define provide an example that just the transformer connected to the BES is included
and specifically exclude connected equipment beyond the LV terminals.
3) Draft implementation plan for requirements R2, R3 & R4 discusses table 1a as basis, should also address tables 1b and 1c.
Response: The SDT thanks you for your comments.
1. Requirement R4, Part4.3 has been added to the standard in consideration of your comments. It reads as follows:
R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, including identification of the resolution of all
2
maintenance correctable issues as follows: [Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]
4.3
Assure either that the components are within acceptable parameters at the conclusion of the maintenance activities or initiate any necessary
3
activities to correct unresolved maintenance correctable issues .
2. The SDT disagrees with your comment. For example, current transformers on low-voltage transformer bushings or low-voltage breakers, which are
associated with differential relays, must be considered within application of PRC-005-2. See Figure 2 in the Supplemental Reference Document (page 28)
for an illustration.
3. The SDT believes that the implementation period for PRC-005-2 must be kept as brief as possible; until PRC-005-2 is fully implemented, entities will have
to be compliant with PRC-005-2 for those components for which implementation has been completed, and with PRC-005-1 for all other components.
However, entities may need considerable time to become compliant with the more specific requirements of PRC-005-2. An implementation period based on
Table 1a seems to be the best compromise period to achieve this. Additionally, the Implementation Plan does not require that entities adopt the Table 1a
activities and intervals, but instead just refers to the Table 1a components and their intervals for establishment of a phased implementation.
Wisconsin Electric
1. In the definition of a Protection System Maintenance Program, the statement is made that "A maintenance program CAN
include...” with a list of seven attributes following. Is it the intent that the PSMP "SHALL include one or more of the following”?
What is to prevent Compliance staff from concluding that all seven of these attributes MUST be included in the PSMP?
2. The standard should more clearly describe what is meant by "verify..." when used in a Maintenance Activity description. Does
2
A maintenance correctable issue is a failure of a device to operate within design parameters that can not be restored to functional order by repair or calibration
while performing the initial on-site maintenance activity, and that requires follow-up corrective action
3
A maintenance correctable issue is a failure of a device to operate within design parameters that can not be restored to functional order by repair or calibration
while performing the initial on-site maintenance activity and that requires follow-up corrective action.
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this require actual paper or electronic documentation? If so, then this should be explicitly stated in the Maintenance Activity
description. We maintain above that the recurring and routine maintenance activities having a 3 month interval should be revised
to use alternate words such as "Check" or "Observe". For example, "Check the continuity of the breaker trip circuit...", or
"Observe the voltage of the station battery". This activity should not be required to have paper or electronic documentation or
evidence. It should be sufficient to have these activities included in the PSMP.
3. It is stated in the Supplementary Reference that actual event data from fault records may be used to satisfy certain
Maintenance Activities, yet the standard itself does not appear to allow for this. Will such evidence be accepted by Compliance
staff?
Response: The SDT thanks you for your comments.
1. Yes, a PSMP should include one or more of the listed activities for any specific component. The definition is intended to identify the possible attributes
of a PSMP. Only those attributes relevant to a specific program and component need be included in the PSMP for that component. The proposed definition
includes the following phrase, making it clear that the PSMP does not have to include all listed items, “A maintenance program for a specific component includes
one or more of the following activities:”
2. The SDT thanks you for your comments and has modified the standard in consideration of your comments.
3. It is difficult to predict what will be accepted by Compliance staff; the SDT believes that you will need to establish a method to capture the evidentiary
data from fault records (such as what is empirically verified, when, and how) within your maintenance records. See FAQ IV-1-B (page 21), FAQ II-3-B (page
9) and Section 11 (page 18) of the Supplemental Reference Document.
Bonneville Power Administration
1. Tables 1a, 1b, and 1c were cumbersome to use because we found ourselves flipping back and forth to compare the
requirements for the different levels of monitoring. Also, in some cases, the types of components were slightly different between
the tables, which created confusion. We believe that it would be much easier to decipher a single table that listed each type of
component only once and showed the requirements and maintenance intervals for the different levels of monitoring on a single
page. Even if it took an entire page for each component, it would be very useful to see all of the options for that component
without having to flip back and forth between tables.
2. Please clarify the requirements for trip coils. Table 1a has as a component type "breaker trip coil only", with a maximum
maintenance interval of 3 months, while Table 1b has as a component type "trip coils and auxiliary relays". Table 1b say that
there are no monitoring attributes for this component and to use the level 1 intervals, but then gives a maximum maintenance
interval of 6 years, which doesn't agree with the 3 month interval given in Table 1a.
3. The terminology used to describe the secondary currents and voltages provided to the relay is confusing. Under the modified
definition of a protection system, it includes the term "voltage and current sensing inputs to protective relays", and in the tables it
uses the term "current and voltage circuit inputs". These terms, especially the use of the word input, give the impression that the
actual input circuitry of the protective relay is what is being described, but we believe that these terms are really meant to describe
the secondary currents and voltages from the instrument transformers (or other devices). BPA suggests revising the terminology
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to describe the secondary currents and voltages. For example, in the maintenance activities section of the tables, you could say,
"Verify that the secondary current and voltages provided to the relay are correct".
4. There is no mention to what the thresholds are when performing these maintenance activities or what corrective actions must
take place and by when they need to be carried out. Is this something we should expect to see soon?
5. The need to measure the cell/unit internal ohmic value every 18 months can be argued. BPA’s Substation Maintenance crew
performs these measurements once every 24 months and with the Operators monthly inspections, we have been able to
effectively catch any problems before a severe event/failure.
6. Communications: It is not clear specifically what equipment is included in "communications". The test interval of 12 years in
table 1b is too long to verify continued proper operation of transfer trip tone equipment. Monitoring the presence of the channel
does not provide any indication of whether the equipment can initiate a trip. Consequently, a required minimum interval of 12
calendar years is too long and does not do anything to verify proper communications support of the relay scheme. A shorter
interval of 6 years, such as that in table 1a makes more sense from a functionality standpoint.
Response: The SDT thanks you for your comments.
1. The SDT has experimented with various arrangements of the Tables with some input from external parties, and feels that the presentation shown in the
standard is the best way to present this complex information. To the degree possible, the SDT has attempted to make the arrangement of the three tables
as similar as possible to address your concern.
2. The cited sections of Table 1a, Table 1b, and Table 1c have been extensively revised.
3. The SDT modified the standard to address your comments by revising the description of these components within the tables and by modifying the
Protection System definition.
4. Note 1 to Table 1a, Table 1b, and Table 1c specify, “adjustment is required to bring measurement accuracy within parameters established by the asset
owner based on the specific application of the component.” Clause R4.3 has been added to the standard to require that the entity “initiate any necessary
activities to correct unresolved maintenance correctible issue.” Because corrective actions will vary widely in type and scope, it is difficult to specify when
it must take place; simple corrective actions may occur rapidly, but highly involved actions may take an extended period to complete.
5. Thank you for your comments concerning the evaluation of cell/unit internal ohmic values to the station base line at the Maximum Maintenance Interval
in Table 1. Because trending is an important element of ohmic measurement evaluation, the SDT believes that extending the Maximum Maintenance
Interval listed in Table 1 for evaluating internal ohmic values would not provide the necessary information for proper evaluation of the ability of the station
battery to perform as designed.
6. The SDT has defined the minimum activities and the maximum intervals necessary to implement an effective PSMP. Some entities may feel that they
need to maintain Protective System components more frequently.
Exelon Generation Company,
June 3, 2010
1. Battery testing should be added to Table 1c for Station dc supply (that uses a battery and charger)
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LLC
Question 10 Comment
2. Table 1c Condition based maintenance. Consider adding Battery Capacity Test on a 6-year interval regardless of other
condition based maintenance performed.
3. Evaluating the measured cell/unit internal ohmic values to station battery baseline does not provide an evaluation of battery
capacity please explain rational for maintenance activity.
4. If the Table 1a maintenance interval is reached and the entity is unable to perform the maintenance task, is it acceptable to
install temporary external monitoring or other measures to defer the maintenance to Table 1b or Table 1c interval? Is it
acceptable in Table 1b to substitute additional or augmented maintenance activities or operator rounds to extend intervals?
5. Table 1c for equipment with "continuous monitoring" states the maximum maintenance interval of "continuous" this does not
seem correct wording consider revising to state "not required."
6. The NERC standard should be revised to include a specific allowance for a deferral or variances of a maintenance activity
based on a formal technical evaluation. Nuclear generating units allow for deferrals and/or variances on certain equipment based
on emergent conditions that would prevent safe isolation and/or testing of function. It should be noted that any deferrals and/or
variances if justified are to be based on a formal evaluation and not based on work management or resource issues.
7. The maintenance intervals and maintenance activities should be referenced directly to a basis document to ensure guidelines
have a specific technical basis (e.g., IEEE-450).
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comments concerning Table 1c. Within Draft 2 of the standard, testing of the battery is not
required if all performance attributes of the battery are monitored.
2. The SDT has modified the standard in consideration of your comments concerning Table 1c and the need for testing to verify that the battery can
perform as designed.
3. The SDT believes that this Maintenance Activity is a viable alternative that a Vented Lead-Acid or Valve-Regulated Lead Acid battery owner can perform
at the Maximum Maintenance Interval of Table 1 in place of conducting a capacity test. See FAQ II-5-F (page 14) and FAQ II-5-G (page 14).
4. R2 of the standard establishes that the entity “ensure the components to which the condition-based criteria are applied (as specified in Tables 1b or 1c),
possess the necessary monitoring attributes.” It appears irrelevant as to when the monitoring system is installed within the Table 1a monitoring interval,
as long as the monitoring satisfies the attributes established in Table 1b or Table 1c as appropriate. If operator rounds, etc, are performed to the intervals
established within the Table 1b general requirements, address the monitoring attributes specified within the Table, and are appropriately documented, they
meet the requirements. However, it seems to the SDT that any temporary monitoring, etc, will have to be in place BEFORE you are overdue on maintenance
and therefore out of compliance.
5. The Maintenance Activities describe that maintenance is actually being performed continuously via the monitoring system. Stating “continuous” for the
interval provides a valuable link to FERC Order 693, which directs NERC to establish maximum maintenance intervals.
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6. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be numerous
opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with shorter
intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance can be done
on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals
would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace
period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a discussion on this issue.
7. IEEE Standards are voluntary unless they are adopted by an “authority having jurisdiction’, thus the IEEE Standards could be adopted here in their
entirety. However, they would require consistent and continual review by NERC to assure that they are, and continue to be, relevant. The SDT elected
instead to use them as a source of material, and to include the relevant required tests within the NERC Standard.
FirstEnergy
1. BES reclosing schemes were recently questioned in a PRC-005-1 interpretation but there is no mention of reclosing schemes in
the draft standard. This interpretation should be integrated into the requirements of PRC-005-2.
2. Lack of Exception Process - The standard as written does not reflect the fact that any one group, such as a TO performing
maintenance on a BES, does not have full control over when an outage can be taken to perform maintenance activities.
Especially regarding functional testing, where the equipment needs to be exercised resulting in some BES components being deenergized, it can be very difficult in certain parts of the T&D system to obtain the necessary outage to complete these tasks. Even
with proper planning, changes in system conditions and unforeseen equipment problems in other areas can impact the ability to
schedule an equipment outage appropriately. Accordingly, a TO can be penalized for not completing prescribed maintenance
within prescribed limits due to factors outside of their control. This type of scenario has already been experienced where
maintenance activities are scheduled upwards of a year in advance, and then inclement weather or system conditions outside of a
TO’s service territory (e.g. unanticipated generating unit shutdown) prevent the work from taking place.
3. The standard should provide some specific guidance to allow relief for such situations, or that properly incents or even requires
independent system operators (ISOs) and other outside groups to also ensure maintenance is completed within prescribed
intervals. If a TO properly considers factors such as weather (not scheduling critical outage during middle of summer), resource
commitment, schedule (the requested outage window is at least one year before maximum interval is met), time of day
(performing work during afterhours period when load is down) etc. then if outages are still denied, that the TO is not penalized for
being out of compliance as maximum intervals are exceeded. This suggested "exception process" should provide requirements
for all parties involved, both those performing the maintenance as well as those controlling and overseeing the system. There
should be required documentation to prove that the parties on both sides made proper efforts to complete the required
maintenance, as well as discuss conflict resolution.
4. With regard to the phrase "including identification of the resolution of all maintenance correctible issues" in Req. R4, we feel
that this requirement should be a subset of R4 since it is part of the implementation of the PSMP. We suggest removing the
phrase from the main requirement of R4 and creating a new 4.3 as follows:"4.3. For all maintenance programs, identify resolutions
for all encountered maintenance correctible issues and take corrective action within a time period suitable for maintaining reliability
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of the affected protection system."
5. With regard to the proposed modification of "Protection System", we suggest adding the word "devices" after "voltage and
current sensing". This would also match what appears to be the SDT’s intended wording as shown in the Supplementary
Reference Document sec. 2.2. Also, we suggest modifications to the proposed definition to add clarity to the types of
communications system protection and the voltage and current sensing devices. The following is our suggestion for wording of the
definition:"Protective relays, communication systems used in communications aided (or pilot) protection, voltage and current
sensing devices and their secondary circuits to protective relays, station DC supply, and DC control circuitry from the station DC
supply through the trip coil(s) of the circuit breakers or other interrupting devices."
6. Protection System Communication Equipment and Channels - Some power line carrier equipment has automatic testing and
remote alarming and some that does not. For other relay communication schemes (e.g., tone transfer trip ckts), if the circuit
travels over our private communications network (fiber or microwave radio), the communication equipment is remotely
monitored/alarmed. In other cases it is not remote monitored. We ask for clarification as follows: As part of our maintenance
program, we check that signal level, reflected power, and data error rate are all within tolerance at the interface between the end
equipment and the communication link. Our question is: Does this meet the intent of the proposed requirements in PRC-005-2 for
maintenance activities for Protection System Communication Equipment and Channels? Or do the requirements ask for
something beyond this?
7. We suggest combining 4.2.2, 4.2.3 and 4.2.4 to read as a new 4.2.2 "Protection System components which are installed as an
underfrequency load shedding, under voltage load shedding or Special Protection System for BES reliability."
Response: The SDT thanks you for your comments.
1. The SDT is required to include/adopt material from approved interpretations within the standard. In the case of reclosing relays, the referenced
interpretation stated that reclosing relays are NOT included, and the draft standard excludes them.
2. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. The SDT is concerned that a “grace period”, if permitted, would be used
to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC
establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 of the
Supplementary Reference Document (page 9) for a discussion on this issue.
3. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. The SDT is concerned that a “grace period”, if permitted, would be used
to establish a de-facto longer interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC
establish maximum maintenance intervals, and allowing for a “grace period” would not conform to this directive. Please refer to Section 8 (page 9) of the
Supplementary Reference Document for a discussion on this issue
4. The SDT has modified the standard in consideration of your comment. Requirement R4, Part 4.3 was added and now reads: Assure either that the
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components are within acceptable parameters at the conclusion of the maintenance activities or initiate any necessary activities to correct unresolved maintenance
4
correctable issues .
5. The SDT believes that your suggestions regarding the Protection System definition may address predominant current technology relatively accurately,
but may be constraining with regards to emerging technologies.
6. If there is remote monitoring of the Channel, then Level 2 requirements indicate a 12 calendar year interval for the tests you describe. If the system is
unmonitored a manual check back or a check of the automated check back is required at a 3 month interval. Unmonitored systems would also have the
signal level, reflected power and data error rate check done on a 6 year interval.
7. The SDT elected to list these components within separate subrequirements in order to maintain linkage to the legacy PRC-008, PRC-011, and PRC-017
standards. Your suggestion may be better adopted in a future revision of this standard (following approval of PRC-005-2).
Dynegy
1. The proposed definition of Protection System needs further clarification. Suggest changing wording around DC supply to read
as follows: "...and DC control circuitry associated with protective devices from the station DC supply".
2. Suggest revising Section 4.2 to separate time based program as its own item under R4.3.
3. Change title on Table 1a to clarify level 1 monitoring as time based.
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comment. The following phrase was added to the definition: and associated circuitry from the
voltage and current sensing devices
2. R4.1 currently addresses implementation of maintenance programs per Table 1a, Table 1b, and Table 1c as different “flavors” of a time-based program,
depending on the degree of monitoring present for the various components. The SDT feels that this is the correct approach. R4.2 specifically addresses
performance-based maintenance, and does not seem relevant to the text of your comment.
3. The SDT has modified the standard in consideration of your comment and added “Time-based” to the title of Table 1a.
MRO NERC Standards Review
Subcommittee
A. In the applicability section 4.2.5.5, change the statement to say, “Protection systems for BES connected station-service
transformers for generators that are part of the BES.”
B. In the applicability section 4.2.5, change the statement to replace “are part of” with “directly connected to”. The “are part of”
will be left to interpretation. Please indicate the added reliability benefit by collecting this in Table 1a Page 9 protection system
4
A maintenance correctable issue is a failure of a device to operate within design parameters that can not be restored to functional order by repair or calibration
while performing the initial on-site maintenance activity and that requires follow-up corrective action.
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communication equipment and channels.
C. If a breaker failure relay is also being used for sync-check, is it required to verify the voltage inputs since they are used for a
closing function and not a tripping function? It is understood that the current inputs would have to be verified since these are used
for breaker failure tripping.
D. Please clarify requirement R1-1.1, does one have to individually list out each Protection System and its associated
maintenance activities or can the PSMP be a generalized procedure that covers each of the components in all of a utility's
Protection Systems?
E. All references to breakers should be eliminated; thus, eliminate breaker trip coils. Breakers are primarily mechanical in nature
and should be excluded similar to mechanical relay systems such as sudden pressure relays.
F. Clarify that trip coils checks or tests can be verified through alternate means other than physically tripping the coil or potentially
requiring system outages to physically trip a coil. Alternate tests could consist of checking self monitoring relays, continuity lights,
etc. Trip coil tests could require transmission line outages which can be denied by regulatory authorities due to system conditions
beyond an entity’s control. Significant delays of months or longer could occur to obtain a transmission line outage. Further,
potentially requiring transmission line outages for trip coil test could harm BES reliability by increase the number of force
transmission line outages due to testing. System reliability could be significantly negatively impacted anytime testing on trip
circuits is performed due to human errors causing outages or regional disturbances.
G. One item R1.3 (inclusion of batteries) was questioned as why this was specifically called out. It should be part of the definition.
H. Define the term “condition-based”.
I. The format of the tables is poor with 17 line items addressed in each. It is difficult to relate one table to another because they are
not consistent with regard to the type of components. For example table 1a references of components a “breaker trip coil (only)”
and the 1b references “trip coils and auxiliary relays”.
J. R1.1 please add “as they apply to the applicable entity”. As stated now, all three tables must be accomplished.
K. Please add the words “time based maintenance methods” to table 1a for clarity in the heading.
L. Table 1b under general description, last sentence the word “elements” should be replaced with “maintenance activities” which
will provide exactly what is intended.
M. Table 1b, if maintenance activities for level 2 monitoring include level 1 maintenance activities, then redundant activities in
table 2 that are contained in table 1 should be removed (the same for table 3 to table 2 to table 1).
N. If an entity maintenances a protective relay such that it is included in level 2 monitoring (a Condition Based Maintenance
program) and this relay is considered to have a maximum interval of 12 years, does the entity need to also perform the
maintenance activities for level 1 monitoring since the table 1b header indicates, “General Description: Protection System
components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
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alarmed failures. Monitoring includes all elements of level 1 monitoring with additional monitoring attributes as listed below for the
individual type of component”?
Response: The SDT thanks you for your comments.
A. The station-service transformer impacts proper operation of the BES generator, whether the station service transformer is connected to the BES (for
example, at 138 kV) or not (for example, connected at 46 kV). (See FAQ III-2-A, page 20)
B. This suggestion may actually bring a small, non-BES, generator facility that is connected to the BES into scope. For example, if a Region specifies that
any generator greater than 20 MVA connected at 100 kV or above is BES, your suggestion would bring a 10 MVA generator (similarly connected) into scope.
Clause 4.2.5 currently limits applicability to BES generators.
C. No. The maintenance activities for this component have been modified to clarify.
D. The entity may use whatever method it wishes, but the documentation of the program and the implementation of the program needs to be adequate to
satisfy the Compliance Enforcement Authority that the program meets the requirements of the standard. Please be advised that all requirements of the
standard must be met, including that the relevant activities in the Tables are performed.
E. The SDT believes that the breaker trip coils are a vital electrically-operated component of the DC control circuit, and they therefore must be included.
For testing the breaker trip coil, the breaker must be observed to trip; however, such additional testing such as travel recorder, breaker timing, etc need not
be performed to satisfy PRC-005.
F. The SDT considers that the electro-mechanical devices (trip coils, aux relay coils, etc) need to be periodically exercised to assure that they operate
properly. Much of the rest of the control circuit can be verified by monitoring, including continuity of the coils, but this doesn’t assure operating integrity
of these devices. An entity is necessarily obligated to manage its maintenance program to complete the necessary activities on time, and various other
NERC standards address the management of risk related to planned outages.
G. In the Protection System Maintenance – Frequently Asked Questions (FAQ) document (FAQ IV-3-G, page 26.) and Supplementary Reference Document
Section 15.4 (page 23), the Drafting Team explains why batteries are excluded from PBM and the standard should include all batteries associated with a
Protection System in a time-based program.
H. The SDT declines to introduce a defined term for this. Table 1b and Table 1c identify condition-based maintenance to include consideration of the
known condition of the component within condition-based maintenance. The Supplemental Reference Document (Section 6, page 8) and the FAQ (V-3,
page 38 and V-4, page 39) also describe condition-based maintenance considerations.
I. The SDT has modified to Tables to make them more consistent with each other.
J. The SDT has modified the standard in consideration of your comment. The original Pwas replaced with a new Part 1.1 and a new Part 1.3 was added as
shown below,
1.1. Identify all Protection System components.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
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per Requirement 1, Part 1.2.
K. The SDT has modified the standard in consideration of your comment - and added “Time-based” to the title of Table 1a.
L. The SDT has modified the standard in consideration of your comment. The revised language does not use the word, “elements” – it reads: Level 2
monitoring includes all monitoring attributes as listed below for the individual type of component.
M. The SDT disagrees. Repeating the activities in Table 1b or Table 1c allows the entity to not refer back to the previous table.
N. If an entity decides to implement Table 1b for qualified components, the activities in Table 1b supersede the comparable activities in Table 1a.
Requirement R1 has been modified to clarify.
CenterPoint Energy
a. CenterPoint Energy believes the existing maintenance standards are preferable to the approach embodied in this proposal.
However, if most entities agree with the SDT’s approach, CenterPoint Energy recommends deleting Under-Frequency Load
Shedding (UFLS) and Under-Voltage Load Shedding (UVLS) system equipment from the scope of this proposal because the
performance requirements for UVLS and UFLS are substantially different from transmission and generation protection schemes.
Few would argue that protection schemes that clear faults on the Bulk Electric System must be very reliable, much more reliable
than schemes that shed distribution load for under-voltage or under-frequency situations. If an entity plans to shed a
contemplated level of load for a contemplated set of circumstances based upon planning simulations, that plan would translate
into a certain number of distribution feeders that are reasonably predicted to shed a load amount that is reasonably close, but not
exactly equal (unless by chance) to the contemplated amount of load shed. For example, if a certain number of distribution
circuits equals 10% of the entity’s load during one time (such as system peak), that same amount of distribution circuits will almost
certainly equal a different percentage of the entity’s load at other times. So, if hypothetically 100 distribution circuits are armed
with UVLS or UFLS relays set a given trip point, the actual percentage of load that will be shed will vary under different system
conditions. Therefore, if 95 of the distribution circuits actually trip on one occasion and 98 trip on another occasion, the difference
in system performance is immaterial because the exercise is not that precise, especially when planning simulation uncertainties
are also introduced into the picture. For these reasons, CenterPoint Energy believes it is unreasonable to impose a high level of
rigidity into load shedding schemes when the designs of the schemes inherently do not depend on such rigidity. If the SDT
agrees, then the revised standard would not be applicable to Distribution Providers, and 4.1.3 can be deleted.
b. CenterPoint Energy also disagrees with the proposed expansion of the Protection System definition. The present definition
does not include trip coils; and correctly so, as trip coils are part of the circuit breaker. A protection system has correctly
performed its function if it provides tripping voltage up to the breaker’s trip coils. From that point, the breaker can fail to timely
interrupt fault current due to several factors such as a binding mechanism that affects breaker clearing time, a broken pull rod, a
bad insulating medium, or bad trip coils. Local breaker failure protection is installed to address the various possible causes of
circuit breaker failure. Planning standard TPL-001 tables 1C and 1D specifically support the present definition, as Delayed
Clearing is noted as due to “stuck breaker or protection system failure”.
Response: The SDT thanks you for your comments.
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a. The four legacy standards are combined here in response to several suggestions, including from FERC (in Order 693) because of substantial equipment
similarities. For the reasons that you note, the activities specified for UFLS and UVLS protection are somewhat less comprehensive than those for fault
protection.
b. The SDT contends that the trip coil itself is an integral and essential component of the station control circuitry, and it must be assured that the trip coil
operates. The SDT has also been diligent in excluding any facets of the breaker mechanism from consideration, thereby excluding consideration of many
of the failure types listed. Many breaker failure schemes are designed with the presumption that the trip coil is properly initiated, and are more focused on
mechanism failures.
NextEra Energy Resources
a. The level of effort that will be required to be in compliance in accordance to PRC-005-2 is substantial. Also, it will be difficult to
create one maintenance program for all NextEra Energy sites that establishes maintenance intervals based the implementation of
a combination of the three allowable types of maintenance programs (time-based, condition based, and/or performance based
maintenance). As a result, a high risk exists that something will be missed or carried out incorrectly.
b. What is the implementation period? How will the standard be implemented in relation to the entity’s maintenance scheduled in
accordance with existing intervals specified in the current Protection System Maintenance and Testing Procedure that meets the
requirements of PRC-005-1 but will exceed PRC-005-2’s established maximum intervals? Once PRC-005-2 becomes mandatory,
entities should not be required to re-do testing in accordance with the new intervals. Instead, entities should be allowed to
implement the newly established intervals after the last known cycle.
c. Protection System Maintenance Program (PSMP):
(c1) The PSMP definition would be better defined if the first sentence was changed to “An ongoing program by which Protection
System components are kept in working order and where malfunctioning components are restored to working order.”
(c2) Please clarify what is meant by “relevant” under the definition of Upkeep. Should “relevant” be changed to “necessary”?
(c3) The definition of Restoration would also be more explicit if changed to:The actions to return malfunctioning components back
to working order by calibration, repair or replacement.
(c4) Please clarify the definition of Restoration. For example, if a direct transfer trip system has dual channels for extra security
even though only one channel is required to protect the reliability of the BES and one channel fails, must both be restored to be
compliant?
d. Protection System (modification):
(d1) Voltage and current sensing inputs to protective relays” should be changed to “voltage and current sensors for protective
relays.” Voltage and current sensors are components that produce voltage and current inputs to protective relays.
(d2) “Auxiliary relays” should be changed to “auxiliary tripping relays” throughout PRC-005-2, FAQ and the Draft Supplementary
Reference.
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(d3) The word “proper” should be removed from the standard. It is ambiguous and should be replaced with a word or words that
are clear and concise.
e. Additionally, NextEra Energy concurs with the following comments made by other entities:
(e1) PRC-005 Sect B (R2): More clarity needs to be provided. Does this requirement require the utility to document the
capabilities of its various protection components to determine fully and partially monitored protection systems? If so the
requirement for such documentation should be clearly spelled out. Usually each requirement has a measurement (of compliance)
and I'm not clear how this will be done.
(e2) PRC-005 Sect B (R4.1): A “grace period” similar to the NPCC Criteria should be considered in case it is not possible to
obtain necessary outages.
Response: The SDT thanks you for your comments.
a. We agree that the effort may be substantial. However, the effort and compliance risk can be minimized by simply implementing Table 1a, together with R1
and R4.
b. A proposed Implementation Plan was posted with this draft of the standard, and will continue to be posted with future drafts (including ballot drafts when
the standard reaches that stage). Please review the posted Implementation Plan.
c1. The SDT does not believe that the suggested change is substantive, and sees no reason to make it.
c2. Some updates may not affect the operation of the device as applied, and therefore are not relevant. “Necessary” would imply an additional level of
review to determine whether the device would operate properly without the updates, while “relevant” simply implies that the update applies to the function.
c3. The SDT does not believe that the suggested change is substantive, and sees no reason to make it.
c4. The standard establishes that all components need to be fully maintained, and that they will function as designed. The SDT appreciates that some
“restoration” activities may take an extended time to complete, but also contends that restoration to the designed condition is a vital element of
maintenance.
d1. The SDT has modified the standard in consideration of your comments.
d2. “Auxiliary tripping relays” may exclude essential other internal Protection System functions. Therefore, the SDT declines to adopt this suggestion.
d3. “Proper”, “working condition”, “correct”, etc, are all somewhat subjective terms that address the application-specific requirements related to the
specific use. For example, one entity’s design standards may require that an electromechanical relay be within a 2% tolerance of the ideal operating
characteristics, while another may only require that it be within 5%. Each of these is proper, correct, etc, for the application.
e1. The requirement establishes that an entity be able to prove that the specified monitoring attributes are met. There may be many methods of
documenting this – see Section 15.6 of the Supplemental Reference Document (page 24) which was posted with this standard. Measures, etc, will be
included with the next posted draft of the standard.
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e2. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals would
thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace period”
would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document for a discussion on this issue.
City Utilities of Springfield, MO
As proposed, this standard is very long and complex. Additionally, in requirement R1, bullet 1.1 ought to state “For each
component used in each Protection System, include all “applicable” maintenance activities specified in Tables 1a, 1b and 1c”. For
instance, if every component has continuous monitoring, why should the program include 1a and 1b?
Response: The SDT thanks you for your comments. The SDT has modified the standard in consideration of your comments. The original Part 1.1 was
replaced with a new Part 1.1 and a new Part 1.3 was added as shown below,
1.1.
Identify all Protection System components.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
per Requirement 1, Part 1.2.
Austin Energy
Austin Energy is meticulous in adhering to the current maintenance standard and is convinced that its current maintenance and
documentation program is adequate to maintain its reliable electric power system.
1. Austin Energy appreciates the good intentions of the SDT but believes that the approach taken increases complexities to the
maintenance process, introduces unwarranted workload in excessive documentation, is inflexible towards system configuration
and experience, and is over prescriptive in nature. The approach also fails to distinguish the harmful effects of over-maintenance,
increasing reliability risk due to human error and ultimately affecting the overall performance and reliability of the system.
2. Another concerning issue is the addition of the breaker trip coil to the protection system definition. Our position is that the trip
coil should be part of the breaker. The protection system would be considered operating correctly if it provided the output signal
for the trip coil when expected. Hence the trip coil should be excluded from the new protection system definition.
3. Performance based maintenance as specified in the attachment is extremely difficult and cumbersome to navigate. The intricate
requirements are difficult to comprehend and will entrap entities making a good faith effort to comply. We believe this approach
may become burdened with undesirable consequences.
4. Last but not least, Austin Energy believes that under-frequency load shedding (UFLS) and under-voltage load shedding (UVLS)
systems should not be included in the scope of this new proposal. UFLS and UVLS are a wholly different entity as compared to
the Bulk Electric System (BES). Rigidity imposed onto distribution system equipment, operating schemes and performance is
uncalled for and overreaching.
Response: The SDT thanks you for your comments.
1. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
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observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to implement an
effective PSMP. To minimize system impact of such maintenance and possible errors, the maintenance necessarily should be scheduled at a time that
minimizes the risks.
2. The SDT contends that the trip coil itself is an integral and essential component of the station control circuitry and it must be assured that the trip coil
operates. The SDT has also been diligent in excluding any facets of the breaker mechanism from consideration.
3. If an entity considers that a PBM would be difficult to implement, they may choose to implement simple time-based maintenance (Table 1a) and/or
condition-based maintenance (Tables 1b and Table 1c). This option is provided for those who elect to take advantage of the opportunities presented.
4. The four legacy standards are combined here in response to several suggestions, including from FERC Order 693 because of substantial equipment
similarities. The SDT disagrees that the requirements for UFLS and UVLS are “uncalled for and overreaching”, and has specified less stringent
requirements for these devices.
Progress Energy
Comments:
1- Requirement R4 “Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, including
identification of the resolution of all maintenance correctible issues as follows: “ Based on the definition provided (A maintenance
correctable issue is a failure of a device to operate within design parameters that can be restored to functional order by calibration,
repair or replacement.) Pr ogress Energy believes that this will become a potential tracking issue. To maintain all of the data
required to meet this definition can be onerous.
2- The biggest concern with the proposed PRC is that for many entities, the proposed maintenance and intervals will greatly
increase the entities workloads. There are not enough relay technicians available to handle this increased workload across the
country.
3- The Implementation Plan for R2, R3, and R4 identified in the Draft Implementation Plan for PRC-005-02, dated July 21, 2009, is
very reasonable. This plan recognizes that it is unrealistic to expect entities that are presently using intervals that exceed the
maximum allowable intervals to immediately be in compliance with the new intervals. It allows implementation to be implemented
across the maximum allowable interval. This is a reasonable approach for the following reasons:
a. Sufficient resources are not available to perform the additional maintenance proposed on an accelerated basis.
b. It allows the staggering of the PMs so that resource loading can be balanced. Without the ability to stagger the PMs, there
would be an initial “bow-wave” of PMs and future “bow-waves” each time the interval is up.
4- The Implementation Plan for R1 identified in the Draft Implementation Plan for PRC-005-02, dated July 21, 2009, is not
reasonable. The implementation plan requires entities to be 100% compliant three months following approval of the PRC. This is
not a reasonable timeframe given the program changes required, including:
a. A massive effort to review circuit schematics to determine whether equipment meets the definition of partial-monitored or
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unmonitored.
b. Many procedures, basis documents, and job plans will need to be revised or created.
c. The work management tool will have to be modified to reflect the new intervals.
5- PRC-008-1 placed only the relays associated with UFLS in the compliance program. Contrary to PRC-008-1, the draft PRC005-02 places all components (relays, instrument transformers, dc supply, breaker trip paths) in the compliance program. This
forces much of the distribution-level components to be placed in the compliance program.
6- The response to Item 2A of the FAQ Document, page 17, seems to indicate that commissioning test results do not have to be
captured as the initial test record, only the in-service date. Is this a correct interpretation of the response?
7- Table 1a (Unmonitored Protection Systems) seems to indicate that a complete functional trip test must be performed for the
UFLS/UVLS protection system control circuitry. This wording is identical with the wording for the protection system control
circuitry (except UFLS/UVLS) table entry. This implies that UFLS/UVLS functional testing should include tripping of the feeder
breakers for these unmonitored systems. Table 1b (Partially-Monitored Protection Systems) indicates that actual tripping of circuit
breakers is not required under the UFLS/UVLS control circuit functional testing. Is this because trip coil continuity is being
monitored and alarmed under Level 2 Monitoring? Must feeder breakers be tripped during the functional testing if the trip coil
continuity is not monitored and alarmed (unmonitored protection system)?
8- All standards to be retired should be specifically listed in the Implementation Plan.
Response: The SDT thanks you for your comments.
1. Requirement R4.3 has been added to the standard to address some of these concerns. It reads as follows:
R4.
Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, including identification of the resolution of
all maintenance correctable issues as follows:
4.3.
Assure either that the components are within acceptable parameters at the conclusion of the maintenance activities or initiate any
necessary activities to correct unresolved maintenance correctable issues.
2. The SDT understands that workloads may increase. However, with increasing sensitivity to degraded system performance, the increased attention to
Protection System maintenance is critical to BES reliability. NERC’s analysis of major system events reveals that Protection System maintenance is a
contributing factor to many major system problems.
3. The SDT appreciates that you recognize these issues which were central in developing the Implementation Plan.
4. Table 1a provides activities and intervals for components for which Level 2 or Level 3 maintenance cannot be fully justified. Additionally, considerable
time can transpire between successful balloting and regulatory approvals and major elements of the standard will be largely established even well before
balloting. Entities are encouraged to proactively begin making the necessary program adjustments.
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5. PRC-008 currently addresses “UFLS equipment” which is a bit vague. Arguably, the identified components within PRC-005-2 may be regarded as various
portions of “UFLS equipment”. The SDT contends that the indicated activities are necessary, and notes that some of the activities are less stringent than
for other Protection System components.
6. FAQ IV-2-A, page 22) now indicates that commissioning records are one option to establish the start date of maintenance intervals, and to establish the
baseline.
7. The Tables have modified to clarify that actual tripping of the breakers is not required for Protection System control circuitry for UFLS/UVLS only.
8. The SDT agrees. The Implementation Plan will be modified to indicate retirement of the four legacy standards upon the completion of the
Implementation Plan.
Nebraska Public Power District
Definition of Terms:
1. Footnote 2 for R4 defines a "maintenance correctable issue". This should be added to the Definition of Terms section.
2. Sections 4.2.5.4 and 4.2.5.5 inappropriately extend Generator Protection Systems to Station Service Transformers. These are
components necessary for plant operation however they are not part of the generator protection scheme. This conclusion is
supported by the explanations on page 16 of the FAQ.
3. The FAQ states the operation of the listed station auxiliary transforms protective relays would result in the trip of the generating
unit and, as such, would be included in the program. The FAQ goes on to state that relays which trip breakers serving station
auxiliary loads such as pumps, fans, or fuel handling equipment, etc., need not be included in the program even if the loss of
those loads could result in a trip of the generating unit. The FAQ appears to be inconsistent. Station auxiliary transformers are
included because they would result in the trip of the generating unit while other loads such as pumps, fans, etc., are excluded
even if their trip could result in a trip of the generating unit. In my opinion, the station service transformers like pumps, fans, etc.
are components necessary for plant operation but not necessary for generator protection and should therefore be excluded from
PRC-005-2 by removing Sections 4.2.5.4 and 4.2.5.5 from the standard and modifying the FAQ accordingly.
4. R1 (1.1) First sentence: "For each component used in each Protection System..." is ambiguous. The sentence should be
revised to say..."For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, and 1c."
This limits the components to only those identified by the definition of a Protection System.
5. R2 End of sentence: "possess the necessary monitoring attributes." is ambiguous. The sentence should be revised to
say..."possess the monitoring attributes identified in Tables 1b or 1c." This specifically defines which attributes are necessary.
6. R4 I am concerned with including the phrase "including identification of the resolution of all maintenance correctible issues".
Providing evidence of implementation of the PSMP will require the collection and submittal of all work documents that restored a
device to functional order by calibration, repair, or replacement. It is reasonable to assume that appropriate corrective actions
were taken for each specific situation. Identification of the resolution will add a significant documentation burden without adding to
the reliability of the BES. Implementation of the PSMP may be evidenced without including identification of the resolution of all
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maintenance correctible issues. It is interesting to note that nowhere in PRC-005-2 does it state that you have to take corrective
actions to return a component to normal operating conditions. "No action taken" can be the resolution taken by the utility of a
maintenance correctible issue.
Response: The SDT thanks you for your comments.
1. Establishing this term within the “Definition of Terms” would add this to the NERC Glossary. Instead, the SDT believes that this term is relevant only to
this Standard, and that establishing it in the Glossary of Terms rather than simply as a term within this standard would expose entities to potential
compliance exposure by having to refer to the Glossary to implement the standard.
2. Station service transformers are system components and the Protection Systems on those system components must be maintained as indicated in this
standard. (See FAQ III-2-A, page 20)
3. Many of the components (pumps, fans, etc) are redundant, and a plant may be able to withstand loss of one of these. However, the loss of the station
service transformer will result in simultaneous loss of many such elements, and will result in immediate plant shutdown. Also, the station service
transformers may be necessary to achieve an orderly plant shutdown, and the loss of a station service transformer may result in a more abrupt plant
shutdown. Improper Protection System performance due to maintenance issues must not be the cause of such an event. (See FAQ III-2-A, page 20)
4. The SDT has modified the standard in consideration of your comment. The original Part 1.1 was replaced with a new Part 1.1 and a new Part 1.3 was
added as shown below,
1.1. Identify all Protection System components.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
per Requirement 1, Part 1.2.
4. The SDT has modified the standard in consideration of your comment. The requirement was modified to read as follows:
R2.
Each Transmission Owner, Generator Owner, and Distribution Provider that uses condition-based maintenance intervals in its PSMP for
partially or fully monitored Protection Systems shall ensure the components to which the condition-based criteria are applied, possess the
monitoring attributes identified in Tables 1b or 1c.
6. A fundamental tenet of compliance is that “if it’s not documented, it’s not done.” Therefore, the documentation you describe will likely be necessary to
demonstrate compliance. The PSMP definition, the new R4.3, and the General Requirements of each Table all establish that maintenance-correctable
issues need to be resolved. If there is a maintenance-correctable issue, “no action taken” does not seem to be an acceptable response.
Florida Municipal Power Agency,
and its Member Cities
1. Facilities applicability 4.2.2, due to the changes in applicability of the draft PRC-006, ought to refer say something like UFLS
which are installed per requirements of PRC-006 rather than per ERO requirements.
2. In requirement R1, bullet 1.1 ought to state “For each component used in each Protection System, include all “applicable”
maintenance activities specified in Tables 1a, 1b and 1c”. For instance, if every component has continuous monitoring, why
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should the program include 1a and 1b?
Response: The SDT thanks you for your comments.
1. The existing PRC-006 establishes that entities install UFLS in accordance with Regional requirements (which, by extension, are ERO requirements). In
accordance with FERC Order 693, PRC-006 is currently undergoing revision to be a continent-wide standard, in which case it will itself be an ERO
requirement. Clause 4.2.2 applies equally to either situation.
2. Requirement R1has been modified in consideration of your comment. The original Part 1.1 was replaced with a new Part 1.1 and a new Part 1.3 was
added as shown below,
1.1. Identify all Protection System components.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
per Requirement 1, Part 1.2.
American Transmission
Company
1. General Comment: The requirements section of the standard seems acceptable.
2. NOTE: Why does R1.3 identify the inclusion of batteries? We believe that this should be part of the definition.
3. We believe that the team needs to define the term “condition-based”.
4. Does the Protection System definition in PRC-005-2 or interpretation of the standard and the tables line up with other NERC
Standards?
5. The table formats (1a through 1b) are confusing and should be reconsidered. We found is difficult to relate one table to
another. (No consistency in the Type of components)
Response: The SDT thanks you for your comments.
1. The SDT thanks you for your support.
2. R1.3 specifies that batteries can be tested ONLY via TBM. That is the intent of the requirement. In the Protection System Maintenance – Frequently
Asked Questions (FAQ) document (FAQ IV-3-G, page 26.) which accompanied the standard and in the Supplementary Reference Document, Section 15.4
(page 23), the SDT explains why batteries are excluded from PBM and the standard should include all batteries associated with a Protection System in a
time-based program.
3. The SDT declines to introduce a defined term for this. Table 1b and Table 1c identify condition-based maintenance to include consideration of the known
condition of the component within condition-based maintenance. The Supplemental Reference Document, Section 6 (page 8) and the FAQ (V-3, page 38
and V-4, page 39) also describe condition-based maintenance considerations.
4. The SDT was required to investigate all uses of this defined term with NERC standards and assure that these changes are consistent with the other
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applications.
5. The SDT has modified to Tables to make them more consistent with each other.
CPS Energy
Have several comments and questions:
1. I think that the way that the tables are done is confusing. My biggest complaint is that the "breakdown" of the Type of
Component varies between the tables. For example, in tables 1a and 1B, you have Protective Relays, but in table 1c, you have
Protective Relays and Protective Relays with trip contacts. This is a little confusing at times.
2. I also find the UFLS/UVLS requirements confusing as well. It can be confusing to figure out when the UFLS/UVLS has a
separate requirement. Would prefer to see the UVLS/UFLS in separate tables; e.g. 2a, 2b, 2c.
3. SPCTF should provide the basis for how the intervals in table 1 were derived. While the supplemental describes that a survey
of its members with a weighted average was used to determine the maintenance intervals. However, what is not clear is what
exactly was surveyed in terms of components. Was it just relay calibration testing? Functional testing? What about
communications, voltage and current sensing devices, trip coils, etc? Was UVLS and UFLS looked at separately from
transmission? Was generation also considered as well? Why did values change from the SPCTF technical reference "Relay
Maintenance Technical Reference" dated September 13, 2007? For example, UVLS/UFLS testing and calibration went from 10
years to 6 years for un-monitored, communications went from 6 months to 3 months for un-monitored, and instrument transformer
testing went from 7 years to 12 years for un-monitored systems. What is the basis for the intervals?
4. The committee should reconsider the use of the term "A/D converters". The point of the requirement is to assure that the
analog signal from the instrument transformer is correct to the processor. Two problems with just saying "A/D converters". One, it
ignores the digital relay input transformers of microprocessor relays. The SEL-4000 test set can bypass these transformers.
Would using this test set be adequate to test the "A/D converters"? Two, some relays, such as the SEL-311L, perform an A/D
self-test. I do not think that the A/D self-test performs the testing that is being sought by the document.
5. Could a better example of "Calendar Year" be provided? Is it simply the years difference, or should the days be included as
well? In your example in the reference document, you show that December 15, 2008 and December 31, 2014 as meeting the
requirement of 6 calendar years. Would like to see a more exaggerated example. Would an unmonitored protective relay is
calibrated on January 1, 2008 and then again on December 31, 2014 meet the "Maximum Maintenance Interval" of "6 Calendar
Years"?
6. Does the standard address breakers and other switching devices that do not have "trip coils". Magnetic actuated circuit
breakers, reclosers, and possibly other devices do not have trip coils to monitor or test. Do the trip coil testing and requirements
fully take this account? If a breaker does not have a trip coil, is some other type of test required? Does not having a trip coil
prevent extending the Protection System Control Circuitry interval to 12 years?
7. The requirement for testing Voltage and Current Sensing devices should be better thought out as to what is trying to be
accomplished. On page 11 of the reference document, item 6 under "Additional Notes for Table” it states that "phase value and
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phase relationships are both equally important to prove". In both the FAQ document (page 6, 3A) and the reference document
(page 21, 15.2), several methods to verify the voltage and current sensing inputs to the protective relays and satisfy the
requirement are given. However, these methods do not all seem to verify the same thing. Totalizing watts and vars on the bus
verifies that the current transformers are correctly and providing correct signals to the relays, but do not necessarily verify that the
voltage sensing device is necessarily correct if the same PT is used for all relays on the bus. Performing a saturation test on a CT
and a ratio test on the PT does not verify the phase angle relationships, which is stated as important on page 11 of the reference
document. What exactly needs to be accomplished by the Voltage and Current Sensing devices testing? That an analog signal is
getting from the instrument transformer to the device? That the signal is an accurate representation of the measured quantity?
What about frequency for UFLS relays, where voltage magnitude may not be that important? Do CT's need to be verified for
multiple CT grounds? Do the any examples described necessarily find multiple ct grounds?
8. This standard should also address the ramifications of RRO's not allowing for equipment to be removed from service for
testing. Either RRO's should be required to allow outages in some time frame or leeway should be given to entities that cannot
get equipment out for maintenance because RRO's will not grant reasonable outage times for testing and maintenance.
9. Page 13 of the reference document states that the 3-month inspection should include checking that "equipment is free of
alarms, check any metered signal levels, and that power is still applied." What is meant by "metered signal levels"? What does
the term "metered" mean, specifically in terms of an on-off power line carrier scheme?
10. It appears that if a company on a TBM plan has shorter intervals than the maximum allowable of this proposed standard, the
company would not be in violation if they did not meet their own plan but still met the intervals required by this proposed standard.
Is this true? Could this actually reduce reliability of the BES if companies are now allowed to extend intervals to those listed in this
document without any justification?
Response: The SDT thanks you for your comments.
1. The SDT has modified to Tables to make them more consistent with each other.
2. Many of the components of UFLS and UVLS are very similar to other generic Protection System components, with similar maintenance activities. The
SDT has modified the Tables to clarify activities which apply specifically to UFLS and/or UVLS.
3. The SPCTF, in an earlier technical paper, provided descriptions of the derivation of the intervals, but this technical paper was not charged with
developing a measurable standard. The SDT has used this information, as well as consideration of system and generation plant operating constraints,
EPRI reports, IEEE surveys, and experience of SDT members and others, to develop the intervals in the tables. These intervals were also adjusted to
address the SPCTF’s recommendations about grace periods without providing grace periods. The SDT also considered intervals that supported
establishment of systemic maintenance programs.
4. The SDT modified the standard in consideration of your comment. A/D converters are now discussed only in the Monitoring Attributes within Table 1c;
otherwise, the relay must be confirmed to operate properly. However, the SDT did NOT define methodology.
5. Disregard the complete date and just look at the year portion. For a 6 calendar-year interval, if the test date was IN 2004, the next test date must be IN or
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before 2010.
6. Where relevant to the requirements of the standard, any of these devices apply similarly. Many of the alternate technologies mentioned do not seem
relevant to BES Protection Systems, but instead to UFLS and/or UVLS systems. The required maintenance activities for these components do not require
actual test tripping.
7. No single method of verification may be relevant for every imaginable situation. The activities relevant to Voltage and Current Sensing Devices have
been revised in consideration of your comment.
8. Some entities may need to perform certain maintenance activities more frequently to assure that the activities are performed within the required
intervals. Allowing a “grace period” would create a standard that is not measurable. Please refer to Section 8 of the Supplementary Reference Document
(page 9) for a discussion on this issue. Outages must be planned in accordance the Reliability Coordinators (RRO’s, or RE’s, have no role in this) to
support reliable system operation.
9. “Metered signal levels” refer to the communication signal levels which are part of proper communications system function for certain equipment, such
as power-line carrier systems. The SDT is continuing to align the three documents (Standard, Supplemental Reference, and FAQ) to assure consistency.
10. You will be held to compliance with your plan, whatever it is, under R4, but your plan must also adhere to the intervals established by NERC. As long
as you still have elements subject to PRC-005-1, you need to comply with the program established for PRC-005-1. When you have fully implemented PRC005-2, the requirements of PRC-005-1 no longer apply. However, the SDT hopes that entities that feel that a shorter interval is appropriate will continue to
use that interval.
JEA
1. Implementation Plan - Strongly encourage keeping the implementation plan and allow for an extension of the implementation
plan for the time required to fund, design, procure, install and commission redundant protection systems for current non-redundant
lockout systems at the lower kV levels of the BES.
2. Our present and past performance of LOR and auxiliary relays will support a PBM/CBM program that allows for a much longer
time than the six years proposed for EM LOR trip testing. To use a TBM for LORs of six years, may in fact, lower the reliability of
the BES due to the complete outages required, along with the detailed procedures that must be created and rigorously followed to
perform these tests without subsequent load loss on the BES.
Response: The SDT thanks you for your comments.
1. If an entity expects to encounter difficulty in performing the maintenance specified in the standard, the SDT encourages them to begin implementation of
the necessary features to support maintenance while the standard is still in a development or approval stage.
2. The SDT encourages you to begin assembling the documentation necessary to support a PBM for these components such that you may implement that
PBM when the standard becomes effective.
Consumers Energy Company
June 3, 2010
1. In Table 1a for Station dc supply it requires verification that no dc supply grounds are present. DC grounds are common
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occurrences and the activity should be to document if dc grounds are present.
2. Please specify how cell to cell connection resistance is measured.
3. For station dc supply (battery is not used) change “Verify the continuity of all circuit connections that can be affected by wear
and corrosion” to “Inspect all circuit connections that can be affected by wear and corrosion.”
4. Is “metered and monitored” equivalent to “alarming”?
5. If a component failure causes the unit to trip, what is the purpose of testing it? It will always test positive until the point of failure
and that point is identified when the unit trips.
6. In the Facilities Section 4.2.5.4 “station service transformer” should be changed to “unit connected auxiliary transformer” to be
consistent with Figure 2 of the Supplement Reference Document.
7. Facilities Section 4.2.5.5 should also include “System connected auxiliary transformers are excluded when only used for unit
start-up.”
8. There should be an allow variance period (grace period) for the testing intervals.
9. The maximum allowable time periods should be in calendar years, defined as “occurring anytime during the calendar year.”
10. The following statement should be added to Requirement 1.2: “Identification at a program level is permissible if all components
use the same maintenance method.”
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard in consideration of your comments concerning dc grounds – the maintenance activity was revised to read, ‘Check for
unintentional grounds.”
2. The IEEE Standards 1188 and 450 have very detailed descriptions of how to measure cell to cell connection resistance using a Micro-Ohm Meter.
3. Upon consideration of your comment, the SDT determined that it is important to both “check the continuity” and to verify the physical condition.
Therefore, the standard has been modified to include both.
4. Not necessarily. “Metered and monitored” are more detailed than “alarming”. Alarms simply report an abnormal condition, while “metered and
monitored” will probably actually report values.
5. In this case, testing of the component should assure that the component functions properly and thus does NOT result in an unintended trip of its system
component, and that it WILL trip when called upon to do so.
6. The SDT contends that “station service transformer” is a more universal description for this component. The Supplemental Reference Document has
been modified for consistency.
7. The SDT contends that “startup transformer” Protection Systems also need to be maintained per PRC-005-2. During startup, these components are
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critical for reliability. On the other hand, maintenance of the Protection Systems on these system elements should be somewhat easier to schedule.
8. The SDT considered this issue when developing the intervals, and realizes that some entities may need to perform certain maintenance activities more
frequently to assure that the activities are performed within the required intervals. Specifically, for generation facilities, there would seem to be numerous
opportunities within the 6-year or longer intervals to perform the required maintenance during a scheduled plant outage, and maintenance with shorter
intervals can be characterized as non-intrusive maintenance, more of an inspection than anything else; the SDT believes that this maintenance can be done
on-line. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals
would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace
period” would not conform to this directive. Please refer to Section 8 of the Supplementary Reference Document (page 9) for a discussion on this issue.
9. All multi-year periods ARE in calendar years. There are other essential shorter intervals, and the SDT does not agree that these can be extended to a
minimum of one calendar year – most of these activities are “inspection” type activities. The SDT does not believe that it is necessary to define this term;
“Calendar year” seems to be a very precise term in itself.
10. To the degree that you can concisely describe your program this way, and demonstrate implementation of your program, it does not seem to the SDT
that this modification to the requirement is necessary.
ITC Holdings
1. In the Definitions of Terms, the Protection System (modification) should include control circuits up to and including the trip coil
of ground switches used in protection schemes.
2. Footnote 2 (Maintenance correctable issue) should be included in the Definition of Terms in the body of the standard.
Response: The SDT thanks you for your comments.
1. To the degree that the ground switch (or, more properly, the Protection System that operates the ground switch) is protecting a BES element, the SDT
classifies the ground switch as an interrupting device.
2. Establishing this term within the “Definition of Terms” would add this to the NERC Glossary. Instead, the SDT believes that this term is relevant only to
this standard, and that establishing it in the Glossary of Terms rather than simply as a term within this standard would expose entities to potential
compliance exposure by having to refer to the Glossary to implement the standard.
Entergy Services, Inc
1. It would be beneficial to also include an explanation or definition of the term “calendar year” in the standard. It is not readily
apparent in the draft standard, especially in light of the new maximum interval requirements, that a task can be performed anytime
between 1/1 and 12/31.
2. Although addressed in the FAQ and Supplement, the terms “Upkeep” and “Restoration” are referenced in the definitions section
of the standard but are not used anywhere else in the document, or with regard to routine activities. They should be eliminated
from the standard unless there are upkeep or restoration requirements.
Response: The SDT thanks you for your comments.
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1. Disregard the complete date and just look at the year portion. For a 6-calendar-year interval, if the test date was IN 2004, the next test date must be IN
2010.
2. While “upkeep” is not used in the standard, the SDT has identified the term as a component of maintenance. “Restoration” is used in R4.3 and within
the header of each Table.
AEP
1. Monitoring and tracking the activities prescribed in the standard seem too complex to manage at a level needed for auditable
compliance. The activities prescribed seem to lean toward conventional protection systems and do not take into account newer
special technology devices (High Voltage DC, Static Var Compensator and Phase Shifting transformer controls) and how there
are to included.
2. R1 1.2 Does the draft standard require a basis for an entities” defined time based maintenance intervals or can an entity just
move directly to the intervals prescribed and use the standard as its basis”
3. R4. This requirement seems to refer to failed equipment and its reporting. This corrective maintenance activity is outside of the
interpreted preventative maintenance theme of the standard and adds another layer of complexity in compliance data retention. It
also implies that a failed piece of equipment or segment could remain failed for the entire maintenance interval.
4a.Tables 1a & 1b. Station dc supply (that has as a component any type of battery) Interval: 18 months - This requirement
incorporates specific gravity testing (where applicable). Although (where applicable) is not defined, it seems it refers to all nonsealed batteries.
4b. For sealed batteries, a more frequent internal ohmic test is prescribed. The same 18 month requirement incorporates ohmic
testing which is essentially equivalent to specific gravity. Specific gravity and measure of internal temperature are invasive tests
which subject personnel to handling acid and subject the battery to damage. If the logic for sealed batteries is to do more frequent
ohmic testing why not allow more frequent ohmic testing as a substitute for specific gravity? We would suggest ohmic testing
every 6 months with any questionable results rechecked using specific gravity. This eliminates excessive intervention into all cells
and gives a validity check on the ohmic testing.
4c.For Ni-Cad the performance service test has no option (6 year intervals). Typically, the Ni-Cad can yield a low voltage
indication; however testing the cells in pairs allows testing and finding bad cells. Why not offer a more frequent ohmic test for the
Ni-Cads?
5. Facilities 4.2.1 and R1. “applied on, or are designed to provide protection for the BES.” This may be in conflict with Regional
Entity (RE) BES definitions. There needs to a clear understanding of what is included and what is not without regional differences.
There should be no responsibilities or requirements of the RE. BES also takes on different meanings depending upon which of
the many standards it is applied. Data Retention 1.4 Data retention for two intervals could mean that records would need to be
kept for 24 years. This seems impractical. Could audit evidence be used in lieu of actual data for long intervals?
6. Tables: Where the interval is in months, the term “calendar” months should be used for clarification.
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7. Table 1a:“verify the continuity of the breaker trip coil”. The SDT assumed that Trip Coil Monitoring (TCM) could be
accomplished by verifying/inspecting red lights. This may be true in most cases, but there are designs that do not incorporate this
type of TCM and the breaker would have to be exercised every 3 months if not operated by natural events unless the scheme gets
replaced. This seems counterproductive to the reliability of the BES. The implementation plan does not take the time required for
upgraded systems into consideration.
8. Table 1a DC Supply, 3 month interval “Verify no dc supply grounds are present.” Does this mean that you are non-compliant if
you have a DC ground? This also needs to be clarified as to the amount of acceptable ground that could be present. Table 1a PS
communications equipment channels 3 month interval: Do the activities imply that only alarms be verified and that no channel
“playback” be performed?
9. If SPR relay or similar auxiliary relay is excluded as a protective relay, then do we not have to verify its tripping contact as part
of the DC system?
10. Table 1a The exclusion of UVLS/UFLS from certain activities is confusing. Does trip coil monitoring not have to be performed
on these systems?
Tables:
11. Since PT and CT devices themselves are not included in the PS definition, then the word “devices” should be removed from
the type of component column describing inputs to the relay.
12. Table 1a. Even though an entity may be on time-based intervals, would a natural occurring fault event reset the maintenance
clock for the protection segment involved?
13. Assessment of Impact of Proposed Modification to the Definition of Protection System: Reclosing and certain auxiliary relays
have been excluded from protection system definition. This new definition would have an impact on other PRC standards that use
this term in its requirements, specifically the Misoperations investigation and reporting standards. These other standards, as
written today, are not clearly written as to the application and assumptions as to what is included in a protection system.
14. Trip coil Monitoring: If the trip coil is actually part of the DC circuitry, then why is there a differing (shorter) interval for this
series connected element?
Response: The SDT thanks you for your comments.
1. The SDT invites additional participation to address such devices.
2. There is no additional basis required for an entity to adopt the maximum allowable intervals established within the standard.
3. The SDT has modified the standard to require that an entity also initiate correction of maintenance-correctable issues. There is no time-period specified
for actually correcting maintenance-correctable issues in recognition of the wide variety of activities that may be represented.
4a. The SDT has modified the standard in consideration of your comments concerning specific gravity not being applicable to non-sealed batteries. The
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maintenance activities no longer include any reference to specific gravity.
4b. The SDT has modified the standard in consideration of your comments concerning specific gravity and internal temperature. The maintenance activity
associated with specific gravity and internal temperature was removed from the revised standard.
4c. Presently there are no other options that are available today to verify that a Ni-Cad battery can perform as designed.
5. NERC standards establish minimum requirements, which can be expanded on by Regional Entities. This standard does NOT place any requirements
upon the Regional Entity. BES is a defined NERC and Regional Entity term which applies uniformly to the various standards. The Records Retention
section has been modified to read as follows:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation of the two most recent performances of each
distinct maintenance activity for the Protection System components, or to the previous on-site audit date, whichever is longer.
6. The SDT has modified the standard in consideration of your comment and the word, “Calendar” was added to clarify that the term “months” means
“calendar months”
7. The SDT has removed the cited requirement.
8. The SDT has modified the standard in consideration of your comments concerning dc grounds (changed to “Check for unintentional grounds” and
compliance FAQ II-5-I, (page 15) explains that the entity is responsible to determine if corrective actions are needed upon detection of unintentional dc
grounds.
9. Yes.
10. The Tables have been modified to better delineate the specific activities related to components associated with UFLS/UVLS relays.
11. The definition has been further modified to add these devices.
12. Only to the degree that the Protection System operation for the natural fault verified the functions and “performed” the activities within the Table. See
FAQ II-4-C, page 10 and Supplementary Reference Document, Section 15.3, page 22.
13. The SDT, in accordance with the NERC Standard Development Procedure, analyzed all other uses of the defined term, “Protection System” within the
NERC standards, and, in a document which was posted with the standard and other associated documents during the comment period, listed all other uses
and concluded that there is no impact on the other uses. Reclosing relays are still not listed in the definition, but auxiliary relays, which previously were
not listed and now are, were implicit in the previous “dc control circuits”.
14. The Tables have been modified to remove this shorter-interval specific activity.
Green Country Energy LLC
None
Georgia System Operations
Corporation
None.
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Operations and Maintenance
None.
ENOSERV
On Table 1A, the maximum time lengths are too long, especially for electro relays. A prime example is when testing a KD relay on
a yearly basis and most of the time needs to be adjusted because of how far off it comes out. Allowing entities to take their time up
to six calendar years may be too long.
Response: The SDT thanks you for your comments. See the Supplementary Reference Document, Section 5.1, page 7.
Xcel Energy
Please clarify if the following are subject to PRC-005-2 requirements:
1) a battery that is in a station where the only BES element is a UFLS scheme
2) batteries used only to support communication elements (microwave houses)
Response: The SDT thanks you for your comments.
1) The SDT has modified the standard to clarify that the only DC Supply maintenance activity relevant to UFLS is to verify the DC supply voltage.
2) The proper functioning of such batteries (communication system) will be addressed by the verification and monitoring of the communications system,
and by addressing maintenance correctable issues related to the communications system. See FAQ II-5-K, page 15.
BGE
1. PRC-005-2R1 1.2
Identify whether each Protection System component is addressed through time-based, conditionbased, performance-based, or a combination of these maintenance methods and identify the associated maintenance interval.
Comment:
The existing standard PRC-005-1 requirement R1.1 says a maintenance program must include the maintenance
and testing intervals and their basis. PRC-005-2 does not have a similar requirement, and the associated FAQ indicates the
standard “establishes the time-basis for a Protection System Maintenance Program to a level of detail not previously required”.
Does PRC-005-2 require evidence to support the basis for a defined maintenance interval, or is the basis now purely defined by
PRC-005-2?
2. R2
Each transmission owner .......shall ensure the components to which condition-based criteria are applied....possess the
necessary monitoring attributes? Comment: Depending on the evidence requirements that are enforced this could be a very large
undertaking offsetting the benefit of extending intervals with CBM. It would be helpful to understand what the drafting team or
other stakeholders would envision as appropriate evidence supporting this requirement.
3. R4 Each transmission owner .......shall implement its PSMP, including the identification of the resolution of all maintenance
correctable issues as follows :4.1 ....within the maximum allowable intervals not to exceed those established in table 1a, 1b, 1c
Comment: It’s inferred that this requirement applies to maintenance correctable issues that are discovered as a consequence of
scheduled maintenance and not as a consequence of monitoring or misoperations. If that inference is incorrect the requirement
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imposes an unequal playing field for the resolution of known correctable issues depending on the monitoring being employed, not
to mention an unreasonably long allowance for the correction of some serious problems. On the other hand, the requirement
imposes an unreasonably short period of time for the resolution of some issues that may be associated with short interval
maintenance/inspection intervals, such as battery grounds.
4. Section D1.4 Data Retention? The Transmission Owner shall...retain documentation for two maintenance intervals....
Comment: Recognizing that in order to achieve compliance PS owners will execute scheduled maintenance on shorter intervals
than the maximum requirement it’s uncertain what this means. Example: Max interval for instrument transformers is 12 years, we
maintain every six. Is the requirement for 24 years of data or 12? It seems like there ought to be an upper limit. 24 years is a very
long time. Table 1a Protection System Control Circuitry (Breaker trip coil only); 3 month maximum interval; verify the
continuity....of the trip circuit.....except for breakers that remain open for the entire maintenance interval. Comments: What’s the
failure-probability justification for this requirement when other similar dc control components have a maximum interval of 6 years?
It seems like the SDT made an assumption that all trip coils are monitored by red lights and could be verified by inspection and
said somewhat arbitrarily, “do it because you can”. “Remaining open for the entire maintenance interval” is a poorly reasoned
effort to arrive at a necessary exception. Even if the red-light-through-the-trip-coil assumption is accurate for a normally open
breaker, it’s unreasonable to demand that an inspection take place if it’s closed at anytime during the interval. The actual time that
its closed might be seconds or a few minutes, but that time would make the exception moot and put the owner out of compliance.
On the subject of three month maximum intervals in general: One can agree that three months is about the right time for some of
these inspections, batteries in particular. However as written, three months and a day is “out of compliance”. More flexibility would
avoid a lot of meaningless “technical fouls”. How about four times a year not more than four months between each...or something
like that.
5. Table 1aStation DC supply (that has as a component any type of battery); verify that no dc supply grounds are present?
Comment: All grounds are not created equal. No guidance for acceptance criteria is given, nor is evaluation/acceptance criteria
explicitly made the responsibility of the battery owner (as it is for relay calibration). Without any guidance the requirement of “no”
grounds is open to unreasonable interpretation (there is always a ground if one considers a high enough resistance) and high
impedance grounds that do not present a risk to the PS will consume effort and attention unnecessarily.
6. Station DC supply (that has as a component any type of battery); Measure to verify that the specific gravity and temperature of
each cell is within tolerance?
Comment: It is not clear that a specific gravity test provides any better data concerning battery health than an impedance test, but
specific gravity testing is a requirement. Can the impedance test be performed as routine maintenance in lieu of a specific gravity
test?
7. General Comment: It is not clear whether Communications batteries should be held to the same testing/maintenance
requirements as the station battery. Communications batteries are in place to supply relatively low power electronic equipment
and do not have to provide energy to trip a breaker. Simple monitoring of the channel may be sufficient to assure battery
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availability, and a less rigorous maintenance plan may be appropriate based on the continuous monitoring and low duty of the
battery.
8. FAQ Group by Monitoring Level A level 2 (partially) monitored Protection System or an individual component of a level 2
monitored Protection System has monitoring and Alarm circuits on the Protection System components. The alarm circuits must
alert a 24-hour staffed operations center.
Comment: The standard Table 1b, General Description for Level 2 monitoring is simply described as Protection System
components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for
alarmed features. This appears to be a conflict between the FAQ and the standard. The more stringent requirement of the FAQ,
for the reporting facility to be manned 24 hours per day, could be read to imply a requirement for a specific time to respond to an
alarm. Is there such a requirement? Is there an implied requirement to document the alarm condition and the response time?
Response: The SDT thanks you for your comments.
1. If a time-based or condition-based program is used according to Tables 1a, 1b, and 1c, no additional basis is needed. If the entity elects to use
Performance-based maintenance, the activities in Attachment A must be used to establish the related basis.
2. See FAQ V-1-D, page 22 for a discussion relevant to your comment.
3. The SDT has modified the standard in consideration of your concern concerning the interval of checking for unintentional dc grounds and the ability to
remove the unintentional ground from the dc system. R4 of The SDT has modified the standard to require initiation of the resolution of maintenancecorrectable issues, rather than to identify their resolution. See FAQ II-5-I, page 15.
4. The data retention section has been modified to read as follows: The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for the Protection System components, or to the previous on-site audit date,
whichever is longer.
5. Both the standard and FAQ document have been modified in consideration of your comments concerning dc grounds to specify that it is up to the owner
to determine if corrective actions are needed for unintentional dc grounds. See FAQ II-5-I, page 15.
6. The standard has been revised to remove maintenance activities related to specific gravity.
7. Communication system batteries are not included in the requirements for “Station Batteries”. The entity must ensure proper operation of the relay
communications circuit which would include adequate maintenance of the equipment including the communication system batteries The proper
functioning of such batteries (communication system) will be addressed by the verification and monitoring of the communications system, and by
addressing maintenance correctable issues related to the communications system. (See FAQ II-5-K, page 15.)
8. The FAQ has been modified to remove this apparent additional requirement.
Transmission Owner
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a. The PSMP definition would be better defined if the first sentence was changed to “An ongoing program by which Protection
System components are kept in working order and where malfunctioning components are restored to working order.”
b. Please clarify what is meant by “relevant” under the definition of Upkeep. Should “relevant” be changed to “necessary”?
c. The definition of Restoration would also be more explicit if changed to “The actions to return malfunctioning components back to
working order by calibration, repair or replacement.
d. Please clarify the definition of Restoration. For example, if a direct transfer trip system has dual channels for extra security
even though only one channel is required to protect the reliability of the BES and one channel fails, must both be restored to be
compliant?
e. Protection System (modification) “Voltage and current sensing inputs to protective relays” should be changed to “voltage and
current sensors for protective relays.” Voltage and current sensors are components that produce voltage and current inputs to
protective relays.
f. “Auxiliary relays” should be changed to “auxiliary tripping relays” throughout PRC-005-2, FAQ and the Draft Supplementary
Reference.
g. The word “proper” should be removed from the standard. It is ambiguous and should be replaced with a word or words that are
clear and concise.
Response: The SDT thanks you for your comments.
a. The SDT does not believe that the suggested change is substantive, and sees no reason to make it.
b. Some updates may not affect the operation of the device as applied, and therefore are not relevant. “Necessary” would imply an additional level of
review to determine whether the device would operate properly without the updates, while “relevant” simply implies that the update applies to the function.
c. The SDT does not believe that the suggested change is substantive, and sees no reason to make it.
d. The standard establishes that all components need to be fully maintained, and that they will function as designed. The SDT appreciates that some
“restoration” activities may take an extended time to complete, but also contends that restoration to the designed condition is a vital element of
maintenance.
e. The critical task is to verify that the proper representation of the primary current and voltage signals will get to the protective relays. The “Type of
Protection System Component” has been modified in an effort to clarify.
f. “Auxiliary tripping relays” may exclude essential other internal Protection System functions. Therefore, the SDT declines to adopt this suggestion.
g. “Proper”, “working condition”, “correct”, etc, are all somewhat subjective terms that address the application-specific requirements related to the specific
use. For example, one entity’s design standards may require that an electromechanical relay be within a 2% tolerance of the ideal operating
characteristics, while another may only require that it be within 5%. Each of these is proper, correct, etc, for the application.
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Ohio Valley Electric Corp.
Question 10 Comment
1. R1.2 seems to require owners to establish there own intervals and basis. Compliance with these requirements should be
based on the intervals that are in tables 1a, 1b and 1c.
2. R4 implies that all maintenance correctible issues must be resolved within the Maintenance Activity Intervals. A diligent effort to
restore proper function of a system should not be penalized if it does not fall within the prescribed maintenance interval.
Response: The SDT thanks you for your comments.
The SDT has modified the standard in consideration of your comment. The Parts of Requirement R1 were modified to read as follows:
1.1. Identify all Protection System components.
1.2
Identify whether each Protection System component is addressed through time-based, condition-based, performance-based, or a combination of these
maintenance methods and identify the associated maintenance interval.
1.3
For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, or 1c associated with the maintenance method used
per Requirement 1, Part 1.2.
1.4
Include all batteries associated with a Protection System in a time-based program.
2. The SDT has modified the standard to require INITIATION of resolution, not the actual resolution. The revised footnote reads as follows: A maintenance
correctable issue is a failure of a device to operate within design parameters that can not be restored to functional order by repair or calibration while performing the
initial on-site maintenance activity, and that requires follow-up corrective action.
E.ON U.S.
1. Recently, NERC made an interpretation on PRC-005-1 which stated that battery chargers were not to be included as part of the
standard. This version of the standard seems to be in direct conflict with that interpretation, and for the reasons stated above
E.ON U.S. recommends that battery chargers not be included in the standard. E.ON U.S. believes that capacity or AC impedance
only needs to be done to determine service life, and therefore a periodic testing of station DC supply does not seem necessary or
prudent.
2. Regarding the “Retention of Records”, retaining records of the latest test seems adequate. E.ON U.S. does not understand the
point of retaining records for the past two test results. This is particularly true for equipment for which there are relatively long
testing intervals, for example, 12 years. Retaining result documents from 24 years ago seems unnecessary and impractical.
3. With regard to NERC’s PRC-005-2 Supplementary Reference Section 2.4 on Applicable Relays, E.ON U.S. offers the following
comments:
3.1. This section extends the applicable relay coverage to IEEE type # 86 and IEEE type # 94. Some utilities define their turbine
trip relay as an IEEE type #94. E.ON U.S. interprets that the NERC scope of applicable relays is that the turbine trip relays would
be excluded; however, it would further clarify this exclusion if it were mentioned as an example in the last sentence.
3.2. The Tables in proposed standard PRC-005-2 require additional clarity. E.ON U.S. suggests renaming tables to 1, 2 and 3 to
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match Level 1, 2 and 3 monitoring. The wording and format of text is not consistent between tables.
3.3. The fields in the tables are incoherent. E.ON U.S. interpretation is that intervals and activities for UFLS and UVLS are
different than other relay systems and components, but this is unclear. E.ON U.S. believes a separate table or sections for UFLS
and UVLS would provide more clarity.
4. In section 7 of the Supplementary Reference the SDT refers to the Bulk Power System instead of the Bulk Electric System.
These are not interchangeable and the SDT needs to explain the need to use the term in this case. The phrase “support from
protection equipment manufacturers” is used several times in the technical reference (Section 8 and Section 13) yet there is no
manufacturer represented on the SDT. Rather than developing one size fits all requirements applicable to all equipment, E.ON
U.S. suggests that the SDT pursue comments from manufacturers to obtain recommendations on what they believe is required to
maintain and test their equipment.
Response: The SDT thanks you for your comments.
1. Although this SDT team (as an Interpretation Drafting Team) drafted the recent NERC interpretation of Protection System as it is applied to PRC-005-1,
the SDT believes that the charger is an integral portion of the Station DC supply; thus it has been added to the definition of Protection System by replacing
“station batteries” in the current definition of Protection System to “station dc supply” in the definition for the proposed standard (PRC-005-2). The SDT
disagrees with your contention that testing of the station dc supply is necessary; the station dc supply is a critical component of the Protection System,
and it must be verified that it can perform its required function.
2. A single record is not adequate to demonstrate that the equipment has been maintained according to the intervals.
3.1. The SDT revised the Supplementary Reference to remove references to IEEE function numbers except where they are critical to the discussion.
3.2. The SDT believes that it is actually a single table with multiple sections and has retained the table numbering. The SDT has worked to improve the
consistency between the table sections.
3.3. The tables have been revised to clarify this area.
4. The Supplementary Reference Document has been modified to use the NERC-defined term of “Bulk Electric System” or its defined abbreviation BES,
rather than “Bulk Power System” or BPS. As for manufacturer input, the SDT is concerned that it would be a violation of NERC Anti-Trust rules to seek
input from manufacturers.
Duke Energy
Regarding the Implementation Plan,
1. R1 compliance should be the first day of the first calendar quarter 18 months following applicable regulatory approvals. Entities
will need this time to change monitoring equipment and develop extensive new work practices and procedures to assure time
frames and documentation of practices comply with the wording of the revised standard.
2. The time frames for R2, R3 and R4 are adequate except in cases where upgrades have to be developed and implemented in
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order to be able to meet the intervals (such as breaker trip coil verification every three months).
3. FAQ 2C “If I am unable to complete the maintenance as required due to a major natural disaster, how will this effect my
compliance with the standard.” Response is the Compliance monitor will consider extenuating circumstances? We would like to
see this statement clarified as to the time frame extensions that result in non compliance or fines.
4. R4 States “each transmission owner” shall implement its PSPM, including identification of the resolution of all maintenance
correctable issues. If the intent is to document resolution to misoperations this is a reasonable request. If the intent is to document
that a relay was found out of calibration on a routine test, which was corrected by recalibration we need some clarity on
expectations of how that would be recorded and tracked. As written this statement is vague and somewhat confusing since % of
allowable error may vary utility to utility. R4 doesn’t appear to allow any time beyond the stated intervals for repairs or
replacements that may take additional time. PRC-005-2 is maintenance and testing standard, and R4 inappropriately requires a
replacement strategy and an obsolescence strategy. Is R4 intended to apply to all equipment in Table 1?
Response: The SDT thanks you for your comments.
1. The SDT believes that time provided for R1 is sufficient. Additionally, entities can use the time required for NERC Board of Trustees and regulatory
approvals to work on implementation.
2. The SDT believes that the times provided for R2, R3, and R4 are adequate.
3. The specific issues of how the Compliance Enforcement Authority would address this issue is outside the scope of the SDT. The response in the FAQ
(FAQ IV-2-D, page 23) is extracted directly from the NERC Sanction Guidelines (effective January 15, 2008)
4. The SDT has modified the standard to require initiation of the resolution of maintenance-correctable issues that cannot be resolved during the on-site
maintenance; this is focused on assuring that the Protection System is capable of performing its desired function. R4 is intended to apply to ALL
equipment in the PSMP.
Northeast Power Coordinating
Council
1. Requirements 4.2.5.4 and 4.2.5.5 require clarification. It is recommended that the drafting team provide a schematic diagram to
provide clarity as to which generator and system connected transformers are included in this facility identification.
2. When Measures are added to the Standard, the SDT must consider how the owner will be required to assess and document the
decision of which table will apply to each protection. While this is a compliance element, the standard should provide clarity on
this matter. As written, the requirement does not seem to be measurable.
3. Requirement R4 requires clarification on what is meant by “including identification of the resolution of all maintenance
correctible issues as follows:” Correctible issues should not be combined in the same sentence with the layout of the tables.
4. Table 1b: In the section for “Protection system communication equipment and channels”, there needs to be clarification on
“verify that the performance of the channel and the quality of the channel meets the performance criteria, such as via
measurement of signal level, reflected power, or data error rate.” This may be done as a pass fail test during trip checks. If the
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communication line successfully sends proper signals for the trip checks, then the communication line is acceptable and no
additional measurement are taken.
5. Table 1c: There is some confusion on what is expected on items that have a Maximum Maintenance Interval reported as
“Continuous”. For example, a component in the “Protection System telecommunication equipment and channels” how would one
provide documentation or proof of the continuous verification of the two items listed in the maintenance activities” In other words
how does one prove “Continuous verification of the communication equipment alarm system is provided” and “Continuous
verification that the performance and the quality of the channel meet the performance criteria is provided”. These activities appear
to be “monitoring attributes” more so than they are maintenance activities.
6. Additionally, the Continuous “Maximum Maintenance Interval” needs clarification
because
•
the interval is a monitoring interval and not a maintenance interval
•
a strict interpretation of “Continuous” could require redundant monitoring systems be installed or locations staffed by
personnel to monitor equipment in the event remote monitoring capabilities are unavailable
•
It is unclear how to provide proof to an auditor that continuous monitoring has occurred over a given interval?
7. Table 1a, 1b, and 1c: The maintenance activity for battery chargers are to perform testing of the charger at full rated current
and verify current-limit performance. The drafting team should provide an industry standard as how to perform this check, or
specify an industry equivalent test.
8. The Table 1b Level 2 Monitoring Attributes for Component “Monitoring and alarming of continuity of trip coil(s)” should be
changed to read “Monitoring and alarming of continuity of all DC circuits including the trip coil(s)”. The present wording is
confusing and can be interpreted to mean that the DC control circuitry needs to be checked every 12 years, as opposed to what
we perceive to be the intended 6 years.
9. The Maintenance Activities in Table 1c are not consistent with the Level 3 Monitoring Attributes for Component “Protection
system telecommunications equipment and channels.”
10. “Continuous verification of interface to protective relays” should be added as a third activity should be added under the
Maintenance Activities column.”
11. In Section A. Introduction, 4.2.4 should be made to read “Protection System components which are installed as a Special
Protection System for BES reliability.
12. For Requirement 4.1, a “grace period” similar to the NPCC criteria should be considered in case it is not possible to obtain any
necessary outages to get the prescribed maintenance done.
13. Requirement R1 should be modified to read “Each Transmission Owner, Generator Owner, and Distribution Provider shall
develop, document, and implement a Protection System Maintenance Program (PSMP) for its Protection Systems that use” This
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revision reinforces what is necessary to ensure proper compliance with the program.
14. “The standard has multiple component tests required at different and conflicting intervals, some interdependent. Preference is
to have the component listed with a common maintenance and testing interval assigned (list the testing required at 2, 4 and 6
years). This same interval should apply to all areas in the table.”
15. Life span of PC’s, software and software license’s are much less than 12 years or asset life. This presents a problem during
an audit where proof is required. The components in modern relays have not been proven over these extended time periods,
users are dependent on proper functions of the alarm output of IED’s. Prefer more frequent maintenance cycles over having to
continuously document proof of a robust CBM or PBM program.
16. The burden placed to provide proof of compliance with a CBM or PBM maintenance program seems to outweigh any benefit in
maintenance costs or reliability.
Response: The SDT thanks you for your comments.
1. Figure 2 in the Supplementary Reference Document (page 28) illustrates generator-connected and system-connected station service transformers.
Additionally, 4.2.5.4 and 4.2.5.5 (in the Applicability section) further state, “for generators that are part of the BES”, which must be taken in the context of
the Regional Entity BES definition.
2. It is beyond the scope of a standard to require specific documentation; the entity must determine what documentation is necessary to clearly
demonstrate that they are meeting the requirements. FAQ V-1-D, page 30 provides a discussion to assist in this determination.
3. The footnote for R4 has been modified to read as follows: A maintenance correctable issue is a failure of a device to operate within design parameters that can
not be restored to functional order by repair or calibration while performing the initial on-site maintenance activity, and that requires follow-up corrective action.
4. A functional test only proves that the communication equipment is working. Table 1b requires that the performance criteria, such as signal levels,
reflected power, etc are verified against the original performance criteria established when the channel was commissioned. See FAQ II-6-D, page 17.
5. For items with a maximum maintenance interval of “continuous”, no activities are required, and the specified activities acknowledge that the monitoring
of the component IS addressing the maintenance of the component.
6. The general information within the Table describes the attributes needed to achieve the Level 3 monitoring, and R2 requires that the entity establish a
basis for the components to be addressed within Table 1c. Supplementary Reference Document, Sections 13 and 14 (page 20) provide discussion on this,
and the Decision Trees in the FAQ and FAQ IV-1-A, page 21 also discuss this.
7. The SDT has modified the standard to remove this requirement in consideration of your comments.
8. The SDT has modified the standard to remove this requirement in consideration of your comments.
9. Table 1c has been modified to improve the consistency.
10. The SDT is not clear as to what you are suggesting.
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11. The SDT has modified the standard in consideration of your comment. As revised, 4.2.4 reads as follows: Protection System components installed as a
Special Protection System for BES reliability.
12. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer interval, and that the established intervals would
thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum maintenance intervals, and allowing for a “grace period”
would not conform to this directive.
13. Documentation is a matter of demonstrating compliance, not of meeting the technical requirements of the Standard. R4 specifies the implementation of
the PSMP.
14. The testing specified for many components is different for the varying intervals; therefore, a separate table entry is present for each distinct interval.
For the most part, the intervals are multiples of each other, (3-months, 18-months, 3-years, 6-years, and 12-years).
15. Entities are certainly free to perform maintenance more frequently than specified in the standards.
16. Entities do not have to adopt CBM or PBM; the entity must decide if the benefits of such programs justify the additional administrative effort.
Saskatchewan Power
Corporation
1. Saskatchewan recommends that the PC's and RC's designate what equipment is applied to protect the BES and should be
included in the protection maintenance program. It is questionable whether the facility owners or Distribution Providers will know.
2. What are the impacts on the BES from the protection systems identified in Facilities 4.2.5 and the FAQ? For example there is
an impact on the BES from generator under-frequency protection not being properly coordinated, but assuming it is and if it is not
maintained isn't the impact to the unit itself? Inadvertent energization protection also seems to be an impact to the unit itself not
the BES? The standard should be concerned with protection systems that impact the BES not equipment protection that has
localized impacts however important they may be.
3. Change Facilities 4.2.2 to “Protection System components used for under-frequency load-shedding systems which are installed
to prevent system under-frequency collapse for BES reliability.” The reference to ERO is unnecessary and inappropriate.
Response: The SDT thanks you for your comments.
1. The SDT disagrees. This standard applies to Protection Systems applied on, or that are designed to provide protection for the BES as defined by the
Regional Entities.
2. Fundamentally, if a system component is part of the BES, the protection on that component indeed affects the BES.
3. The SDT believes that this Applicability is correctly stated in the standard. This directly reflects the current PRC-008-1 standard.
Detroit Edison
1. Suggest that the term “alarmed failures” in the table headings be changed to “alarmed abnormalities” to better indicate that the
monitored parameter may be in an abnormal state or out of range but not necessarily failed.
2. Does “system-connected” station service transformers refer to transformers connected to the BES or transformers connected to
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a system at any voltage level?
3. Is the intent of R1.1.2 that each Protection System component (specific relay at specific location) be listed individually with its
associated maintenance method and interval or can the general component category be listed as such?
4. Regarding R4, further clarification would be helpful in understanding the intent of the term “resolution of all maintenance
correctible issues” as it applies to R4.1 and R4.2. Is it intended that “maintenance correctible issues” be completed within the
interval?
5. It is recommended that each line in the tables be given a number or letter designation to make reference to that row easier.
Response: The SDT thanks you for your comments.
1. The SDT understands your comment, and has elected to leave the terminology in the standard unchanged. While “failure” is not a defined term within
th
the standard, the 11 Edition of Merriam Webster’s Collegiate Dictionary includes, within the definition of failure, several relevant applications of this term,
including “an omission of occurrence or performance”, “a failing to perform a duty or expected action”, “a state of inability to perform a normal function”,
and “an abrupt cessation or normal functioning”.
2. This phrase refers to generation plant station-service transformers connected at any voltage level, provided that the generator is part of the BES.
3. This depends on the description of your program. You will need to describe your program in a way that will satisfy the requirements of the Standard.
4. The SDT has modified the standard to require initiation of the resolution of maintenance-correctible issues, with no specific time-frame on completing
the resolution.
5. The SDT thanks you for your suggestion. This has been considered several times during the development of the tables, and several different
arrangements attempted, and the SDT believes that the current presentation is the most effective way to present this complex material. The SDT will,
however, continue to consider suggestions to improve this.
SERC (PCS)
The “zero tolerance” structure proposed combined with the large volume and complexity of Protection System components forces
an entity to shorten their intervals well below maximum. We instead propose a calendar increment carryover period in which a
small percentage of carryover components would be tracked and addressed. For example, up to 1% of an entity’s communication
channel 6 year verifications could carryover into the next year. These carryover components would be addressed with high
priority in that next calendar increment. There are many barriers to 100% completion or zero tolerance. Some utilities have over
ten thousand components.
Response: The SDT thanks you for your comments. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer
interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum
maintenance intervals, and allowing for a “grace period” would not conform to this directive.
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1. The “zero tolerance” structure proposed within this standard combined with the large volume and complexity of Protection
System components requires a utilities processes and built-in grace periods to perform to perfection. Although this is a worthy
goal for our industry, this can result in a large number of non-compliances for minor documentation issues or slightly missed
maintenance schedules on an insignificant percentage of relays. The processing of these non-compliances can be costly in terms
of resources that could be better utilized to address other transmission reliability matters. To provide a better approach, we
suggest an incremental carryover system be permitted that would allow up to 0.5 percent of the PRC-005 maintenance task to be
carried over to the next period, provided they are random events (not repetitive). As an example, a small percentage of our
Protective System Control Trip tests on a 6-year interval could be carried over into the next calendar year when a generator
outage is rescheduled. With this provision, these few tests could be handled without risk of a generator trip and without a
compliance consequence. These carryover tasks could be addressed through an action plan with a defined completion date, and
could be documented through a regional web portal. There are many barriers to 100% completion at a zero tolerance level with
this volume of tasks.
Response: The SDT thanks you for your comments. The SDT is concerned that a “grace period”, if permitted, would be used to establish a de-facto longer
interval, and that the established intervals would thus not be measurable. Additionally, FERC Order 693 directed that NERC establish maximum
maintenance intervals, and allowing for a “grace period” would not conform to this directive.
Oncor Electric Delivery
1. The drafting team is to be commended for taking the Technical Paper and Draft Standard that was prepared by the NERC
System Protection and Control Taskforce (SPCTF) and the recommendations of the SAR drafting team to create PRC-005-2.
This draft standard allows the owners of Protection Systems several options in establishing a maintenance program tailored to
their equipment and the topography of their system.
Response: The SDT thanks you for your support.
US Bureau of Reclamation
The significance of this issue is not reflected in the period of time needed to review the documents. The supplement has many
good ideas; however, the concept is going further than needed for establishing consistent maintenance intervals.
Response: The SDT thanks you for your comments. The NERC Standard Development Process normally allows for only 30-day or 45-day comment
postings. The SDT intends to continue to use only the 45-day posting period of these in recognition of the extensive material to review.
RRI Energy
June 3, 2010
1. The standard was written to implement generally accepted practices, but has developed requirements that are overly
prescriptive relative to what will be required to demonstration compliance. The standard should not assume the need to write all
aspects of a maintenance program into the standard or that maintenance programs will only consist of the standard requirements.
Protection systems of the BES have and will continue to perform very reliably with the basic elements of a maintenance program
without the need to divert resources for the development of excessive documentation to demonstrate compliance. PRC-005-1 is
the most violated standard in the industry; not because of the lack of maintenance to protection systems, but because the
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documentation requirements of the standard, given the large magnitude of components that fall within the scope of the standard.
This standard significantly increases the administrative burden for additional documentation, without corresponding improvements
to the reliability of the BES.
2. Recommend rewording A.4.2.5.1 as follows: “Generator Protection system components that trip the generator circuit breakers
to separate and isolate the generator from the BES either directly in the breaker trip coil circuit or through interposing lockout or
auxiliary tripping relays.” This document should not expand the compliance scope beyond the definition of the BES. The
generator protection systems that “trip the generator” also perform additional control functions that extend beyond the electrical
isolation of the generating unit from the BES. These additional circuits do not protect the BES and do not belong in the scope of
this document.
3. Recommend rewording A.4.2.5.4 as follows: “Protection systems for generator-connected station service transformers that trip
the generator circuit breakers to separate and isolate the generator from the BES.” This document should not expand the
compliance scope beyond the definition of the BES. Related protection circuits of the transformer not involved with the electrical
isolation of the generating unit from the BES does not belong in the scope of this document.
4. Recommend rewording A.4.2.5.5 as follows: “Protection systems for BES elements connecting to the station service
transformers of generating stations.” This document should not expand the compliance scope beyond the definition of the BES.
The requirement incorporates radial feeds (with dedicated breakers) into the scope of the standard that are not necessarily a part
of the BES as defined by some RRO’s. Station service transformers are not necessarily required for generating unit operation. In
some cases there are redundant sources for startup or back-up power. Protection of these transformers does not belong in the
scope of the standard if they are not a part of the BES.
5. The suggested rewording of R1.2 is as follows: “Identify whether each Protection System component is addressed through
time-based, condition-based, performance-based, or a combination of these maintenance methods.” The requirement for the
registered entity to list the interval of maintenance does not belong in the standard, especially since the maximum intervals are
listed in the standard tables. The registered entity may have internal documents that intentionally target a shorter duration than
the maximum interval of Table 1a. The failure to meeting those internally established targets can be a violation of the standard by
the wording of this requirement. Allow R4 of the standard to identify the maximum allowable intervals.
6. In R4, the requirement for “identification of the resolution of all maintenance correctible issues” should be separated from the
maintenance intervals; which define the maximum intervals of maintenance activities. The requirement should be eliminated to
remove the overly prescriptive requirements of auditable documentation. If retained, a rewording of the requirement is as follows:
“Each Transmission Owner, Generator Owner, and Distribution Provider shall identify the resolution of all issues identified and not
corrected at the time the maintenance is initiated and the protected element is returned to service.” The documented resolution of
maintenance correctible issues (if retained) should apply only to activities that are unresolved and incomplete during the normal
maintenance process. The standard should not micromanage the documentation process by creating requirements for excessive
auditable records needed to demonstrate compliance of routine maintenance activities.
7. In R4, the requirements for Generator Owners which establish the durations of maximum allowable intervals should be
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separated from the Transmission Owners, even if the intervals are the same. The reason is to allow for the assignment of
different Violation Risk Factors. The Violation Risk Factor for the application of a 20 MVA generating unit with an operating
capacity factor of less than 5%, and connected to a 138 kV system, should not be the same as those applied to a 500kV
transmission line. The violation risks factors for these two applications are significantly different, and the ability to recognize this is
not permitted by the standard presently.
8. Similarly, the criteria used for the sizing of station batteries for a large generating station is very different than those used for
transmission facilities. Very little of the generating station battery sizing is related to BES protection, and nearly all generator
protection system operations occur without reliance upon the battery. Without NERC standard requirements, Generator Owners
have their own natural incentives to maintain batteries for the protection of the turbine generator bearings on the loss of AC power.
With the most basic requirements of an inspection and maintenance program, there is an extremely high degree of reliability given
the typical design of DC systems within a generating station, even without documented compliance to a rigid set of standards.
With very basic, elementary maintenance (documented or not), the statistical probability for the random and simultaneous failure
of multiple battery cells to disable the protection system of a generating station for the milliseconds of time required to separate a
generating unit from the BES is insignificant (well in excess of 1 billion to 1 across an entire calendar quarter).
9. Violation risk factors and the resulting penalties for non-compliance need to be realistic.
Response: The SDT thanks you for your comments.
1. The SDT believes that the level of prescription within the standard is necessary to satisfy the guidance in FERC Order 693, and also to address
observations from the Compliance Monitoring entities (the Regional Entities and NERC) that PRC-005-1 is excessively general. FERC Order 672 also
specifies that NERC Reliability Standards should be clear and unambiguous. The SDT has therefore defined the minimum activities necessary to
implement an effective PSMP.
2. The SDT believes that the standard is correct as drafted. Not only does the generator need to be disconnected, but this BES component must also be
protected. Please refer to FAQ III-2-A, page 20 for a discussion of relevant Protection System components.
3. A loss of a generator-connected station auxiliary transformer will result in a loss of the generating plant if the plant is being provided with auxiliary
power from that source.
4. A loss of a system-connected station auxiliary transformer could result in a loss of the generating plant if the plant was being provided with auxiliary
power from that source, and this auxiliary transformer may directly affect the ability to start up the plant and to connect the plant to the system.
5. Inclusion of the intervals is necessary for PBM, and entities may elect to commit to more demanding intervals because of their experience.
6. The SDT has modified the standard to require initiation of the resolution of maintenance-correctible issues, but establishes no time line for the actual
resolution, in recognition of the wide variation in the type of problems and the scale of the resolution.
7. The SDT disagrees. It the protection on the cited 20 MVA generating unit fails to properly isolate the unit from the system for fault conditions, it could
have serious effects on reliability.
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8. The SDT believes that the station dc supply is such an integral part of the Protection System of a generating station that, it falls under NERC Reliability
Standard purview and at a minimum must be maintained using the Maintenance Activities and Maximum Maintenance Intervals of Table 1.
9. The SDT will consider this with developing VRFs and VSLs.
Lower Colorado River Authority
We commend the work done by the SDTSDT. In particular, the merging of previous standards PRC-005-0, PRC-008-0, PRC-0110, and PRC-017-0 which will help with the efficient management of these standards.
Response: The SDT thanks you for your support.
Ontario Power Generation
We note that Verification of Voltage and Current Sensing Device Inputs to Protective Relays is a somewhat ambiguous activity.
NERC’s audit observation team came up with a similar finding. The supporting documents provide some clarity but in our opinion
it would be helpful if the SDT could elaborate this activity in more detail in the Table itself.
Response: The SDT thanks you for your comments. The Tables have been modified to clarify this issue.
Southern Company
1. We presently utilize a UFLS system distributed across many transmission and distribution substations. Are the station batteries
located in stations with no network transmission protection schemes (other than UFLS) subject to the requirements of PRC-0052? This was not addressed in previous revisions.
2. We presently utilize a UVLS system distributed across many transmission and distribution substations. Are the station batteries
located in stations with no network transmission protection schemes (other than UVLS) subject to the requirements of PRC-0052?
3. In the applicability section, there is no exception for smaller units and those with very low capacity factors. Rather, those that
“are part of the BES” are in the scope. We recommend that smaller units and low capacity factor units be exempt from the
requirements of this standard or have extended maintenance intervals. Refer to the current SERC supplement for PRC-005-1.
Section II.A. of the May 29, 2008: SERC Supplement Maintenance & Testing Protection Systems (Transmission, Generation,
UFLS, UVLS, & SPS) NERC Reliability Standards PRC-005-1, PRC-008, PRC-011, & PRC-017.The applicability section
paragraph 4.2.4 should read “are installed” rather than “is installed”.
4. Note 2 at the bottom of the table (1c) implies that one has to apply voltage and inject current into the microprocessor relay to
perform trip checks. Is this the intent of the statement? If so, Note 2 should be revised to make clear the intention. We don’t
think this is necessary with microprocessor relays since they monitor inputs
5. Why is the Violation Severity Level Matrix not a part of this standard revision?
6. In cases where a common dc system exists between a generator owner and transmission owner, who is the responsible entity?
7. We appreciate the work that went into the implementation plan. We agree with the concept of phasing in mandatory compliance
June 3, 2010
181
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Question 10 Comment
and the timing of the implementation.
8. Consider defining the Monitoring Levels once and reformatting the information contained within Tables 1a, 1b, and 1c to
regroup the information by component type rather than by Monitor Level. When considering the various monitoring levels for the
protection system components, each entity will consider each component type apart from the others when determining the Monitor
Level to apply, so this reorganization will assist the end user to understand and apply the levels. See samples attached as a
separate document:
Response: The SDT thanks you for your comments.
1. The SDT has modified the standard to clarify that the only DC Supply requirement relevant to UVLS and UFLS is to verify the DC supply voltage, and that
this may be performed in conjunction with the UFLS/UVLS maintenance itself.
2. The SDT has modified the standard to clarify that the only DC Supply requirement relevant to UVLS and UFLS is to verify the DC supply voltage, and that
this may be performed in conjunction with the UFLS/UVLS maintenance itself.
3. This is properly a NERC registration issue and one of the regional BES definitions. We appreciate that you may disagree with these, but you should seek
resolution via other means. The SDT has modified the standard in consideration of your editorial concern. It the protection on a small generating unit fails
to properly isolate the unit from the system for fault conditions, it could have serious effects on reliability.
4. Note 2 has been removed from the Table.
5. Even though the SDT worked on a VSL matrix during development of this draft, the SDT elected to constrain this posting only to the requirements and
supporting developments. The SDT believes that this was such an extensive body of material that it would be distracting to include compliance elements.
The SDT also recognized that extensive changes were likely to occur to the standard in response to this posting, and considered this in their decision to
not include compliance elements. They will be included in the next posting.
6. The SDT believes that the owner of the battery is responsible. This can be worked out by agreements between the entities.
7. The SDT thanks you for your support.
8. The SDT has experimented with various arrangements of the Tables with some input from external parties, and believes that the presentation shown in
the standard is the best way to present this complex information. The SDT has attempted to make the arrangement of the three tables as similar as
possible to address your concern.
PacifiCorp
What is the definition of "Calendar Year"? Does the term "Six calendar years" include any date in 2004 to any date in 2010?
Response: The SDT thanks you for your comments. Disregard the complete date and just look at the year portion. For a 6 calendar-year interval, if the test
date was IN 2004, the next test must be completed by the end of 2010.
June 3, 2010
182
Consideration of Comments on draft of PRC-005-2 — Project 2007-17
Organization
Question 10 Comment
AECI
Puget Sound Energy
Great improvement in the standards and clarity of expectations. We appreciate the combining of the multiple PRC standards.
PSE would appreciate the comments and clarification needed regarding the interpretation for PRC-005 under Project 2009-17 to
be included in PRC-005-2. It appears that the interpretation allowed regions to define variances due to the variance in the
Regional Entity definitions of the BES. But how the BES is defined and documented as such creates ongoing confusion for the
registered entities.
Response: The SDT thanks you for your comments. The NERC definition for BES specifically includes, “As specified by the regions”. As long as this
definition persists, the issue noted in your comments will also persist. It is outside the scope of this standard to address these issues.
June 3, 2010
183
Standard PRC-005-2 — Protection System Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approves SAR for posting on June 5, 2007.
2. The SAR was posted for comment from June 11, 2007–July 10, 2007.
3. The SC approves development of the standard on August 13, 2007.
4. First posting of revised standard on July 24, 2009.
5. Second posting of revised standard on June 11, 2010
Description of Current Draft:
This is the second draft of the Standard. This standard merges previous standards PRC-005-1, PRC-0080, PRC-011-0, and PRC-017-0. It also addresses FERC comments from Order 693, and addresses
observations from the NERC System Protection and Control Task Force, as presented in NERC SPCTF
Assessment of Standards: PRC-005-1 — Transmission and Generation Protection System Maintenance
and Testing, PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs, PRC011-0 — UVLS System Maintenance and Testing, PRC-017-0 — Special Protection System Maintenance
and Testing.
Future Development Plan:
Anticipated Actions
1. Post for combined pre-ballot review and comment.
Anticipated Date
June 11–July 16, 2010
2. Conduct initial ballot.
July 8–July 17, 2010
3. Drafting Team Responds to Comments.
July 19–July 22, 2010
4. Post response to comments and modified standard.
July 23, 2010
5. Conduct 10-day recirculation ballot.
July 23–August 2, 2010
6. Present to BOT for action.
August 5, 2010
May 27, 2010
1
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
•
•
•
•
•
•
Verification — A means of determining that the component is functioning correctly.
Monitoring — Observation of the routine in-service operation of the component.
Testing — Application of signals to a component to observe functional performance or
output behavior, or to diagnose problems.
Inspection — To detect visible signs of component failure, reduced performance and
degradation.
Calibration — Adjustment of the operating threshold or measurement accuracy of a
measuring element to meet the intended performance requirement.
Upkeep — Routine activities necessary to assure that the component remains in good
working order and implementation of any manufacturer’s hardware and software service
advisories which are relevant to the application of the device.
Restoration — The actions to restore proper operation of malfunctioning components.
Protection System (modification) — Protective relays, communication systems necessary for
correct operation of protective functions, voltage and current sensing inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station dc supply, and control circuitry
associated with protective functions from the station dc supply through the trip coil(s) of the circuit
breakers or other interrupting devices.
May 27, 2010
2
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems applied on, or designed to provide protection for the BES.
4.2.2
Protection System components used for underfrequency load-shedding systems
installed per ERO underfrequency load-shedding requirements.
4.2.3
Protection System components used for undervoltage load-shedding systems
installed to prevent system voltage collapse or voltage instability for BES
reliability.
4.2.4
Protection System components installed as a Special Protection System for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection System components that act to trip the generator either directly or
via generator lockout or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for generator-connected station service transformers for
generators that are part of the BES.
4.2.5.5 Protection Systems for system-connected station service transformers for
generators that are part of the BES.
5.
(Proposed) Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems that use
measurements of voltage, current, frequency and/or phase angle to determine anomalies and to
May 27, 2010
3
Standard PRC-005-2 — Protection System Maintenance
trip a portion of the BES1 and that are applied on, or are designed to provide protection for the
BES. The PSMP shall meet the following criteria: [Violation Risk Factor: High] [Time
Horizon: Long Term Planning]
1.1. Identify all Protection System components.
1.2. Identify whether each Protection System component is addressed through time-based (per
Table 1a), condition-based (per Table 1b or 1c), performance-based (per Attachment A),
or a combination of these maintenance methods and identify the associated maintenance
interval.
1.3. For each Protection System component, include all maintenance activities specified in
Tables 1a, 1b, or 1c associated with the maintenance method used per Requirement 1,
Part 1.2.
1.4. Include all batteries associated with the station dc supply component of a Protection
System in a time-based program.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses conditionbased maintenance intervals in its PSMP for partially or fully monitored Protection Systems
shall ensure the components to which the condition-based criteria are applied, possess the
monitoring attributes identified in Tables 1b or 1c. [Violation Risk Factor: Medium] [Time
Horizon: Long Term Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Long Term Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its
PSMP, including identification of the resolution of all maintenance correctable issues2 as
follows: [Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]
4.1.
For time-based or condition-based maintenance programs, perform, the maintenance
activities detailed in Table 1 (for the appropriate monitoring level(s)) for all Protection
System components according to the PSMP established per Requirement R1within
maximum allowable intervals not to exceed those established in Tables 1a, 1b, and 1c.
4.2.
For performance-based maintenance programs, perform, the maintenance activities
detailed in Table 1 (for the appropriate monitoring level(s)) for all Protection System
components in accordance within the maximum allowable intervals established per
Requirement R3.
4.3.
Ensure either that the components are within acceptable parameters at the conclusion
of the maintenance activities or initiate any necessary activities to correct unresolved
maintenance correctable issues 3.
1
Devices that sense non-electrical conditions, such as thermal or transformer sudden pressure relays are not
included within the scope of this standard.
2
A maintenance correctable issue is a failure of a device to operate within design parameters that cannot be restored
to functional order by repair or calibration while performing the initial on-site maintenance activity, and that
requires follow-up corrective action
3
A maintenance correctable issue is a failure of a device to operate within design parameters that cannot be restored
to functional order by repair or calibration while performing the initial on-site maintenance activity and that requires
follow-up corrective action.
May 27, 2010
4
Standard PRC-005-2 — Protection System Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider will have a
documented Protection System Maintenance program that addresses protective relays,
communication systems necessary for correct operation of protective functions, voltage and
current sensing inputs to protective relays and associated circuitry from the voltage and current
sensing devices, station dc supply, and control circuitry associated with protective functions
from the station dc supply through the trip coil(s) of the circuit breakers or other interrupting
devices, as required by Requirement R1. For each protection system component, the
documentation shall include the type of maintenance program applied, maintenance activities,
and maintenance intervals as specified in Requirement R1, Parts 1.1 through 1.4.
M2. Each Transmission Owner and Generator Owner that uses a condition-based maintenance
program should have evidence such as engineering drawings or manufacturer’s information
showing that the components possess the monitoring attributes identified in Tables 1b or 1c, as
required by Requirement R2.
M3. Each Transmission Owner, Generator Owner, or Distribution Provider that uses a performancebased maintenance program should have evidence such as equipment lists, maintenance
records, and analysis records and results that its performance-based maintenance program is in
accordance with Requirement R3.
M4. Each Transmission Owner, Generator Owner, or Distribution Provider shall have evidence
such as maintenance records or maintenance summaries (including dates that the components
were maintained) that it has implemented the Protection System Maintenance Program in
accordance with Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System components, or to the previous on-site audit date, whichever is
longer.
The Compliance Enforcement Authority shall keep the last periodic audit report and all
requested and submitted subsequent compliance records.
1.4. Additional Compliance Information
None.
May 27, 2010
5
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels
Requirement
Number
R1
Lower VSL
Moderate VSL
High VSL
Severe VSL
The entity’s PSMP included all of the
‘types’ of components included in the
definition of ‘Protection System’, but,
for no more than 5% of the
components, failed to either
The entity’s PSMP included all of
the ‘types’ of components included
in the definition of ‘Protection
System’, but, for greater than 5%,
but no more than 10% of the
components, failed to either
The entity’s PSMP included all of
the ‘types’ of components included
in the definition of ‘Protection
System’, but, for greater than 10%,
but no more than 15%, of the
components, failed to either
The entity’s PSMP failed to
address one or more of the types of
components included in the
definition of ‘Protection System’
OR
Entity has not established a PSMP.
OR
The entity’s’ PSMP included all of
the ‘types’ of components included
in the definition of ‘Protection
System’, but, for more than 15% of
the components, failed to either
• Identify the component,
• Specify whether the component is
being addressed by time-based,
condition-based, or performancebased maintenance, or
• Include all maintenance activities
specified in Table 1a, Table 1b, or
Table 1c, as applicable.
• Identify the component,
• Identify the component,
• Specify whether the component
is being addressed by timebased, condition-based, or
performance-based
maintenance, or
• Specify whether the component
is being addressed by timebased, condition-based, or
performance-based
maintenance, or
• Include all maintenance
activities specified in Table 1a,
Table 1b, or Table 1c, as
applicable.
• Include all maintenance
activities specified in Table 1a,
Table 1b, or Table 1c, as
applicable.
• Identify the component,
• Specify whether the component
is being addressed by timebased, condition-based, or
performance-based
maintenance, or
• Include all maintenance
activities specified in Table 1a,
Table 1b, or Table 1c, as
applicable.
R2
May 27, 2010
Entity has Protection System
components in a condition-based
PSMP, but documentation to support
Partially-Monitored Protection System
classification or Fully-Monitored
Protection System classification is
incomplete on no more than 5% of the
Protection System components
maintained according to Tables 1b and
1c.
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support Partially-Monitored
Protection System classification or
Fully-Monitored Protection System
classification is incomplete on more
than 5%, but 10% or less, of the
Protection System components
maintained according to Tables 1b
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support Partially-Monitored
Protection System classification or
Fully-Monitored Protection System
classification is incomplete on more
than 10%, but 15% or less, of the
Protection System components
maintained according to Tables 1b
6
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support Partially-Monitored
Protection System classification or
Fully-Monitored Protection System
classification is incomplete on more
than 15% of the Protection System
components maintained according
to Tables 1b and 1c.
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Moderate VSL
and 1c.
Severe VSL
and 1c.
R3
Entity has Protection System elements
in a performance-based PSMP but has:
1) Failed to reduce countable events to
less than 4% within three years.
OR
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for 5% or less of components
in any individual segment
OR
3) Maintained a segment with 54-59
components or containing different
manufacturers.
NA
R4
Entity has failed to complete scheduled
program on 5% or less of total
Protection System components.
Entity has failed to complete
scheduled program on greater than
5%, but no more than 10% of total
Protection System components.
May 27, 2010
High VSL
Entity has Protection System
elements in a performance-based
PSMP but has failed to reduce
countable events to less than 4%
within four years.
Entity has Protection System
components in a performancebased PSMP but has:
1) Failed to reduce countable
events to less than 4% within five
years.
OR
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for over 5% of components
in any individual segment.
OR
3) Maintained a segment with less
than 54 components.
OR
4) Failed to annually update the list
of components,
• Perform maintenance on the
greater of 5% of the segment
population or 3 components, or
• Annually analyze the program
activities and results for each
segment.
Entity has failed to complete
scheduled program on greater than
10%, but no more than 15% of total
Protection System components.
Entity has failed to complete
scheduled program on greater than
15% of total Protection System
components.
OR
Entity has failed to initiate
resolution of maintenancecorrectable issues
7
Standard PRC-005-2 – Protection System Maintenance
E. Regional Variances
None
F. Supplemental Reference Documents
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference — July 2009.
2. NERC Protection System Maintenance Standard PRC-005-2 FREQUENTLY ASKED
QUESTIONS — Practical Compliance and Implementation DRAFT 1.0 — June 2009
Version History
Version
Date
Action
2
TBD
Complete revision, absorbing maintenance
requirements from PRC-005-1, PRC-008-0,
PRC-011-0, PRC-017
Draft 2: May 27, 2010
Change Tracking
Complete revision
8
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection System
Component
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays) with simulated electrical inputs. (Note 1)
Verify that settings are as specified.
Protective Relays
6 Calendar Years
For microprocessor relays, check the relay inputs and outputs that are essential to proper functioning of the Protection
System.
For microprocessor relays, verify acceptable measurement of power system input values.
Voltage and Current
Sensing Inputs to Protective
Relays and associated
circuitry
12 Calendar
Years
Verify proper functioning of the current and voltage signals necessary for Protection System operation from the voltage
and current sensing devices to the protective relays.
Control and trip circuits with
electromechanical trip or
auxiliary contacts (except for
microprocessor relays,
UFLS or UVLS)
6 Calendar Years
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits,
including all electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System.
Control and trip circuits with
unmonitored solid-state trip
or auxiliary contacts (except
for UFLS or UVLS)
12 Calendar
Years
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits,
including all solid-state trip and auxiliary contacts (e.g. paths with no moving parts), devices, and connections essential
to proper functioning of the Protection System.
Control and trip circuits with
electromechanical trip or
auxiliary (UFLS/UVLS
Systems Only)
6 Calendar Years
Control and trip circuits with
unmonitored solid-state trip
or auxiliary contacts
(UFLS/UVLS Systems Only)
12 Calendar
Years
Draft 2: May 27, 2010
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits,
including all electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System,
except .that verification does not require actual tripping of circuit breakers or interrupting devices.
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuit,
including all solid-state trip and auxiliary contacts (e.g. paths with no moving parts), devices, and connections essential
to proper functioning of the Protection System, except that verification does not require actual tripping of circuit
breakers or interrupting devices.
9
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection System
Component
Maximum
Maintenance
Interval
Station dc Supply (used only
for UVLS or UFLS)
(when the
associated UVLS
or UFLS system
is maintained)
Maintenance Activities
Verify proper voltage of the dc supply.
Verify:
Station dc supply
18 Calendar
Months
•
State of charge of the individual battery cell/units
•
Float voltage of battery charger
•
Battery continuity
•
Battery terminal connection resistance
•
Battery cell-to-cell connection resistance
Inspect:
•
Cell condition of all individual battery cells where cells are visible – or measure battery cell/unit internal ohmic
values where the cells are not visible
•
Physical condition of battery rack
•
The condition of non-battery-based dc supply
Check:
Station dc supply (that has
as a component any type of
battery)
Station dc supply (that has
as a component Valve
Regulated Lead-Acid
batteries)
Draft 2: May 27, 2010
3 Calendar
Months
3 Calendar Years
- or 3 Calendar
Months
•
Electrolyte level (excluding valve-regulated lead acid batteries)
•
Station dc supply voltage
•
For unintentional grounds
Verify that the station battery can perform as designed by conducting a performance or service capacity test of the
entire battery bank. (3 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values to
station battery baseline. (3 months)
10
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection System
Component
Station dc supply
(that has as a component
Vented Lead-Acid Batteries)
Maximum
Maintenance
Interval
6 Calendar Years
- or 18 Calendar
Months
Maintenance Activities
Verify that the station battery can perform as designed by conducting a performance, service, or modified performance
capacity test of the entire battery bank. (6 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values to
station battery baseline. (18 Months)
Station dc supply (that has
as a component NickelCadmium batteries)
6 Calendar Years
Verify that the substation battery can perform as designed by conducting a performance service, or modified
performance capacity test of the entire battery bank.
Station dc supply (battery is
not used)
6 Calendar Years
Verify that the dc supply can perform as designed when the ac power from the grid is not present.
Verify proper voltage of the station dc supply.
Verify that no unintentional dc supply grounds are present.
Station dc Supply (battery is
not used)
18 Calendar
Months
Perform a visual inspection, of all components of the station dc supply to verify that the physical condition of the station
dc supply is as desired and any visual inspection if required by the manufacturer on the condition of the dc supply that
is the source of dc power when ac power is unavailable.
Verify where applicable the proper voltage level of each component of the station dc supply.
Verify the correct operation of ac powered dc power supplies.
Verify the continuity of all circuit connections that can be affected by wear or corrosion. Inspect all circuit connections
that can be affected by wear and corrosion.
Associated communications
systems
Associated communications
systems
Draft 2: May 27, 2010
3 Calendar
Months
6 Calendar Years
Verify that the Protection System communications system is functional.
Verify that the performance of the channel and the quality of the channel meets performance criteria, such as via
measurement of signal level, reflected power, or data error rate.
Verify proper functioning of communications equipment inputs and outputs that are essential to proper functioning of
the Protection System.
Verify the signals to/from the associated protective relay(s).
11
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection System
Component
UVLS and UFLS relays that
comprise a protection
scheme distributed over the
power system
Relay sensing for
Centralized UFLS or UVLS
systems UVLS and UFLS
relays that comprise a
protection scheme
distributed over the power
system
SPS
Draft 2: May 27, 2010
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays) with simulated electrical inputs. (Note 1)
6 Calendar Years
Verify proper functioning of the relay trip outputs.
For microprocessor relays verify the proper functioning of the A/D converters.
Verify that settings are as specified.
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of the UFLS or UVLS systems at
the intervals established for those individual components. The output action may be breaker tripping, or other control
action that must be verified, but may be verified in overlapping segments. A grouped output control action need be
verified only once within the specified time interval, but all of the UFLS or UVLS components whose operation leads to
that control action must each be verified.
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of the SPS at the intervals
established for those individual components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output control action need be verified only
once within the specified time interval, but all of the SPS components whose operation leads to that control action must
each be verified.
12
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the maintenancecorrectable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring includes all monitoring
attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Includes
•
Internal self diagnosis and
alarm capability
•
Alarm must assert for power
supply failures
Verify acceptable measurement of power system input values.
•
Input voltage or current
waveform sampling three or
more times per power cycle
For microprocessor relays, check the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Protective Relays
•
Verify the status of relays is normal with no alarms indicated.
12 Calendar Years
Verify that settings are as specified.
Conversion of samples to
numeric values for
measurement calculations by
microprocessor electronics
that are also performing self
diagnosis and alarming
Verify that the relay alarms will be received at the location where action can be taken.
Verify correct operation of output actions that are used for tripping.
Voltage and
Current Sensing
Inputs to
Protective Relays
and associated
circuitry
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
12 Calendar Years
Verify the proper functioning of current and voltage circuit signals necessary for
Protection System operation from the voltage and current sensing devices to the
protective relays.
Control Circuitry
(Trip Coils and
Auxiliary Relays)
Monitoring and alarming of continuity of
trip circuits(s)
6 Calendar Years
Verify that each breaker trip coil, each auxiliary relay, and each lockout relay is
electrically operated within this time interval.
Draft 2: May 27, 2010
13
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the maintenancecorrectable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring includes all monitoring
attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Control Circuitry
(Trip Circuits)
(except for
UFLS/UVLS)
Monitoring of Protection System
component inputs, outputs, and
connections with reporting of
monitoring alarms to a location where
action can be taken
Connection paths using electronic
signals or data messages are
monitored by periodic signal changes
or messages that verify ability to
convey Protection System operating
values
12 Calendar Years
Verify that the alarms will be received at the location where action can be taken.
Control and trip
circuitry
Monitoring of the continuity of breaker
trip circuits along with the presence of
tripping voltage supply all the way from
relay terminals (or from inside the
relay) through to the trip coil(s),
including any auxiliary contacts
essential to proper Protection System
operation. If a trip circuit comprises
multiple paths, each of the paths must
be monitored, including monitoring of
the operating coil circuit(s) and the
tripping circuits of auxiliary tripping
relays and lockout relays. Alarming for
loss of continuity or dc supply for trip
circuits is reported to a location where
action can be taken.
12 Calendar Years
Verify that the alarms will be received at the location where action can be taken.
Draft 2: May 27, 2010
14
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the maintenancecorrectable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring includes all monitoring
attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
6 Calendar Years
Verify that the monitoring devices are calibrated (where necessary) and alarms will be
received at the location where action can be taken.
Monitor and alarm for:
Station dc supply
•
Station dc supply voltage
•
Unintentional dc grounds
•
Electrolyte level of all cells in
a station battery
•
Individual battery cell/unit
state of charge
•
Battery continuity of station
battery
•
Cell-to-cell and battery
terminal resistance
Inspect:
Station dc supply
Station dc supply
(that has as a
component Valve
Regulated LeadAcid batteries)
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
Draft 2: May 27, 2010
18 Calendar
Months
3 Calendar Years
- or 3 Calendar Months
•
Cell condition of individual battery cells where cells are visible, or measure
battery cell/unit internal ohmic values where cells are not visible
•
Physical condition of battery rack
•
The condition of non-battery based dc supply
Verify that the station battery can perform as designed by conducting a performance or
service capacity test of the entire battery bank. (3 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (3 months)
15
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the maintenancecorrectable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring includes all monitoring
attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Verify that the substation battery can perform as designed by conducting a
performance service, or modified performance capacity test of the entire battery bank.
(6 calendar years)
Station dc supply
(that has as a
component
Vented LeadAcid batteries)
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
Station dc supply
(that has as a
component
Nickel-Cadmium
batteries)
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
6 Calendar Years
Verify that the substation battery can perform as designed by conducting a
performance service, or modified performance capacity test of the entire battery bank.
Station dc Supply
(battery is not
used)
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
6 Calendar Years
Verify that the dc supply can perform as designed when ac power from the grid is not
present.
12 Calendar Years
Verify that the performance of the channel and the quality of the channel meets
performance criteria, such as via measurement of signal level, reflected power, or data
error rate.
Verify proper functioning of communications equipment inputs and outputs that are
essential to proper functioning of the Protection System.
Verify the signals to/from the associated protective relay(s).
Verify proper functioning of alarm notification.
Associated
communications
system
Monitoring and alarming of protection
communications system by
mechanisms that check for presence of
the communications channel.
Draft 2: May 27, 2010
6 Calendar Years
- or 18 Calendar
Months
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (18 Months)
16
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the maintenancecorrectable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring includes all monitoring
attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
UVLS and UFLS
relays that
comprise a
protection
scheme
distributed over
the power
system
Includes internal self diagnosis and
alarm capability, which must assert for
power supply failures. Includes input
voltage or current waveform sampling
three or more times per power cycle,
and conversion of samples to numeric
values for measurement calculations
by microprocessor electronics that are
also performing self diagnosis and
alarming.
12 Calendar Years
Verify the status of relays as in service with no alarms.
Verify acceptable measurement of power system input values the proper function of
the A/D converters (if included in relay).
Verify proper functioning of the relay trip outputs.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can be taken.
Relay sensing for
centralized UFLS
or UVLS systems
See the attributes of Level 2 Monitoring
for the individual components of the
SPS
See Maintenance
Intervals for the
individual
components of the
UFLS/UVLS
Perform all of the Maintenance activities listed above as established for components of
the UFLS or UVLS systems at the intervals established for those individual
components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified time interval, but all of the
UFLS or UVLS components whose operation leads to that control action must each be
verified.
SPS
See the attributes of Level 2
Monitoring for the individual
components of the SPS
See Maintenance
Intervals for the
individual
components of the
SPS
Perform all of the Maintenance activities listed above as established for components of
the SPS, at the intervals established for those individual components. The output
action may be breaker tripping, or other control action that must be verified, but may be
verified in overlapping segments. A grouped output control action need be verified
only once within the specified time interval, but all of the SPS components whose
operation leads to that control action must each be verified.
Draft 2: May 27, 2010
Maximum
Maintenance
Interval
Maintenance Activities
17
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Continuous verification of the status of the relays
Protective Relays
Relay A/D converters are
continuously monitored and alarmed
Continuous
Protective Relays
with trip contacts
All Level attributes, except relay
possesses mechanical output
contacts
12 Calendar
Years
Verify proper functioning of the relay trip contacts.
Verification of the analog values
(magnitude and phase angle)
measured by the microprocessor
relay or comparable device, by
comparing against other
measurements using other voltage
and current sensing devices
Continuous
Continuous verification and comparison of the current and voltage signals from the
voltage and current sensing devices of the Protection System
Monitoring and alarming of the alarm
path itself
Continuous
Continuous verification of the status of the monitored control circuits
Voltage and Current
Sensing Inputs to
Protective Relays and
associated circuitry
Protection System
control and trip
circuitry
Alarm on change of settings
Inspect:
Station dc supply
No Level 3 monitoring attributes are
defined – use Level 1 Maintenance
Activities and intervals
Draft 2: May 27, 2010
18 Calendar
Months
•
Cell condition of all individual battery cells where cells are visible – or measure
battery cell/unit internal ohmic values where the cells are not visible
•
Physical condition of battery rack
•
The condition of non-battery-based dc supply
18
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Station dc supply
(that has as a
component Valve
Regulated Lead-Acid
batteries)
Level 3 Monitoring Attributes for
Component
No Level 3 monitoring attributes are
defined – use Level 1 Maintenance
Activities and intervals
Station dc supply
(that has as a
component Vented
Lead-Acid Batteries)
No Level 3 monitoring attributes are
defined – use Level 1 Maintenance
Activities and intervals
Station dc supply
(that has as a
component NickelCadmium batteries)
No Level 3 monitoring attributes are
defined – use Level 1 Maintenance
Activities and intervals
Station dc Supply
(any battery
technology)
Monitoring and alarming for station dc
supply voltage, unintentional dc
grounds, electrolyte level of all cells of
a station battery, individual battery
cell/unit state of charge, battery
continuity of station battery and cellto-cell and battery terminal resistance
Draft 2: May 27, 2010
Maximum
Maintenance
Interval
Maintenance Activities
3 Calendar Years
Verify that the station battery can perform as designed by conducting a performance or
service capacity test of the entire battery bank. (3 calendar years)
- or 3 Calendar
Months
6 Calendar Years
- or 18 Calendar
Months
6 Calendar Years
Continuous
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (3 months)
Verify that the station battery can perform as designed by conducting a performance
service, or modified performance capacity test of the entire battery bank. (6 calendar
years)
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (18 Months)
Verify that the substation battery can perform as designed by conducting a performance
service, or modified performance capacity test of the entire battery bank.
Continuous monitoring of station dc supply voltage, unintentional dc grounds,
electrolyte level of all cells of a station battery, individual battery cell/unit state of
charge, battery continuity of station battery and cell-to-cell and battery terminal
resistance are provided with alarming to remote location upon any failure of the
monitoring device or when sensors for the devises are out of calibration.
19
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Station dc Supply
which do not use a
station battery
Level 3 Monitoring Attributes for
Component
No Level 3 monitoring attributes are
defined – use Level 1 Maintenance
Activities and intervals
Associated
communications
systems
Evaluating the performance of the
channel and its interface to protective
relays to determine the quality of the
channel and alarming if the channel
does not meet performance criteria
UVLS and UFLS
relays that comprise a
protection scheme
distributed over the
power system.
The relay A/D converters are
continuously monitored and alarmed.
Relay sensing for
centralized UFLS or
UVLS systems.
Maximum
Maintenance
Interval
6 Calendar Years
Continuous
Maintenance Activities
Verify that the dc supply can perform as designed when the ac power from the grid is
not present.
Continuous verification that the performance and quality of the channel meets
performance criteria is provided.
Continuous verification of the communications equipment alarm system is provided.
Continuous verification of the status of the relays
Continuous
Alarm on change of settings
Verification does not require actual tripping of circuit breakers or interrupting devices
See the attributes of Level 3
Monitoring for the individual
components of the UFLS/UVLS
Draft 2: May 27, 2010
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of
the UFLS or UVLS systems at the intervals established for those individual
components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified time interval, but all of the
UFLS or UVLS components whose operation leads to that control action must each be
verified.
20
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
SPS
Level 3 Monitoring Attributes for
Component
See the attributes of Level 3
Monitoring for the individual
components of the SPS
Maximum
Maintenance
Interval
Maintenance Activities
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of
the SPS at the intervals established for those individual components. The output action
may be breaker tripping, or other control action that must be verified, but may be
verified in overlapping segments. A grouped output control action need be verified only
once within the specified time interval, but all of the SPS components whose operation
leads to that control action must each be verified.
Notes for Table 1a, Table 1b, and Table 1c
1. For some Protection System components, adjustment is required to bring measurement accuracy within parameters established by the asset owner based on the specific
application of the component. A calibration failure is the result if testing finds the specified parameters to be out of tolerance.
Draft 2: May 27, 2010
21
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
Segment: In this procedure, the term, “segment” is a grouping of Protection Systems or
components from a single manufacturer, with common factors such that consistent performance
is expected across the entire population of the segment, and shall only be defined for a
population of 60 or more individual components. 4
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of components included in each designated segment of
the Protection System component population.
2. Maintain the components in each segment according to the time-based maximum
allowable intervals established in Table 1 until results of maintenance activities for the
segment are available for a minimum of 30 individual components of the segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events 5 for each included component.
4. Analyze the maintenance program activities and results for each segment to determine the
overall performance of the segment and develop maintenance intervals.
5. Determine the maximum allowable maintenance interval for each segment such that the
segment experiences countable events on no more than 4% of the components within the
segment, for the greater of either the last 30 components maintained or all components
maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
4. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
4
Entities with smaller populations of component devices may aggregate their populations to define a segment and
shall share all attributes of a single performance-based program for that segment.
5
Countable events include any failure of a component requiring repair or replacement, any condition discovered
during the verification activities in Table 1a through Table 1c which requires corrective action, or a Misoperation
attributed to hardware failure or calibration failure.
Draft 2: May 27, 2010
22
Standard PRC-005-2 – Protection System Maintenance
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
5. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
Draft 2: May 27, 2010
23
Standard PRC-005-2 — Protection System Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approves SAR for posting on June 5, 2007.
2. The SAR was posted for comment from June 11, 2007–July 10, 2007.
3. The SC approves development of the standard on August 13, 2007.
4. First posting of revised standard on July 24, 2009.
5. Second posting of revised standard on June 11, 2010
Description of Current Draft:
This is the second draft of the Standard. This standard merges previous standards PRC-005-1, PRC-0080, PRC-011-0, and PRC-017-0. It also addresses FERC comments from Order 693, and addresses
observations from the NERC System Protection and Control Task Force, as presented in NERC SPCTF
Assessment of Standards: PRC-005-1 — Transmission and Generation Protection System Maintenance
and Testing, PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs, PRC011-0 — UVLS System Maintenance and Testing, PRC-017-0 — Special Protection System Maintenance
and Testing.
Future Development Plan:
Anticipated Actions
1. Post for combined pre-ballot review and comment.
Anticipated Date
June 11–July 16, 2010
2. Conduct initial ballot.
July 8–July 17, 2010
3. Drafting Team Responds to Comments.
July 19–July 22, 2010
4. Post response to comments and modified standard.
July 23, 2010
5. Conduct 10-day recirculation ballot.
July 23–August 2, 2010
6. Present to BOT for action.
August 5, 2010
May 27, 2010
1
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program can include:for a specific component includes one or more of the
following activities:
•
•
•
•
•
•
•
Verification — A means of determining that the component is functioning correctly.
Monitoring — Observation of the routine in-service operation of the component.
Testing — Application of signals to a component to observe functional performance or
output behavior, or to diagnose problems.
Physical iInspection — To detect visible signs of component failure, reduced
performance and degradation.
Calibration — Adjustment of the operating threshold or measurement accuracy of a
measuring element to meet the intended performance requirement.
Upkeep — Routine activities necessary to assure that the component remains in good
working order and implementation of any manufacturer’s hardware and software service
advisories which are relevant to the application of the device.
Restoration — The actions to restore proper operation of malfunctioning components.
Protection System (modification) — Protective relays, communication systems necessary for
correct operation of protective devicesfunctions, voltage and current sensing inputs to protective relays,
and associated circuitry from the voltage and current sensing devices, station DC dc supply, and DC
control circuitry associated with protective functions from the station DC dc supply through the trip
coil(s) of the circuit breakers or other interrupting devices.
May 27, 2010
2
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems that are applied on, or are designed to provide protection for
the BES.
4.2.2
Protection System components used for underfrequency load-shedding systems
which are installed per ERO underfrequency load-shedding requirements.
4.2.3
Protection System components used for undervoltage load-shedding systems
which are installed to prevent system voltage collapse or voltage instability for
BES reliability.
4.2.4
Protection System components which is installed as a Special Protection System
for BES reliability.
4.2.5
Protection Systems for Generatorgenerator Facilities that are part of the BES,
including:
4.2.5.1 Protection systemSystem components that act to trip the generator either
directly or via generator lockout or auxiliary tripping relays.
4.2.5.2 Protection systemsSystems for generator step-up transformers for generators
that are part of the BES.
4.2.5.3 Protection systemsSystems for transformers connecting aggregated
generation, where the aggregated generation is part of the BES (e.g.,
transformers connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection systemsSystems for generator-connected station service
transformers for generators that are part of the BES.
4.2.5.5 Protection systemsSystems for system-connected station service transformers
for generators that are part of the BES.
5.
5.
(Proposed) Effective Date: TBD
To Be DeterminedSee Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems that use
May 27, 2010
3
Standard PRC-005-2 — Protection System Maintenance
measurements of voltage, current, frequency and/or phase angle to determine anomalies and to
trip a portion of the BES1 and that are applied on, or are designed to provide protection for the
BES. The PSMP shall meet the following criteria: [Violation Risk Factor: TBDHigh] [Time
Horizon: Long Term Planning]
1.1. For each component used in each Protection System, include all maintenance activities
specified in Tables 1a, 1b, and 1c.
1.1. Identify all Protection System components.
1.2. Identify whether each Protection System component is addressed through time-based (per
Table 1a), condition-based (per Table 1b or 1c), performance-based (per Attachment A),
or a combination of these maintenance methods and identify the associated maintenance
interval.
1.3. For each Protection System component, include all maintenance activities specified in
Tables 1a, 1b, or 1c associated with the maintenance method used per Requirement 1,
Part 1.2.
1.3.1.4.Include all batteries associated with the station dc supply component of a Protection
System in a time-based program.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses conditionbased maintenance intervals in its PSMP for partially or fully monitored Protection Systems
shall ensure the components to which the condition-based criteria are applied, (as specified in
Tables 1b or 1c), possess the necessary monitoring attributes identified in Tables 1b or 1c.
[Violation Risk Factor: TBDMedium] [Time Horizon: Long Term Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: TBDMedium] [Time Horizon: Long Term Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its
PSMP, including identification of the resolution of all maintenance correctiblecorrectable
issues 2 as follows: [Violation Risk Factor: TBDMedium] [Time Horizon: Long Term
Planning]
4.1.
For time-based or condition-based maintenance programs, perform, the Maintenance
maintenance activities detailed in Table 1 (for the appropriate monitoring level(s)) for
all Protection System components withinaccording to yourthe PSMP established per
Requirement R1within maximum allowable intervals not to exceed those established
in Tables 1a, 1b, and 1c.
4.2.
For performance-based maintenance programs, perform, the maintenance activities
detailed in Table 1 (for the appropriate monitoring level(s)) for all Protection System
1
Devices that sense non-electrical conditions, such as thermal or transformer sudden pressure relays are not
included within the scope of this standard.
2
A maintenance correctable issue is a failure of a device to operate within design parameters that cannot be restored
to functional order by repair or calibration, repair or replacement. while performing the initial on-site maintenance
activity, and that requires follow-up corrective action
May 27, 2010
4
Standard PRC-005-2 — Protection System Maintenance
components in accordance within the maximum allowable intervals established per
Requirement R3.
4.3.
Ensure either that the components are within acceptable parameters at the conclusion
of the maintenance activities or initiate any necessary activities to correct unresolved
maintenance correctable issues 3.
C. Measures(TBD)
M1. Each Transmission Owner, Generator Owner and Distribution Provider will have a
documented Protection System Maintenance program that addresses protective relays,
communication systems necessary for correct operation of protective functions, voltage and
current sensing inputs to protective relays and associated circuitry from the voltage and current
sensing devices, station dc supply, and control circuitry associated with protective functions
from the station dc supply through the trip coil(s) of the circuit breakers or other interrupting
devices, as required by Requirement R1. For each protection system component, the
documentation shall include the type of maintenance program applied, maintenance activities,
and maintenance intervals as specified in Requirement R1, Parts 1.1 through 1.4.
M2. Each Transmission Owner and Generator Owner that uses a condition-based maintenance
program should have evidence such as engineering drawings or manufacturer’s information
showing that the components possess the monitoring attributes identified in Tables 1b or 1c, as
required by Requirement R2.
M3. Each Transmission Owner, Generator Owner, or Distribution Provider that uses a performancebased maintenance program should have evidence such as equipment lists, maintenance
records, and analysis records and results that its performance-based maintenance program is in
accordance with Requirement R3.
M4. Each Transmission Owner, Generator Owner, or Distribution Provider shall have evidence
such as maintenance records or maintenance summaries (including dates that the components
were maintained) that it has implemented the Protection System Maintenance Program in
accordance with Requirement R4.
C.D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
1.2. Compliance Monitoring Period and Reset Time Frame
1.3.1.2.
Not ApplicableCompliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
3
A maintenance correctable issue is a failure of a device to operate within design parameters that cannot be restored
to functional order by repair or calibration while performing the initial on-site maintenance activity and that requires
follow-up corrective action.
May 27, 2010
5
Standard PRC-005-2 — Protection System Maintenance
1.4.1.3.
Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation for of the two most recent performances of each distinct maintenance
intervalsactivity for the Protection System components, or to the previous on-site audit
date, whichever is longer.
or for the time period specified above, whichever is longerThe Compliance Enforcement
Authority shall keep the last periodic audit report and all requested and submitted
subsequent compliance records.
1.5.1.4.
Additional Compliance Information
None.
2.
May 27, 2010
6
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels - TBD
Requirement
Number
R1
Lower VSL
Moderate VSL
High VSL
Severe VSL
The entity’s PSMP included all of the
‘types’ of components included in the
definition of ‘Protection System’, but,
for no more than 5% of the
components, failed to either
The entity’s PSMP included all of
the ‘types’ of components included
in the definition of ‘Protection
System’, but, for greater than 5%,
but no more than 10% of the
components, failed to either
The entity’s PSMP included all of
the ‘types’ of components included
in the definition of ‘Protection
System’, but, for greater than 10%,
but no more than 15%, of the
components, failed to either
The entity’s PSMP failed to
address one or more of the types of
components included in the
definition of ‘Protection System’
• Identify the component,
• Identify the component,
Entity has not established a PSMP.
• Specify whether the component
is being addressed by timebased, condition-based, or
performance-based
maintenance, or
• Specify whether the component
is being addressed by timebased, condition-based, or
performance-based
maintenance, or
OR
• Include all maintenance
activities specified in Table 1a,
Table 1b, or Table 1c, as
applicable.
• Include all maintenance
activities specified in Table 1a,
Table 1b, or Table 1c, as
applicable.
• Identify the component,
• Specify whether the component is
being addressed by time-based,
condition-based, or performancebased maintenance, or
• Include all maintenance activities
specified in Table 1a, Table 1b, or
Table 1c, as applicable.
OR
The entity’s’ PSMP included all of
the ‘types’ of components included
in the definition of ‘Protection
System’, but, for more than 15% of
the components, failed to either
• Identify the component,
• Specify whether the component
is being addressed by timebased, condition-based, or
performance-based
maintenance, or
• Include all maintenance
activities specified in Table 1a,
Table 1b, or Table 1c, as
applicable.
R2
May 27, 2010
Entity has Protection System
components in a condition-based
PSMP, but documentation to support
Partially-Monitored Protection System
classification or Fully-Monitored
Protection System classification is
incomplete on no more than 5% of the
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support Partially-Monitored
Protection System classification or
Fully-Monitored Protection System
classification is incomplete on more
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support Partially-Monitored
Protection System classification or
Fully-Monitored Protection System
classification is incomplete on more
7
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support Partially-Monitored
Protection System classification or
Fully-Monitored Protection System
classification is incomplete on more
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Protection System components
maintained according to Tables 1b and
1c.
R3
Entity has Protection System elements
in a performance-based PSMP but has:
Moderate VSL
than 5%, but 10% or less, of the
Protection System components
maintained according to Tables 1b
and 1c.
NA
1) Failed to reduce countable events to
less than 4% within three years.
High VSL
Severe VSL
than 10%, but 15% or less, of the
Protection System components
maintained according to Tables 1b
and 1c.
than 15% of the Protection System
components maintained according
to Tables 1b and 1c.
Entity has Protection System
elements in a performance-based
PSMP but has failed to reduce
countable events to less than 4%
within four years.
Entity has Protection System
components in a performancebased PSMP but has:
OR
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for 5% or less of components
in any individual segment
1) Failed to reduce countable
events to less than 4% within five
years.
OR
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for over 5% of components
in any individual segment.
OR
3) Maintained a segment with 54-59
components or containing different
manufacturers.
OR
3) Maintained a segment with less
than 54 components.
OR
4) Failed to annually update the list
of components,
• Perform maintenance on the
greater of 5% of the segment
population or 3 components, or
• Annually analyze the program
activities and results for each
segment.
R4
May 27, 2010
Entity has failed to complete scheduled
program on 5% or less of total
Entity has failed to complete
scheduled program on greater than
Entity has failed to complete
scheduled program on greater than
8
Entity has failed to complete
scheduled program on greater than
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Protection System components.
Moderate VSL
High VSL
5%, but no more than 10% of total
Protection System components.
10%, but no more than 15% of total
Protection System components.
Severe VSL
15% of total Protection System
components.
OR
Entity has failed to initiate
resolution of maintenancecorrectable issues
May 27, 2010
9
Standard PRC-005-2 – Protection System Maintenance
D.E.
Regional DifferencesVariances
None
E.F.
Supplemental Reference Documents
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. 1. PRC-005-2 Protection System Maintenance Supplementary Reference -— July 2009.
2.
NERC Protection System Maintenance Standard PRC-005-2 FREQUENTLY ASKED
QUESTIONS -— Practical Compliance and Implementation DRAFT 1.0 -— June 2009
Version History
Version
Date
Action
2
TBD
Complete revision, absorbing maintenance
requirements from PRC-005-1, PRC-008-0,
PRC-011-0, PRC-017
Draft 2: April, 2010May 27, 2010
Change Tracking
Complete revision
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection SystemsSystem Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection System
Component
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays) with simulated electrical inputs. (Note 1)
Verify proper functioning of the relay trip outputsthat settings are as specified.
Protective Relays
6 Calendar Years
For microprocessor relays verify , check the relay inputs and outputs that are essential to proper functioning of the A/D
converters (Note 2)Protection System.
Verify that settings are as specified. For microprocessor relays, verify acceptable measurement of power system input
values.
Voltage and Current
Sensing Devices
Inputs to Protective Relays
and associated circuitry
Protection System Control
Circuitry (Breaker Trip Coil
Only)and trip circuits with
electromechanical trip or
auxiliary contacts (except for
microprocessor relays,
UFLS or UVLS)
12 Calendar
Years
6 Calendar
Years3 Months
Verify proper functioning of the current and voltage circuit inputs signals necessary for Protection System operation
from the voltage and current sensing devices to the protective relays.
Verify the continuity of the breaker trip circuit including trip coil (except for protection system control circuitry associated with
breakers that remain open for the entire “maintenance interval” period”).
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits,
including all electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System.
Protection System Control
Circuitry (Trip Circuits)and
trip circuits with unmonitored
solid-state trip or auxiliary
contacts (except for UFLS
or UVLS)
612 Calendar
Years
Control and trip circuits with
electromechanical trip or
auxiliary (UFLS/UVLS
Systems Only)
6 Calendar Years
Draft 2: April, 2010May 27, 2010
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuitcircuits,
including all solid-state trip and auxiliary contacts (e.g. paths with no moving parts), devices, and connections essential
to proper functioning of the Protection System.
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits,
including all electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System,
except .that verification does not require actual tripping of circuit breakers or interrupting devices.
11
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection SystemsSystem Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection System
Component
Maximum
Maintenance
Interval
Maintenance Activities
Protection System Control
Circuitry (Trip Circuits)and
trip circuits with unmonitored
solid-state trip or auxiliary
contacts (UFLS/UVLS
Systems Only)
(when the
associated UVLS
or UFLS system is
maintained)12
Calendar Years
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuit,
including all solid-state trip and auxiliary contacts (e.g. paths with no moving parts), devices, and connections essential
to proper functioning of the Protection System., except that verification does not require actual tripping of circuit
breakers or interrupting devices.
Station dc Supply (used only
for UVLS or UFLS)
(when the
associated UVLS
or UFLS system
is maintained)
Verify proper voltage of the dc supply.
Verify:
Station dc supply Station dc
supply (that has as a
component any type of
battery)
18 Calendar
Months3 Months
•
State of charge of the individual battery cell/units
•
Float voltage of battery charger
•
Battery continuity
•
Battery terminal connection resistance
•
Battery cell-to-cell connection resistance
Inspect:
•
Cell condition of all individual battery cells where cells are visible – or measure battery cell/unit internal ohmic
values where the cells are not visible
•
Physical condition of battery rack
•
The condition of non-battery-based dc supply
Verify proper electrolyte level (excluding valve-regulated lead acid batteries).
Verify proper voltage of the station battery.
Verify that no dc supply grounds are present.
Draft 2: April, 2010May 27, 2010
12
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection SystemsSystem Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection System
Component
Maximum
Maintenance
Interval
Maintenance Activities
Check:
Station dc supply (that has
as a component any type of
battery)
3 Calendar
Months
•
Electrolyte level (excluding valve-regulated lead acid batteries)
•
Station dc supply voltage
For unintentional groundsVerify proper electrolyte level (excluding valve-regulated lead acid batteries).
Verify proper voltage of the station battery.
•
Verify that no dc supply grounds are present.
Verify proper voltage of each individual cell or unit in the station battery.
Station dc supply
(that has as a component
any type of battery)
Verify that station battery charger provides the correct float and equalize voltages.
Verify continuity and cell integrity of entire battery.
18 Months
Perform a visual cell inspection of all cells for “cell condition” (where cells are visible) or measurement of cell/unit
internal ohmic values (where cells are not visible).
Measure that specific gravity and temperature of each cell is within tolerance(where applicable)
Verify cell to cell and terminal connection resistance is within tolerance
Inspect the structural integrity of the battery rack.
Station dc supply (that has
as a component Valve
Regulated Lead-Acid
batteries)
3 Calendar Years
- or 3 Calendar
Months
Draft 2: April, 2010May 27, 2010
Verify that the station battery can perform as designed by conducting a performance or service capacity test of the
entire battery bank. (3 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values to
station battery baseline. (3 months)
13
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection SystemsSystem Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Maximum
Maintenance
Interval
Maintenance Activities
6 Calendar Years
Or
Verify that the station battery can perform as designed by conducting a performance, service, or modified performance
capacity test of the entire battery bank. (6 calendar years)
Type of Protection System
Component
Station dc supply
(that has as a component
Vented Lead-Acid Batteries)
- or 18 Calendar
Months
Station dc supply (that has
as a component NickelCadmium batteries)
6 Calendar Years
Verify that the substation battery can perform as designed by conducting a performance service, or modified
performance capacity test of the entire battery bank.
Station dc supply (battery is
not used)(that useswhich do
not use a station battery and
charger)
6 Calendar Years
Verify that the battery chargerdc supply can perform as designed by testing thatwhen the charger will provide full rated
current and will properly current-limit.ac power from the grid is not present.
- or Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values to
station battery baseline. (18 Months)
Verify proper voltage of the station dc supply.
Verify that no unintentional dc supply grounds are present.
Station dc Supply (battery is
not used)
18 Calendar
Months
Perform a visual inspection, of all components of the station dc supply to verify that the physical condition of the station
dc supply is as desired and any visual inspection if required by the manufacturer on the condition of the dc supply that
is the source of dc power when ac power is unavailable.
Verify where applicable the proper voltage level of each component of the station dc supply.
Verify the correct operation of ac powered dc power supplies.
Verify the continuity of all circuit connections that can be affected by wear or corrosion. Inspect all circuit connections
that can be affected by wear and corrosion.
Station dc Supply (used only
for UVLS or UFLS)
(when the
associated UVLS
or UFLS system is
maintained)
Draft 2: April, 2010May 27, 2010
Verify proper voltage of the dc supply.
14
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection SystemsSystem Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not transmitted
to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection System
Component
Maximum
Maintenance
Interval
Protection systemAssociated
communications equipment
and channels.systems
3 Calendar
Months
Verify that the Protection System communications monitoring and alarms reflect the intended communications system
condition by means of a substation inspection.is functional.
6 Calendar Years
Verify that the performance of the channel and the quality of the channel meets performance criteria, such as via
measurement of signal level, reflected power, or data error rate.
Verify proper functioning of communications equipment outputs. inputs and outputs that are essential to proper
functioning of the Protection System.
Verify the signals to/from the associated protective relay(s).
Protection systemAssociated
communications equipment
and channels.systems
UVLS and UFLS relays that
comprise a protection
scheme distributed over the
power system
Relay sensing for
Centralized UFLS or UVLS
systemssystems UVLS and
UFLS relays that comprise a
protection scheme
distributed over the power
system
SPS
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays) with simulated electrical inputs. (Note 1)
6 Calendar Years
Verify proper functioning of the relay trip outputs.
For microprocessor relays verify the proper functioning of the A/D converters (Note 2) .
Verify that settings are as specified.
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of the UFLS or UVLS systems at
the intervals established for those individual components. The output action may be breaker tripping, or other control
action that must be verified, but may be verified in overlapping segments. A grouped output control action need be
verified only once within the specified time interval, but all of the UFLS or UVLS components whose operation leads to
that control action must each be verified.
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of the SPS at the intervals
established for those individual components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output control action need be verified only
once within the specified time interval, but all of the SPS components whose operation leads to that control action must
each be verified.
Draft 2: April, 2010May 27, 2010
15
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elementsDetected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1
day or less of level 1 the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level
2 monitoring with additional includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Includes internal
•
Internal self diagnosis and
alarm capability, which
•
Alarm must assert for power
supply failures. Includes input
•
Input voltage or current
waveform sampling three or
more times per power cycle,
and conversion
Protective Relays
•
Verify the status of relays is normal with no alarms indicated.
Verify theacceptable measurement of power system input values.
12 Calendar Years
For microprocessor relays, check the relay inputs and outputs that are essential to
proper functioning of the A/D converters within the relay by testing or comparing values
against other devicesProtection System.
Verify proper functioning of the relay trip outputs.
Verify that settings are as specified.
Conversion of samples to
numeric values for
measurement calculations by
microprocessor electronics
that are also performing self
diagnosis and alarming
Verify that the relay alarms will be received at the location where action can be taken.
See Note 2.Verify correct operation of output actions that are used for tripping.
Voltage and
Current Sensing
Devices - Inputs
to Protective
Relays and
associated
circuitry
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
12 Calendar Years
Verify the proper functioning of current and voltage circuit inputssignals necessary for
Protection System operation from the voltage and current sensing devices to the
protective relays.
Protection System
Control Circuitry
(Trip Coils and
Auxiliary Relays)
No Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities and intervalsMonitoring and
alarming of continuity of trip circuits(s)
6 Calendar Years
Verify that each breaker trip coil, each auxiliary relay, and each lockout relay is
electrically operated within this time interval.
Draft 2: April, 2010May 27, 2010
16
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elementsDetected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1
day or less of level 1 the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level
2 monitoring with additional includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Perform a complete functional trip test that includes all sections of the Protection System trip
circuit, including all auxiliary contacts essential to proper functioning of the Protection System.
Verify that the relay alarms will be received at the location where action can be taken.
Monitoring and alarming of continuity of
trip coil(s)
Protection System
Control Circuitry
(Trip Circuits)
(except for
UFLS/UVLS)
Monitoring of Protection System
component inputs, outputs, and
connections with reporting of
monitoring alarms to a location where
action can be taken
Connection paths using electronic
signals or data messages are
monitored by periodic signal changes
or messages that verify ability to
convey Protection System operating
values
Draft 2: April, 2010May 27, 2010
17
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elementsDetected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1
day or less of level 1 the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level
2 monitoring with additional includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
(when the associated
UVLS or UFLS
system is
maintained)12
Calendar Years
Perform a complete functional trip test that includes all sections of the Protection System trip
circuit, including all auxiliary contacts essential to proper functioning of the Protection System.
(Verification does not require actual tripping of circuit breakers or interrupting devices.)
Verify that the relay alarms will be received at the location where action can be taken.
Monitoring and alarming of continuity of
trip coil(s)
Protection System
Control Circuitry
(Trip Circuits)
(UFLS/UVLS
Systems
Only)Control and
trip circuitry
Monitoring of the continuity of breaker
trip circuits along with the presence of
tripping voltage supply all the way from
relay terminals (or from inside the
relay) through to the trip coil(s),
including any auxiliary contacts
essential to proper Protection System
operation. If a trip circuit comprises
multiple paths, each of the paths must
be monitored, including monitoring of
the operating coil circuit(s) and the
tripping circuits of auxiliary tripping
relays and lockout relays. Alarming for
loss of continuity or dc supply for trip
circuits is reported to a location where
action can be taken.
Draft 2: April, 2010May 27, 2010
18
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elementsDetected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1
day or less of level 1 the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level
2 monitoring with additional includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
MonitoringMonitor and alarming of the
station alarm for:
Station dc supply
(that has as a
component any
type of battery)
•
Station dc supply voltage
•
Detection and alarming of
Unintentional dc grounds.
•
Electrolyte level of all cells in
a station battery
•
Individual battery cell/unit
state of charge
•
Battery continuity of station
battery
•
Cell-to-cell and battery
terminal resistance
Draft 2: April, 2010May 27, 2010
3 Months
6 Calendar yYears
Verify proper electrolyte level (excluding Valve-Regulated Lead Acid batteries).
Verify that the monitoring devices are calibrated (where necessary) and alarms will be
received at the location where action can be taken.
19
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elementsDetected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1
day or less of level 1 the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level
2 monitoring with additional includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Verify proper voltageInspect:
Cell condition of each individual cell or unit in the station battery.
Verify that station battery charger provides the correct float and equalize voltages.
Station dc
supply(that has as
a component any
type of battery)
Station dc supply
(that has as a
component Valve
Regulated LeadAcid batteries)
Monitoring and alarming of the station dc
supply voltage.
Detection and alarming of dc grounds. No
Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
Monitoring and alarming of the station dc
supply voltage.
Detection and alarming of dc grounds. No
Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
Draft 2: April, 2010May 27, 2010
Verify electrical continuity of the entire battery.
•
18 Calendar
Months
3 Calendar Years
- or 3 Calendar Months
Perform a visual cell inspection of all cells for “cell condition” (where cells are
visible), or measurement of measure battery cell/unit internal ohmic values. (
where cells are not visible)
Measure that specific gravity and temperature of each cell is within tolerance. (where
applicable)
Verify cell to cell and terminal connection resistance is within tolerance.
•
Inspect the structural integrity of the Physical condition of battery rack
•
Verify that the The condition of non-battery voltage andbased dc supply ground
alarms will be received at the location where action can be taken.
Verify that the station battery can perform as designed by conducting a performance or
service capacity test of the entire battery bank. (3 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (3 months)
20
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elementsDetected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1
day or less of level 1 the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level
2 monitoring with additional includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Station dc supply
(that has as a
component
Vented LeadAcid batteries)
Monitoring and alarming of the station dc
supply voltage.
Detection and alarming of dc grounds.No
Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
6 Calendar Years
- or 18 Calendar
Months
Station dc supply
(that has as a
component
Nickel-Cadmium
batteries)
Monitoring and alarming of the station dc
supply voltage.
Detection and alarming of dc grounds.No
Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
6 Calendar Years
Station dc supply
(that uses a battery
and charger)
Monitoring and alarming of the
station dc supply voltage.
Detection and alarming of dc
grounds.
Draft 2: April, 2010May 27, 2010
6 Calendar
Years
Maintenance Activities
Verify that the substation battery can perform as designed by conducting a
performance service, or modified performance capacity test of the entire battery bank.
(6 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (18 Months)
Verify that the substation battery can perform as designed by conducting a
performance service, or modified performance capacity test of the entire battery bank.
Verify that the battery charger can perform as designed by testing that the charger will provide full
rated current and will properly current-limit.
21
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elementsDetected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1
day or less of level 1 the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level
2 monitoring with additional includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Maximum
Maintenance
Interval
Level 2 Monitoring Attributes for
Component
Maintenance Activities
Verify proper voltage of that the station dc supply, and where applicable, of each component
of the station dc supply.
Station dc Supply
(battery is not
used)
Station dc Supply
(used only for
UVLS or UFLS)
Protection
systemAssociated
communications
equipment and
channels.system
Verify the proper operation of ac powered dc power supplies.
Monitoring and alarming of the station dc
supply voltage.
Detection and alarming of dc grounds.No
Level 2 monitoring attributes are
defined – use Level 1 Maintenance
Activities
No Level 2 monitoring
attributes are defined – use
Level 1 Maintenance Activities
and intervals
Verify the continuity of all circuit connections that can be affected by wear or corrosion.
18 Months
6 Calendar Years
(when the
associated
UVLS or UFLS
system is
maintained)
Monitoring and alarming of protection
communications system by
mechanisms that check for presence of
the communications channel.
Draft 2: April, 2010May 27, 2010
Perform a visual inspection, of all components of the station dc supply to verify that the
physical condition of the station dc supply is perform as desired and any visual inspection if
required by the manufacturer on the condition of the dc supply that is the source of dc
powerdesigned when ac power is unavailable.
Verify that the station dc supply voltage and dc supply ground alarms will be received at a
location where action can be taken.from the grid is not present.
Verify proper voltage of the dc supply
12 Calendar Years
Verify that the performance of the channel and the quality of the channel meets
performance criteria, such as via measurement of signal level, reflected power, or data
error rate.
Verify proper functioning of communications equipment inputs and outputs that are
essential to proper functioning of the Protection System.
Verify the signals to/from the associated protective relay(s).
Verify proper functioning of alarm notification.
22
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action can be
taken for alarmed failures. Monitoring includes all elementsDetected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1
day or less of level 1 the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level
2 monitoring with additional includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of
Protection
System
Component
Level 2 Monitoring Attributes for
Component
UVLS and UFLS
relays that
comprise a
protection
scheme
distributed over
the power
system
Includes internal self diagnosis and
alarm capability, which must assert for
power supply failures. Includes input
voltage or current waveform sampling
three or more times per power cycle,
and conversion of samples to numeric
values for measurement calculations
by microprocessor electronics that are
also performing self diagnosis and
alarming.
12 Calendar Years
Verify the status of relays as in service with no alarms.
Verify theVerify acceptable measurement of power system input values the proper
function of the A/D converters (if included in relay).
Verify proper functioning of the relay trip outputs.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can be taken.
Relay sensing for
centralized UFLS
or UVLS systems
See the attributes of Level 12
Monitoring for the individual
components of the SPS
See Maintenance
Intervals for the
individual
components of the
UFLS/UVLS
Perform all of the Maintenance activities listed above as established for components of
the UFLS or UVLS systems at the intervals established for those individual
components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified time interval, but all of the
UFLS or UVLS components whose operation leads to that control action must each be
verified.
SPS
See the attributes of Level 1 2
Monitoring for the individual
components of the SPS
See Maintenance
Intervals for the
individual
components of the
SPS
Perform all of the Maintenance activities listed above as established for components of
the SPS, at the intervals established for those individual components. The output
action may be breaker tripping, or other control action that must be verified, but may be
verified in overlapping segments. A grouped output control action need be verified
only once within the specified time interval, but all of the SPS components whose
operation leads to that control action must each be verified.
Draft 2: April, 2010May 27, 2010
Maximum
Maintenance
Interval
Maintenance Activities
23
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection SystemsSystem Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all elementsattributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Continuous verification of the status of the relays. (Note 2)
Protective Relays
The relayRelay A/D converters are
continuously monitored and alarmed
Continuous
Protective Relays
with trip contacts
All Level attributes, except relay
possesses mechanical output
contacts
12 Calendar
Years
Verify proper functioning of the relay trip contacts.
Voltage and Current
Sensing Devices
Inputs to Protective
Relays and
associated circuitry
Verification of the ac analog values
(magnitude and phase angle)
measured by the microprocessor
relay or comparable device, by
comparing against other
measurements using other instrument
transformers.voltage and current
sensing devices
Continuous
Continuous verification and comparison of the current and voltage signals from the
voltage and current sensing devices of the Protection System
Protection System
control and trip
circuitry
Monitoring and alarming of the alarm
path itself
Continuous
Continuous verification of the status of the monitored control circuits
Draft 2: April, 2010May 27, 2010
Alarm on change of settings
24
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection SystemsSystem Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all elementsattributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Protection System
Control Circuitry (Trip
Coils and Auxiliary
Relays)Station dc
supply
Protection System
Control Circuitry (Trip
Circuits)Station dc
supply (that has as a
component Valve
Regulated Lead-Acid
batteries)
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Maintenance Activities
Each breaker trip coil, each auxiliary relay, and each lockout relay must be electrically
operated within this time interval.Inspect:
No Level 3 monitoring attributes are
defined – use Level 21 Maintenance
Activities and intervals
Monitoring of the continuity of breaker
trip circuits (with alarming for noncontinuity), along with the presence of
tripping voltage supply all the way
from relay terminals (or from inside
the relay) through to the trip coil,
including any auxiliary contacts
essential to proper Protection System
operation. If a trip circuit comprises
multiple paths, each of the paths must
be monitored, including monitoring of
the operating coil circuit(s) and the
tripping circuits of auxiliary tripping
relays and lockout relays.No Level 3
monitoring attributes are defined –
use Level 1 Maintenance Activities
and intervals
Draft 2: April, 2010May 27, 2010
618 Calendar
YearsMonths
Continuous3
Calendar Years
- or 3 Calendar
Months
•
Cell condition of all individual battery cells where cells are visible – or measure
battery cell/unit internal ohmic values where the cells are not visible
•
Physical condition of battery rack
•
The condition of non-battery-based dc supply
Continuous monitoring of trip voltage and trip path integrity of entire trip circuit is
provided with alarming to remote terminal unit upon any failure of the trip path. Verify
that the station battery can perform as designed by conducting a performance or
service capacity test of the entire battery bank. (3 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (3 months)
25
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection SystemsSystem Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all elementsattributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Level 3 Monitoring Attributes for
Component
Station dc Supply
(any battery
technology)supply
(that has as a
component Vented
Lead-Acid Batteries)
Monitoring and alarming the station
dc supply status, including, for station
dc supplies that have as a component
a battery, the voltage, specific gravity,
electrolyte level, temperature and
connectivity (cell to cell and terminal
connection resistance) of each cell as
well as the battery system terminal
voltage and electrical continuity of the
overall battery system.
Monitoring and alarming if the
performance capability of the battery
is degraded.
Monitoring and alarming the ac
powered dc power supply status
including low and high voltage and
charge rate for station dc supplies
that have battery systems.
Detection and alarming of dc
grounds.No Level 3 monitoring
attributes are defined – use Level 1
Maintenance Activities and intervals
Draft 2: April, 2010May 27, 2010
Maximum
Maintenance
Interval
Maintenance Activities
Verify that the station battery charger operation provides the correct float and equalize
voltages
6 Calendar Years
- or 18 Calendar
Months
Performcan perform as designed by conducting a visual inspectionperformance service,
or modified performance capacity test of the station battery and charger, individual cells
(including electrolyte level), connections, and racks to verify that the physical condition
of the battery is as desired, and that no associated alarm lamps are illuminated.entire
battery bank. (6 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (18 Months)
26
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection SystemsSystem Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all elementsattributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Level 3 Monitoring Attributes for
Component
Maximum
Maintenance
Interval
Station dc supply
(that useshas as a
battery and
charger)component
Nickel-Cadmium
batteries)
Monitoring and alarming the station
dc supply status, including, for station
dc supplies that have as a component
a battery, the voltage, specific gravity,
electrolyte level, temperature and
connectivity (cell to cell and terminal
connection resistance) of each cell as
well as the battery system terminal
voltage and electrical continuity of the
overall battery system.
Monitoring and alarming if the
performance capability of the battery
is degraded.
Monitoring and alarming the ac
powered dc power supply status
including low and high voltage and
charge rate for station dc supplies
that have battery systems.
Detection and alarming of dc
grounds.No Level 3 monitoring
attributes are defined – use Level 1
Maintenance Activities and intervals
6 Calendar Years
Draft 2: April, 2010May 27, 2010
Maintenance Activities
Verify that the substation battery charger can perform as designed by testing
thatconducting a performance service, or modified performance capacity test of the
charger will provide full rated current and will properly current-limit.entire battery bank.
27
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection SystemsSystem Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all elementsattributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Level 3 Monitoring Attributes for
Component
Station dc Supply
(any battery is not
used)technology)
Monitoring and alarming thefor station
dc supply status, including output
voltage, unintentional dc grounds,
electrolyte level of the dc supply.
Monitoringall cells of a station battery,
individual battery cell/unit state of
charge, battery continuity of station
battery and alarming if the
performance capability of the dc
supply is degraded.
Detectioncell-to-cell and alarming of
dc grounds.battery terminal
resistance
Station dc Supply
(used only for UVLS
or UFLS)which do not
use a station battery
No Level 3 monitoring attributes are
defined – use Level 21 Maintenance
Activities and intervals
Protection system
telecommunications
equipment and
channels.Associated
communications
systems
Evaluating the performance of the
channel and its interface to protective
relays to determine the quality of the
channel and alarming if the channel
does not meet performance criteria
Draft 2: April, 2010May 27, 2010
Maximum
Maintenance
Interval
Continuous
Maintenance Activities
Continuous verification of the status of the station dc supply and its ability to deliver dc
power when required, is provided.Continuous monitoring of station dc supply voltage,
unintentional dc grounds, electrolyte level of all cells of a station battery, individual
battery cell/unit state of charge, battery continuity of station battery and cell-to-cell and
battery terminal resistance are provided with alarming to remote location upon any
failure of the monitoring device or when sensors for the devises are out of calibration.
(when the
associated UVLS
Verify proper voltage ofthat the dc supply can perform as designed when the ac power
or UFLS system is
from the grid is not present.
maintained)6
Calendar Years
Continuous
Continuous verification that the performance and quality of the channel meets
performance criteria is provided.
Continuous verification of the communications equipment alarm system is provided.
28
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection SystemsSystem Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and verified, and
detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms and monitored values are
transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection Systems must be reported within 1 hour or
less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 3 Monitoring
includes all elementsattributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Type of Protection
System Component
Level 3 Monitoring Attributes for
Component
UVLS and UFLS
relays that comprise a
protection scheme
distributed over the
power system.
The relay A/D converters are
continuously monitored and alarmed.
Relay sensing for
centralized UFLS or
UVLS systems.
SPS
Maximum
Maintenance
Interval
Maintenance Activities
Continuous verification of the status of the relays. (Note 2)
Continuous
Alarm on change of settings
Verification does not require actual tripping of circuit breakers or interrupting devices
See the attributes of Level 3
Monitoring for the individual
components of the UFLS/UVLS
See the attributes of Level 3
Monitoring for the individual
components of the SPS
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of
the UFLS or UVLS systems at the intervals established for those individual
components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified time interval, but all of the
UFLS or UVLS components whose operation leads to that control action must each be
verified.
See Maintenance
Activities
Perform all of the Maintenance activities listed above as established for components of
the SPS at the intervals established for those individual components. The output action
may be breaker tripping, or other control action that must be verified, but may be
verified in overlapping segments. A grouped output control action need be verified only
once within the specified time interval, but all of the SPS components whose operation
leads to that control action must each be verified.
Notes for Table 1a, Table 1b, and Table 1c
1. For some Protection System components, adjustment is required to bring measurement accuracy within parameters established by the asset owner based on the specific
application of the component. A calibration failure is the result if testing finds the specified parameters to be out of tolerance.
2. Microprocessor relays typically are specified by manufacturers as not requiring calibration, but power system input values must be verified as correct within the Table
intervals. The integrity of the digital inputs and outputs will be verified with the Protection System Control Circuitry.
Draft 2: April, 2010May 27, 2010
29
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
Segment: In this procedure, the term, “segment” is a grouping of Protection Systems or
component devicescomponents from a single manufacturer, with common factors such that
consistent performance is expected across the entire population of the segment, and shall only be
defined for a population of 60 or more individual components. 4
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of components included in each designated segment of
the Protection System component population.
2. Maintain the components in each segment according to the time-based maximum
allowable intervals established in Table 1 until results of maintenance activities for the
segment are available for a minimum of 30 individual components of the segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events 5 for each included component.
4. Analyze the maintenance program activities and results for each segment to determine the
overall performance of the segment and develop maintenance intervals.
5. Determine the maximum allowable maintenance interval for each segment such that the
segment experiences countable events on no more than 4% of the components within the
segment, for the greater of either the last 30 components maintained or all components
maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
4. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
44
Entities with smaller populations of component devices may aggregate their populations to define a segment and
shall share all attributes of a single performance-based program for that segment.
5
Countable events include any failure of a component requiring repair or replacement, any condition discovered
during the verification activities in Table 1a through Table 1c which requires corrective action, or a Misoperation
attributed to hardware failure or calibration failure.
Draft 2: April, 2010May 27, 2010
Standard PRC-005-2 – Protection System Maintenance
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
5. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
Draft 2: April, 2010May 27, 2010
Draft Implementation Plan for PRC-005-02
Background:
In developing the implementation plan, the Standard Drafting Team considered the following:
1. The requirements set forth in the proposed standard establish maximum allowable maintenance
intervals for the first time. The established maximum allowable intervals may be shorter than those
currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the proposed
standard, it is unrealistic for those entities to be immediately in compliance with the new intervals.
Further, entities should be allowed to become compliant in such a way as to facilitate a continuing
maintenance program.
3. Entities that have previously been performing maintenance within the newly specified intervals may
not have all the documentation needed to demonstrate compliance with all of the maintenance
activities specified.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall follow the protection
system maintenance and testing program it used to perform maintenance and testing to comply with PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 (for the protection system components identified in PRC005-2 Table 1a) until that Transmission Owner, Generator Owner or Distribution Provider meets initial
compliance for maintenance of the same protection system component, in accordance with the phasing
specified below.
For audits that are conducted during the time period when entities are modifying their existing protection
system maintenance and testing programs to become compliant with the maintenance activities and
intervals specified in PRC-005-2, each responsible entity must be prepared to identify:
•
All of its applicable protection system components
•
For each component, whether maintenance of that component is still being addressed under PRC005-1 or has been moved under PRC-005-2
•
Evidence that each component has been maintained under the relevant requirements
Implementation plan for Requirement R1:
•
Entities shall be 100% compliant on the first day of the first calendar quarter three months
following applicable regulatory approvals, or in those jurisdictions where no regulatory approval
is required, on the first day of the first calendar quarter six months following Board of Trustees
adoption.
Implementation plan for Requirements R2, R3, and R4:
1. For Protection System Components with maximum allowable intervals of less than 1 year, as
established in Table 1a,
a. The entity shall be 100% compliant on the first day of the first calendar quarter 12
months following applicable regulatory approval, or in those jurisdictions where no
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regulatory approval is required, on the first day of the first calendar quarter 12 months
following Board of Trustees adoption.
2. For Protection System Components with maximum allowable intervals 1 year or more, but 2
years or less, as established in Table 1a,
a. The entity shall be 100% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 2 calendar
years following Board of Trustees adoption.
3. For Protection System Components with maximum allowable intervals of 6 years, as established
in Table 1a,
a. The entity shall be 30% compliant on the first day of the first calendar quarter 2 calendar
years following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 2 calendar
years following Board of Trustees adoption.
b. The entity shall be 60% compliant on the first day of the first calendar quarter 4 calendar
years following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 6
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 6 calendar
years following Board of Trustees adoption.
4. For Protection System Components with maximum allowable intervals of 12 years, as established
in Table 1a,
a. The entity shall be 30% compliant on the first day of the first calendar quarter 4 calendar
years following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
b. The entity shall be 60% compliant on the first day of the first calendar quarter following
8 calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 8 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 12
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 12
calendar years following Board of Trustees adoption.
Applicability:
This standard applies to the following functional entities:
•
Transmission Owners
•
Generator Owners
•
Distribution Providers
Draft 2: June 3, 2010
2
Draft Implementation Plan for PRC-005-02
Background:
In developing the implementation plan, the Standard Drafting Team considered the following:
1. The requirements set forth in the proposed standard establish maximum allowable maintenance
intervals for the first time. The established maximum allowable intervals may be shorter than those
currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the proposed
standard, it is unrealistic for those entities to be immediately in compliance with the new intervals.
Further, entities should be allowed to become compliant in such a way as to facilitate a continuing
maintenance program.
3. Until an entity is 100% compliant with PRC-005-2, the entity must be in compliance with PRC-005-1
for those components for which the implementation schedule for PRC-005-2 is not yet applicable.
4.3. Entities that have previously been performing maintenance within the newly specified intervals may
not have all the documentation needed to demonstrate compliance with all of the maintenance
activities specified.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall follow the protection
system maintenance and testing program it used to perform maintenance and testing to comply with PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 (for the protection system components identified in PRC005-2 Table 1a) until that Transmission Owner, Generator Owner or Distribution Provider meets initial
compliance for maintenance of the same protection system component, in accordance with the phasing
specified below.
For audits that are conducted during the time period when entities are modifying their existing protection
system maintenance and testing programs to become compliant with the maintenance activities and
intervals specified in PRC-005-2, each responsible entity must be prepared to identify:
•
All of its applicable protection system components
•
For each component, whether maintenance of that component is still being addressed under PRC005-1 or has been moved under PRC-005-2
•
Evidence that each component has been maintained under the relevant requirements
Implementation plan for Requirement R1:
•
Entities shall be 100% compliant on the first day of the first calendar quarter three months
following applicable regulatory approvals, or in those jurisdictions where no regulatory approval
is required, on the first day of the first calendar quarter threesix months following Board of
Trustees adoption.
Implementation plan for Requirements R2, R3, and R4:
1. For Protection System Components with maximum allowable intervals of less than 1 year, as
established in Table 1a,
a. The entity shall be 100% compliant on the first day of the first calendar quarter 12
months following applicable regulatory approval, or in those jurisdictions where no
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regulatory approval is required, on the first day of the first calendar quarter 12 months
following Board of Trustees adoption.
2. For Protection System Components with maximum allowable intervals 1 year or more, but 2
years or less, as established in Table 1a,
a. The entity shall be 100% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 2 calendar
years following Board of Trustees adoption.
3. For Protection System Components with maximum allowable intervals of 6 years, as established
in Table 1a,
a. The entity shall be 30% compliant on the first day of the first calendar quarter 2 calendar
years following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 2 calendar
years following Board of Trustees adoption.
b. The entity shall be 60% compliant on the first day of the first calendar quarter 4 calendar
years following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 6
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 6 calendar
years following Board of Trustees adoption.
4. For Protection System Components with maximum allowable intervals of 12 years, as established
in Table 1a,
a. The entity shall be 30% compliant on the first day of the first calendar quarter 4 calendar
years following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
b. The entity shall be 60% compliant on the first day of the first calendar quarter following
8 calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 8 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 12
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 12
calendar years following Board of Trustees adoption.
Applicability:
This standard applies to the following functional entities:
•
Transmission Owners
•
Generator Owners
•
Distribution Providers
Draft 2: June 3, 2010
2
Implementation Plan for the Revised Definition of Protection System
Prerequisite Approvals or Activities:
The implementation of the revised definition is not dependent upon any other activity.
Recommended Modifications to Already Approved Standards
The non-capitalized version of the term, “protection system” is used in the following approved
standards:
•
NUC-001-2 – Nuclear Plant Interface Coordination
•
PER-005-1 – System Personnel Training
•
PRC-001-1 – System Protection Coordination
The term, “protection system” shall be capitalized where used in these standards when the
definition of “Protection System” is approved by applicable regulatory authorities.
Proposed Effective Date:
Each responsible entity (Distribution Provider that owns a transmission Protection System,
Transmission Owner, and Generator Owner) shall modify its protection system maintenance and
testing program description and basis document(s) (required in Requirement R1 of PRC-005-1 –
Transmission and Generation Protection System Maintenance and Testing) as necessary to
reflect the modified definition of ‘Protection System’ by the end of the first calendar quarter six
months following regulatory approvals and implement any additional maintenance and testing
(required in Requirement R2 of PRC-005-1 – Transmission and Generation Protection System
Maintenance and Testing) by the end of the first complete maintenance and testing cycle
described in the entity’s program description and basis document(s) following establishment of
the program changes resulting from the revised definition.
The original definition of “Protection System” shall be retired at the same time the revised
definition becomes effective.
Unofficial Comment Form for Proposed Definition of Protection System for
Project 2007-17
Please DO NOT use this form. Please use the electric comment form at the link below to
submit comments on the draft definition of “Protection System.” Comments must be
submitted by July 16, 2010. If you have questions please contact Al McMeekin at
[email protected] or by telephone at 803.530.1963.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Background Information:
The Protection System Maintenance and Testing Standard Drafting Team (PSMT SDT)
posted a proposed revision to the definition of the term, “Protection System” and proposed
revisions to PRC-005-2 — Protection System Maintenance for a 45-day public comment
period from July 24, 2009 through September 8, 2009. There were 55 sets of comments,
including comments from more than 130 different people from over 75 companies
representing all of the 10 Industry Segments, however less than 10 of these sets of
comments included any comments on the proposed modification to the term, “Protection
System.”
The drafting team posted a table that showed all the existing uses of the term, “Protection
System” in already approved standards, and concluded that the new definition of Protection
System (which clarifies that the dc Supply is part of a Protection System) remains
consistent with the existing uses. The non-capitalized version of the term, “protection
system” is used in the following approved standards:
•
NUC-001-2 — Nuclear Plant Interface Coordination
•
PER-005-1 — System Personnel Training
•
PRC-001-1 — System Protection Coordination
The proposed modifications address ambiguities the PSMT SDT identified within the existing
approved definition, and are important for the detailed use of the definition within the draft
PRC-005-2 standard.
When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the
drafting team and directed that work to close this reliability gap should be given “priority.”
In support of this direction, the PSMT SDT has separated its work in refining PRC-005-2
from its work in revising the definition of “Protection System.”
The drafting team initially proposed changes to the definition as shown below:
Protective relays, associated communication systems necessary for correct operation
of protective devices, voltage and current sensing inputs to protective relays devices,
station DC supply batteries, and DC control circuitry from the station DC supply
through the trip coil(s) of the circuit breakers or other interrupting devices.
Based on stakeholder comments, the drafting team made minor changes to the proposed
definition as shown below.
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Unofficial Comment Form — Proposed Definition of Protection System Project 2007-17
Protective relays, associated communication systems necessary for correct operation
of protective devicesfunctions, voltage and current sensing inputs to protective
relays and associated circuitry from the voltage and current sensing devices, station
dc supply, and DC control circuitry associated with protective functions from the
station dc supply through the trip coil(s) of the circuit breakers or other interrupting
devices.
The proposed definition of Protection System now reads as follows:
Protective relays, communication systems necessary for correct operation of
protective functions, voltage and current sensing inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station dc supply,
and control circuitry associated with protective functions from the station dc supply
through the trip coil(s) of the circuit breakers or other interrupting devices.
1. Do you believe the proposed definition of Protection System is ready for ballot? If not,
please explain why.
Yes
No
Comments:
2. Do you agree with the implementation plan for the revised definition of Protection
System? The implementation plan has two phases – the first phase gives entities at
least six months to update their protection system maintenance and testing program;
the second phase starts when the protection system maintenance and testing program
has been updated and requires implementation of any additional maintenance and
testing associated with the program changes by the end of the first complete
maintenance and testing cycle described in the entity’s revised program. If you disagree
with this implementation plan, please explain why.
Yes
No
Comments:
2
Unofficial Comment Form for 2nd Draft of the Standard for Protection
System Maintenance and Testing Project 2007-17
Please DO NOT use this form. Please use the electronic comment form at the link below to
submit comments on the 2nd draft of the PRC-005-2 standard for Protection System
Maintenance and Testing. Comments must be submitted by July 16, 2010. If you have
questions please contact Al McMeekin at [email protected] or by telephone at 803530-1963.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Background Information:
The Protection System Maintenance and Testing Standard Drafting Team (PSMT SDT) has
made substantial changes to the second posting of PRC-005-2 base on comments received
from the industry. The changes included:
•
Re-naming the standard from “Protection System Maintenance and Testing” to
“Protection System Maintenance”
•
Revisions to the standard and tables regarding the maintenance activities and
associated maintenance intervals
•
Revisions to the tables regarding condition-based and performance based
maintenance programs
•
Revisions to the Supplemental Reference and the FAQ documents
In addition, Violation Risk Factors (VRFs), Time Horizons, Measures, and Compliance
elements including Violation Security Levels (VSLs) have been supplied with this version of
the draft standard. The rationale for the team's assignments pertaining to the VRFs and
VSLs are posted in a separate document.
The PSMT SDT would like to receive industry comments on this standard.
1. The SDT has made significant changes to the minimum maintenance activities and
maximum allowable intervals within Tables 1a, 1b, and 1c, particularly related to station
dc supply and dc control circuits. Do you agree with these changes? If not, please
provide specific suggestions for improvement.
Yes
No
Comments:
2. The SDT has included VRFs and Time Horizons with this posting. Do you agree with the
assignments that have been made? If not, please provide specific suggestions for
improvement.
Yes
No
Comments:
3. The SDT has included Measures and Data Retention with this posting. Do you agree
with the assignments that have been made? If not, please provide specific suggestions
for improvement.
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Unofficial Comment Form — Protection System Maintenance and Testing Project 2007-17
Yes
No
Comments:
4. The SDT has included VSLs with this posting. Do you agree with the assignments that
have been made? If not, please provide specific suggestions for change.
Yes
No
Comments:
5. The SDT has revised the “Supplementary Reference” document which is supplied to
provide supporting discussion for the Requirements within the standard. Do you agree
with the changes? If not, please provide specific suggestions for change.
Yes
No
Comments:
6. The SDT has revised the “Frequently-Asked Questions” (FAQ) document which is
supplied to address anticipated questions relative to the standard. Do you agree with
these changes? If not, please provide specific suggestions for change.
Yes
No
Comments:
7. If you have any other comments on this Standard that you have not already provided in
response to the prior questions, please provide them here.
Comments:
2
NERC Protection System Maintenance Standard
PRC-005-2
FREQUENTLY ASKED QUESTIONS Practical Compliance and Implementation
April 16, 2010
Informative Annex to Standard PRC-005-2
Prepared by the
Protection System Maintenance and Testing Standard Drafting Team
Table of Contents
Table of Contents
Introduction .......................................................................................................................................................... 2
Executive Summary.............................................................................................................................................. 2
Terms Used in PRC-005-2 .................................................................................................................................... 2
Frequently Asked Questions ................................................................................................................................ 3
I
General FAQs: .......................................................................................................................................... 3
II
Group by Type of Protection System Component: ....................................................................................... 5
1.
All Protection System Components ............................................................................................................. 5
2.
Protective Relays ....................................................................................................................................... 5
3.
Voltage and Current Sensing Device Inputs to Protective Relays ................................................................ 8
4.
Protection System Control Circuitry ......................................................................................................... 10
5.
Station dc Supply ..................................................................................................................................... 12
6.
Protection System Communications Equipment ........................................................................................ 15
7.
UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power System............... 18
8.
SPS or Relay Sensing for Centralized UFLS or UVLS............................................................................... 18
III
Group by Type of BES Facility:................................................................................................................ 19
1.
All BES Facilities..................................................................................................................................... 19
2.
Generation .............................................................................................................................................. 20
3.
Transmission ........................................................................................................................................... 21
IV
Group by Type of Maintenance Program:................................................................................................. 21
1.
All Protection System Maintenance Programs .......................................................................................... 21
2.
Time-Based Protection System Maintenance (TBM) Programs ................................................................. 22
3.
Performance-Based Protection System Maintenance (PBM) Programs ..................................................... 24
V
Group by Monitoring Level:..................................................................................................................... 29
1.
All Monitoring Levels .............................................................................................................................. 29
2.
Level 1 Monitored Protection Systems (Unmonitored Protection Systems) ................................................ 39
3.
Level 2 Monitored Protection Systems (Partially Monitored Protection Systems) ...................................... 39
4.
Level 3 Monitored Protection Systems (Fully Monitored Protection Systems)............................................ 40
Appendix A — Protection System Maintenance Standard Drafting Team....................................................... 41
Index ................................................................................................................................................................... 42
Draft 2: April, 2010
Page i
PRC-005-2 Frequently-Asked Questions
Introduction
The following is a draft collection of questions and answers that the PSMT SDT believes could be helpful
to those implementing NERC Standard PRC-005-2 Protection System Maintenance. As the draft standard
proceeds through development, this FAQ document will be revised, including responses to key or frequent
comments from the posting process. The FAQ will be organized at a later time during the development of
the draft Standard.
This FAQ document will support both the Standard and the associated Technical Reference document.
Executive Summary
•
Write later if needed
Terms Used in PRC-005-2
Maintenance Correctable Issue – As indicated in footnote 2 of the draft standard, a maintenance
correctable issue is a failure of a device to operate within design parameters that can not be restored to
functional order by repair or calibration while performing the initial on-site maintenance activity, and that
requires follow-up corrective action.
Segment – As indicated in PRC-005-2 Attachment A Criteria for a Performance-Based Protection System
Maintenance Program, a segment is a “A grouping of Protection Systems or components of a particular
model or type from a single manufacturer, with other common factors such that consistent performance is
expected across the entire population of the segment, and shall only be defined for a population of 60 or
more individual components.”
Component – This equipment is first mentioned in Requirement 1.1 of this standard. A component is any
individual discrete piece of equipment included in a Protection System, such as a protective relay or current
sensing device. Types of components are listed in Table 1 (“Maximum Allowable Testing Intervals and
Maintenance Activities for Unmonitored Protection Systems”). For components such as dc circuits, the
designation of what constitutes a dc control circuit component is somewhat arbitrary and is very dependent
upon how an entity performs and tracks the testing of the dc circuitry. Some entities test their dc circuits on
a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus, entities are
allowed the latitude to designate their own definitions of “dc control circuit components.” Another example
of where the entity has some discretion on determining what constitutes a single component is the voltage
and current sensing devices, where the entity may choose either to designate a full three-phase set of such
devices or a single device as a single component.
Countable Event – As indicated in footnote 4 of PRC-005-2 Attachment A, Criteria for a Performancebased Protection System Maintenance Program, countable events include any failure of a component
requiring repair or replacement, any condition discovered during the verification activities in Table 1a
through Table 1c which requires corrective action, or a Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different from
specified settings, Protection System component configuration errors, or Protection System application
errors are not included in Countable Events.
Draft 2: April, 2010
Page 2
PRC-005-2 Frequently-Asked Questions
Frequently Asked Questions
I
General FAQs:
1. The standard seems very complicated, and is difficult to understand. Can it be simplified?
Because the standard is establishing parameters for condition-based Maintenance (R2) and
performance-based Maintenance (R3) in addition to simple time-based Maintenance, it does appear
to be complicated. At its simplest, an entity needs to follow R1 and R4 and perform ONLY timebased maintenance according to Table 1a, eliminating R2 and R3 from consideration altogether. If
an entity then wishes to take advantage of monitoring on its Protection System components, R2
comes into play, along with Tables 1b and 1c. If an entity wishes to use historical performance of
its Protection System components to perform performance-based Maintenance, R3 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
Draft 2: April, 2010
Page 3
PRC-005-2 Frequently-Asked Questions
Requirements
Flowchart
Start
PRC-005-2
Note: GO, DP, & TO
may use one or
multiple programs
Each GO, DP, & TO
shall establish a
maintenance
program [R1]
Performance
Based
Time Based
Decide if using Time Based, Condition
Baesd, and/or Performance Based
program
•
•
Condition Based
•
Ensure
components
have necessary
monitoring [R2]
Separate components
into appropriate
families of 60 or more
Maintain components
for each segment per
Table One until at
least 30 components
have been tested
Analyze data to
determine appropriate
interval for
segment(s)
[R3]
Perform maintenance
activities from Table One
for each segment with
interval from analysis
above and collect data for
future analysis
[R3, R4.4.2]
Maintain components
per Table One
Intervals and
Activities [R4.4.1]
•
Maintain
components per
Table One
Intervals and
Activities [R4.4.1]
•
•
Collect countable
events from
maintenance and
failures
Analyze data from
maintenance of last
30 components and/
or last year to verify
countable events
below 4%
Adjust maintenance
interval to keep
countable events
below 4%
[R3]
Implement
corrective
actions as
needed [R4]
End
Draft 2: April, 2010
Page 4
PRC-005-2 Frequently-Asked Questions
II
Group by Type of Protection System Component:
1. All Protection System Components
A.
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this standard?
No. As stated in R1, this standard covers protective relays that use measurements of voltage,
current and/or phase angle to determine anomalies and to trip a portion of the BES. Reclosers,
reclosing relays, closing circuits and auto-restoration schemes are used to cause devices to
close as opposed to electrical-measurement relays and their associated circuits that cause
circuit interruption from the BES; such closing devices and schemes are more appropriately
covered under other NERC Standards. There is one notable exception: if a Special Protection
System incorporates automatic closing of breakers, the related closing devices are part of the
SPS and must be tested accordingly.
B.
Why does PRC-005-2 not specifically require maintenance and testing procedures as
reflected in the previous standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2
requires a documented Maintenance program, and is focused on establishing Requirements
rather than prescribing methodology to meet those Requirements. Between the activities
identified in Tables 1a, 1b, and 1c, and the various components of the definition established
for a “Protection System Maintenance Program”, PRC-005-2 establishes the activities and
time-basis for a Protection System Maintenance Program to a level of detail not previously
required.
2. Protective Relays
A.
How do I approach testing when I have to upgrade firmware of a microprocessor relay?
The component “Upkeep” in the definition of a Protection System Maintenance Program,
addresses “Routine activities necessary to assure that the component remains in good working
order and implementation of any manufacturer’s hardware and software service advisories
which are relevant to the application of the device.” The Maintenance Activities specified in
Table 1a, Table 1b, and Table 1c do not present any requirements related to Upkeep for
Protective Relays. However, the entity should assure that the relay continues to function
properly after implementation of firmware changes.
B.
Please clarify what is meant by restoration in the definition of maintenance.
The component “Restoration” in the definition of a Protection System Maintenance Program,
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities
specified in Table 1a, Table 1b, and Table 1c do not present any requirements related to
Draft 2: April, 2010
Page 5
PRC-005-2 Frequently-Asked Questions
Restoration; R4.3 of the standard does require that the entity “initiate any necessary activities
to correct unresolved maintenance correctable issues”. Some examples of restoration (or
correction of maintenance-correctable issues) include, but are not limited to, replacement of
capacitors in distance relays to bring them to working order; replacement of relays, or other
Protection System components, to bring the Protection System to working order; upgrade of
electro-mechanical or solid-state protective relays to micro-processor based relays following
the discovery of failed components. Restoration, as used in this context is not to be confused
with Restoration rules as used in system operations. Maintenance activity necessarily includes
both the detection of problems and the repairs needed to eliminate those problems. This
standard does not identify all of the Protection System problems that must be detected and
eliminated, rather it is the intent of this standard that an entity determines the necessary
working order for their various devices and keeps them in working order. If an equipment item
is repaired or replaced then the entity can restart the maintenance-time-interval-clock if
desired, however the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements; in other words do not discard maintenance data that goes to verify your work
C.
If I upgrade my old relays then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced then the entity can restart the maintenanceactivity-time-interval-clock if desired, however the replacement of equipment does not remove
any documentation requirements. The requirements in the standard are intended to ensure that
an entity has a maintenance plan and that the entity adheres to minimum activities and
maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance cycles is intended to demonstrate compliance with the interval. Therefore, if you
upgrade or replace equipment then you still must maintain the documentation for the previous
equipment, thus demonstrating compliance with the time interval requirement prior to the
replacement action.
D.
What is meant by “Verify that settings are as specified” maintenance activity in tables 1a
and 1b?
Verification of settings is an activity directed mostly towards microprocessor based relays.
For relay maintenance departments that choose to test microprocessor based relays in the same
manner as electro-mechanical relays are tested, the testing process sometimes requires that
some specific functions be disabled. Later tests might enable the functions previously disabled
but perhaps still other functions or logic statements were then masked out. It is imperative that,
when the relay is placed into service, the settings in the relay be the settings that were intended
to be in that relay or as the Standard states “…settings are as specified.”
Many of the microprocessor based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement a simple recorded acknowledgement that
this was done is sufficient.
The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is simply to
check that the settings in the relay match the settings specified to those placed into the relay.
Draft 2: April, 2010
Page 6
PRC-005-2 Frequently-Asked Questions
E.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in tables 1a and 1b?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection, and thus the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
F.
I use my protective relays only as sources of metered quantities and breaker status for
SCADA and EMS through a substation distributed RTU or data concentrator to the
control center. What are the maintenance requirements for the relays?
This standard addresses only devices “that are applied on, or are designed to provide
protection for the BES.” Protective relays, providing only the functions mentioned in the
question, are not included.
G.
I use my protective relays for fault and disturbance recording, collecting oscillographic
records and event records via communications for fault analysis to meet NERC and
DME requirements. What are the maintenance requirements for the relays?
For relays used only as disturbance monitoring equipment, the NERC standard PRC-018-1 R3
& R6 states the maintenance requirements, and is being addressed by a Standards activity that
is revising PRC-002-1 and PRC-018-1. For protective relays “that are applied on, or are
designed to provide protection for the BES,” this standard applies, even if they also perform
DME functions.
H.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system rating
changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system uprates, upgrades and overall changes meet any and all other
requirements and standards then the requirements of PRC-005-2 are simple – if the Protection
system component performs a Protection system function then it must be maintained. If the
component no longer performs Protection System functions than it does not require
maintenance activities under the Tables of PRC-005-2. While many entities might physically
remove a component that is no longer needed there is no requirement in PRC-005-2 to remove
such component(s). Obviously, prudence would dictate that an “out-of-service” device is truly
made inactive. There are no record requirements listed in PRC-005-2 for Protection System
components not used.
I.
While performing relay testing of a protective device on our Bulk Electric System it was
discovered that the protective device being tested was either broken or out of calibration.
Does this satisfy the relay testing requirement even though the protective device tested
bad, and may be unable to be placed back into service?
Yes, PRC-005-2 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-2
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requirement although the protective device may be unable to be returned to service under
normal calibration adjustments. R4.3 states (the entity must):
The entity must assure either that the components are within acceptable parameters at the
conclusion of the maintenance activities or initiate any necessary activities to correct
unresolved maintenance correctable issues.
J.
If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R4.3) (in essence) state that the entity assure the
components are within the owner’s acceptable operating parameters, if not then actions must
be initiated to correct the deviance. The type of corrective activity is not stated; however it
could include repairs or replacements. Documentation is always a necessity (“If it is not
documented then it wasn’t done!”)
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
K.
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
3. Voltage and Current Sensing Device Inputs to Protective Relays
A.
What is meant by “…verify the current and voltage circuit inputs from the voltage and
current sensing devices to the protective relays …” Do we need to perform ratio,
polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current sensing devices (typically voltage and current transformers). This can be as
difficult as is proposed by the question (with additional testing on the cabling and substation
wiring to ensure that the values arrive at the relays); or simplicity can be achieved by other
verification methods. While some examples follow, these are not intended to represent an allinclusive list; technology advances and ingenuity should not be excluded from making
comparisons and verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional testing on the
panel wiring to ensure that the values arrive at those relays) with the other phases, and verify
that residual currents are within expected bounds
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•
Observe all three phase currents and the residual current at the relay panel with an oscilloscope,
observing comparable magnitudes and proper phase relationship, with additional testing on the
panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay (such as, but not limited to, a query
to the microprocessor relay), to another protective relay monitoring the same line, with currents
supplied by different CT’s.
•
Compare the secondary values, at the relay with values measured by test instruments (such as,
but not limited to multi-meters, voltmeter, clamp-on ammeters, etc) and verified by calculations
and known ratios to be the values expected. For example a single PT on a 100KV bus will have
a specific secondary value that when multiplied by the PT ratio arrives at the expected bus
value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned relay,
compare those SCADA values to the values as determined by the questioned relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by the
questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that, an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring systems.
B.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral currents, or
3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities may be also verified by use of oscillographic records for connected
microprocessor relays as recorded during system disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known fault locations.
C.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify
the insulation of the wiring between the instrument transformer and the relay.
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D.
My plant generator and transformer relays are electromechanical and do not have
metering functions as do microprocessor based relays. In order for me to compare the
instrument transformer inputs to these relays to the secondary values of other metered
instrument transformers monitoring the same primary voltage and current signals, it
would be necessary to temporarily connect test equipment like voltmeters and clamp on
ammeters to measure the input signals to the relays. This practice seems very risky and
a plant trip could result if the technician were to make an error while measuring these
current and voltage signals. How can I avoid this risk? Also, what if no other
instrument transformers are available which monitor the same primary voltage or
current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests
to adequately “verify the current and voltage circuit inputs from the voltage and current
sensing devices to the protective relays …” while eliminating the risk of tripping an in service
generator or transformer. Similarly, this same offline test methodology can be used to verify
the relay input voltage and current signals to relays when there are no other instrument
transformers monitoring available for purposes of signal comparison.
4. Protection System Control Circuitry
A.
Is it permissible to verify circuit breaker tripping at a different time (and interval) than
when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual components’
maximum allowable testing intervals.
B.
The Protection System Maintenance Standard describes requirements for verifying the
tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC-005-2 are intended to verify the integrity of tripping circuits, including
the breaker trip coil, as well as the presence of auxiliary supply (usually a dc battery) for
energizing the trip coil if a protection function operates. Beyond this, PRC-005-2 sets no
requirements for verifying circuit breaker performance, or for maintenance of the circuit
breaker.
C.
How do I test each dc Control Circuit path, as established for level 2 (partially monitored
protection systems) monitoring of a “Protection System Control Circuitry (Trip coils and
auxiliary relays)”?
Table 1b specifies that each breaker trip coil, auxiliary relay, and lockout relay must
be operated within the specified time period. The required operations may be via
targeted maintenance activities, or by documented operation of these devices for other
purposes such as fault clearing.
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D.
What does this standard require for testing an Auxiliary Tripping Relay?
Table 1 requires that the trip test must verify that the auxiliary tripping relay(s) and/or lockout
relay(s) operate(s) electrically and that their trip output(s) perform as expected. Auxiliary
outputs not in a trip path (i.e. alarming or DME input) are not required to be checked.
E.
What does a functional trip test include?
An operational trip test must be performed on each portion of a trip circuit. Each control
circuit path that produces a trip signal must be verified; this includes trip coils, auxiliary
tripping relays, lockout relays, and communications-assisted-trip schemes.
A trip test may be an overall test that verifies the operation of the entire trip scheme at once, or
it may be several tests of the various portions that make up the entire trip path, provided that
testing of the various portions of the trip scheme verifies all of the portions, including parallel
paths, and overlaps those portions.
A circuit breaker or other interrupting device needs to be trip tested at least once per trip coil..
Discrete-component auxiliary relays and lock-out relays must be verified by trip test. The trip
test must verify that the auxiliary or lock-out relay operates electrically and that the relay’s trip
output(s) change(s) state. Software latches or control algorithms, including trip logic
processing implemented as programming component such as a microprocessor relay that take
the place of (conventional) discrete component auxiliary relays or lock-out relays do not have
to be routinely trip tested.
Normally-closed auxiliary contacts from other devices (for example, switchyard-voltage-level
disconnect switches, interlock switches, or pressure switches) which are in the breaker trip
path do not need to be tested.
F.
Is a Sudden Pressure Relay an Auxiliary Tripping Relay?
No. IEEE C37.2-2008 assigns the device number 94 to auxiliary tripping relays. Sudden
pressure relays are assigned device number 63, and is excluded from the Standard by footnote
1.
G.
The standard specifically mentions Auxiliary and Lock-out relays; what is an Auxiliary
Tripping Relay?
An auxiliary relay, IEEE Device Number 94, is described in IEEE Standard C37.2-2008 as “A
device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate
tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should
open automatically, even though its closing circuit is maintained closed.”
H.
What is a Lock-out Relay?
A lock-out relay, IEEE Device Number 86, is described in IEEE Standard C37.2 as “A device
that trips and maintains the associated equipment or devices inoperative until it is reset by an
operator, either locally or remotely.”
I.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
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You must conduct a test(s) to verify the integrity of the trip circuit. This standard does not
cover circuit breaker maintenance or transformer maintenance. The standard also does not
cover testing of devices such as sudden pressure relays (63), temperature relays (49), and other
relays which respond to mechanical parameters rather than electrical parameters.
5. Station dc Supply
A.
What constitutes the station dc supply as mentioned in the definition of Protective
System?
The station direct current (dc) supply normally consists of two components: the battery
charger and the station battery itself. There are also emerging technologies that provide a
source of dc supply that does not include either a battery or charger.
Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1.
Emerging Technologies - Station dc supplies are currently being developed that use other
energy storage technologies beside the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1 presents maintenance activities and maximum allowable testing
intervals for these new station dc supply technologies. However, because these technologies
are relatively new the maintenance activities for these station dc supplies may change over
time.
B.
In the Maintenance Activities for station dc supply in Table 1, what do you mean by
“continuity”?
Because the Standard pertains to maintenance not only of the station battery, but also the
whole station dc supply, continuity checks of the station dc supply are required. “Continuity”
as used in Table 1 refers to verifying that there is a continuous current path from the positive
terminal of the station battery set to the negative terminal, otherwise there is no way of
determining that a station battery is available to supply dc current to the station.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path the battery set will not be
available for service.
C.
Why is it necessary to verify the continuity of the dc supply?
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In the event of the loss of the ac source or battery charger, the battery must be capable of
supplying dc current, both for continuous dc loads and for tripping breakers and switches.
Without continuity, the battery cannot perform this function.
If the battery charger is not sized to handle the maximum dc current required to operate the
protective systems, it is sized only to handle the constant dc load of the station and the
charging current required to bring the battery back to full charge following a discharge. At
those stations, the battery charger would not be able to trip breakers and switches if the battery
experiences loss of continuity.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
◊
◊
D.
Many battery chargers produce harmonics which can cause failure of dc power supplies in
microprocessor based protective relays and other electronic devices connected to station
dc supply. In these cases, the substation battery serves as a filter for these harmonics.
With the loss of continuity in the battery, the filter provided by the battery is no longer
present.
Loss of electrical continuity of the station battery will cause, regardless of the battery
charger’s output current capability, a delayed response in full output current from the
charger. Almost all chargers have an intentional 1 to 2 second delay to switch from a low
substation dc load current to the maximum output of the charger. This delay would cause
the opening of circuit breakers to be delayed which could violate system performance
standards.
How do you verify continuity of the dc supply?
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery unless the battery charger is taken out of service. At that time
a break in the continuity of the station battery current path will be revealed because there will
be no voltage on the substation dc circuitry.
Although the Standard prescribes what must be done during the maintenance activity it does
not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery.
◊
◊
◊
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path through
the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of the
various dc-supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor based battery chargers have developed methods for their
equipment to periodically (or continuously) test for battery continuity. For example, one
manufacturer periodically reduces the float voltage on the battery until current from the
battery to the dc load can be measured to confirm continuity.
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No matter how the electrical continuity of a battery set is verified it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1 to insure that the station
dc supply will provide the required current to the Protection System at all times.
E.
When should I check the station batteries to see if they have sufficient energy to perform
as designed?
The answer to this question depends on the type of battery (valve regulated lead-acid, vented
lead acid, or nickel-cadmium), the maintenance activity chosen, and the type of time based
monitoring level selected.
For example, if you have a Valve Regulated Lead-Acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every three months.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every 3 calendar years.
F.
Why in Table 1 are there two Maintenance Activities with different Maximum
Maintenance Intervals listed to verify that the station battery can perform as designed?
The two acceptable methods for proving that a station battery can perform as designed are
based on two different philosophies. The first activity requires a capacity discharge test of the
entire battery set to verify that degradation of one or several components (cells) in the set has
not deteriorated to a point where the total capacity of the battery system falls below its
designed rating. The second maintenance activity requires tests and evaluation of the internal
ohmic measurements on each of the individual cells/units of the battery set to determine that
each component can perform as designed and therefore the entire battery set can be verified to
perform as designed.
The maximum maintenance interval for discharge capacity testing is longer than the interval
for testing and evaluation of internal ohmic cell measurements. An individual component of a
battery set may degrade to an unacceptable level without causing the total battery set to fall
below its designed rating under capacity testing. However, since the philosophy behind
internal ohmic measurement evaluation is based on the fact that each battery component must
be verified to be able to perform as designed, the interval for verification by this maintenance
activity must be shorter to catch individual cell/unit degradation.
G.
What is the justification for having two different Maintenance Activities listed in Table 1
to verify that the station battery can perform as designed?
IEEE Standards 450, 1188, and 1106 for vented lead-acid, valve-regulated lead-acid (VRLA),
and nickel-cadmium batteries, respectively (which together are the most commonly used
substation batteries on the BES) go into great detail about capacity testing of the entire battery
set to determine that a battery can perform as designed.
The first maintenance activity listed in Table 1 for verifying that a station battery can perform
as designed uses maximum maintenance intervals for capacity testing that were designed to
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PRC-005-2 Frequently-Asked Questions
align with the IEEE battery standards. This maintenance activity is applicable for vented leadacid, valve-regulated lead-acid, and nickel-cadmium batteries.
The second maintenance activity listed in Table 1 for verifying that a station battery can
perform as designed uses maximum maintenance intervals for evaluating internal ohmic
measurements in relation to their baseline measurements that are based on industry experience,
EPRI technical reports and application guides, and the IEEE battery standards. By evaluating
the internal ohmic measurements for each cell and comparing that measurement to the cell’s
baseline ohmic measurement (taken at the time of the battery set’s acceptance capacity test),
low-capacity cells can be identified and eliminated to keep the battery set capable of
performing as designed. This maintenance activity is applicable only for vented lead-acid and
VRLA batteries.
H.
Why in Table 1 of PRC-005-2 is there a maintenance activity to inspect the structural
intergrity of the battery rack?
The three IEEE standards (1188, 450, and 1106) for VRLA, vented lead-acid, and nickelcadmium batteries all recommend that as part of any battery inspection the battery rack should
be inspected. The purpose of this inspection is to verify that the battery rack is correctly
installed and has no deterioration that could weaken its structural integrity. Because the
battery rack is specifically designed for the battery that is mounted on it, weakening of its
structural members by rust or corrosion can physically jeopardize the battery.
I.
What is required to comply with the “Unintentional Grounds” requirement?
In most cases, the first ground that appears on a battery pole is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on unintentional DC grounds. The standard merely requires that a check be made for
the existence of Unintentional DC Grounds. Obviously a “check-off” of some sort will have to
be devised to demonstrate that a check is routinely done for Unintentional DC Grounds.
J.
Where the standard refers to “all cells” is it sufficient to have a documentation method
that refers to “all cells” or do we need to have separate documentation for every cell? For
example to I need 60 individual documented check-offs for good electrolyte level or
would a single check-off per bank be sufficient??
A single check-off per battery bank is sufficient.
K.
Does this standard refer to Station batteries or all batteries, for example Communication
Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communication sites. The batteries covered under PRC-005-2 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System.
6. Protection System Communications Equipment
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A.
What are some examples of mechanisms to check communications equipment
functioning?
For Level 1 unmonitored Protection Systems, various types of communications systems will
have different facilities for on-site integrity checking to be performed at least every three
months during a substation visit. Some examples are:
◊ On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier checkback test from one terminal.
◊ Systems which use frequency-shift communications with a continuous guard signal (over a
telephone circuit, analog microwave system, etc.) can be checked by observing a loss-ofguard indication or alarm. For frequency-shift power line power-line carrier systems, the
guard signal level meter can also be checked.
◊ Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
◊ Digital communications systems have some sort of data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For Level 2 partially monitored Protection Systems, various types of communications systems
will have different facilities for monitoring the presence of the communications channel, and
activating alarms that can be monitored remotely. Some examples are:
◊ On-off power-line carrier systems can be shown to be operational by automated periodic
power-line carrier checkback tests, with remote alarming of failures.
◊ Systems which use a frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be remotely monitored with a lossof-guard alarm or low signal level alarm.
◊ Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
◊ Digital communications systems can activate remotely monitored alarms for data reception
loss or data error indications.
For Level 3 fully monitored Protection Systems, the communications system must monitor all
aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
◊ In many communications systems signal quality measurements including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio, propagation
delay, and data error rates are compared to alarm limits. These alarms are connected for
remote monitoring.
◊ Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment location
is continuously being reflected at the remote monitoring site.
B.
What is needed for the 3-month inspection of communication-assisted trip scheme
equipment?
The 3-month inspection applies to Level 1 (Unmonitored) equipment. An example of
compliance with this requirement might be, but is not limited to:
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With each site visit, check that the equipment is free from alarms, check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (ie FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard.
C.
Does a fiber optic I/O scheme used for breaker tripping or control within a station, for
example - transmitting a trip signal or control logic between the control house and the
breaker control cabinet, constitute a communication system?
This equipment is presently classified as being part of the Protection System Control Circuitry
and tested per the portions of Table 1 applicable to Protection System Control Circuitry rather
than those portions of the table applicable to communication equipment.
D.
In Table 1b, the Maintenance Activities section of the Protective System
Communications Equipment and Channels refers to the quality of the channel meeting
“performance criteria”. What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating
normally an alarm will be indicated. For Level 1 systems this alarm will probably be on the
panel. For Level 2 and Level 3 systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each protective system
communications channel that is consistent with proper functioning of the Protection System.
If that level of nominal performance is not being met, the system will go into alarm.
Following are some examples of protective system communications channel performance
criteria:
◊ For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system is
calibrated and if the signal level drops below an established level, the system will indicate
an alarm.
◊ An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use checkback testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes this
signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full power
and reduced power tests are typically run. Power levels for these tests are determined at the
time of calibration.
◊ Pilot wire relay systems use a hardwire communications circuit to communicate between
the local and remote ends of the protective zone. This circuit is monitored by circulating a
dc current between the relay systems. A typical level may be 1 mA. If the level drops
below the setting of the alarm monitor, the system will indicate an alarm.
◊ Modern digital relay systems use data communications to transmit relay information to the
remote end relays. An example of this is a line current differential scheme commonly used
on transmission lines. The protective relays communicate current magnitude and phase
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PRC-005-2 Frequently-Asked Questions
information over the communications path to determine if the fault is located in the
protective zone. Quantities such as digital packet loss, bit error rate and channel delay are
monitored to determine the quality of the channel. These limits are determined and set
during relay commissioning. Once set, any channel quality problems that fall outside the
set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be - it
just requires that the entity establish nominal criteria so protective system channel monitoring
can be performed.
7. UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power
System
A.
We have an Under Voltage Load Shedding (UVLS) system in place that prevents one of
our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation as stated indicates that the tripping action was intended to prevent low
distribution voltage for a transmission system that was intact except for the line that was out of
service.
This Standard is not applicable to this UVLS.
B.
We have a UFLS scheme that sheds the necessary load through distribution-side circuit
breakers and circuit reclosers. Do the trip-test requirements for circuit breakers apply to
our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential Lock-Out Relay. While many failures of
these distribution breakers could add up to be significant, it is also believed that distribution
breakers are operated often on just fault clearing duty and therefore the distribution circuit
breakers are operated at least as frequently as any requirements that might have appeared in
this standard.
C.
What does “distributed over the power system” mean?
This refers to the common practice of applying UFLS on the distribution system, with each
UFLS individually tripping a relatively low value of load. Therefore, the program is
implemented via a large number of individual UFLS components performing independently,
and the failure of any individual component to perform properly will have a minimal impact
on the effectiveness of the overall UFLS program. Some UVLS systems are applied similarly.
8. SPS or Relay Sensing for Centralized UFLS or UVLS
A.
Do I have to perform a full end-to-end test of a Special Protection System?
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PRC-005-2 Frequently-Asked Questions
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end-to-end test.
B.
What about SPS interfaces between different entities or owners?
All SPS owners should have maintenance agreements that state which owner will perform
specific tasks. SPS segments can be tested individually, but must overlap.
C.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
Any Phasor Measurement Unit (PMU) function whose output is used in a protection system or
Special Protection System (as opposed to a monitoring task) must be verified as a component
in a Protection System.
D.
How do I maintain a Special Protection System or Relay Sensing for Centralized UFLS
or UVLS Systems?
Components of the SPS, UFLS, or UVLS should be maintained like similar components used
for other Protection System functions.
The output action verification may be breaker tripping, or other control action that must be
verified, but may be verified in overlapping segments. A grouped output control action need
be verified only once within the specified time interval, but all of the SPS, UFLS, or UVLS
components whose operation leads to that control action must each be verified.
E.
What does “centralized” mean?
This refers to the practice of applying sensing units at many locations over the system, with all
these components providing intelligence to an analytical system which then directs action to
address a detected condition. In some cases, this action may not take place at the same
location as the sensing units. This approach is often applied for complex SPS, and may be
used for UVLS where necessary to address the conditions of concern.
III
Group by Type of BES Facility:
1. All BES Facilities
A.
What, exactly, is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms
Used in Reliability Standards, and is not being modified within this draft Standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving
only load with one transmission source are generally not included in this definition.
Each Regional Entity implements a definition of the Bulk Electric System that is based on this
NERC definition, in some cases, supplemented by additional criteria. These regional
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PRC-005-2 Frequently-Asked Questions
definitions have been documented and provided to FERC as part of a June 16, 2007
Informational Filing.
2. Generation
A.
Please provide a sample list of devices or systems that must be verified in a generator,
generator step-up transformer, and generator connected station auxiliary transformer to
meet the requirements of this Maintenance Standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay may include but are not necessarily limited to:
• Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
• Loss-of-field relays
• Volts-per-hertz relays
• Negative sequence overcurrent relays
• Over voltage and under voltage protection relays
• Stator-ground relays
• Communications-based protection systems such as transfer-trip systems
• Generator differential relays
• Reverse power relays
• Frequency relays
• Out-of-step relays
• Inadvertent energization protection
• Breaker failure protection
For generator step up or generator-connected station auxiliary transformers, operation of any
the following associated protective relays frequently would result in a trip of the generating unit
and, as such, would be included in the program:
• Transformer differential relays
• Neutral overcurrent relay
• Phase overcurrent relays
A loss of a system-connected station auxiliary transformer could result in a loss of the
generating plant if the plant was being provided with auxiliary power from that source, and this
auxiliary transformer may directly affect the ability to start up the plant and to connect the plant
to the system. Thus, operation of any of the following relays associated with system-connected
station auxiliary transformers would be included in the program:
• Transformer differential relays
• Neutral overcurrent relay
• Phase overcurrent relays
Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program even if the loss of the those loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
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PRC-005-2 Frequently-Asked Questions
this program even if a trip of these devices might eventually result in a trip of the generating
unit.
3. Transmission
A.
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having relevant
facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
IV
Group by Type of Maintenance Program:
1. All Protection System Maintenance Programs
A. I can’t figure out how to demonstrate compliance with the requirements for level 3 (fully
monitored) Protection Systems. Why does this Maintenance Standard describe a
maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for level 3 (fully monitored) Protection
Systems is likely to be very involved, and may include detailed manufacturer documentation of
complete internal monitoring within a device, comprehensive design drawing reviews, and
other detailed documentation. This Standard does not presume to specify what documentation
must be developed; only that it must be comprehensive.
There may actually be some equipment available that is capable of meeting level-3 monitoring
criteria, in which case it may be maintained according to Table 1c. However, even if there is
no equipment available today that can meet this level of monitoring, the Standard establishes
the necessary requirements for when such equipment becomes available.
By creating a roadmap for development, this provision makes the Standard technology-neutral.
The standard drafting team wants to avoid the need to revise the Standard in a few years to
accommodate technology advances that are certainly coming to the industry.
B. What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the Requirement being documented, include but
are not limited to:
•
•
•
•
•
•
•
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database screen shots that demonstrate compliance information
Diagrams, engineering prints, schematics, maintenance and testing records, etc.
Logs (operator, substation, and other types of log)
Inspection forms
U.S. or Canadian mail, memos, or email proving the required information was exchanged,
coordinated, submitted or received
• Database lists and records
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PRC-005-2 Frequently-Asked Questions
• Check-off forms (paper or electronic)
• Any record that demonstrates that the maintenance activity was known and accounted for.
C. If I replace a failed Protection System component with another component, what testing
do I need to perform on the new component?
The replacement component must be tested to a degree that assures that it will perform as
intended. If it is desired to reset the Table 1 maintenance interval for the replacement
component, all relevant Table 1 activities for the component should be performed.
D. Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records to
demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electro-mechanical protective relays be
tested, for routine scheduled tests, every 3 calendar years with a maximum allowed grace
period of an additional 18 months. This entity would be required to maintain its records of
maintenance of its last two routine scheduled tests. Thus its test records would have a latest
routine test as well as its previous routine test. The interval between tests is therefore provable
to an auditor as being within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to have three test results proving two time intervals, but rather have two test
results proving the last interval. The drafting team contends that this minimizes storage
requirements while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance Based Maintenance then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
2. Time-Based Protection System Maintenance (TBM) Programs
A. What does this Maintenance Standard say about commissioning? Is it necessary to have
documentation in your maintenance history of the completion of commission testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified on Table 1a of PRC-005-2, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation and need not be re-verified
within an ongoing maintenance program. Example – it is not necessary to re-verify correct
terminal strip wiring on an ongoing basis.
PRC-005-2 assumes that thorough commission testing was performed prior to a protection
system being placed in service. PRC-005-2 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
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PRC-005-2 Frequently-Asked Questions
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content
and therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
An entity would be wise to retain commissioning records to show a maintenance start date. (See
next FAQ).
B. How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a facility and its associated
Protection System were placed in service. Alternatively, an entity may choose to use the date
of completion of the commission testing of the Protection System component as the starting
point in determining its first maintenance due dates. Whichever method is chosen, for newly
installed Protection Systems the maintenance program should clearly identify when
maintenance is first due.
C. The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled outage
following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals.
D. If I am unable to complete the maintenance as required due to a major natural disaster
(hurricane, earthquake, etc), how will this affect my compliance with this standard.
The NERC Sanction Guidelines provides that the Compliance Monitor will consider
extenuating circumstances when considering any sanctions. 1
E. What if my observed testing results show a high incidence of out-of-tolerance relays, or,
even worse, I am experiencing numerous relay misoperations due to the relays being outof-tolerance?
Any entity can choose to test some or all of their Protection System more frequently (or, to
express it differently, exceed the minimum requirements of the Standard). Particularly, if you
find that the maximum intervals in the Standard do not achieve your expected level of
performance, it is understandable that you would maintain the related equipment more
frequently.
F. We believe that the 3-month interval between inspections is unneccessary, why can we not
perform these inspections twice per year?
The standard drafting team believes that routine monthly inspections are the norm. To align
routine station inspections with other important inspections the 3-month interval was chosen. In
1 Sanction Guidelines of the North American Electric Reliability Corporation. Effective January 15, 2008.
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PRC-005-2 Frequently-Asked Questions
lieu of station visits many activities can be accomplished with automated monitoring and
alarming.
G. Our maintenance plan calls for us to perform routine protective relay tests every 3 years;
if we are unable to achieve this schedule but we are able to complete the procedures in less
than the Maximum Time Interval then are we in or out of compliance?
You are out of compliance. You must maintain your equipment to your stated intervals within
your maintenance plan. The protective relays (and any Protection System component) cannot
be tested at intervals that are longer than the maximum allowable interval stated in the Tables.
Therefore you should design your maintenance plan such that it is not in conflict with the
Minimum Activities and the Maximum Intervals. You then must maintain your equipment
according to your maintenance plan.
3. Performance-Based Protection System Maintenance (PBM) Programs
A. I’m a small entity and cannot aggregate a population of Protection System components to
establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of
individual Protection System components to create a segment that crosses ownership
boundaries. All entities participating in a joint program should have a single documented joint
management process, with consistent Protection System Maintenance Programs (practices,
maintenance intervals and criteria), for which the multiple owners are individually responsible
with respect to the requirements of the Standard. The requirements established for
performance-based maintenance must be met for the overall aggregated program on an ongoing
basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power-plant
vs. substation, and weather conditions.
B. Can an owner go straight to a performance-based maintenance program schedule, if they
have previously gathered records?
Yes. An owner can go to a performance-based maintenance program immediately. The owner
will need to comply with the requirements of a performance-based maintenance program as
listed in the standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they can not prove that they have collected the data as required
for a performance-based maintenance program then they will need to wait until they can prove
compliance.
C. When establishing a performance-based maintenance program, can I use test data from
the device manufacturer, or industry survey results, as results to help establish a basis for
my performance-based intervals?
No. You must use actual in-service test data for the components in the segment.
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PRC-005-2 Frequently-Asked Questions
D. What types of misoperations or events are not considered countable events in the
performance-based Protection System Maintenance (PBM) Program?
Countable events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned.
Human errors resulting in Protection System Misoperations during system installation or
maintenance activities are not considered countable events. Examples of excluded human
errors include relay setting errors, design errors, wiring errors, inadvertent tripping of devices
during testing or installation, and misapplication of Protection System components. Examples
of misapplication of Protection System components include wrong CT or PT tap position,
protective relay function misapplication, and components not specified correctly for their
installation.
Certain types of Protection System component errors that cause Misoperations are not
considered countable events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
E. What are some examples of methods of correcting segment perfomance for PerformanceBased Maintenance?
There are a number of methods that may be useful for correcting segment performance for malperforming segments in a performance-based maintenance system. Some examples are listed
below.
•
The maximum allowable interval, as established by the performance-based maintenance
system, can be decreased. This may, however, be slow to correct the performance of the
segment.
•
Identifiable sub-groups of components within the established segment, which have been
identified to be the mal-performing portion of the segment, can be broken out as an
independent segment for target action. Each resulting segment must satisfy the minimum
population requirements for a performance-based maintenance program in order to remain
within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
Components within the mal-performing segment can be replaced with other components
(electromechanical distance relays with microprocessor relays, for example) to remove the
mal-performing segment.
F. If I find (and correct) a maintenance-correctable issue as a result of a misoperation
investigation (Re: PRC-004), how does this affect my performance-based maintenance
program?
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC-004 required misoperation investigation/corrective action), the actions performed
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PRC-005-2 Frequently-Asked Questions
count as a maintenance activity, and “reset the clock” on everything you’ve done. In a
performance-based maintenance program, you also need to record the maintenance-correctable
issue with the relevant component group and use it in the analysis to determine your correct
performance-based maintenance interval for that component group.
G. Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation from
the factory to the job site, length of time before a charge is put on the battery, the method of
installation, the voltage level and duration of equalize charges, the float voltage level used, and
the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a performance-based Protection System Maintenance
(PBM) program. These inherent variances in the aging process of a battery cell make
establishment of a designated segment based on manufacturer and type of battery impossible.
The whole point of PBM is that if all variables are isolated then common aging and
performance criteria would be the same. However, there are too many variables in the electrochemical process to completely isolate all of the performance-changing criteria.
Similarly Functional Entities that want to establish a condition-based maintenance program
using Level 3 monitoring of the battery used in a station dc supply can not do so. Inspection of
the battery is required on a Maximum Maintenance Interval listed in the tables due to the aging
processes of station batteries. However, Level 3 monitoring of a battery can eliminate the
requirement for periodic testing and some inspections (see Level 3 Monitoring Attributes for
Component of table 1c).
H. Please provide an example of the calculations involved in extending maintenance time
intervals using PBM.
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
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PRC-005-2 Frequently-Asked Questions
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30.
•
For the sake of example only the following will show 6 failures per year, reality may
well have different numbers of failures every year. PBM requires annual assessment of
failures found per units tested.
After the first year of tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure
rate.
•
This entity is now allowed to extend the maintenance interval if they choose.
The entity chooses to extend the maintenance interval of this population segment out to 10
years.
•
This represents a rate of 100 units tested per year; entity selects 100 units to be tested in
the following year.
•
After that year of testing these 100 units the entity again finds 6 failed units. 6/100= 6%
failures.
•
This entity has now exceeded the acceptable failure rate for these devices and must
accelerate testing of all of the units at a higher rate such that the failure rate is found to
be less than 4% per year; the entity has three years to get this failure rate down to 4%
or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 8 years. This
means that they will now test 125 units per year (1000/8). The entity has just two years left to
get the test rate corrected.
•
After a year they again find 6 failures out of the 125 units tested. 6/125= 5% failures.
In response to the 5% failure rate, the entity decreases the testing interval to 7 years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to get
the test rate corrected.
•
After a year they again find 6 failures out of the 143 units tested. 6/143= 4.2% failures.
(Note that the entity has tried 5 years and they were under the 4% limit and they tried 7 years
and they were over the 4% limit. They must be back at 4% failures or less in the next year so
they might simply elect to go back to 5 years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to 6 years.
This means that they will now test 167 units per year (1000/6).
•
After a year they again find 6 failures out of the 167 units tested. 6/167= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 6 years or less. Entity chose 6 year interval and effectively
extended their TBM (5 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; this is there to prevent an
entity from “gaming the system”. An entity might arbitrarily extend time intervals from 6 years
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PRC-005-2 Frequently-Asked Questions
to 20 years. In the event that an entity finds a failure rate greater than 4% then the test rate must
be accelerated such that within three years the failure rate must be brought back down to 4% or
less.
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PRC-005-2 Frequently-Asked Questions
Here is a table that demonstrates the values discussed:
Year #
Total
Population
Test
Interval
Units to be
Tested
(P)
(I)
(U= P/I)
# of
Failures
Found
Failure
Rate
Decision
to Change
Interval
Interval
Chosen
(=F/U)
(F)
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
V
Group by Monitoring Level:
1. All Monitoring Levels
A.
Please provide an example of the level 1 monitored (unmonitored) versus other levels of
monitoring available?
A level 1 (Unmonitored) Protection System has no monitoring and alarm circuits on the
Protection System components.
A level 2 (Partially) monitored Protection System or an individual component of a level 2
(Partially) monitored Protection System has monitoring and alarm circuits on the Protection
System components. The alarm circuits must alert a 24-hr staffed operations center.
There can be a combination of monitored and unmonitored Protection Systems within any
given substation or plant; there can also be a combination of monitored and unmonitored
components within any given Protection System.
Example #1: A combination of level 2 (Partially) monitored and level 1 (unmonitored)
components within a given Protection System is:
◊
◊
◊
◊
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center. (level 2)
Instrumentation transformers, with no monitoring, connected as inputs to that relay. (level
1)
A vented lead-acid battery with low voltage alarm connected to SCADA. (level 2)
A circuit breaker with a trip coil, with no monitor circuit. (level 1)
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PRC-005-2 Frequently-Asked Questions
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum test
intervals of:
◊
◊
◊
◊
The microprocessor relay is verified every 12 calendar years.
The instrumentation transformers are verified every 12 calendar years.
The battery is verified every 6 calendar years by performing a performance capacity test of
the entire battery bank or by evaluating the measured cell/unit internal ohmic values to
station battery baseline every 18 months.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
Example #2: A combination of level 2 (partially) monitored and level 1 (unmonitored)
components within a given Protection System is:
◊
◊
◊
◊
A microprocessor relay with integral alarm that is not connected to SCADA. (level 1)
Instrument transformers, with no monitoring, connected as inputs to that relay. (level 1)
A vented lead-acid battery with low voltage alarm connected to SCADA. (level 2)
A circuit breaker with a trip coil, with no circuits monitored. (level 1)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum test
intervals of:
◊
◊
◊
◊
The microprocessor relay is verified every 6 calendar years.
The instrumentation transformers are verified every 12 calendar years.
The battery is verified every 6 calendar years by performing a performance capacity test of
the entire battery bank or by evaluating the measured cell/unit internal ohmic values to
station battery baseline every 18 months.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
Example #3: A combination of level 2 (partially) monitored and level 1 (unmonitored)
components within a given Protection System is:
◊
◊
◊
◊
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed operations
center. (level 2)
Instrument transformers, with no monitoring, connected as inputs to that relay (level 1)
Battery without any alarms connected to SCADA (level 1)
Circuit breaker with a trip coil, with no circuits monitored (level 1)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components shall have
maximum test intervals of:
◊ The microprocessor relay is verified every 12 calendar years.
◊ The instrument transformers are verified every 12 calendar years.
◊ The battery is verified every 3 months, every 18 months, plus, depending upon the type of
battery used it may be verified at other maximum test intervals, as well.
◊ The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
B.
What is the intent behind the different levels of monitoring?
The intent behind different levels of monitoring is to allow less frequent manual intervention
when more information is known about the condition of Protection System components.
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PRC-005-2 Frequently-Asked Questions
C.
Do all monitoring levels apply to all components in a protection system?
No. For some components in a protection system, certain levels of monitoring will not be
relevant. See table below:
D.
My microprocessor relays and dc circuit alarms are contained on relay panels in a 24hour attended control room. Does this qualify as an extended time interval conditionbased system?
Yes, provided the station attendant monitors the alarms and other indications and reports them
within the given time limits that are stated in the criteria of the Table 1b or Table 1c.
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PRC-005-2 Frequently-Asked Questions
Monitoring Level Applicability Table
(See related definition and decision tree for various level requirements)
Level 1
(Unmonitored)
Level 2
(Partially
Monitored)
Level 3
(Fully
Monitored)
Protective relays
Y
Y
Y
Instrument transformer Inputs to
Protective Relays
Y
N
Y
Protection System control circuitry
(Other than aux-relays & lock-out
relays)
Y
Y
Y
Aux-relays & lock-out relays
Y
N
N
DC supply (other than station
batteries)
Y
Y
Y
Station batteries
Y
N
N
Y
Y
Y
UVLS and UFLS relays that comprise
a protection scheme distributed over
the power system
Y
Y
Y
SPS, including verification of end-toend performance, or relay sensing
for centralized UFLS or UVLS
systems
Y
Y
Y
Protection Component
Protection system communications
equipment and channels
Y = Monitoring Level Applies
N = Monitoring Level Not Applicable
E.
When documenting the basis for inclusion of components into the appropriate levels of
monitoring as per Requirement R2 of the standard, is it necessary to provide this
documentation via a device by device listing of components and the specific monitoring
attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
systems are Level 2 - Partially Monitored by stating the following within the program
description:
Draft 2: April, 2010
Page 32
PRC-005-2 Frequently-Asked Questions
“All substation dc systems are considered Level 2 - Partially Monitored and subject to
Table 1b requirements as all substation dc systems are equipped with dc voltage
alarms and ground detection alarms that are sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device level
list of exclusions. Example:
“Except as noted below, all substation dc systems are considered Level 2 - Partially
Monitored and subject to Table 1b requirements as all substation dc systems are
equipped with dc voltage alarms and ground detection alarms that are sent to the
manned control center. The dc systems of Substation X, Substation Y, and Substation
Z are considered Level 1 - Unmonitored and subject to Table 1a requirements as they
are not equipped with ground detection capability.”
Regardless whether this documentation is provided via a device by device listing of
monitoring attributes, by global statements of the monitoring attributes of an entire population
of component types, or by some combination of these methods, it should be noted that auditors
may request supporting drawings or other documentation necessary to validate the inclusion of
the device(s) within the appropriate level of monitoring. This supporting background
information need not be maintained within the program document structure but should be
retrievable if requested by an auditor.
F.
How do I know what monitoring level I am under? – Include Decision Trees
Decision Trees are provided below for each of the following categories of equipment to assist
in the determination of the level of monitoring.
◊
◊
◊
◊
◊
Protective Relays
Current and Voltage Sensing Devices
Protection System Control Circuitry
Station dc Supply
Protection System Communication Systems
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PRC-005-2 Frequently-Asked Questions
Draft 2: April, 2010
Page 34
PRC-005-2 Frequently-Asked Questions
Draft 2: April, 2010
Page 35
PRC-005-2 Frequently-Asked Questions
CONTROL CIRCUIT
MONITOR LEVEL
DECISION TREE
Start
No
Meets
requirements for
Level 2
Monitoring
Yes
?
Is the following true?
1. Control Circuit whose alarms are
automatically provided daily (or more
frequently) to a location where action
can be taken to initiate resolution for
alarmed failures.
2. Monitoring and alarming of
continuity of trip circuit(s).
Note: Trip coils, auxiliary relays, and
lock-out relays must be electrically
operated at Level 1 interval.
Yes
No
?
Meets
requirements for
Level 3
Monitoring
Is the following true?
1. Every function required for correct operation of
Control Cirucuit is continuously monitored and
verified, and detected maintenance-correctable
issues reported.
2. Verification of the means by which alarms and
monitored values are transmitted to a location
where action can be taken to initiate resolution.
3. Detected maintenance-correctable issues for
Control Circuit are be reported within 1 hour or
less of the maintenance-correctable issue
occurring, to a location where action can be taken
to initiate resolution.
4. Monitoring of the continuity of breaker trip
circuits (with alarming for non-continuity), along
with the presence of tripping voltage supply all the
way from relay terminals (or from inside the relay)
though the trip coil, including any auxiliary
contacts essential to proper Protection System
operation. If a trip circuit comprises multiple
paths, each of the paths must be monitored,
including monitoring of the operating coil circuit(s)
and the tripping circuits of auxiliary tripping relays
and lockout relays.
Level 1 Monitored
Control Circuit
Note: Trip coils, auxiliary relays, and lock-out
relays must be electrically operated at Level 1
interval.
End
Draft 2: April, 2010
Page 36
PRC-005-2 Frequently-Asked Questions
DC SUPPLY
MONITOR LEVEL
DECISION TREE
Note: Physical inspection of the battery is
required regardless of level of monitoring used.
Start
No
Yes
?
Meets
requirements for
Level 2 Monitoring
Is the following true?
1. DC Supply whose alarms are automatically
provided daily (or more frequently) to a location
where action can be taken for alarmed failures.
2. Monitoring and alarming for the following
items:
- station dc supply
- unintential dc grounds
- electrolyte level of all cells
- individual battery cell/unit state of charge
- continuity of battery cell-to-cell and terminal
resistance
No
Yes
?
Meets
requirements for
Level 3 Monitoring
Is the following true?
1. Verification of the means by which alarms and
monitored values are transmitted to a location
where action can be taken.
2. Detected maintenance-correctable issues are
reported within 1 hour or less of the
maintenance-correctable issue occurring, to a
location where action can be taken to inititate
resolution of the maintenance correctable issue.
3. Monitoring and alarming the station dc supply
status, including, for station dc supplies that
have as a component a battery, the voltage,
specific gravity, electrolyte level, temperature
and connectivity (cell to cell and terminal
connection resistance) of each cell as well as
the battery system terminal voltage and
electrical continuity of the overall battery system.
4. Monitoring and alarming if the performance
capability of the battery is degraded.
5. Monitoring and alarming the ac powered dc
power supply status including low and high
voltage and charge rate for station dc supplies
that have battery systems.
Level 1 Monitored
DC Supply
End
Draft 2: April, 2010
Page 37
PRC-005-2 Frequently-Asked Questions
COMMUNICATION SYSTEM
MONITOR LEVEL
DECISION TREE
Start
No
?
Meets
requirements for
Level 2 Monitoring
Yes
Is the following true?
1. Communication
Equipment whose alarms
are automatically provided
daily (or more frequently)
to a location where action
can be taken to initiate
resolution for alarmed
failures.
2. Monitoring and alarming
of protection
communications system
by mechanisms that check
for presence of the
communications channel.
No
?
Yes
Meets
requirements for
Level 3 Monitoring
Is the following true?
1. Verification of the means by
which alarms and monitored
values are transmitted to a
location where action can be
taken to initiate resolution.
2. Detected maintenancecorrectable issues are reported
within 1 hour or less of the
maintenance-correctable issue
occurring, to a location where
action can be taken to initiate
resolution.
3. Evaluating the performance of
the channel and its interface to
protective relays to determine
the quality of the channel and
alarming if the channel does not
meet performance criteria
Level 1 Monitored
Comm. Equip.
End
Draft 2: April, 2010
Page 38
PRC-005-2 Frequently-Asked Questions
2. Level 1 Monitored Protection Systems (Unmonitored Protection Systems)
A.
We have an electromechanical (unmonitored) relay that has a trip output to a lockout
relay (unmonitored) which trips our transformer off-line by tripping the transformer’s
high-side and low-side circuit breakers. What testing must be done for this system?
This system is made up of components that are level 1 (unmonitored). Assuming a time-based
protection system maintenance program schedule, each component must be maintained per
Table 1a – Level 1 Monitoring Maximum Allowable Testing Intervals and Maintenance
Activities.
3. Level 2 Monitored Protection Systems (Partially Monitored Protection Systems)
A.
We have a 30 year old oil circuit breaker with a red indicating lamp on the substation
relay panel that is illuminated only if there is continuity through the breaker trip coil.
There is no SCADA monitor or relay monitor of this trip coil. The line protection relay
package that trips this circuit breaker is a microprocessor relay that has an integral
alarm relay that will assert on a number of conditions that includes a loss of power to the
relay. This alarm contact connects to our SCADA system and alerts our 24-hour
operations center of relay trouble when the alarm contact closes. This microprocessor
relay trips the circuit breaker only and does not monitor trip coil continuity or other
things such as trip current. Is this an unmonitored or a partially-monitored system?
How often must I perform maintenance?
The protective relay is a level 2 (partially) monitored component of your protection system
and can be maintained every 12 years or when a maintenance correctable issue arises.
Assuming a time-based protection system maintenance program schedule, this component
must be maintained per Table 1b – Level 2 Monitoring Maximum Allowable Testing Intervals
and Maintenance Activities
The rest of your protection system contains components that are level 1 (unmonitored) and
must be maintained within at least the maximum verification intervals of Table 1a.
B.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Examples include using values gathered via data
communications and automatically comparing these values with values from other sources,
and using groupings of other measurements (such as vector summation of bus feeder currents)
for comparison if calibration requirements assure acceptable measurement of power system
input values. Other methods are possible.
C.
For a level 2 monitored Protection System (Partially Monitored Protection System)
pertaining to Protection System communications equipment and channels, how is the
performance criteria involved in the maintenance program?
The entity determines the performance criteria for each installation, depending on the
technology implemented. If the communication channel performance of a Protection System
varies from the pre-determined performance criteria for that system, these results should be
investigated and resolved.
Draft 2: April, 2010
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PRC-005-2 Frequently-Asked Questions
D.
My system has alarms that are gathered once daily through an auto-polling system; this
is not really a conventional SCADA system but does it meet the Table 1b requirements
for inclusion as Level 2?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the maintenance-correctable issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
4. Level 3 Monitored Protection Systems (Fully Monitored Protection Systems)
A.
Why are there activities defined for a level-3 monitored Protection System? The
technology does not seem to exist at this time to implement this monitoring level.
There may actually be some equipment available that is capable of meeting level-3 monitoring
criteria, in which case it may be maintained according to Table 1c. However, even if there is
no equipment available today that can meet this level of monitoring; the Standard establishes
the necessary requirements for when such equipment becomes available. By creating a
roadmap for development, this provision makes the Standard technology-neutral. The
standard drafting team wants to avoid the need to revise the Standard in a few years to
accommodate technology advances that are certainly coming to the industry.
Draft 2: April, 2010
Page 40
PRC-005-2 Frequently-Asked Questions
Ap p e n d ix A — P ro te c tio n S ys te m Ma in te n a n c e
S ta n d a rd Dra ftin g Te a m
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Mark Lukas
ComEd
Merle E. Ashton
Tri-State G&T
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
Bob Bentert
Florida Power & Light Company
John Ciufo
Hydro One Inc
Sam Francis
Oncor
Carol A Gerou
Midwest Reliability Organization
William Shultz
Southern Company Generation
Russell C Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
Draft 2: April, 2010
Mark Peterson
Great River Energy
William Shultz
Southern Company Generation
Leonard Swanson, Jr
National Grid USA
Eric A Udren
Quanta Technology
Philip B Winston
Georgia Power Company
John A Zipp
ITC Holdings
Page 41
PRC-005-2 Frequently-Asked Questions
In d e x
3-month interval, 24
corrective, 2, 5, 26
aggregate, 24, 25
countable events, 2, 25
alarm, 16, 17, 18, 29, 30,
38
current and voltage
measurements, 9
automated monitoring and
alarming, 24
data retention, 22
microprocessor, 5, 6, 7, 9,
10, 11, 13, 14, 26, 29,
30, 38
Misoperations, 2, 25
nickel-cadmium, 14, 15
ohmic, 14, 15, 29, 30
DC ground, 15
out-of-service, 7
auto-restoration, 5
documentation, 6, 21, 23,
31, 32
partially monitored, 11, 16
documentation method, 15
PBM, 24, 25, 26, 27
electromechanical, 7, 10,
26, 38
performance-based
maintenance, 25, 26
electro-mechanical relays,
6
pilot wire, 16
broken, 7
capacity, 14, 15, 29, 30
evidence, 6, 22
channel performance, 18,
38
fiber optic I/O scheme, 17
auxiliary relay, 11
batteries, 12, 13, 14, 15,
26, 27, 31
battery, 10, 12, 13, 14, 15,
26, 27, 29, 30
PMU, 19
power-line carrier, 16
pressure relays, 11, 12
firmware, 5, 25
frequency-shift, 16
protective relays, 5, 6, 7, 8,
10, 12, 13, 16, 18, 20
fully monitored, 16, 21
reclosing relays, 5
guard, 16, 17
Restoration, 5
Level 1, 16, 17, 31, 32, 38
sample list of devices, 20
Level 2, 16, 17, 31, 32, 38
segment, 2, 24, 25, 26, 27
Level 3, 16, 17, 27, 31, 39
settings, 2, 6, 7, 12, 22
lockout relay, 11, 20, 38
SPS, 5, 19, 31
maintenance correctable
issue, 2, 38
Table 1a, 2, 3, 5, 23, 32,
38
maintenance plan, 6, 22,
24
Table 1b, 5, 11, 17, 32, 38
charger, 12, 13, 14
check-off, 15
closing circuits, 5
commission, 23
Communication Site
Batteries, 15
communications, 7, 11, 16,
17, 18, 31, 38
communications channel,
16, 17
communications-assistedtrip, 11
component, 2, 5, 11, 14,
19, 22, 23, 25, 26, 29,
31, 32, 38
continuity, 12, 13, 14, 38
Draft 2: April, 2010
Table 1c, 2, 5, 21, 39
maximum allowable
interval, 24, 26
TBM, 22
trip coil, 10, 11, 29, 30, 38
Page 42
PRC-005-2 Frequently-Asked Questions
trip signal, 11, 17
unmonitored, 16, 29, 30,
38
voltage and current
sensing devices, 2, 8, 10
UVLS, 18, 19, 31
VRLA, 14, 15
trip test, 11
tripping circuits, 10
UFLS, 18, 19, 31
valve-regulated lead-acid,
15
unintentional ground, 15
vented lead-acid, 15, 29
Draft 2: April, 2010
Page 43
PRC-005-2 —NERC Protection System
Maintenance Standard PRC-005-2
Frequently Asked Questions
FREQUENTLY ASKED QUESTIONS Practical Compliance and Implementation (Draft 1)
April 16, 2010
Informative Annex to Standard PRC-005-2
Prepared by the
Protection System Maintenance and Testing Standard Drafting Team
July, 2009
PRC-005-2 — Protection System Maintenance - Frequently Asked QuestionsTable of Contents
Table of Contents
Introduction .......................................................................................................................................................... 2
Executive Summary.............................................................................................................................................. 2
Terms Used in PRC-005-2 .................................................................................................................................... 2
Frequently Asked Questions ................................................................................................................................ 3
I
General FAQs: .......................................................................................................................................... 3
II
Group by Type of Protection System Component: ....................................................................................... 5
1.
All Protection System Components ............................................................................................................. 5
2.
Protective Relays ....................................................................................................................................... 5
3.
Voltage and Current Sensing Device Inputs to Protective Relays ................................................................ 8
4.
Protection System Control Circuitry ......................................................................................................... 10
5.
Station dc Supply ..................................................................................................................................... 12
6.
Protection System Communications Equipment ........................................................................................ 16
7.
UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power System............... 18
8.
SPS or Relay Sensing for Centralized UFLS or UVLS............................................................................... 19
III
Group by Type of BES Facility:................................................................................................................ 20
1.
All BES Facilities..................................................................................................................................... 20
2.
Generation .............................................................................................................................................. 20
3.
Transmission ........................................................................................................................................... 21
IV
Group by Type of Maintenance Program:................................................................................................. 22
1.
All Protection System Maintenance Programs .......................................................................................... 22
2.
Time-Based Protection System Maintenance (TBM) Programs ................................................................. 23
3.
Performance-Based Protection System Maintenance (PBM) Programs ..................................................... 25
V
Group by Monitoring Level:..................................................................................................................... 29
1.
All Monitoring Levels .............................................................................................................................. 29
2.
Level 1 Monitored Protection Systems (Unmonitored Protection Systems) ................................................ 41
3.
Level 2 Monitored Protection Systems (Partially Monitored Protection Systems) ...................................... 41
4.
Level 3 Monitored Protection Systems (Fully Monitored Protection Systems)............................................ 42
Appendix A — Protection System Maintenance Standard Drafting Team....................................................... 43
Index ................................................................................................................................................................... 44
Draft 1: July 21, 20092: April, 2010
Page i
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Introduction
The following is a draft collection of questions and answers that the PSMT SDT believes could be helpful
to those implementing NERC Standard PRC-005-2 Protection System Maintenance. As the draft standard
proceeds through development, this FAQ document will be revised, including responses to key or frequent
comments from the posting process. The FAQ will be organized at a later time during the development of
the draft Standard.
This FAQ document will support both the Standard and the associated Technical Reference document.
Executive Summary
•
To be addedWrite later if needed.
Terms Used in PRC-005-2
Maintenance Correctable Issue – As indicated in footnote 2 of the draft standard, a maintenance
correctable issue is a failure of a device to operate within design parameters that can not be restored to
functional order by repair or calibration, repair or replacement while performing the initial on-site
maintenance activity, and that requires follow-up corrective action.
Segment – As indicated in PRC-005-2 Attachment A Criteria for a Performance-Based Protection System
Maintenance Program, a segment is a “A grouping of Protection Systems or component
devicescomponents of a particular model or type from a single manufacturer, with other common factors
such that consistent performance is expected across the entire population of the segment, and shall only be
defined for a population of 60 or more individual components.”
Component – This equipment is first mentioned in Requirement 1, Part 1.1 of this standard. A component
is any individual discrete piece of equipment included in a Protection System, such as a protective relay or
current sensing device. Types of components are listed in Table 1 (“Maximum Allowable Testing Intervals
and Maintenance Activities for Unmonitored Protection Systems”). For components such as dc circuits, the
designation of what constitutes a dc control circuit elementcomponent is somewhat arbitrary and is very
dependent upon how an entity performs and tracks the testing of the dc circuitry. Some entities test their dc
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of “dc control circuit
elementscomponents.” Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices,, where the entity may choose
either to designate a full three-phase set of such devices or a single device as a single component.
Countable Event – As indicated in footnote 4 of PRC-005-2 Attachment A, Criteria for a Performancebased Protection System Maintenance Program, countable events include any failure of a component
requiring repair or replacement, any condition discovered during the verification activities in Table 1a
through Table 1c which requires corrective action, or a Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different from
specified settings, Protection System component configuration errors, or Protection System application
errors are not included in Countable Events.
Draft 1: July 21, 20092: April, 2010
Page 2
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Frequently Asked Questions
I
General FAQs:
1. The standard seems very complicated, and is difficult to understand. Can it be simplified?
Because the standard is establishing parameters for condition-based Maintenance (R2) and
performance-based Maintenance (R3) in addition to simple time-based Maintenance, it does appear
to be complicated. At its simplest, an entity needs to follow R1 and R4 and perform ONLY timebased maintenance according to Table 1a,, eliminating R2 and R3 from consideration altogether. If
an entity then wishes to take advantage of monitoring on its Protection System components, R2
comes into play, along with Tables 1b and 1c. If an entity wishes to use historical performance of
its Protection System components to perform performance-based Maintenance, R3 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
Draft 1: July 21, 20092: April, 2010
Page 3
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Requirements
Flowchart
Start
PRC-005-2
Note: GO, DP, & TO
may use one or
multiple programs
Each GO, DP, & TO
shall establish a
maintenance
program [R1]
Performance
Based
Time Based
Decide if using Time Based, Condition
Baesd, and/or Performance Based
program
•
•
Condition Based
•
Ensure
components
have necessary
monitoring [R2]
Separate components
into appropriate
families of 60 or more
Maintain components
for each segment per
Table One until at
least 30 components
have been tested
Analyze data to
determine appropriate
interval for
segment(s)
[R3]
Perform maintenance
activities from Table One
for each segment with
interval from analysis
above and collect data for
future analysis
[R3, R4.4.2]
Maintain components
per Table One
Intervals and
Activities [R4.4.1]
•
Maintain
components per
Table One
Intervals and
Activities [R4.4.1]
•
•
Collect countable
events from
maintenance and
failures
Analyze data from
maintenance of last
30 components and/
or last year to verify
countable events
below 4%
Adjust maintenance
interval to keep
countable events
below 4%
[R3]
Implement
corrective
actions as
needed [R4]
End
Draft 1: July 21, 20092: April, 2010
Page 4
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
II
Group by Type of Protection System Component:
1. All Protection System Components
A.
Are power circuit reclosers, reclosing relays,, closing circuits and auto-restoration
schemes covered in this standard?
No. As stated in R1, this standard covers protective relays that use measurements of voltage,
current and/or phase angle to determine anomalies and to trip a portion of the BES. Reclosers,
reclosing relays,, closing circuits and auto-restoration schemes are used to cause devices to
close as opposed to electrical-measurement relays and their associated circuits that cause
circuit interruption from the BES; such closing devices and schemes are more appropriately
covered under other NERC Standards. There is one notable exception: if a Special Protection
System incorporates automatic closing of breakers, the related closing devices are part of the
SPS and must be tested accordingly.
B.
Why does PRC-005-2 not specifically require maintenance and testing procedures as
reflected in the previous standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2
requires a documented Maintenance program, and is focused on establishing Requirements
rather than prescribing methodology to meet those Requirements. Between the activities
identified in Tables 1a, 1b, and 1c, and the various components of the definition established
for a “Protection System Maintenance Program”, PRC-005-2 establishes the activities and
time-basis for a Protection System Maintenance Program to a level of detail not previously
required.
2. Protective Relays
A.
How do I approach testing when I have to upgrade firmware of a microprocessor relay?
The component “Upkeep” in the definition of a Protection System Maintenance Program,
addresses “Routine activities necessary to assure that the component remains in good working
order and implementation of any manufacturer’s hardware and software service advisories
which are relevant to the application of the device.” The Maintenance Activities specified in
Table 1a,, Table 1b,, and Table 1c do not present any requirements related to Upkeep for
Protective Relays. However, the entity should assure that the relay continues to function
properly after implementation of firmware changes.
B.
Please clarify what is meant by restoration in the definition of maintenance.
The component “Restoration” in the definition of a Protection System Maintenance Program,
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities
specified in Table 1a, Table 1b, and Table 1c do not present any requirements related to
Draft 1: July 21, 20092: April, 2010
Page 5
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Restoration; R4.3 of the standard does require that the entity “initiate any necessary activities
to correct unresolved maintenance correctable issues”. Some examples of restoration (or
correction of maintenance-correctable issues) include, but are not limited to, replacement of
capacitors in distance relays to bring them to working order; replacement of relays, or other
Protection System components, to bring the Protection System to working order; upgrade of
electro-mechanical or solid-state protective relays to micro-processor based relays following
the discovery of failed components. Restoration, as used in this context is not to be confused
with Restoration rules as used in system operations. Maintenance activity necessarily includes
both the detection of problems and the repairs needed to eliminate those problems. This
standard does not identify all of the Protection System problems that must be detected and
eliminated, rather it is the intent of this standard that an entity determines the necessary
working order for their various devices and keeps them in working order. If an equipment item
is repaired or replaced then the entity can restart the maintenance-time-interval-clock if
desired, however the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements; in other words do not discard maintenance data that goes to verify your work
C.
If I upgrade my old relays then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced then the entity can restart the maintenanceactivity-time-interval-clock if desired, however the replacement of equipment does not remove
any documentation requirements. The requirements in the standard are intended to ensure that
an entity has a maintenance plan and that the entity adheres to minimum activities and
maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance cycles is intended to demonstrate compliance with the interval. Therefore, if you
upgrade or replace equipment then you still must maintain the documentation for the previous
equipment, thus demonstrating compliance with the time interval requirement prior to the
replacement action.
D.
What is meant by “Verify that settings are as specified” maintenance activity in tables 1a
and 1b?
Verification of settings is an activity directed mostly towards microprocessor based relays.
For relay maintenance departments that choose to test microprocessor based relays in the same
manner as electro-mechanical relays are tested, the testing process sometimes requires that
some specific functions be disabled. Later tests might enable the functions previously disabled
but perhaps still other functions or logic statements were then masked out. It is imperative that,
when the relay is placed into service, the settings in the relay be the settings that were intended
to be in that relay or as the Standard states “…settings are as specified.”
Many of the microprocessor based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement a simple recorded acknowledgement that
this was done is sufficient.
The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is simply to
check that the settings in the relay match the settings specified to those placed into the relay.
Draft 1: July 21, 20092: April, 2010
Page 6
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
E.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in tables 1a and 1b?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection, and thus the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
B.F. I use my protective relays only as sources of metered quantities and breaker status for
SCADA and EMS through a substation distributed RTU or data concentrator to the
control center. What are the maintenance requirements for the relays?
This standard addresses only devices “that are applied on, or are designed to provide
protection for the BES.” Protective relays, providing only the functions mentioned in the
question, are not included.
C.G. I use my protective relays for fault and disturbance recording, collecting oscillographic
records and event records via communications for fault analysis to meet NERC and
DME requirements. What are the maintenance requirements for the relays?
For relays used only as disturbance monitoring equipment, the NERC standard PRC-018-1 R3
& R6 states the maintenance requirements, and is being addressed by a Standards activity that
is revising PRC-002-1 and PRC-018-1. For protective relays “that are applied on, or are
designed to provide protection for the BES,” this standard applies, even if they also perform
DME functions.
H.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system rating
changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system uprates, upgrades and overall changes meet any and all other
requirements and standards then the requirements of PRC-005-2 are simple – if the Protection
system component performs a Protection system function then it must be maintained. If the
component no longer performs Protection System functions than it does not require
maintenance activities under the Tables of PRC-005-2. While many entities might physically
remove a component that is no longer needed there is no requirement in PRC-005-2 to remove
such component(s). Obviously, prudence would dictate that an “out-of-service” device is truly
made inactive. There are no record requirements listed in PRC-005-2 for Protection System
components not used.
I.
While performing relay testing of a protective device on our Bulk Electric System it was
discovered that the protective device being tested was either broken or out of calibration.
Does this satisfy the relay testing requirement even though the protective device tested
bad, and may be unable to be placed back into service?
Yes, PRC-005-2 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-2
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requirement although the protective device may be unable to be returned to service under
normal calibration adjustments. R4.3 states (the entity must):
The entity must assure either that the components are within acceptable parameters at the
conclusion of the maintenance activities or initiate any necessary activities to correct
unresolved maintenance correctable issues.
J.
If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R4.3) (in essence) state that the entity assure the
components are within the owner’s acceptable operating parameters, if not then actions must
be initiated to correct the deviance. The type of corrective activity is not stated; however it
could include repairs or replacements. Documentation is always a necessity (“If it is not
documented then it wasn’t done!”)
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
K.
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
3. Voltage and Current Sensing Device Inputs to Protective Relays
A.
What is meant by “…verify the current and voltage circuit inputs from the voltage and
current sensing devices to the protective relays …” …” Do we need to perform ratio,
polarity and saturation tests every few years?
No. You must proveverify that the protective relay is receiving the expected values from the
voltage and current sensing devices (typically voltage and current transformers). This can be
as difficult as is proposed by the question (with additional testing on the cabling and substation
wiring to ensure that the values arrive at the relays); or simplicity can be achieved by other
verification methods. Some examples follow:While some examples follow, these are not
intended to represent an all-inclusive list; technology advances and ingenuity should not be
excluded from making comparisons and verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional testing on the
panel wiring to ensure that the values arrive at those relays) with the other phases, and verify
that residual currents are within expected bounds
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•
Observe all three phase currents and the residual current at the relay panel with an oscilloscope,
observing comparable magnitudes and proper phase relationship, with additional testing on the
panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay, (such as, but not limited to, a query
to the microprocessor relay), to another protective relay monitoring the same line, with currents
supplied by different CTs.CT’s.
•
Compare the secondary values, at the relay with values measured by test instruments (such as,
but not limited to multi-meters, voltmeter, clamp-on ammeters, etc) and verified by calculations
and known ratios to be the values expected. For example a single PT on a 100KV bus will have
a specific secondary value that when multiplied by the PT ratio arrives at the expected bus
value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned relay,
compare those SCADA values to the values as determined by the questioned relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by the
questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that, an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring systems.
B.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral currents, or
3V0 voltages, by comparison, when my system is closely balanced?
These values will be zero, or very small, for any reasonably balanced system. To verify these
values by comparison, you will need to rely on the normal condition that your system is not
perfectly balanced, and there will usually be a small zero-sequence current or voltage, and
these values can be measured with instruments having a sufficiently low resolution range. A
reading of precisely zero will probably suggest that there is an opening (or some other
problem) in the measuring circuit. A finite value of a few percent of the phase quantities,
however, may suggest that the measuring circuit is indeed performing properly.
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities may be also verified by use of oscillographic records for connected
microprocessor relays as recorded during system disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known fault locations.
C.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not required by the Maintenance
Standardspecifically required by the Maintenance Standard. However, if the method of
verifying CT and PT inputs to the relay involves some other method than actual observation of
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current and voltage transformer secondary inputs to the relay, it might be necessary to perform
some sort of cable integrity test to verify that the instrument transformer secondary signals are
actually making it to the relay and not being shunted off to ground. For instance, you could
use CT excitation tests and PT turns ratio tests and compare to baseline values to verify that
the instrument transformer outputs are acceptable. However, to conclude that these acceptable
transformer instrument output signals are actually making it to the relay inputs, it also would
be necessary to verify the insulation of the wiring between the instrument transformer and the
relay.
D.
My plant generator and transformer relays are electromechanical and do not have
metering functions as do microprocessor based relays. In order for me to compare the
instrument transformer inputs to these relays to the secondary values of other metered
instrument transformers monitoring the same primary voltage and current signals, it
would be necessary to temporarily connect test equipment like voltmeters and clamp on
ammeters to measure the input signals to the relays. This practice seems very risky and
a plant trip could result if the technician were to make an error while measuring these
current and voltage signals. How can I avoid this risk? Also, what if no other
instrument transformers are available which monitor the same primary voltage or
current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests
to adequately “verify the current and voltage circuit inputs from the voltage and current
sensing devices to the protective relays …” while eliminating the risk of tripping an in service
generator or transformer. Similarly, this same offline test methodology can be used to verify
the relay input voltage and current signals to relays when there are no other instrument
transformers monitoring available for purposes of signal comparison.
4. Protection System Control Circuitry
A.
Is it permissible to verify circuit breaker tripping at a different time (and interval) than
when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual components’
maximum allowable testing intervals.
B.
The Protection System Maintenance Standard describes requirements for verifying the
tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC-005-2 are intended to verify the integrity of tripping circuits,, including
the breaker trip coil,, as well as the presence of auxiliary supply (usually a dc battery)) for
energizing the trip coil if a protection function operates. Beyond this, PRC-005-2 sets no
requirements for verifying circuit breaker performance, or for maintenance of the circuit
breaker.
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C.
How do I test each dc Control Circuit path, as established for level 2 (partially monitored
protection systems) monitoring of a “Protection System Control Circuitry (Trip coils and
auxiliary relays)”?
Table 1b specifies that each breaker trip coil,, auxiliary relay,, and lockout relay must
be operated within the specified time period. The required operations may be via
targeted maintenance activities, or by documented operation of these devices for other
purposes such as fault clearing.
D.
What does this standard require for testing an Auxiliary Tripping Relay?
Table 1 requires that the trip test must verify that the auxiliary tripping relay (94) (s) and/or
lockout relay (86) operates(s) operate(s) electrically and that their trip output(s) perform as
expected. Auxiliary outputs not in a trip path (i.e. alarming or DME input) are not required to
be checked.
E.
What does a functional trip test include?
An operational trip test must be performed on each portion of a trip circuit. Each control
circuit path that produces a trip signal must be verified; this includes trip coils, auxiliary
tripping relays (94),, lockout relays (86), and communications--assisted-trip schemes.
A trip test may be an overall test that verifies the operation of the entire trip scheme at once, or
it may be several tests of the various portions that make up the entire trip schemepath,
provided that testing of the various portions of the trip scheme verifies all of the portions,
including parallel paths, and overlaps those portions.
A circuit breaker or other interrupting device needs to be trip tested at least once per trip coil.
Breaker auxiliary contacts that are essential for the proper operation of the protective relay
trip-circuit (or trip-logic) must be verified as providing the correct breaker open/close status
information to the Protection System...
Discrete-component auxiliary relays (94) and lock-out relays (86) must be provenverified by
trip test.. The trip test must verify that the auxiliary or lock-out relay operates electrically and
that the relay’s trip output(s) change(s) state. Software latches or control algorithms, including
trip logic processing implemented as programming component such as a microprocessor relay
that take the place of (conventional) discrete component auxiliary relays or lock-out relays do
not have to be routinely trip tested.
Normally-closed auxiliary contacts from other devices (for example, switchyard-voltage-level
disconnect switches, interlock switches, or pressure switches) which are in the breaker trip
path do not need to be tested.
F.
Is a Sudden Pressure Relay an Auxiliary Tripping Relay?
No. IEEE C37.2-2008 assigns the device number 94 to auxiliary tripping relays. Sudden
pressure relays are assigned device number 63, and is excluded from the Standard by footnote
1.
G.
The standard specifically mentions Auxiliary and Lock-out relays; what is an Auxiliary
Tripping Relay?
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An auxiliary relay,, IEEE Device Number 94, is described in IEEE Standard C37.2-2008 as “A
device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate
tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should
open automatically, even though its closing circuit is maintained closed.”
H.
What is a Lock-out Relay?
A lock-out relay, IEEE Device Number 86, is described in IEEE Standard C37.2 as “A device
that trips and maintains the associated equipment or devices inoperative until it is reset by an
operator, either locally or remotely.”
I.
My mechanical device does not operate electrically and does not have calibration
settings;; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of the trip circuit. This standard does not
cover circuit breaker maintenance or transformer maintenance. The standard also does not
cover testing of devices such as sudden pressure relays (63), temperature relays (49), and other
relays which respond to mechanical parameters rather than electrical parameters.
5. Station dc Supply
A.
What constitutes the station dc supply as mentioned in the definition of Protective
System?
The station direct current (dc) supply normally consists of two components: the battery
charger and the station battery itself. There are also emerging technologies that provide a
source of dc supply that does not include either a battery or charger.
Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1.
Emerging Technologies - Station dc supplies are currently being developed that use other
energy storage technologies beside the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1 presents maintenance activities and maximum allowable testing
intervals for these new station dc supply technologies. However, because these technologies
are relatively new the maintenance activities for these station dc supplies may change over
time.
B.
In the Maintenance Activities for station dc supply in Table 1, what do you mean by
“continuity”?”?
Because the Standard pertains to maintenance not only of the station battery,, but also the
whole station dc supply, continuity checks of the station dc supply are required. “Continuity”
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as used in Table 1 refers to verifying that there is a continuous current path from the positive
terminal of the station battery set to the negative terminal, otherwise there is no way of
determining that a station battery is available to supply dc current to the station.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path the battery set will not be
available for service.
C.
Why is it necessary to verify the continuity of the dc supply?
In the event of the loss of the ac source or battery charger,, the battery must be capable of
supplying dc current, both for continuous dc loads and for tripping breakers and switches.
Without continuity,, the battery cannot perform this function.
If the battery charger is not sized to handle the maximum dc current required to operate the
protective systems, it is sized only to handle the constant dc load of the station and the
charging current required to bring the battery back to full charge following a discharge. At
those stations, the battery charger would not be able to trip breakers and switches if the battery
experiences loss of continuity..
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
◊
◊
D.
Many battery chargers produce harmonics which can cause failure of dc power supplies in
microprocessor based protective relays and other electronic devices connected to station
dc supply. In these cases, the substation battery serves as a filter for these harmonics.
With the loss of continuity in the battery, the filter provided by the battery is no longer
present.
Loss of electrical continuity of the station battery will cause, regardless of the battery
charger’scharger’s output current capability, a delayed response in full output current from
the charger. Almost all chargers have an intentional 1 to 2 second delay to switch from a
low substation dc load current to the maximum output of the charger. This delay would
cause the opening of circuit breakers to be delayed which could violate system
performance standards.
How do you verify continuity of the dc supply?
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery unless the battery charger is taken out of service. At that time
a break in the continuity of the station battery current path will be revealed because there will
be no voltage on the substation dc circuitry.
Although the Standard prescribes what must be done during the maintenance activity it does
not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery..
◊
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
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◊
◊
discharging. Even when a battery is charged there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path through
the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of the
various dc-supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor based battery chargers have developed methods for their
equipment to periodically (or continuously) testedtest for battery continuity.. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
No matter how the electrical continuity of a battery set is verified it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1 to insure that the station
dc supply will provide the required current to the Protection System at all times.
E.Why is specific gravity testing required?
Specific gravity testing measures the state of the charge for each individual cell, and is
performed to determine the condition of the charging system as well as the condition of the
individual cell.
Specific gravity measurements can also be used as an indication of loss of continuity over a
period of time. Specific gravity measurement is a method of determining the state of charge of
a battery. Loss of continuity in the battery circuit will not allow charging current to flow
through the battery and the battery cells will eventually self discharge causing the specific
gravity to approach the specific gravity value of water which is 1.0.
If the specific gravity measurements taken during an inspection are determined to be low, this
indicates that the battery is in a state of discharge. If no recent high discharges of the battery
have occurred and the float voltage is normal, then the continuity of the battery circuit can be
suspected and other tests such as measuring battery current should be made to determine if the
specific gravity readings are an indication of loss of battery continuity.
F.E. When should I check the station batteries to see if they have sufficient energy to perform
as designed?
The answer to this question depends on the type of battery (valve regulated lead-acid, vented
lead acid, or nickel-cadmium),), the maintenance activity chosen, and the type of time based
monitoring level selected.
For example, if you have a Valve Regulated Lead-Acid (VRLA)) station battery,, and you
have chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s
baseline, you will have to perform verification at a maximum maintenance interval of no
greater than every three months.
If, for a VRLA station battery,, you choose to conduct a performance capacity test on the
entire station battery as the maintenance activity, then you will have to perform verification at
a maximum maintenance interval of no greater than every 3 calendar years.
G.F. Why in Table 1 are there two Maintenance Activities with different Maximum
Maintenance Intervals listed to verify that the station battery can perform as designed?
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The two acceptable methods for proving that a station battery can perform as designed are
based on two different philosophies. The first activity requires a capacitivecapacity discharge
test of the entire battery set to proveverify that degradation of one or several components
(cells) in the set has not deteriorated to a point where the total capacity of the battery system
falls below its designed rating. The second maintenance activity requires tests and evaluation
of the internal ohmic measurements on each of the individual cells/units of the battery set to
determine that each component can perform as designed and therefore the entire battery set
can be provenverified to perform as designed.
The maximum maintenance interval for discharge capacity testing is longer than the interval
for testing and evaluation of internal ohmic cell measurements. An individual component of a
battery set may degrade to an unacceptable level without causing the total battery set to fall
below its designed rating under capacity testing. However, since the philosophy behind
internal ohmic measurement evaluation is based on the fact that each battery component must
be provenverified to be able to perform as designed, the interval for verification by this
maintenance activity must be shorter to catch individual cell/unit degradation.
H.G. What is the justification for having two different Maintenance Activities listed in
Table 1 to verify that the station battery can perform as designed?
IEEE Standards 450, 1188, and 1106 for vented lead-acid,, valve-regulated lead-acid
(VRLA),), and nickel-cadmium batteries,, respectively (which together are the most
commonly used substation batteries on the BES) go into great detail about capacity testing of
the entire battery set to determine that a battery can perform as designed.
The first maintenance activity listed in Table 1 for verifying that a station battery can perform
as designed uses maximum maintenance intervals for capacity testing that were designed to
align with the IEEE battery standards. This maintenance activity is applicable for vented leadacid,, valve-regulated lead-acid,, and nickel-cadmium batteries..
The second maintenance activity listed in Table 1 for verifying that a station battery can
perform as designed uses maximum maintenance intervals for evaluating internal ohmic
measurements in relation to their baseline measurements that are based on industry experience,
EPRI technical reports and application guides, and the IEEE battery standards. By evaluating
the internal ohmic measurements for each cell and comparing that measurement to the cell’s
baseline ohmic measurement (taken at the time of the battery set’s acceptance capacity test),
low-capacity cells can be identified and eliminated to keep the battery set capable of
performing as designed. This maintenance activity is applicable only for vented lead-acid and
VRLA batteries..
I.H. Why in Table 1 of PRC-005-2 is there a maintenance activity to inspect the structural
intergrity of the battery rack?
The three IEEE standards (1188, 450, and 1106) for VRLA,, vented lead-acid,, and nickelcadmium batteries all recommend that as part of any battery inspection the battery rack should
be inspected. The purpose of this inspection is to proveverify that the battery rack is correctly
installed and has no deterioration that could weaken its structural integrity. Because the
battery rack is specifically designed for the battery that is mounted on it, weakening of its
structural members by rust or corrosion can physically jeopardize the battery.
I.
What is required to comply with the “Unintentional Grounds” requirement?
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In most cases, the first ground that appears on a battery pole is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on unintentional DC grounds. The standard merely requires that a check be made for
the existence of Unintentional DC Grounds. Obviously a “check-off” of some sort will have to
be devised to demonstrate that a check is routinely done for Unintentional DC Grounds.
J.
Where the standard refers to “all cells” is it sufficient to have a documentation method
that refers to “all cells” or do we need to have separate documentation for every cell? For
example to I need 60 individual documented check-offs for good electrolyte level or
would a single check-off per bank be sufficient??
A single check-off per battery bank is sufficient.
K.
Does this standard refer to Station batteries or all batteries, for example Communication
Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communication sites. The batteries covered under PRC-005-2 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System.
6. Protection System Communications Equipment
A.
What are some examples of mechanisms to check communications equipment
functioning?
For Level 1 unmonitored Protection Systems, various types of communications systems will
have different facilities for on-site integrity checking to be performed at least every three
months during a substation visit. Some examples are:
◊ On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier checkback test from one terminal.
◊ Systems which use frequency-shift communications with a continuous guard signal (over a
telephone circuit, analog microwave system, etc.) can be checked by observing a loss-ofguard indication or alarm.. For frequency-shift power line power-line carrier systems, the
guard signal level meter can also be checked.
◊ Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
◊ Digital communications systems have some sort of data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For Level 2 partially monitored Protection Systems, various types of communications systems
will have different facilities for monitoring the presence of the communications channel,, and
activating alarms that can be monitored remotely. Some examples are:
◊ On-off power-line carrier systems can be shown to be operational by automated periodic
power-line carrier checkback tests, with remote alarming of failures.
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◊ Systems which use a frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be remotely monitored with a lossof-guard alarm or low signal level alarm.
◊ Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
◊ Digital communications systems can activate remotely monitored alarms for data reception
loss or data error indications.
For Level 3 fully monitored Protection Systems, the communications system must monitor all
aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays..
◊ In many communications systems signal quality measurements including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio, propagation
delay, and data error rates are compared to alarm limits. These alarms are connected for
remote monitoring.
◊ Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment location
is continuously being reflected at the remote monitoring site.
B.
What is needed for the 3-month inspection of communication-assisted trip scheme
equipment?
The 3-month inspection applies to Level 1 (Unmonitored) equipment. An example of
compliance with this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms, check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (ie FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard.
C.
Does a fiber optic I/O scheme used for breaker tripping or control within a station, for
example - transmitting a trip signal or control logic between the control house and the
breaker control cabinet, constitute a communication system?
This equipment is presently classified as being part of the Protection System Control Circuitry
and tested per the portions of Table 1 applicable to Protection System Control Circuitry rather
than those portions of the table applicable to communication equipment.
D.
In Table 1b,, the Maintenance Activities section of the Protective System
Communications Equipment and Channels refers to the quality of the channel meeting
“performance criteria”. What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating
normally an alarm will be indicated. For Level 1 systems this alarm will probably be on the
panel. For Level 2 and Level 3 systems, the alarm will be transmitted to a remote location.
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Each entity will have established a nominal performance level for each protective system
communications channel that is consistent with proper functioning of the Protection System.
If that level of nominal performance is not being met, the system will go into alarm..
Following are some examples of protective system communications channel performance
criteria:
◊ For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system is
calibrated and if the signal level drops below an established level, the system will indicate
an alarm..
◊ An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use checkback testing to determine channel performance.. A
predetermined signal sequence is sent to the remote end and the remote end decodes this
signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full power
and reduced power tests are typically run. Power levels for these tests are determined at the
time of calibration.
◊ Pilot wire relay systems use a hardwire communications circuit to communicate between
the local and remote ends of the protective zone. This circuit is monitored by circulating a
dc current between the relay systems. A typical level may be 1 mA. If the level drops
below the setting of the alarm monitor, the system will indicate an alarm.
◊ Modern digital relay systems use data communications to transmit relay information to the
remote end relays. An example of this is a line current differential scheme commonly used
on transmission lines. The protective relays communicate current magnitude and phase
information over the communications path to determine if the fault is located in the
protective zone. Quantities such as digital packet loss, bit error rate and channel delay are
monitored to determine the quality of the channel. These limits are determined and set
during relay commissioning. Once set, any channel quality problems that fall outside the
set levels will indicate an alarm..
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be - it
just requires that the entity establish nominal criteria so protective system channel monitoring
can be performed.
7. UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power
System
A.
We have an Under Voltage Load Shedding (UVLS)) system in place that prevents one of
our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
The situation as stated indicates that the tripping action was intended to prevent low
distribution voltage for a transmission system that was intact except for the line that was out of
service.
This Standard is not applicable to this UVLS..
UVLS installed to prevent system voltage collapse or voltage instability for BES reliability is
covered by this standard.
B.
We have a UFLS scheme that sheds the necessary load through distribution-side circuit
breakers and circuit reclosers. Do the trip-test requirements for circuit breakers apply to
our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential Lock-Out Relay. While many failures of
these distribution breakers could add up to be significant, it is also believed that distribution
breakers are operated often on just fault clearing duty and therefore the distribution circuit
breakers are operated at least as frequently as any requirements that might have appeared in
this standard.
C.
What does “distributed over the power system” mean?
This refers to the common practice of applying UFLS on the distribution system, with each
UFLS individually tripping a relatively low value of load. Therefore, the program is
implemented via a large number of individual UFLS components performing independently,
and the failure of any individual component to perform properly will have a minimal impact
on the effectiveness of the overall UFLS program. Some UVLS systems are applied similarly.
8. SPS or Relay Sensing for Centralized UFLS or UVLS
A.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end-to-end test.
B.
What about SPS interfaces between different entities or owners?
All SPS owners should have maintenance agreements that state which owner will perform
specific tasks. SPS segments can be tested individually, but must overlap.
C.
What do I have to do if I am using a phasor measurement unit (PMU)) as part of a
Protection System or Special Protection System?
Any Phasor Measurement Unit (PMU)) function whose output is used in a protection system
or Special Protection System (as opposed to a monitoring task) must be verified as a
component in a Protection System.
D.
How do I maintain a Special Protection System or Relay Sensing for Centralized UFLS
or UVLS Systems?
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Components of the SPS,, UFLS,, or UVLS should be maintained like similar components used
for other Protection System functions.
The output action verification may be breaker tripping, or other control action that must be
verified, but may be verified in overlapping segments. A grouped output control action need
be verified only once within the specified time interval, but all of the SPS,, UFLS,, or UVLS
components whose operation leads to that control action must each be verified.
E.
What does “centralized” mean?
This refers to the practice of applying sensing units at many locations over the system, with all
these components providing intelligence to an analytical system which then directs action to
address a detected condition. In some cases, this action may not take place at the same
location as the sensing units. This approach is often applied for complex SPS, and may be
used for UVLS where necessary to address the conditions of concern.
III
Group by Type of BES Facility:
1. All BES Facilities
A.
What, exactly, is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms
Used in Reliability Standards, and is not being modified within this draft Standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving
only load with one transmission source are generally not included in this definition.
Each Regional Entity implements a definition of the Bulk Electric System that is based on this
NERC definition, in some cases, supplemented by additional criteria. These regional
definitions have been documented and provided to FERC as part of a June 16, 2007
Informational FilingJune 16, 2007 Informational Filing.
2. Generation
A.
Please provide a sample list of devices or systems that must be verified in a generator,
generator step-up transformer, and generator connected station auxiliary transformer to
meet the requirements of this Maintenance Standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay may include but are not necessarily limited to:
• Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
• Loss-of-field relays
• Volts-per-hertz relays
• Negative sequence overcurrent relays
• Over voltage and under voltage protection relays
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
•
•
•
•
•
•
•
•
Stator-ground relays
Communications-based protection systems such as transfer-trip systems
Generator differential relays
Reverse power relays
Frequency relays
Out-of-step relays
Inadvertent energization protection
Breaker failure protection
For generator step up or generator-connected station auxiliary transformers, operation of any
the following associated protective relays frequently would result in a trip of the generating unit
and, as such, would be included in the program:
• Transformer differential relays
• Neutral overcurrent relay
• Phase overcurrent relays
A loss of a system-connected station auxiliary transformer could result in a loss of the
generating plant if the plant was being provided with auxiliary power from that source., and this
auxiliary transformer may directly affect the ability to start up the plant and to connect the plant
to the system. Thus, operation of any of the following relays associated with system-connected
station auxiliary transformers would be included in the program:
• Transformer differential relays
• Neutral overcurrent relay
• Phase overcurrent relays
Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program even if the loss of the those loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program even if a trip of these devices might eventually result in a trip of the generating
unit.
3. Transmission
A.
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having relevant
facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
IV
Group by Type of Maintenance Program:
1. All Protection System Maintenance Programs
A. I can’t figure out how to demonstrate compliance with the requirements for level 3 (fully
monitored)) Protection Systems. Why does this Maintenance Standard describe a
maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for level 3 (fully monitored)) Protection
Systems is likely to be very involved, and may include detailed manufacturer documentation of
complete internal monitoring within a device, comprehensive design drawing reviews, and
other detailed documentation. This Standard does not presume to specify what documentation
must be developed; only that it must be comprehensive.
There may actually be some equipment available that is capable of meeting level-3 monitoring
criteria, in which case it may be maintained according to Table 1c.. However, even if there is
no equipment available today that can meet this level of monitoring, the Standard establishes
the necessary requirements for when such equipment becomes available.
By creating a roadmap for development, this provision makes the Standard technology-neutral.
The standard drafting team wants to avoid the need to revise the Standard in a few years to
accommodate technology advances that are certainly coming to the industry.
B. What forms of evidence are acceptable?
Acceptable forms of evidence,, as relevant for the Requirement being documented, include but
are not limited to:
•
•
•
•
•
•
•
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database screen shots that demonstrate compliance information
Diagrams, engineering prints, schematics, maintenance and testing records, etc.
Logs (operator, substation, and other types of log)
Inspection forms
U.S. or Canadian mail, memos, or email proving the required information was exchanged,
coordinated, submitted or received
• Database lists and records
• Check-off forms (paper or electronic)
• Any record that demonstrates that the maintenance activity was known and accounted for.
C. If I replace a failed Protection System component with another component, what testing
do I need to perform on the new component?
The replacement component must be tested to a degree that assures that it will perform as
intended. If it is desired to reset the Table 1 maintenance interval for the replacement
component, all relevant Table 1 activities for the component should be performed.
D. Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records to
demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electro-mechanical protective relays be
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
tested, for routine scheduled tests, every 3 calendar years with a maximum allowed grace
period of an additional 18 months. This entity would be required to maintain its records of
maintenance of its last two routine scheduled tests. Thus its test records would have a latest
routine test as well as its previous routine test. The interval between tests is therefore provable
to an auditor as being within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to have three test results proving two time intervals, but rather have two test
results proving the last interval. The drafting team contends that this minimizes storage
requirements while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance Based Maintenance then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
2. Time-Based Protection System Maintenance (TBM)) Programs
A. What does this Maintenance Standard say about commissioning? Is it necessary to have
documentation in your maintenance history of the completion of commission testing?
Commissioning tests are regarded as a construction activity, not a maintenance activity.
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified on Table 1a of PRC-005-2, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation and need not be re-verified
within an ongoing maintenance program. Example – it is not necessary to re-verify correct
terminal strip wiring on an ongoing basis.
PRC-005-2 assumes that thorough commission testing was performed prior to a protection
system being placed in service. PRC-005-2 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content
and therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
An entity would be wise to retain commissioning records to show a maintenance start date. (See
next FAQ).
B. How do you determine the initial due date for maintenance?
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
The initial due date for maintenance should be based upon when a facility and its associated
Protection System were placed in service. Alternatively, an entity may choose to use the date
of completion of the commission testing of the Protection System component as the starting
point in determining its first maintenance due dates. Whichever method is chosen, for newly
installed Protection Systems the maintenance program should clearly identify when
maintenance is first due.
B.C. The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled outage
following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals.
C.D. If I am unable to complete the maintenance as required due to a major natural
disaster (hurricane, earthquake, etc), how will this affect my compliance with this
standard.
The NERC Sanction Guidelines provides that the Compliance Monitor will consider
extenuating circumstances when considering any sanctions. 1
D.E. What if my observed testing results show a high incidence of out-of-tolerance relays,
or, even worse, I am experiencing numerous relay misoperations due to the relays being
out-of-tolerance?
Any entity can choose to test some or all of their Protection System more frequently (or, to
express it differently, exceed the minimum requirements of the Standard). Particularly, if you
find that the maximum intervals in the Standard do not achieve your expected level of
performance, it is understandable that you would maintain the related equipment more
frequently.
F. We believe that the 3-month interval between inspections is unneccessary, why can we not
perform these inspections twice per year?
The standard drafting team believes that routine monthly inspections are the norm. To align
routine station inspections with other important inspections the 3-month interval was chosen. In
lieu of station visits many activities can be accomplished with automated monitoring and
alarming.
G. Our maintenance plan calls for us to perform routine protective relay tests every 3 years;
if we are unable to achieve this schedule but we are able to complete the procedures in less
than the Maximum Time Interval then are we in or out of compliance?
You are out of compliance. You must maintain your equipment to your stated intervals within
your maintenance plan. The protective relays (and any Protection System component) cannot
be tested at intervals that are longer than the maximum allowable interval stated in the Tables.
Therefore you should design your maintenance plan such that it is not in conflict with the
1 Sanction Guidelines of the North American Electric Reliability Corporation. Effective January 15, 2008.
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Minimum Activities and the Maximum Intervals. You then must maintain your equipment
according to your maintenance plan.
3. Performance-Based Protection System Maintenance (PBM)) Programs
A. I’m a small entity and cannot aggregate a population of Protection System components to
establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of
individual Protection System components to create a segment that crosses ownership
boundaries. All entities participating in a joint program should have a single documented joint
management process, with consistent Protection System Maintenance Programs (practices,
maintenance intervals and criteria), for which the multiple owners are individually responsible
with respect to the requirements of the Standard. The requirements established for
performance-based maintenance must be met for the overall aggregated program on an ongoing
basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power-plant
vs. substation, and weather conditions.
B. Can an owner go straight to a performance-based maintenance program schedule, if they
have previously gathered records?
Yes. An owner can go to a performance-based maintenance program immediately. The owner
will need to comply with the requirements of a performance-based maintenance program as
listed in the standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they can not prove that they have collected the data as required
for a performance-based maintenance program then they will need to wait until they can prove
compliance.
C. When establishing a perfomanceperformance-based maintenance program, can I use test
data from the device manufacturer, or industry survey results, as results to help establish
a basis for my performance-based intervals?
No. You must use actual in-service test data for the components in the segment. .
D. What types of misoperations or events are not considered countable events in the
performance-based Protection System Maintenance (PBM)) Program?
Countable events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component..
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned.
Human errors resulting in Protection System Misoperations during system installation or
maintenance activities are not considered countable events.. Examples of excluded human
errors include relay setting errors, design errors, wiring errors, inadvertent tripping of devices
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
during testing or installation, and misapplication of Protection System components. Examples
of misapplication of Protection System components include wrong CT or PT tap position,
protective relay function misapplication, and components not specified correctly for their
installation.
Certain types of Protection System component errors that cause Misoperations are not
considered countable events.. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
E. What are some examples of methods of correcting segment perfomance for PerformanceBased Maintenance?
There are a number of methods that may be useful for correcting segment performance for malperforming segments in a performance-based maintenance system. Some examples are listed
below.
•
The maximum allowable interval,, as established by the performance-based maintenance
system, can be decreased. This may, however, be slow to correct the performance of the
segment..
•
Identifiable sub-groups of components within the established segment,, which have been
identified to be the mal-performing portion of the segment, can be broken out as an
independent segment for target action. Each resulting segment must satisfy the minimum
population requirements for a performance-based maintenance program in order to remain
within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
Components within the mal-performing segment can be replaced with other components
(electromechanical distance relays with microprocessor relays, for example) to remove the
mal-performing segment.
F. If I find (and correct) a maintenance-correctable issue as a result of a misoperation
investigation (Re: PRC-004), how does this affect my performance-based maintenance
program?
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC-004 required misoperation investigation/corrective action), the actions performed
count as a maintenance activity, and “reset the clock” on everything you’ve done. In a
performance-based maintenance program, you also need to record the maintenance-correctable
issue with the relevant component group and use it in the analysis to determine your correct
performance-based maintenance interval for that component group.
G. Why are batteries excluded from PBM?? What about exclusion of batteries from
condition based maintenance?
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation from
the factory to the job site, length of time before a charge is put on the battery,, the method of
installation, the voltage level and duration of equalize charges, the float voltage level used, and
the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performanceperformance-based Protection System
Maintenance (PBM)) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and
performance criteria would be the same. However, there are too many variables in the electrochemical process to completely isolate all of the performance-changing criteria.
Similarly Functional Entities that want to establish a condition-based maintenance program
using Level 3 monitoring of the battery used in a station dc supply can not do so. Inspection of
the battery is required on a Maximum Maintenance Interval listed in the tables due to the aging
processes of station batteries.. However, Level 3 monitoring of a battery can eliminate the
requirement for periodic testing and some inspections (see Level 3 Monitoring Attributes for
Component of table 1c).
H. Please provide an example of the calculations involved in extending maintenance time
intervals using PBM.
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60.
They start out testing all of the relays within the prescribed Table requirements (6 year max) by
testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is greater
than the minimum sample size requirement of 30.
•
For the sake of example only the following will show 6 failures per year, reality may
well have different numbers of failures every year. PBM requires annual assessment of
failures found per units tested.
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
After the first year of tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure
rate.
•
This entity is now allowed to extend the maintenance interval if they choose.
The entity chooses to extend the maintenance interval of this population segment out to 10
years.
•
This represents a rate of 100 units tested per year; entity selects 100 units to be tested in
the following year.
•
After that year of testing these 100 units the entity again finds 6 failed units. 6/100= 6%
failures.
•
This entity has now exceeded the acceptable failure rate for these devices and must
accelerate testing of all of the units at a higher rate such that the failure rate is found to
be less than 4% per year; the entity has three years to get this failure rate down to 4%
or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 8 years. This
means that they will now test 125 units per year (1000/8). The entity has just two years left to
get the test rate corrected.
•
After a year they again find 6 failures out of the 125 units tested. 6/125= 5% failures.
In response to the 5% failure rate, the entity decreases the testing interval to 7 years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to get
the test rate corrected.
•
After a year they again find 6 failures out of the 143 units tested. 6/143= 4.2% failures.
(Note that the entity has tried 5 years and they were under the 4% limit and they tried 7 years
and they were over the 4% limit. They must be back at 4% failures or less in the next year so
they might simply elect to go back to 5 years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to 6 years.
This means that they will now test 167 units per year (1000/6).
•
After a year they again find 6 failures out of the 167 units tested. 6/167= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 6 years or less. Entity chose 6 year interval and effectively
extended their TBM (5 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; this is there to prevent an
entity from “gaming the system”. An entity might arbitrarily extend time intervals from 6 years
to 20 years. In the event that an entity finds a failure rate greater than 4% then the test rate must
be accelerated such that within three years the failure rate must be brought back down to 4% or
less.
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Here is a table that demonstrates the values discussed:
Year #
Total
Population
Test
Interval
Units to be
Tested
(P)
(I)
(U= P/I)
# of
Failures
Found
Failure
Rate
Decision
to Change
Interval
Interval
Chosen
(=F/U)
(F)
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
V
Group by Monitoring Level:
1. All Monitoring Levels
A.
Please provide an example of the level 1 monitored (unmonitored)) versus other levels of
monitoring available?
A level 1 (Unmonitored) Protection System has no monitoring and alarm circuits on the
Protection System components.
A level 2 (Partially) monitored Protection System or an individual component of a level 2
(Partially) monitored Protection System has monitoring and alarm circuits on the Protection
System components. The alarm circuits must alert a 24-hr staffed operations center.
There can be a combination of monitored and unmonitored Protection Systems within any
given substation or plant; there can also be a combination of monitored and unmonitored
components within any given Protection System.
Example #1: A combination of level 2 (Partially) monitored and level 1 (unmonitored))
components within a given Protection System is:
◊
◊
◊
◊
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center. (level 2)
Instrumentation transformers, with no monitoring, connected as inputs to that relay. (level
1)
A vented lead-acid battery with low voltage alarm connected to SCADA. (level 2)
A circuit breaker with a trip coil,, with no monitor circuit. (level 1)
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum test
intervals of:
◊
◊
◊
◊
The microprocessor relay is verified every 12 calendar years.
The instrumentation transformers are verified every 12 calendar years.
The battery is verified every 6 calendar years by performing a performance capacity test of
the entire battery bank or by evaluating the measured cell/unit internal ohmic values to
station battery baseline every 18 months.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
Example #2: A combination of level 2 (partially) monitored and level 1 (unmonitored))
components within a given Protection System is:
◊
◊
◊
◊
A microprocessor relay with integral alarm that is not connected to SCADA. (level 1)
Instrument transformers, with no monitoring, connected as inputs to that relay. (level 1)
A vented lead-acid battery with low voltage alarm connected to SCADA. (level 2)
A circuit breaker with a trip coil,, with no circuits monitored. (level 1)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum test
intervals of:
◊
◊
◊
◊
The microprocessor relay is verified every 6 calendar years.
The instrumentation transformers are verified every 12 calendar years.
The battery is verified every 6 calendar years by performing a performance capacity test of
the entire battery bank or by evaluating the measured cell/unit internal ohmic values to
station battery baseline every 18 months.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
Example #3: A combination of level 2 (partially) monitored and level 1 (unmonitored))
components within a given Protection System is:
◊
◊
◊
◊
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed operations
center. (level 2)
Instrument transformers, with no monitoring, connected as inputs to that relay (level 1)
Battery without any alarms connected to SCADA (level 1)
Circuit breaker with a trip coil,, with no circuits monitored (level 1)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components shall have
maximum test intervals of:
◊ The microprocessor relay is verified every 12 calendar years.
◊ The instrument transformers are verified every 12 calendar years.
◊ The battery is verified every 3 months, every 18 months, plus, depending upon the type of
battery used it may be verified at other maximum test intervals, as well.
◊ The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
B.
What is the intent behind the different levels of monitoring?
The intent behind different levels of monitoring is to allow less frequent manual intervention
when more information is known about the condition of Protection System components.
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
C.
Do all monitoring levels apply to all components in a protection system?
No. For some components in a protection system, certain levels of monitoring will not be
relevant. See table below:
D.
My microprocessor relays and dc circuit alarms are contained on relay panels in a 24hour attended control room. Does this qualify as an extended time interval conditionbased system?
Yes, provided the station attendant monitors the alarms and other indications and reports them
within the given time limits that are stated in the criteria of the Table 1b or Table 1c.
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Monitoring Level Applicability Table
(See related definition and decision tree for various level requirements)
Level 1
(Unmonitored)
Level 2
(Partially
Monitored)
Level 3
(Fully
Monitored)
Protective relays
Y
Y
Y
Instrument transformer Inputs to
Protective Relays
Y
N
Y
Protection System control circuitry
(Other than aux-relays & lock-out
relays)
Y
Y
Y
Aux-relays & lock-out relays
Y
N
N
DC supply (other than station
batteries))
Y
Y
Y
Station batteries
Y
N
N
Y
Y
Y
UVLS and UFLS relays that comprise
a protection scheme distributed over
the power system
Y
Y
Y
SPS,, including verification of end-toend performance, or relay sensing
for centralized UFLS or UVLS
systems
Y
Y
Y
Protection Component
Protection system communications
equipment and channels
Y = Monitoring Level Applies
N = Monitoring Level Not Applicable
D.E. When documenting the basis for inclusion of components into the appropriate levels of
monitoring as per Requirement R2 of the standard, is it necessary to provide this
documentation via a device by device listing of components and the specific monitoring
attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
systems are Level 2 - Partially Monitored by stating the following within the program
description:
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Page 32
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
“All substation dc systems are considered Level 2 - Partially Monitored and subject to
Table 1b requirements as all substation dc systems are equipped with dc voltage
alarms and ground detection alarms that are sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device level
list of exclusions. Example:
“Except as noted below, all substation dc systems are considered Level 2 - Partially
Monitored and subject to Table 1b requirements as all substation dc systems are
equipped with dc voltage alarms and ground detection alarms that are sent to the
manned control center. The dc systems of Substation X, Substation Y, and Substation
Z are considered Level 1 - Unmonitored and subject to Table 1a requirements as they
are not equipped with ground detection capability.”
Regardless whether this documentation is provided via a device by device listing of
monitoring attributes, by global statements of the monitoring attributes of an entire population
of component types, or by some combination of these methods, it should be noted that auditors
may request supporting drawings or other documentation necessary to validate the inclusion of
the device(s) within the appropriate level of monitoring. This supporting background
information need not be maintained within the program document structure but should be
retrievable if requested by an auditor.
E.F. How do I know what monitoring level I am under? – Include Decision Trees
Decision Trees are provided below for each of the following categories of equipment to assist
in the determination of the level of monitoring.
◊
◊
◊
◊
◊
Protective Relays
Current and Voltage Sensing Devices
Protection System Control Circuitry
Station dc Supply
Protection System Communications Equipment and ChannelsCommunication Systems
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
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PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
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Page 35
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
CONTROL CIRCUIT
MONITOR LEVEL
DECISION TREE
Start
No
Meets
requirements for
Level 2
Monitoring
Yes
?
Is the following true?
1. Control Circuit whose alarms are
automatically provided daily (or more
frequently) to a location where action
can be taken to initiate resolution for
alarmed failures.
2. Monitoring and alarming of
continuity of trip circuit(s).
Note: Trip coils, auxiliary relays, and
lock-out relays must be electrically
operated at Level 1 interval.
Yes
No
?
Meets
requirements for
Level 3
Monitoring
Is the following true?
1. Every function required for correct operation of
Control Cirucuit is continuously monitored and
verified, and detected maintenance-correctable
issues reported.
2. Verification of the means by which alarms and
monitored values are transmitted to a location
where action can be taken to initiate resolution.
3. Detected maintenance-correctable issues for
Control Circuit are be reported within 1 hour or
less of the maintenance-correctable issue
occurring, to a location where action can be taken
to initiate resolution.
4. Monitoring of the continuity of breaker trip
circuits (with alarming for non-continuity), along
with the presence of tripping voltage supply all the
way from relay terminals (or from inside the relay)
though the trip coil, including any auxiliary
contacts essential to proper Protection System
operation. If a trip circuit comprises multiple
paths, each of the paths must be monitored,
including monitoring of the operating coil circuit(s)
and the tripping circuits of auxiliary tripping relays
and lockout relays.
Level 1 Monitored
Control Circuit
Note: Trip coils, auxiliary relays, and lock-out
relays must be electrically operated at Level 1
interval.
End
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Page 36
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
CONTROL CIRCUIT
MONITOR LEVEL
DECISION TREE
Start
No
Meets
requirements for
Level 2
Monitoring
Yes
?
Is the following true?
1. Control Circuit whose alarms are
automatically provided daily (or more
frequently) to a location where action
can be taken to initiate resolution for
alarmed failures.
2. Monitoring and alarming of
continuity of trip circuit(s).
Note: Trip coils, auxiliary relays, and
lock-out relays must be electrically
operated at Level 1 interval.
Yes
No
?
Meets
requirements for
Level 3
Monitoring
Is the following true?
1. Every function required for correct operation of
Control Cirucuit is continuously monitored and
verified, and detected maintenance-correctable
issues reported.
2. Verification of the means by which alarms and
monitored values are transmitted to a location
where action can be taken to initiate resolution.
3. Detected maintenance-correctable issues for
Control Circuit are be reported within 1 hour or
less of the maintenance-correctable issue
occurring, to a location where action can be taken
to initiate resolution.
4. Monitoring of the continuity of breaker trip
circuits (with alarming for non-continuity), along
with the presence of tripping voltage supply all the
way from relay terminals (or from inside the relay)
though the trip coil, including any auxiliary
contacts essential to proper Protection System
operation. If a trip circuit comprises multiple
paths, each of the paths must be monitored,
including monitoring of the operating coil circuit(s)
and the tripping circuits of auxiliary tripping relays
and lockout relays.
Level 1 Monitored
Control Circuit
Note: Trip coils, auxiliary relays, and lock-out
relays must be electrically operated at Level 1
interval.
End
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Page 37
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
DC SUPPLY
MONITOR LEVEL
DECISION TREE
Note: Physical inspection of the battery is
required regardless of level of monitoring used.
Start
No
Yes
?
Meets
requirements for
Level 2 Monitoring
Is the following true?
1. DC Supply whose alarms are automatically
provided daily (or more frequently) to a location
where action can be taken for alarmed failures.
2. Monitoring and alarming for the following
items:
- station dc supply
- unintential dc grounds
- electrolyte level of all cells
- individual battery cell/unit state of charge
- continuity of battery cell-to-cell and terminal
resistance
No
Yes
?
Meets
requirements for
Level 3 Monitoring
Is the following true?
1. Verification of the means by which alarms and
monitored values are transmitted to a location
where action can be taken.
2. Detected maintenance-correctable issues are
reported within 1 hour or less of the
maintenance-correctable issue occurring, to a
location where action can be taken to inititate
resolution of the maintenance correctable issue.
3. Monitoring and alarming the station dc supply
status, including, for station dc supplies that
have as a component a battery, the voltage,
specific gravity, electrolyte level, temperature
and connectivity (cell to cell and terminal
connection resistance) of each cell as well as
the battery system terminal voltage and
electrical continuity of the overall battery system.
4. Monitoring and alarming if the performance
capability of the battery is degraded.
5. Monitoring and alarming the ac powered dc
power supply status including low and high
voltage and charge rate for station dc supplies
that have battery systems.
Level 1 Monitored
DC Supply
End
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Page 38
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
DC SUPPLY
MONITOR LEVEL
DECISION TREE
Note: Physical inspection of the battery is
required regardless of level of monitoring used.
Start
No
Yes
?
Meets
requirements for
Level 2 Monitoring
Is the following true?
1. DC Supply whose alarms are automatically
provided daily (or more frequently) to a location
where action can be taken for alarmed failures.
2. Monitoring and alarming for the following
items:
- station dc supply
- unintential dc grounds
- electrolyte level of all cells
- individual battery cell/unit state of charge
- continuity of battery cell-to-cell and terminal
resistance
No
Yes
?
Meets
requirements for
Level 3 Monitoring
Is the following true?
1. Verification of the means by which alarms and
monitored values are transmitted to a location
where action can be taken.
2. Detected maintenance-correctable issues are
reported within 1 hour or less of the
maintenance-correctable issue occurring, to a
location where action can be taken to inititate
resolution of the maintenance correctable issue.
3. Monitoring and alarming the station dc supply
status, including, for station dc supplies that
have as a component a battery, the voltage,
specific gravity, electrolyte level, temperature
and connectivity (cell to cell and terminal
connection resistance) of each cell as well as
the battery system terminal voltage and
electrical continuity of the overall battery system.
4. Monitoring and alarming if the performance
capability of the battery is degraded.
5. Monitoring and alarming the ac powered dc
power supply status including low and high
voltage and charge rate for station dc supplies
that have battery systems.
Level 1 Monitored
DC Supply
End
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Page 39
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
COMMUNICATION SYSTEM
MONITOR LEVEL
DECISION TREE
Start
No
?
Meets
requirements for
Level 2 Monitoring
Yes
Is the following true?
1. Communication
Equipment whose alarms
are automatically provided
daily (or more frequently)
to a location where action
can be taken to initiate
resolution for alarmed
failures.
2. Monitoring and alarming
of protection
communications system
by mechanisms that check
for presence of the
communications channel.
No
?
Yes
Meets
requirements for
Level 3 Monitoring
Is the following true?
1. Verification of the means by
which alarms and monitored
values are transmitted to a
location where action can be
taken to initiate resolution.
2. Detected maintenancecorrectable issues are reported
within 1 hour or less of the
maintenance-correctable issue
occurring, to a location where
action can be taken to initiate
resolution.
3. Evaluating the performance of
the channel and its interface to
protective relays to determine
the quality of the channel and
alarming if the channel does not
meet performance criteria
Level 1 Monitored
Comm. Equip.
End
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Page 40
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
2. Level 1 Monitored Protection Systems (Unmonitored Protection Systems)
A.
We have an electromechanical (unmonitored)) relay that has a trip output to a lockout
relay (unmonitored) which trips our transformer off-line by tripping the transformer’s
high-side and low-side circuit breakers. What testing must be done for this system?
This system is made up of components that are level 1 (unmonitored).). Assuming a timebased protection system maintenance program schedule, each component must be maintained
per Table 1a – Level 1 Monitoring Maximum Allowable Testing Intervals and Maintenance
Activities.
3. Level 2 Monitored Protection Systems (Partially Monitored Protection Systems)
A.
We have a 30 year old oil circuit breaker with a red indicating lamp on the substation
relay panel that is illuminated only if there is continuity through the breaker trip coil..
There is no SCADA monitor or relay monitor of this trip coil. The line protection relay
package that trips this circuit breaker is a microprocessor relay that has an integral
alarm relay that will assert on a number of conditions that includes a loss of power to the
relay. This alarm contact connects to our SCADA system and alerts our 24-hour
operations center of relay trouble when the alarm contact closes. This microprocessor
relay trips the circuit breaker only and does not monitor trip coil continuity or other
things such as trip current. Is this an unmonitored or a partially-monitored system?
How often must I perform maintenance?
The protective relay is a level 2 (partially) monitored component of your protection system
and can be maintained every 12 years or when a maintenance correctable issue arises.
Assuming a time-based protection system maintenance program schedule, this component
must be maintained per Table 1b – Level 2 Monitoring Maximum Allowable Testing Intervals
and Maintenance Activities
The rest of your protection system contains components that are level 1 (unmonitored)) and
must be maintained within at least the maximum verification intervals of Table 1a..
B.
How do I verify the A/D converters of microprocessor--based relays?
There are a variety of ways to do this. Examples include using values gathered via data
communications and automatically comparing these values with values from other sources,
and using groupings of other measurements (such as vector summation of bus feeder currents)
for comparison if calibration requirements assure acceptable measurement of power system
input values. Other methods are possible.
C.
For a level 2 monitored Protection System (Partially Monitored Protection System)
pertaining to Protection System communications equipment and channels, how is the
performance criteria involved in the maintenance program?
The entity determines the performance criteria for each installation, depending on the
technology implemented. If the communication channel performance of a Protection System
varies from the pre-determined performance criteria for that system, these results should be
investigated and resolved.
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Page 41
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
D.
My system has alarms that are gathered once daily through an auto-polling system; this
is not really a conventional SCADA system but does it meet the Table 1b requirements
for inclusion as Level 2?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the maintenance-correctable issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
4. Level 3 Monitored Protection Systems (Fully Monitored Protection Systems)
A.
Why are there activities defined for a level-3 monitored Protection System? The
technology does not seem to exist at this time to implement this monitoring level.
There may actually be some equipment available that is capable of meeting level-3 monitoring
criteria, in which case it may be maintained according to Table 1c.
. However, even if there is no equipment available today that can meet this level of
monitoring,; the Standard establishes the necessary requirements for when such equipment
becomes available. By creating a roadmap for development, this provision makes the Standard
technology-neutral. The standard drafting team wants to avoid the need to revise the Standard
in a few years to accommodate technology advances that are certainly coming to the industry.
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Page 42
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
Ap p e n d ix A — P ro te c tio n S ys te m Ma in te n a n c e
S ta n d a rd Dra ftin g Te a m
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle E. Ashton
Tri-State Transmission and Generation
CooperativeG&T
Bob Bentert
Florida Power & Light Company
Al Calafiore
NERC Staff
North American Electric Reliability
Corporation
John Ciufo
Hydro One Inc
Richard Ferner
Western Area Power Administration
Sam Francis
Oncor
Carol A Gerou
Midwest Reliability Organization
Mark Lukas
ComEd
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
Mark Peterson
Great River Energy
William Shultz
Southern Company Generation
Leonard Swanson, Jr
National Grid USA
Roger D Greene
William Shultz
Southern Company Generation
Eric A Udren
Quanta Technology
Russell C Hardison
Tennessee Valley Authority
Philip B Winston
Georgia Power Company
David Harper
NRG Texas Maintenance Services
John A Zipp
ITC Holdings
John Kruse
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Page 43
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
In d e x
3-month interval, 24
corrective, 2, 5, 26
aggregate, 24, 25
countable events, 2, 25
alarm, 16, 17, 18, 29, 30,
38
current and voltage
measurements, 9
automated monitoring and
alarming, 24
data retention, 22
microprocessor, 5, 6, 7, 9,
10, 11, 13, 14, 26, 29,
30, 38
Misoperations, 2, 25
nickel-cadmium, 14, 15
ohmic, 14, 15, 29, 30
DC ground, 15
auto-restoration, 5
out-of-service, 7
documentation, 6, 21, 23,
31, 32
partially monitored, 11, 16
documentation method, 15
PBM, 24, 25, 26, 27
electromechanical, 7, 10,
26, 38
performance-based
maintenance, 25, 26
electro-mechanical relays,
6
pilot wire, 16
broken, 7
capacity, 14, 15, 29, 30
evidence, 6, 22
channel performance, 18,
38
fiber optic I/O scheme, 17
auxiliary relay, 11
batteries, 12, 13, 14, 15,
26, 27, 31
battery, 10, 12, 13, 14, 15,
26, 27, 29, 30
PMU, 19
power-line carrier, 16
pressure relays, 11, 12
firmware, 5, 25
frequency-shift, 16
protective relays, 5, 6, 7, 8,
10, 12, 13, 16, 18, 20
fully monitored, 16, 21
reclosing relays, 5
guard, 16, 17
Restoration, 5
Level 1, 16, 17, 31, 32, 38
sample list of devices, 20
Level 2, 16, 17, 31, 32, 38
segment, 2, 24, 25, 26, 27
Level 3, 16, 17, 27, 31, 39
settings, 2, 6, 7, 12, 22
lockout relay, 11, 20, 38
SPS, 5, 19, 31
maintenance correctable
issue, 2, 38
Table 1a, 2, 3, 5, 23, 32,
38
maintenance plan, 6, 22,
24
Table 1b, 5, 11, 17, 32, 38
charger, 12, 13, 14
check-off, 15
closing circuits, 5
commission, 23
Communication Site
Batteries, 15
communications, 7, 11, 16,
17, 18, 31, 38
communications channel,
16, 17
communications-assistedtrip, 11
component, 2, 5, 11, 14,
19, 22, 23, 25, 26, 29,
31, 32, 38
Table 1c, 2, 5, 21, 39
maximum allowable
interval, 24, 26
continuity, 12, 13, 14, 38
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TBM, 22
trip coil, 10, 11, 29, 30, 38
Page 44
PRC-005-2 — Protection System Maintenance - Frequently-Asked Questions
trip signal, 11, 17
unmonitored, 16, 29, 30,
38
voltage and current
sensing devices, 2, 8, 10
UVLS, 18, 19, 31
VRLA, 14, 15
trip test, 11
tripping circuits, 10
UFLS, 18, 19, 31
valve-regulated lead-acid,
15
unintentional ground, 15
vented lead-acid, 15, 29
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Page 45
PRC-005-2
Protection System Maintenance
Draft Supplementary Reference
May 27, 2010
Prepared by the
Protection System Maintenance and Testing Standard Drafting Team
PRC-005-2
Project 2007-17
Table of Contents
1. Introduction and Summary ..................................................................................................... 3
2. Need for Verifying Protection System Performance................................................................ 3
2.1 Existing NERC Standards for Protection System Maintenance and Testing .......................... 3
2.2 Proposed Modification to NERC Glossary Definition ........................................................... 4
2.3 Applicability of New Protection System Maintenance Standards .......................................... 4
2.4 Applicable Relays ................................................................................................................ 4
3. Relay Product Generations ..................................................................................................... 5
4. Definitions ............................................................................................................................. 5
5. Time-Based Maintenance (TBM) Programs ........................................................................... 6
Maintenance Practices ................................................................................................................. 6
5.1 Extending Time-Based Maintenance .................................................................................... 7
6. Condition-Based Maintenance (CBM) Programs .................................................................... 8
7. Time-Based versus Condition-Based Maintenance ................................................................. 9
8. Maximum Allowable Verification Intervals ............................................................................ 9
Maintenance Tests....................................................................................................................... 9
8.1 Table of Maximum Allowable Verification Intervals .......................................................... 10
Level 1 Monitoring (Unmonitored) Table 1a ............................................................................ 11
Level 2 Monitoring (Partially Monitored) Table 1b .................................................................. 11
Level 3 Monitoring (Fully Monitored) Table 1c ....................................................................... 11
8.2 Retention of Records .......................................................................................................... 12
8.3 Basis for Table 1 Intervals .................................................................................................. 13
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays ................................ 13
9. Performance-Based Maintenance Process ............................................................................. 15
9.1 Minimum Sample Size ....................................................................................................... 16
10. Overlapping the Verification of Sections of the Protection System ..................................... 18
11. Monitoring by Analysis of Fault Records ........................................................................... 18
12. Importance of Relay Settings in Maintenance Programs ..................................................... 19
13. Self-Monitoring Capabilities and Limitations ..................................................................... 20
14. Notification of Protection System Failures .......................................................................... 20
15. Maintenance Activities ....................................................................................................... 21
15.1 Protective Relays .............................................................................................................. 21
15.2 Voltage & Current Sensing Devices ................................................................................. 21
15.3 DC Control Circuitry ........................................................................................................ 22
15.4 Batteries and DC Supplies ................................................................................................ 23
15.5 Tele-protection equipment ................................................................................................ 23
15.6 Examples of Evidence of Compliance............................................................................... 24
16. References .......................................................................................................................... 26
Figures ...................................................................................................................................... 27
Figure 1: Typical Transmission System ..................................................................................... 27
Figure 2: Typical Generation System ........................................................................................ 28
Figure 3: Requirements Flowchart............................................................................................. 30
Appendix A............................................................................................................................... 31
Appendix B — Protection System Maintenance Standard Drafting Team .................................. 34
Draft 2: April, 2010
Page 2
This supplementary reference to PRC-005-2 borrows heavily from the technical reference by the System
Protection and Control Task Force (SPCTF) (Protection System Maintenance Technical Reference paper
approved by the Planning Committee in September 2007). Additionally, the Protection System
Maintenance and Testing Standard Drafting Team (PSMTSDT) for PRC-005-2 (Project 2007-17) utilized
maintenance program data from various generation and transmission utilities across the NERC
boundaries; as well as data from IEEE and EPRI.
1. Introduction and Summary
NERC currently has four reliability standards that are mandatory and enforceable in the United States and
address various aspects of maintenance and testing of Protection and Control systems. These standards
are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for Protection Systems,
and that these entities must be able to demonstrate they are carrying out such a program, there are no
specifics regarding the technical requirements for Protection System maintenance programs. Furthermore,
FERC Order 693 directed additional modifications respective to Protection System maintenance
programs. This revision of PRC-005-1 combines and replaces PRC-005, PRC-008, PRC-011 and PRC017.
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate their
performance until a fault or other power system problem requires that they operate to protect power
system elements, or even the entire Bulk Electric System (BES). Lacking faults or system problems, the
protection systems may not operate for extended periods. A Misoperation - a false operation of a
protection system or a failure of the protection system to operate, as designed, when needed - can result in
equipment damage, personnel hazards, and wide area disturbances or unnecessary customer outages. A
maintenance or testing program is used to determine the performance and availability of protection
systems.
Typically, utilities have tested protection systems at fixed time intervals, unless they had some incidental
evidence that a particular protection system was not behaving as expected. Testing practices vary widely
across the industry. Testing has included system functionality, calibration of measuring relays, and
correctness of settings. Typically, a protection system must be visited at its installation site and removed
from service for this testing.
Fundamentally, a reliability standard for Protection System Maintenance and Testing requires the
performance of the maintenance activities that are necessary to detect and correct plausible age and
service related degradation of components such that a properly built and commissioned Protection System
will continue to function as designed over its service life.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset owner
define a testing program. The starting point is the existing Standard PRC-005, briefly restated as follows:
Purpose: To ensure all transmission and generation Protection Systems affecting the reliability of the
Bulk Electric System (BES) are maintained and tested.
Draft 2: April, 2010
Page 3
PRC-005-1 is not specific on where the boundaries of the Protection Systems lie. However, the definition
of Protection System in the NERC Glossary of Terms used in Reliability Standards indicates what must
be included as a minimum.
Definition of Protection System (excerpted from the NERC Standards Glossary of Terms):
Protective relays, associated communication systems, voltage and current sensing devices, station
batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
Requirements: The owner shall have a documented maintenance program with test intervals. The owner
must keep records showing that the maintenance was performed at the specified intervals.
2.2 Proposed Modification to NERC Glossary Definition
The Protection Systems Maintenance and Testing Standard Drafting Team (PSM SDT), proposes changes
to the NERC glossary definition of Protection Systems as follows:
Protection System (modification) - Protective relays, communication systems necessary for correct
operation of protective functions, voltage and current sensing devices inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station DC supply, and control
circuitry, associated with protective functions from the station DC supply through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from the
original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“… and that are applied on, or are designed to provide protection for the BES.”
The drafting team intends that this Standard will not apply to “merely possible” parallel paths, (subtransmission and distribution circuits), but rather the standard applies to any Protection System that is
designed to detect a fault on the BES and take action in response to that fault. The Standard Drafting
Team does not feel that Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the Regional definitions of the
BES.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and voltage
sensing devices, dc control circuitry and associated communications circuits. The relays to which this
standard applies are those relays that use measurements of voltage, current, frequency and/or phase angle
and provide a trip output to trip coils, dc control circuitry or associated communications equipment. This
definition extends to IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or trip-free relay)
as these devices are tripping relays that respond to the trip signal of the protective relay that processed the
signals from the current and voltage sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration, pressure,
seismic, thermal or gas accumulation) are not included.
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3. Relay Product Generations
The likelihood of failure and the ability to observe the operational state of a critical protection system,
both depends on the technological generation of the relays as well as how long they have been in service.
Unlike many other transmission asset groups, protection and control systems have seen dramatic
technological changes spanning several generations. During the past 20 years, major functional advances
are primarily due to the introduction of microprocessor technology for power system devices such as
primary measuring relays, monitoring devices, control systems, and telecommunications equipment.
Modern microprocessor based relays have six significant traits that impact a maintenance strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and some
connected substation inputs and outputs such as trip coil continuity. Most relay users are aware
that these relays have self monitoring, but are not focusing on exactly what internal functions are
actually being monitored. As explained further below, every element critical to the protection
system must be monitored, or else verified periodically.
•
Ability to capture fault records showing how the protection system responded to a fault in its zone
of protection, or to a nearby fault for which it is required not to operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-fault times. The relays can compute values such as MW and MVAR line
flows that are sometimes used for operational purposes such as SCADA.
•
Data communications via ports that provide remote access to all of the results of protection
system monitoring, recording, and measurement.
•
Ability to trip or close circuit breakers and switches through the protection system outputs, on
command from remote data communications messages or from relay front panel button requests.
•
Construction from electronic components some of which have shorter technical life or service life
than electromechanical components of prior protection system generations.
4. Definitions
Protection System Maintenance Program (PSMP) – An ongoing program by which Protection System
components are kept in working order and proper operation of malfunctioning components is restored. A
maintenance program for a specific component includes one or more of the following activities:
An ongoing program by which Protection System components are kept in working order and where
malfunction components are restored to working order
Verification – A means of determining that the component is functioning correctly.
•
Monitoring – Observation of the routine in-service operation of the component.
•
Testing – Application of signals to a component to observe functional performance or output
behavior, or to diagnose problems.
•
Inspection – To detect visible signs of component failure, reduced performance and degradation.
•
Calibration – Adjustment of the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
•
Upkeep – Routine activities necessary to assure that the component remains in good working
order and implementation of any manufacturer’s hardware and software service advisories which
are relevant to the application of the device.
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•
Restoration – The actions to restore proper operation of malfunctioning components.
5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which protection systems are maintained or verified according
to a time schedule. The scheduled program often calls for technicians to travel to the physical site and
perform a functional test on protection system components. However, some components of a TBM
program may be conducted from a remote location - for example, tripping a circuit breaker by
communicating a trip command to a microprocessor relay to determine if the entire protection system
tripping chain is able to operate the breaker.
Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have been
developed from prior experience or manufacturers’ recommendations. The TBM verification
interval is based on a variety of factors, including experience of the particular asset owner,
collective experiences of several asset owners who are members of a country or regional council,
etc. The maintenance intervals are fixed, and may range in number of months or in years.
TBM can include review of recent power system events near the particular terminal. Operating
records may verify that some portion of the protection system has operated correctly since the last
test occurred. If specific protection scheme components have demonstrated correct performance
within specifications, the maintenance test time clock is reset for those components.
•
PBM – performance-based maintenance - intervals are established based on analytical or
historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied by
adjustments to maintenance intervals are used to justify continued use of PBM-developed
extended intervals when test failures or in-service failures occur infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from nondisruptive self monitoring of components demonstrate operational status as those components
remain in service. Whatever is verified by CBM does not require manual testing, but taking
advantage of this requires precise technical focus on exactly what parts are included as part of the
self diagnostics.
Microprocessor based protective relays that perform continuous self-monitoring verify correct
operation of most components within the device. Self-monitoring capabilities may include the ac
signal inputs, analog measuring circuits, processors and memory for measurement, protection,
and data communications, trip circuit monitoring, and protection or data communications signals.
For those conditions, failure of a self-monitoring routine generates an alarm and may inhibit
operation to avoid false trips. When internal components, such as critical output relay contacts,
are not equipped with self-monitoring, they can be manually tested. The method of testing may
be local or remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike TBM,
PBM intervals are adjusted based on good or bad experiences. The CBM verification intervals can be
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hours or even milliseconds between non-disruptive self monitoring checks within or around components
as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete Protection
System. The following diagram illustrates the relationship between various types of maintenance
practices described in this section. In the Venn diagram the overlapping regions show the relationship of
TBM with PBM historical information and the inherent continuous monitoring offered through CBM.
This figure shows:
•
•
•
Region 1: The TBM intervals that are increased based on known reported operational condition of
individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been subject to
TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
5.1 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly established to
assure proper functioning of each component of the protection system, when data on the reliability of the
components is not available other than observations from time-based maintenance. The following factors
may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from relay self
monitoring, for example), the intervals may be extended or manual testing may be eliminated.
This is referred to as condition-based maintenance or CBM. CBM is valid only for precisely the
components subject to monitoring. In the case of microprocessor-based relays, self-monitoring
may not include automated diagnostics of every component within a microprocessor.
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•
Previous maintenance history for a group of components of a common type may indicate that the
maintenance intervals can be extended while still achieving the desired level of performance. This
is referred to as performance-based maintenance or PBM. It is also sometimes referred to as
reliability-centered maintenance or RCM, but PBM is used in this document.
•
Observed proper operation of a component may be regarded as a maintenance verification of the
respective component or element in a microprocessor-based device. For such an observation, the
maintenance interval may be reset only to the degree that can be verified by data available on the
operation. For example, the trip of an electromechanical relay for a fault verifies the trip contact
and trip path, but only through the relays in series that actually operated; one operation of this
relay cannot verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is not unusual
to cause failure of a component by removing it from service and restoring it. The improper application of
test signals may cause failure of a component. For example, in electromechanical overcurrent relays, test
currents have been known to destroy convolution springs.
In addition, maintenance usually takes the component out of service, during which time it is not able to
perform its function. Cutout switch failures, or failure to restore switch position, commonly lead to
protection failures.
6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information available from
modern microprocessor-based relays and other intelligent electronic devices (IEDs) that monitor
protection system elements. These relays and IEDs generate monitoring information during normal
operation, and the information can be assessed at a convenient location remote from the substation. The
information from these relays and IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in relay logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillograph records for
faults and disturbances, metered values, and binary input status reports. Some of these are
available on the relay front panel display, but may be available via data communications
ports. Large files of fault information can only be retrieved via data communications.
These results comprise a mass of data that must be further analyzed for evidence of the
operational condition of the protection system.
Using these two types of information, the user can develop an effective maintenance program carried out
mostly from a central location remote from the substation. This approach offers the following advantages:
1. Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
2. Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some relays will show health problems by
incorrect relaying before being caught in the next test round. The frequent or continuous
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nature of CBM makes the effective verification interval far shorter than any required
TBM maximum interval.
7. Time-Based versus Condition-Based Maintenance
Time-based and condition-based maintenance programs are both acceptable, if implemented according
to technically sound requirements. Practical programs can employ a combination of time-based and
condition-based maintenance. The standard requirements introduce the concept of optionally using
condition monitoring as a documented element of a maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule dated March
16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability Standards for the BulkPower System, directed NERC to submit a modification to PRC-005-1 that includes a requirement that
maintenance and testing of a protection system must be carried out within a maximum allowable interval
that is appropriate to the type of the protection system and its impact on the reliability of the Bulk Power
System. Accordingly, this Supplementary Reference Paper refers to the specific maximum allowable
intervals in PRC-005-2. The defined time limits allow for longer time intervals if the maintained device is
monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay between the
moment of a protection failure and time the protection system owner knows about it, for the monitored
segments of the protection system. In some cases, the verification is practically continuous - the time
interval between verifications is minutes or seconds. Thus, technically sound, condition-based verification
(as specified in the header and the “Monitoring Attributes” column of Tables 1b and 1c of PRC-005-2),
meets the verification requirements of the FERC order even more effectively than the strictly time-based
tests of the same system elements as contained in Table 1a.
The result is that:
This NERC standards permits utilities to use a technically sound approach and to take advantage of
remote monitoring, data analysis, and control capabilities of modern protection systems to reduce the
need for periodic site visits and invasive testing of components by on-site technicians. This periodic
testing must be conducted within maximum time intervals specified in Tables 1a, 1b and 1c of PRC-0052.
8. Maximum Allowable Verification Intervals
The Maximum Allowable Testing Intervals and Maintenance Activities requirements show how CBM
with newer relay types can reduce the need for many of the tests and site visits that older protection
systems require. As explained below, there are some sections of the protection system that monitoring or
data analysis may not verify. Verifying these sections of the Protection Systems requires some persistent
TBM activity in the maintenance program. However, some of this TBM can be carried out remotely - for
example, exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if there has
been no fault or routine operation to demonstrate performance of relay tripping circuits.
Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is operating
correctly after a time period of field installation. These tests may be used to ensure that individual
components are still operating within acceptable performance parameters - this type of test is needed for
components susceptible to degraded or changing characteristics due to aging and wear. Full system
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performance tests may be used to confirm that the total protection system functions from measurement of
power system values, to properly identifying fault characteristics, to the operation of the interrupting
devices.
8.1 Table of Maximum Allowable Verification Intervals
Table 1, in the standard, specifies maximum allowable verification intervals for various generations of
protection systems and categories of equipment that comprise protection systems. The right column
indicates maintenance activities required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1 shows an
example of telecommunications-assisted line protection system comprising substation equipment at each
terminal and a telecommunications channel for relaying between the two substations. Figure 2 shows a
typical Generation station layout. The various subsystems of a Protection System that need to be verified
are shown. UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated in these
Figures.
While it is easy to associate protective relays to the three levels of monitoring, it is also true that most of
the components that can make up a Protection System can also have technological advancements that
place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables (Tables 1a, 1b and 1c collectively Tables) from
PRC-005-2:
• First check the table header description to verify that your equipment meets the monitoring
requirements. If your equipment does not meet the monitoring requirements of Table 1c then
check Table 1b. If your equipment does not meet the requirements of Table 1b then use Table 1a.
•
If you find a piece of equipment that meets the monitoring requirements of Table 1b or 1c then
you can take advantage of the extended time intervals allowed by Table 1b and 1c. Your
maintenance plan must document that this component can be maintained by the requirements of
Table 1b or 1c because it has the necessary attributes required within that Table.
•
Once you determine which table applies to your equipment’s monitoring requirements then check
the Maintenance Activity that is required for that particular component. This Maintenance
Activity is the minimum maintenance activity that must be documented.
•
If your PSMP (plan) requires more then you must document more.
•
After the maintenance activity is known, check the Maximum Maintenance Interval; this time is
the maximum time allowed between hands-on maintenance activity cycles of this component.
•
If your PSMP (plan) requires activities more often than the Tables maximum then you must
document those activities more often.
•
Any given set of Protection System equipment can be maintained with any combination of Tables
1a, 1b and 1c. An entity does not have to stick to Table 1a just because some of its equipment is
un-monitored.
•
An entity does not have to utilize the extended time intervals in Tables 1b or 1c. An easy choice
to make is to simply utilize Table 1a. While the maintenance activities resulting from choosing to
use only Table 1a would require more maintenance man-hours, the maintenance requirements
may be simpler to document and the resulting maintenance plans may be easier to create.
For each Protection System component, Table 1 shows maximum allowable testing intervals for
unmonitored, partially monitored and fully monitored protection systems:
Table 1 Maximum Allowable Testing Intervals and Maintenance Activities
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Level 1 Monitoring (Unmonitored) Table 1a
This table applies to electromechanical, analog solid state and other un-monitored Protection Systems
components. This table represents the starting point for all required maintenance activities. The object of
this group of requirements is to have specific activities accomplished at maximum set time intervals.
From this group of activities it follows that CBM or PBM can increase the time intervals between the
hands-on maintenance actions.
Level 2 Monitoring (Partially Monitored) Table 1b
This table applies to microprocessor relays and other associated Protection System components whose
self-monitoring alarms are transmitted to a location (at least daily) where action can be taken for alarmed
failures. The attributes of the monitoring system must meet the requirements specified in the header of the
Table 1b. Given these advanced monitoring capabilities, it is known that there are specific and routine
testing functions occurring within the device. Because of this ongoing monitoring hands-on action is
required less often because routine testing is automated. However, there is now an additional task that
must be accomplished during the hands-on process – the monitoring and alarming functions must be
shown to work.
Level 3 Monitoring (Fully Monitored) Table 1c
This table applies to microprocessor relays and other associated Protection System components in which
every element or function required for correct operation of the Protection System component is monitored
continuously and verified, including verification of the means by which failure alarms or indicators are
transmitted to a location within 1 hour or less of the maintenance-correctable issue occurring. This is the
highest level of monitoring and if it is available then this gives an entity the ability to have continuous
testing of their (Level 3 Monitored) Protection System Component and thus does not have to manually
intervene to accomplish routine testing chores. Level 3 Fully Monitored yields continuous monitoring
advantages but has substantial technical hurdles that must be overcome; namely that monitoring also
verifies the failure of the monitoring and alarming equipment. Without this important ingredient a device
that is thought to be continuously monitored could be in an alarm state without the asset owner being
aware of this alarm state.
Additional Notes for Table 1a, Table 1b, and Table 1c
1. For electro-mechanical relays, adjustment is required to bring measurement accuracy within the
tolerance needed by the asset owner. Microprocessor-relays with no remote monitoring of alarm
contacts, etc, are un-monitored relays and need to be verified within the Table interval as other
un-monitored relays but may be verified as functional by means other than testing by simulated
inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring calibration, but
acceptable measurement of power system input values must be verified (verification of the
Analog to Digital [A/D] converters) within the Table intervals. The integrity of the digital inputs
and outputs must be verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a protection system or
SPS (as opposed to a monitoring task) must be verified as a component in a protection system.
4. In addition to verifying the circuitry that supplies dc to the protection system, the owner must
maintain the station dc supply. The most widespread station dc supply is the station battery and
charger. Unlike most Protection System elements physical inspection of station batteries for
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signs of component failure, reduced performance, and degradation are required to ensure that the
station battery is reliable enough to deliver dc power when required. IEEE Standards 450, 1188,
and 1106 for Vented Lead-Acid, Valve-Regulated Lead-Acid, and Nickel-Cadmium batteries,
respectively (which are the most commonly used substation batteries on the NERC BES) have
been developed as an important reference source of maintenance recommendations. The
Protection System owner might use the applicable IEEE recommended practice which contains
information and recommendations concerning the maintenance, testing and replacement of its
substation battery. However, the methods prescribed in these IEEE recommendations cannot be
specifically required because they do not apply to all battery applications.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS systems,
and large entities will usually maintain a portion of these systems in any given year.
Additionally, if relatively small quantities of such systems do not perform properly, it will not
affect the integrity of the overall program.
6. Voltage & Current Sensing Device circuit input connections to the protection system relays can
be verified by comparison of measured values on live circuits or by using test currents and
voltages on equipment out of service for maintenance. The verification process can be automated
or manual. The values should be verified to be as expected, (phase value and phase relationships
are both equally important to verify).
7. Verify the protection system tripping function by performing an operational trip test on all
components contained in the trip circuit. This includes circuit breaker or circuit switcher trip
coils, auxiliary tripping relays (94), lock-out relays (86), and communications-assisted trip
scheme elements. Each control circuit path that carries trip signal must be verified, although each
path must be checked only once. A maintenance program may include performing an overall test
for the entire system at one time, or several split system tests with overlapping trip verification. A
documented real-time trip of any given trip path is acceptable in lieu of a functional trip test.
8. “End-to-end test” as used in this supplementary reference is any testing procedure that creates a
remote input to the local communications-assisted trip scheme. While this can be interpreted as a
GPS-type functional test it is not limited to testing via GPS. Any remote scheme manipulation
that can cause action at the local trip path can be used to functionally-test the dc Control
Circuitry. A documented real-time trip of any given trip path is acceptable in lieu of a functional
trip test. It is possible, with sufficient monitoring, to be able to verify each and every parallel trip
path that participated in any given dc Control Circuit trip. Or, another possible solution is that a
single trip path from a single monitored relay can be verified to be the trip path that successfully
tripped during a real-time operation. The variations are only limited by the degree of engineering
and monitoring that an entity desires to pursue.
9. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus feeder
currents) can be used for comparison if calibration requirements assure acceptable measurement
of power system input values.
10. Notes 1-9 attempt to describe the testing activities they do not represent the only methods to
achieve these activities but rather some possible methods.
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three years.
However, with a three year retention cycle, the records of verification for a protection system will
typically be discarded before the next verification, leaving no record of what was done if a Misoperation
or failure is to be analyzed.
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PRC-005-2 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation
of the two most recent performances of each distinct maintenance activity for the Protection System
components, or to the previous on-site audit date, whichever is longer.
This requirement assures that the documentation shows that the interval between maintenance cycles
correctly meets the maintenance interval limits.
8.3 Basis for Table 1 Intervals
SPCTF authors collected all available data from Regional Entities (REs) on time intervals recommended
for maintenance and test programs. The recommendations vary widely in categorization of relays, defined
maintenance actions, and time intervals, precluding development of intervals by averaging. SPCTF also
reviewed the 2005 Report [2] of the IEEE Power System Relaying Committee Working Group I-17
(Transmission Relay System Performance Comparison). Review of the I-17 report shows data from a
small number of utilities, with no company identification or means of investigating the significance of
particular results.
To develop a solid current base of practice, SPCTF surveyed its members regarding their maintenance
intervals for electromechanical and microprocessor relays, and asked the members to also provide
definitively-known data for other entities. The survey represented 470 GW of peak load, or 64% of the
NERC peak load. Maintenance interval averages were compiled by weighting reported intervals
according to the size (based on peak load) of the reporting utility. Thus, the averages more accurately
represent practices for the large populations of protection systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of 5 years for
electromechanical or solid state relays, and 7 years for un-monitored microprocessor relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond 7 years,
based on favorable experience with the particular products they have installed. To provide a technical
basis for such extension, SPCTF authors developed a recommendation of 10 years using the Markov
modeling approach from [1] as summarized in Section 8.4. The results of this modeling depend on the
completeness of self-testing or monitoring. Accordingly, this extended interval is allowed by Table 1 only
when such relays are monitored as specified in the header of Table 1b. Monitoring is capable of reporting
protection system health issues that are likely to affect performance within the 10 year time interval
between verifications.
It is important to note that, according to modeling results, protection system availability barely changes as
the maintenance interval is varied below the 10-year mark. Thus, reducing the maintenance interval does
not improve protection system availability. With the assumptions of the model regarding how
maintenance is carried out, reducing the maintenance interval actually degrades protection system
availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level. The industry
has experience with self-monitoring microprocessor relays that leads to the Table 1 value for partial
monitoring as explained in Section 8.3. To develop a basis for the maximum interval for monitored
relays in their Protection System Maintenance – A Technical Reference, the SPCTF used the
methodology of Reference [1], which specifically addresses optimum routine maintenance intervals. The
Markov modeling approach of [1] is judged to be valid for the design and typical failure modes of
microprocessor relays.
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The SPCTF authors ran test cases of the Markov model to calculate two key probability measures:
• Relay Unavailability - the probability that the relay is out of service due to failure or maintenance
activity while the power system element to be protected is in service.
• Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a fault occurs, leading to failure to operate for the fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test). ST = 0 if
there is no self-monitoring; ST = 1 for full monitoring. Practical ST values are estimated to range from
.75 to .95. The SPCTF simulation runs used constants in the Markov model that were the same as those
used in [1] with the following exceptions:
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal fault clearing time of 10 cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup fault clearing time of 50 cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a protection system)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a protection system repair after failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to these
parameter adjustments.
The resulting curves for Relay Unavailability and Abnormal Unavailability versus maintenance interval
showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years – the curve is flat,
with no significant change in either unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years, much lower than MTBF values
typically published for these relays. Also, the Markov modeling indicates that both the relay
unavailability and abnormal unavailability actually become higher with more frequent testing. This
shows that the time spent on these more frequent tests yields no failure discoveries that approach the
negative impact of removing the relays from service and running the tests.
PSMT SDT further notes that the SPCTF also allowed 25% extensions to the “maximum time intervals”.
With a 5 year time interval established between manual maintenance activities and a 25% time extension
then this equates to a 6.25 year maximum time interval. It is the belief of the PSMT SDT that the SPCTF
understood that 6.25 years was thereby an adequate maximum time interval between manual maintenance
activities. The PSMT SDT has followed the FERC directive for a maximum time interval and has
determined that no extensions will be allowed. Six years has been set for the maximum time interval
between manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval between
maintenance activities. A 10 year interval with a 25% allowed extension equates to a maximum allowed
interval of 12.5 years between manual maintenance activities. The Standard does not allow extensions on
any component of the protection system; thus the maximum allowed interval for these devices has been
set to12 years. Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum Maintenance
Interval”. The PSMT SDT deemed it necessary to include the term “Calendar” to facilitate annual
maintenance planning, scheduling and implementation. This need is the result of known occurrences of
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system requirements that could cause maintenance schedules to be missed by a few days or weeks. The
PSMT SDT chose the term “Calendar” to preclude the need to have schedules be met to the day. An
electro-mechanical protective relay that is maintained in year #1 need not be revisited until 6 years later
(year #7). For example: a relay was maintained April 10, 2008; maintenance would need to be completed
no later than December 31, 2014.
Section 9 describes a performance-based maintenance process which can be used to justify maintenance
intervals other than those described in Table 1.
Section 10 describes sections of the protection system, and overlapping considerations for full verification
of the protection system by segments. Segments refer to pieces of the protection system, which can range
from a single device to a panel to an entire substation.
Section 11 describes how relay operating records can serve as a basis for verification, reducing the
frequency of manual testing.
Section 13 describes how a cooperative effort of relay manufacturers and protection system users can
improve the coverage of self-monitoring functions, leading to full monitoring of the bulk of the protection
system, and eventual elimination of manual verification or testing.
9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a performance-based maintenance process may be used to establish
maintenance intervals (PRC-005 Attachment A Criteria for a Performance-Based Protection System
Maintenance Program). A performance-based maintenance process may justify longer maintenance
intervals, or require shorter intervals relative to Table 1. In order to use a performance-based maintenance
process, the documented maintenance program must include records of repairs, adjustments, and
corrections to covered protection systems in order to provide historical justification for intervals other
than those established in Table 1. Furthermore, the asset owner must regularly analyze these records of
corrective actions to develop a ranking of causes. Recurrent problems are to be highlighted, and remedial
action plans are to be documented to mitigate or eliminate recurrent problems.
Utilities with performance-based maintenance track performance of protection systems, demonstrate how
they analyze findings of performance failures and aberrations, and implement continuous improvement
actions. Since no maintenance program can ever guarantee that no malfunction can possibly occur,
documentation of a performance-based maintenance program would serve the utility well in explaining to
regulators and the public a Misoperation leading to a major system outage event.
A performance-based maintenance program requires auditing processes like those included in widely used
industrial quality systems (such as ISO 9001-2000, Quality management systems — Requirements; or
applicable parts of the NIST Baldridge National Quality Program). The audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance-based Maintenance (PBM) program the asset owner must first sort the
various Protection System components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM but does not own 60 units to
comprise a population then that asset owner may combine data from other asset owners until the needed
60 units is aggregated. Each population segment must be composed of like devices from the same
manufacturer and subjected to similar environmental factors. For example: One segment cannot be
Draft 2: April, 2010
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comprised of both GE & Westinghouse electro-mechanical lock-out relays; likewise, one segment cannot
be comprised of 60 GE lock-out relays, 30 of which are in a dirty environment and the remaining 30 from
a clean environment.
9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling distribution of the
sample mean can be approximated by a normal probability distribution.” The Central Limit Theorem
states: “In selecting simple random samples of size n from a population, the sampling distribution of the
sample mean x can be approximated by a normal probability distribution as the sample size becomes
large.” (Essentials of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003)
To use the Central Limit Theorem in statistics, the population size should be large. The references below
are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30), the
central limit theorem enables us to conclude that the sampling distribution of the sample
mean can be approximated by a normal distribution.” (Essentials of Statistics for
Business and Economics, Anderson, Sweeney, Williams, 2003)
“If samples of size n, when n>=30, are drawn from any population with a mean u and a
standard deviation σ, the sampling distribution of sample means approximates a normal
distribution. The greater the sample size, the better the approximation.” (Elementary
Statistics - Picturing the World, Larson, Farber, 2003)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005)
“… the normal is often used as an approximation to the t distribution in a test of a null
hypothesis about the mean of a normally distributed population when the population
variance is estimated from a relatively large sample. A sample size exceeding 30 is often
given as a minimal size in this connection.” (Statistical Analysis for Business Decisions,
Peters, Summers, 1968)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated using the
bound on the Error of Distribution Formula when the expected result is of a “Pass/Fail” format and will
be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
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Β = bound on the error of distribution (allowable error)
z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
z
n = π(1 − π)
Β
2
Minimum Population Size to use Performance-based Program
One entity’s population of components should be large enough to represent a sizeable sample of a
vendor’s overall population of manufactured devices. For this reason the following assumptions are
made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-based Program
The number of components that should be included in a sample size for evaluation of the appropriate
testing interval can be smaller because a lower confidence level is acceptable since the sample testing is
repeated or updated annually. For this reason, the following assumptions are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation mentioned.
Using this and the results of the equation, the following numbers are recommended:
Minimum Population Size to use Performance-based Maintenance Program = 60
Minimum Sample Size to evaluate Performance-based Program = 30.
Once the population segment is defined then maintenance must begin within the intervals as outlined for
Level 1 monitoring, (Table 1a). Time intervals can be lengthened provided the last year’s worth of
devices tested (or the last 30 units maintained, whichever is more) had fewer than 4% countable events. It
is notable that 4% is specifically chosen because an entity with a small population (60 units) would have
to adjust its time intervals between maintenance if more than 1 countable event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to adjust the time
Draft 2: April, 2010
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interval between maintenance activities if even one unit is found out of tolerance or causes a misoperation.
The minimum number of units that can be tested in any given year is 5% of the population. Note that this
5% threshold sets a practical limitation on total length of time between intervals at 20 years.
If at any time the number of countable events equals or exceeds 4% of the last year’s tested-devices (or
the last 30 units maintained, whichever is more) then the time period between manual maintenance
activities must be decreased. There is a time limit on reaching the decreased time at which the countable
events is less than 4%; this must be attained within three years.
This additional time period of three years to restore segment performance to <4% countable events is
mandated to keep entities from “gaming the PBM system”. It is believed that this requirement provides
the economic disincentives to discourage asset owners from arbitrarily pushing the PBM time intervals
out to up to 20 years without proper statistical data.
10. Overlapping the Verification of Sections of the Protection System
Table 1 requires that every protection system element be periodically verified. One approach is to test the
entire protection scheme as a unit, from voltage and current sources to breaker tripping. For practical
ongoing verification, sections of the protection system may be tested or monitored individually. The
boundaries of the verified sections must overlap to ensure that there are no gaps in the verification. See
Appendix A for additional discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as appropriate, to
establish and operate a maintenance program. For example, a protection system may be divided into
multiple overlapping sections with a different maintenance methodology for each section:
•
•
•
•
Time-based maintenance with appropriate maximum verification intervals for categories
of equipment as given in the Unmonitored, Partially Monitored, or Fully Monitored
Tables;
Full monitoring as described in header of Table 1c;
A performance-based maintenance program as described in Section 9;
Opportunistic verification using analysis of fault records as described in Section 11
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve fault event records and oscillographic records by data
communications after a fault. They analyze the data closely if there has been an apparent Misoperation, as
NERC standards require. Some advanced users have commissioned automatic fault record processing
systems that gather and archive the data. They search for evidence of component failures or setting
problems hidden behind an operation whose overall outcome seems to be correct. The relay data may be
augmented with independently captured digital fault recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for a manual
time-interval based check on protection systems whose operations are analyzed. Even electromechanical
protection systems instrumented with DFR channels may achieve some CBM benefit. The completeness
of the verification then depends on the number and variety of faults in the vicinity of the relay that
produce relay response records, and the specific data captured.
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A typical fault record will verify particular parts of certain protection systems in the vicinity of the fault.
For a given protection system installation, it may or may not be possible to gather within a reasonable
amount of time an ensemble of internal and external fault records that completely verify the protection
system.
For example, fault records may verify that the particular relays that tripped are able to trip via the control
circuit path that was specifically used to clear that fault. A relay or DFR record may indicate correct
operation of the protection communications channel. Furthermore, other nearby protection systems may
verify that they restrain from tripping for a fault just outside their respective zones of protection. The
ensemble of internal fault and nearby external fault event data can verify major portions of the protection
system, and reset the time clock for the Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel with
multiple relays, only the specific relay(s) whose operation can be observed without ambiguity in the
record and the associated wiring paths are verified. Be careful about using fault response data to verify
that settings or calibration are correct. Unless records have been captured for multiple faults close to
either side of a setting boundary, setting or calibration could still be incorrect.
If fault record data is used to show that portions or all of a protection system have been verified to meet
Table 1 requirements, the owner must retain the fault records used, and the maintenance related
conclusions drawn from this data and used to defer Table 1 tests, for at least the retention time interval
given in Section 8.2.
12. Importance of Relay Settings in Maintenance Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to show that
the relays have correct settings and calibration. Microprocessor relays, by contrast, provide the means for
continuously monitoring measurement accuracy. Furthermore, the relay digitizes inputs from one set of
signals to perform all measurement functions in a single self-monitoring microprocessor system. These
relays do not require testing or calibration of each setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older relays. Some
microprocessor relays have hundreds or thousands of settings, many of which are critical to protection
system performance.
Monitoring does not check measuring element settings. Analysis of fault records may or may not reveal
setting problems. To minimize risk of setting errors after commissioning, the user should enforce strict
settings data base management, with reconfirmation (manual or automatic) that the installed settings are
correct whenever maintenance activity might have changed them. For background and guidance, see [5].
Table 1 requires that settings must be verified to be as specified. The reason for this requirement is
simple. With legacy relays (non-microprocessor protective relays) it is necessary to know the value of the
intended setting in order to test, adjust and calibrate the relay. Proving that the relay works per specified
setting was the de facto procedure. However, with the advanced microprocessor relays it is possible to
change relay settings for the purpose of verifying specific functions and then neglect to return the settings
to the specified values. While there is no specific requirement to maintain a settings management process
there remains a need to verify that the settings left in the relay are the intended, specified settings. This
need may manifest itself after any of the following:
•
•
•
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
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13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products for nearly
20 years. Theoretically, any element that is monitored does not need a periodic manual test. A problem
today is that the community of manufacturers and users has not created clear documentation of exactly
what is and is not monitored. Some unmonitored but critical elements are buried in installed systems that
are described as self-monitoring.
Until users are able to document how all parts of a system which are required for the protective functions
are monitored or verified (with help from manufacturers), they must continue with the unmonitored or
partially monitored intervals established in Table 1.
Going forward, manufacturers and users can develop mappings of the monitoring within relays, and
monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of full monitoring, the manufacturers of the microprocessor-based self-monitoring
components in the protection system should publish for the user a document or map that shows:
•
How all internal elements of the product are monitored for any failure that could
impact protection system performance.
•
Which connected circuits are monitored by checks implemented within the product;
how to connect and set the product to assure monitoring of these connected circuits;
and what circuits or potential problems are not monitored.
With this information in hand, the user can document full monitoring for some or all sections by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component and
circuit that is critical to protection is monitored by the microprocessor product(s) or by
other design features.
•
Extending the monitoring to include the alarm transmission facilities through which
failures are reported within a given time frame to allocate where action can be taken to
initiate resolution of the alarm attributed to a maintenance correctable issue, so that
failures of monitoring or alarming systems also lead to alarms and action.
•
Documenting the plans for verification of any unmonitored elements according to the
requirements of Table 1.
14. Notification of Protection System Failures
When a failure occurs in a protection system, power system security may be compromised, and
notification of the failure must be conducted in accordance with relevant NERC standard(s). Knowledge
of the failure may impact the system operator’s decisions on acceptable loading conditions.
This formal reporting of the failure and repair status to the system operator by the protection system
owner also encourages the system owner to execute repairs as rapidly as possible. In some cases, a
microprocessor relay or carrier set can be replaced in hours; wiring termination failures may be repaired
in a similar time frame. On the other hand, a component in an electromechanical or early-generation
electronic relay may be difficult to find and may hold up repair for weeks. In some situations, the owner
may have to resort to a temporary protection panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would be that a
BES entity could be prudent in its protective relay maintenance but if its battery maintenance program is
lacking then reliability could still suffer. The NERC glossary outlines a Protection System as containing
specific components. PRC-005-02 requires specific maintenance activities be accomplished within a
specific time interval. As noted previously, higher technology equipment can contain integral monitoring
capability that actually performs maintenance verification activities routinely and often; therefore manual
intervention to perform certain activities on these type devices may not be needed.
15.1 Protective Relays
These relays are defined as the devices that receive the input signal from the current and voltage sensing
devices and are used to isolate a faulted portion of the BES. Devices that sense thermal, vibration,
seismic, pressure, gas or any other non-electrical inputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor based equipment in the
following ways, the relays should meet the asset owners’ tolerances.
•
•
Non-microprocessor devices must be tested with voltage and/or current applied to the device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test mandated.
o There is no specific documentation mandated.
15.2 Voltage & Current Sensing Devices
These are the current and voltage sensing devices, usually known as instrument transformers. There is
presently a technology available (fiber-optic Hall-effect) that does not utilize conventional transformer
technology; these devices and other technologies that produce quantities that represent the primary values
of voltage and current are considered to be a type of voltage and current sensing devices included in this
standard.
The intent of the maintenance activity is to verify the input to the protective relay from the device that
produces the current or voltage signal sample.
There is no specific test mandated for these devices. The important thing about these signals is to know
that the expected output from these devices actually reaches the protective relay. Therefore, the proof of
the proper operation of these devices also demonstrates the integrity of the wiring (or other medium used
to convey the signal) from the current and voltage sensing device all the way to the protective relay. The
following observations apply.
• There is no specific ratio test, routine test or commissioning test mandated.
• There is no specific documentation mandated.
• It is required that the signal be present at the relay.
• This expectation can be arrived at from any of a number of means; by calculation, by comparison
to other circuits, by commissioning tests, by thorough inspection, or by any means needed to
verify the circuit meets the asset owner’s protection system maintenance program.
• An example of testing might be a saturation test of a CT with the test values applied at the relay
panel; this therefore tests the CT as well as the wiring from the relay all the back to the CT.
• Another possible test is to measure the signal from the voltage and/or current sensing devices,
during load conditions, at the input to the relay.
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•
•
•
•
Another example of testing the various voltage and/or current sensing devices is to query the
microprocessor relay for the real-time loading; this can then be compared to other devices to
verify the quantities applied to this relay. Since the input devices have supplied the proper values
to the protective relay then the verification activity has been satisfied. Thus event reports (and
oscillographs) can be used to verify that the voltage and current sensing devices are performing
satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this should add up to
zero watts and zero vars thus proving the voltage and/or current sensing devices system
throughout the bus.
Another method for proving the voltage and/or current sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
Other methods that provide documentation that the expected transformer values as applied to the
inputs to the protective relays are acceptable.
15.3 DC Control Circuitry
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit switcher or
any other interrupting device. It includes the wiring from the batteries to the relays. It includes the wiring
(or other signal conveyance) from every trip output to every trip coil. It includes any device needed for
the correct processing of the needed trip signal to the trip coil of the interrupting device. In short, every
trip path must be verified; the method of verification is optional to the asset owner. An example of testing
methods to accomplish this might be to verify, with a volt-meter, the existence of the proper voltage at the
open contacts and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker (or other
interrupting device) at least once. There is a requirement to operate the circuit breaker (or other
interrupting device) at least once every six years as part of the complete functional test. If a monitoring
system is installed that verifies every parallel trip path then the manual-intervention testing of those
parallel trip paths can be extended to twelve years, however the actual operation of the circuit breaker
must still occur at least once every six years. This 6-year tripping requirement can be completed as easily
as tracking the real-time fault-clearing operations on the circuit breaker.
The circuit-interrupting device should not be confused with a motor-operated disconnect. The intent of
this standard is to require maintenance intervals and activities on Protection Systems equipment and not
just all equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground switch as an
interrupting device if this ground switch is utilized in a Protection System and forces a ground fault to
occur that then results in an expected Protection System operation to clear the forced ground fault.
Distribution circuit breakers that participate in the UFLS scheme are excluded from the trip-testing
requirements. There are many circuit interrupting devices in the distribution system that will be operating
for any given under-frequency event that requires tripping for that event. A failure in the tripping-action
of a single distribution breaker will be far less significant than, for example, any single Transmission
Protection System failure such as a failure of a Bus Differential Lock-Out Relay. While many failures of
these distribution breakers could add up to be significant, it is also believed that distribution breakers are
operated often on just fault clearing duty and therefore the distribution circuit breakers are operated at
least as frequently as any requirements that might have appeared in this standard.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay (86) in
any given trip scheme. These electro-mechanical devices must be trip tested. The PSMT SDT considers
these devices to share some similarities in failure modes as electro-mechanical protective relays; as such
there is a six year maximum interval between mandated maintenance tasks.
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When verifying the operation of the 94 and 86 relays each normally-open contact that closes to pass a trip
signal must be verified as operating correctly. Normally-open contacts that are not used to pass a trip
signal and normally-closed contacts do not have to be verified. Verification of the tripping paths is the
requirement.
New technology is also accommodated here; there are some tripping systems that have replaced the
traditional hard-wired trip circuitry with other methods of trip-signal conveyance such as fiber-optics. It is
the intent of the PSMT SDT to include this, and any other, technology that is used to convey a trip signal
from a protective relay to a circuit breaker (or other interrupting device) within this category of
equipment.
15.4 Batteries and DC Supplies
IEEE guidelines were consulted to arrive at the maintenance activities for batteries. The following
guidelines were used: IEEE 450 (for Vented Lead-Acid batteries), IEEE 1188 (for Valve-Regulated LeadAcid batteries) and IEEE 1106 (for Nickel-Cadmium batteries).
The present NERC definition of a Protection System is “protective relays, associated communication
systems, voltage and current sensing devices, station batteries and dc control circuitry.” The station
battery is not the only component that provides dc power to a Protection System. In the new definition
for Protection System “station batteries” are replaced with “station dc supply” to make the battery charger
and dc producing stored energy devices (that are not a battery) part of the Protection System that must be
maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and testing
procedures that allow the owner to choose how to verify that a battery string is free of open circuits. The
term “continuity” was introduced into the standard to allow the owner to choose how to verify continuity
of a battery set by various methods, and not to limit the owner to the two methods recommended in the
IEEE standards. Continuity as used in Table 1 of the standard refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative terminal.
Without verifying continuity of a station battery, there is no way to determine that the station battery is
available to supply dc power to the station.
Batteries cannot be a unique population segment of a Performance-based Maintenance Program (PBM)
because there are too many variables in the electro-chemical process to completely isolate all of the
performance-changing criteria necessary for using PBM on battery systems.
15.5 Tele-protection equipment
This is also known as associated telecommunications equipment. The equipment used for tripping in a
communications assisted trip scheme is a vital piece of the trip circuit. Remote action causing a local trip
can be thought of as another parallel trip path to the trip coil that must be tested.
Besides the trip output and wiring to the trip coil(s) there is also a communications medium that must be
maintained.
Newer technologies now exist that achieve communications-assisted tripping without the conventional
wiring practices of older technology.
For example: older technologies may have included Frequency Shift Key methods. This technology
requires that guard and trip levels be maintained.
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The actual tripping path(s) to the trip coil(s) may be tested as a parallel trip path within the dc control
circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are then
interpreted locally as trip signals.
The requirements apply to the communicated signal needed for the proper operation of the protective
relay trip logic or scheme. Therefore this standard is applied to equipment used to convey both trip signals
and block signals.
It was the intent of this standard to require that a test be made of any communications-assisted trip
scheme regardless of the vintage of the technology. The essential element is that the tripping occurs
locally when the remote action has been asserted.
Evidence of operational test or documentation of measurement of signal level, reflected power or dataerror rates is needed.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the control
house to the circuit interrupting device in the yard. This method of tripping the circuit breaker, even
though it might be considered communications, must be maintained per the dc control circuitry
maintenance requirements.
15.6 Examples of Evidence of Compliance
To comply with the requirements of this Standard an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team recognizes
that there are concurrent evidence requirements of other standards that could, at times fulfill
evidence requirements of this standard.
For example: maintaining evidence for operation of Special Protection Systems could
concurrently be utilized as proof of the operation of the associated trip coil (provided one can be
certain of the trip coil involved). Thus the reporting requirements that one may have to do for the
misoperation of a Special Protection Scheme under PRC-016 could work for the activity tracking
requirements under this PRC-005-2.
Another example might be:
Some entities maintain records of all interruptions. These records can be concurrently utilized, if
the entity desires, as DC Trip Path verifications.
Analysis of Event Recordings can provide details that can eliminate some hands-on maintenance
activities; however, merely printing out the event report provides limited benefit of verification of
specific maintenance items.
Standardized-forms, hard or soft copy, can be created, filled out and archived. These forms can be
of the entities’ design and can be aimed at answering the specific requirements of the Standard as
well as additional requirements as needed by the entity.
Fill-in blanks, check-boxes, drop-down lists, auto-date formats, etc. can all be used as the primary
action is the maintenance activity; the secondary action is to verify that the maintenance activity
was performed.
Other evidence of compliance might be, but is not limited to:
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Prints, maintenance plans, training materials, policies, procedures, data print-outs or exhibits,
correspondence, reports, data-base records, etc.
There is the legacy method of paper trail for everything, this is acceptable. There are also
paperless systems existing and evolving that are also acceptable.
Proof of compliance should simply be the entities’ records of maintenance completed.
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16. References
NERC/SPCTF/Relay_Maintenance_Tech_Ref_approved_by_PC.pdf
1. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J. Kumm, M.S.
Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power Delivery, Vol. 10,
No. 2, April 1995.
2. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003, 2004
and 2005,” Working Group I17 of Power System Relaying Committee of IEEE Power
Engineering Society, May 2006.
3. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System Relaying
Committee of IEEE Power Engineering Society, September 16, 1999.
4. “Transmission Protective Relay System Performance Measuring Methodology,” Working
Group I3 of Power System Relaying Committee of IEEE Power Engineering Society, January
2002.
5. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3 of
Power System Relaying Committee of IEEE Power Engineering Society, December 2006.
6. “Proposed Statistical Performance Measures for Microprocessor-Based Transmission-Line
Protective Relays, Part I - Explanation of the Statistics, and Part II - Collection and Uses of
Data,” Working Group D5 of Power System Relaying Committee of IEEE Power
Engineering Society, May 1995; Papers 96WM 016-6 PWRD and 96WM 127-1 PWRD,
1996 IEEE Power Engineering Society Winter Meeting.
7. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
8. “Use of Preventative Maintenance and System Performance Data to Optimize Scheduled
Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia Tech Protective
Relay Conference, May 1996.
PSMT SDT References
9. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams, 2003
10. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore, 2005
11. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
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Figures
Figure 1: Typical Transmission System
For information on numbered components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
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Figure 2: Typical Generation System
For information on numbered components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
Draft 2: April, 2010
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Figure 1 & 2 Legend – Components of Protection Systems
Number In
Figure
Component of Protection
System
Includes
Excludes
1
Protective relays
All protective relays that use current and/or voltage
inputs from current & voltage sensors and that trip the
86, 94 or trip coil.
Devices that use non-electrical methods of operation
including thermal, pressure, gas accumulation, and
vibration. Any ancillary equipment not specified in the
definition of Protection systems. Control and/or
monitoring equipment that is not a part of the automatic
tripping action of the Protection System
2
Voltage & Current Sensing
Devices and associated
circuitry
The signals from the voltage & current sensing devices
for protective relays as well as the wiring (or other
medium) used to convey signal output from the sensor
to the protective relay input.
Voltage & current sensing devices that are not a part of
the Protection System, including sync-check systems,
metering systems and data acquisition systems.
3
DC Circuitry
All control wiring (or other medium for conveying trip
signals) associated with the tripping action of 86
devices, 94 devices or trip coils (from all parallel trip
paths). This would include fiber-optic systems that
carry a trip signal as well as hard-wired systems that
carry trip current.
Closing circuits, SCADA circuits
4
Station dc supply
Batteries and battery chargers and any control
power system which has the function of
supplying power to the protective relays,
associated trip circuits and trip coils.
Any power supplies that are not used to power
protective relays or their associated trip circuits
and trip coils.
5
Associated
communications
systems
Tele-protection equipment used to convey
remote tripping action to a local trip coil or
blocking signal to the trip logic (if applicable).
Any communications equipment that is not used
for remote tripping action to a local trip coil or
blocking signal to the trip logic (if applicable).
(Return)
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Figure 3: Requirements Flowchart
Requirements
Flowchart
Start
PRC-005-2
Each GO, DP, & TO
shall establish a
maintenance
program (R1)
Time -Based or
Condition-Based
Maintenance
PerformanceBased
Maintenance
Identify components using
TBM, CBM, PBM or
combination (R1.1)
•
Ensure components have
attributes that allow CBM
(Table 1b or Table 1c) or
default to Table 1a
(R2)
•
•
Separate components into segments of 60 or
more
Maintain components for each segment per
Table 1 until at least 30 components have been
tested
Analyze data to determine appropriate interval
for segment(s)
(R3, Attachment A)
Note: GO, DP, & TO
may use one or both
programs
•
•
•
Maintain components per
Table One Intervals and
Activities (R4.1)
•
•
•
Perform maintenance activities from Table 1 for
each segment
Use interval from analysis above
Collect data for future analysis
(R4.2, R3, Attachment A)
Collect countable events from maintenance and
failures
Analyze data from maintenance of last 30
components and/or last year (whichever is
more) to verify countable events are less than
4% threshold
Adjust maintenance interval to keep countable
events below 4%
(R3, Attachment A)
Initiate
corrective
actions as
needed (R4.3)
End
Draft 2: April, 2010
Page 30
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in Section 10
of the paper. As an example, Figure A-1 shows protection for a critical transmission line by carrier
blocking directional comparison pilot relaying. The goal is to verify the ability of the entire two-terminal
pilot protection scheme to protect for line faults, and to avoid over-tripping for faults external to the
transmission line zone of protection bounded by the current transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays themselves,
the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of internal
electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report the
state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of other
relays, meters, or DFRs. The other readings may be from redundant relaying or measurement
systems or they may be derived from values in other protection zones. Comparison with other
such readings to within required relaying accuracy verifies Voltage & Current Sensing
Draft 2: April, 2010
Page 31
Devices, wiring, and analog signal input processing of the relays. One effective way to do
this is to utilize the relay metered values directly in SCADA, where they can be compared
with other references or state estimator values.
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the protection
system, so each carrier set has a connected or integrated automatic checkback test unit. The
automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation or
noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the protection
system elements that experience tells us are the most prone to fail. But, does this comprise a complete
verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded regions
show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
Draft 2: April, 2010
Page 32
2. Within each line relay, all the microprocessors that participate in the trip decision have been
verified by internal monitoring. However, the trip circuit is actually energized by the contacts
of a small telephone-type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a fault.
3. The check-back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying circuit
or the carrier receiver output state. These connections include microprocessor I/O ports,
electronic driver circuits, wiring, and sometimes telephone-type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but this
does not confirm that the state change indication is correct when the breaker or switch opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified maximum time
interval between trip tests. Clearing of naturally-occurring faults are demonstrations of operation that
reset the time interval clock for testing of each breaker tripped in this way. If faults do not occur, manual
tripping of the breaker through the relay trip output via data communications to the relay microprocessor
meets the requirement for periodic testing.
PRC-005 does not address breaker maintenance, and its protection system test requirements can be met by
energizing the trip circuit in a test mode (breaker disconnected) through the relay microprocessor. This
can be done via a front-panel button command to the relay logic, or application of a simulated fault with a
relay test set. However, utilities have found that breakers often show problems during protection system
tests. It is recommended that protection system verification include periodic testing of the actual tripping
of connected circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and that the
other relay demonstrate reception of that blocking carrier. This can be observed from relay or DFR
records during naturally occurring faults, or by a manual test. If the checkback test sequence were
incorporated in the relay logic, the carrier sets and carrier channel are then included in the overlapping
segments monitored by the two relays, and the monitoring gap is completely eliminated.
Draft 2: April, 2010
Page 33
Appendix B — Protection System Maintenance Standard
Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Mark Lukas
ComEd
Merle E. Ashton
Tri-State G&T
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
Bob Bentert
Florida Power & Light Company
John Ciufo
Hydro One Inc
Sam Francis
Oncor
Carol A Gerou
Midwest Reliability Organization
William Shultz
Southern Company Generation
Russell C Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
Draft 2: April, 2010
Mark Peterson
Great River Energy
William Shultz
Southern Company Generation
Leonard Swanson, Jr
National Grid USA
Eric A Udren
Quanta Technology
Philip B Winston
Georgia Power Company
John A Zipp
ITC Holdings
Page 34
PRC-005-2
— System Maintenance
Draft Supplementary Reference (Draft 1)
Protection
May 27, 2010
Prepared by the
Protection System Maintenance and Testing Standard Drafting Team
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
July, 2009
PRC-005-2
Project 2007-17
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Page 2
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Table of Contents
1. Introduction and Summary ..................................................................................................... 4
2. Need for Verifying Protection System Performance................................................................ 4
2.1 Existing NERC Standards for Protection System Maintenance and Testing .......................... 4
2.2 Proposed Modification to NERC Glossary Definition ........................................................... 5
2.3 Applicability of New Protection System Maintenance Standards .......................................... 5
2.4 Applicable Relays ................................................................................................................ 5
3. Relay Product Generations ..................................................................................................... 6
4. Definitions ............................................................................................................................. 6
5. Time-Based Maintenance (TBM) Programs ........................................................................... 7
Maintenance Practices ................................................................................................................. 7
5.1 Extending Time-Based Maintenance .................................................................................... 8
6. Condition-Based Maintenance (CBM) Programs .................................................................... 9
7. Time-Based versus Condition-Based Maintenance ............................................................... 10
8. Maximum Allowable Verification Intervals .......................................................................... 10
Maintenance Tests..................................................................................................................... 11
8.1 Table of Maximum Allowable Verification Intervals .......................................................... 11
Level 1 Monitoring (Unmonitored) Table 1a ............................................................................ 12
Level 2 Monitoring (Partially Monitored) Table 1b .................................................................. 12
Level 3 Monitoring (Fully Monitored) Table 1c ....................................................................... 12
8.2 Retention of Records .......................................................................................................... 14
8.3 Basis for Table 1 Intervals .................................................................................................. 14
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays ................................ 15
9. Performance-Based Maintenance Process ............................................................................. 16
9.1 Minimum Sample Size ....................................................................................................... 17
10. Overlapping the Verification of Sections of the Protection System ..................................... 19
11. Monitoring by Analysis of Fault Records ........................................................................... 20
12. Importance of Relay Settings in Maintenance Programs ..................................................... 20
13. Self-Monitoring Capabilities and Limitations ..................................................................... 21
14. Notification of Protection System Failures .......................................................................... 22
15. Maintenance Activities ....................................................................................................... 22
15.1 Protective Relays .............................................................................................................. 22
15.2 Voltage & Current Sensing Devices ................................................................................. 22
15.3 DC Control Circuitry ........................................................................................................ 23
15.4 Batteries and DC Supplies ................................................................................................ 24
15.5 Tele-protection equipment ................................................................................................ 25
16. References ............................................................ 15.6 Examples of Evidence of Compliance
Figures .................................................................................................................. 16. References
Figure 1: Typical Transmission System ............................................................................. Figures
Figure 21: Typical GenerationTransmission System .................................................................. 28
Figure 3: Requirements Flowchart2: Typical Generation System............................................... 29
Appendix A.............................................................................. Figure 3: Requirements Flowchart
PRC-005-2 Protection Systems Maintenance & Testing Standard Drafting Team ....... Appendix A
Appendix B — Protection System Maintenance Standard Drafting Team .................................. 36
Draft 1: July, 20092: April, 2010
Page 3
26
27
28
31
33
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
This supplementary reference to PRC-005-2 borrows heavily from the technical reference by the System
Protection and Control Task Force (SPCTF) (Protection System Maintenance Technical Reference paper
approved by the Planning Committee in September 2007). Additionally, the Protection System
Maintenance and Testing Standard Drafting Team (PSMT SDTPSMTSDT) for PRC-005-2 (Project 200717) utilized data available from IEEE, EPRI and maintenance programsprogram data from various
generation and transmission utilities across the NERC boundaries.; as well as data from IEEE and EPRI.
1. Introduction and Summary
NERC currently has four reliability standards that are mandatory and enforceable in the United States and
address various aspects of maintenance and testing of protectionProtection and controlControl systems.
These standards are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for Protection Systems,
and that these entities must be able to demonstrate they are carrying out such a program, there are no
specifics regarding the technical requirements for Protection System maintenance programs. Furthermore,
FERC Order 693 directed additional modifications respective to Protection System maintenance
programs. This revision of PRC-005-1 combines and replaces PRC-005, PRC-008, PRC-011 and PRC017.
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate their
performance until a fault or other power system problem requires that they operate to protect power
system elements, or even the entire Bulk Electric System (BES). Lacking faults or system problems, the
protection systems may not operate for extended periods. A misoperationMisoperation - a false operation
of a protection system or a failure of the protection system to operate, as designed, when needed - can
result in equipment damage, personnel hazards, and wide area disturbances or unnecessary customer
outages. A maintenance or testing program is used to determine the performance and availability of
protection systems.
Typically, utilities have tested protection systems at fixed time intervals, unless they had some incidental
evidence that a particular protection system was not behaving as expected. Testing practices vary widely
across the industry. Testing has included system functionality, calibration of measuring relays, and
correctness of settings. Typically, a protection system must be visited at its installation site and removed
from service for this testing.
Fundamentally, a reliability standard for Protection System Maintenance and Testing requires the
performance of the maintenance activities that are necessary to detect and correct plausible age and
service related degradation of components such that a properly built and commissioned Protection System
will continue to function as designed over its service life.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset owner
define a testing program. The starting point is the existing Standard PRC-005, briefly restated as follows:
Purpose: To ensure all transmission and generation Protection Systems affecting the reliability of the
Bulk Electric System (BES) are maintained and tested.
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Page 4
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
PRC-005-1 is not specific on where the boundaries of the Protection Systems lie. However, the definition
of Protection System in the NERC Glossary of Terms Used in Reliability Standards used in Reliability
Standards indicates what must be included as a minimum.
Definition of Protection System (excerpted from the NERC Standards Glossary of Terms):
Protective relays, associated communication systems, voltage and current sensing devices, station
batteries and dc control circuitry.
Applicability: Owners of generation, transmission, and transmission Protection Systems.
Requirements: The owner shall have a documented maintenance program with test intervals. The owner
must keep records showing that the maintenance was performed at the specified intervals.
2.2 Proposed Modification to NERC Glossary Definition
The Protection Systems Maintenance and Testing Standard Drafting Team (PSM SDT), proposes changes
to the NERC glossary definition of Protection Systems as follows:
Protection System (modification) - Protective relays, associated communication systems necessary for
correct operation of protective devicesfunctions, voltage and current sensing devices inputs to protective
relays and associated circuitry from the voltage and current sensing devices, station DC supply, and DC
control circuitry, associated with protective functions from the station DC supply through the trip coil(s)
of the circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from the
original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“… and that are applied on, or are designed to provide protection for the BES.”
The drafting team intends that this Standard will not apply to “merely possible” parallel paths, (subtransmission and distribution circuits), but rather the standard applies to any Protection System that is
designed to detect a fault on the BES and take action in response to that fault. The Standard Drafting
Team does not feel that Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the Regional definitions of the
BES.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and voltage
sensing devices, dc control circuitry and associated communications circuits. The relays to which this
standard applies are those relays that that use measurements of voltage, current, frequency and/or phase
angle and provide a trip output to trip coils, dc control circuitry or associated communications equipment.
This definition extends to IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or trip-free
relay) as these devices are tripping relays that respond to the trip signal of the protective relay that
processed the signals from the current and voltage sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration, pressure,
seismic, thermal or gas accumulation) are not included.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
3. Relay Product Generations
The likelihood of failure and the ability to observe the operational state of a critical protection system,
both depends on the technological generation of the relays as well as how long they have been in service.
Unlike many other transmission asset groups, protection and control systems have seen dramatic
technological changes spanning several generations. During the past 20 years, major functional advances
are primarily due to the introduction of microprocessor technology for power system devices such as
primary measuring relays, monitoring devices, control systems, and telecommunications equipment.
Modern microprocessor based relays have six significant traits that impact a maintenance strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and some
connected substation inputs and outputs such as trip coil continuity. Most relay users are aware
that these relays have self monitoring, but are not focusing on exactly what internal functions are
actually being monitored. As explained further below, every element critical to the protection
system must be monitored, or else verified periodically.
•
Ability to capture fault records showing how the protection system responded to a fault in its zone
of protection, or to a nearby fault for which it is required not to operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-fault times. The relays can compute values such as MW and MVAR line
flows that are sometimes used for operational purposes such as SCADA.
•
Data communications via ports that provide remote access to all of the results of protection
system monitoring, recording, and measurement.
•
Ability to trip or close circuit breakers and switches through the protection system outputs, on
command from remote data communications messages or from relay front panel button requests.
•
Construction from electronic components some of which have shorter technical life or service life
than electromechanical components of prior protection system generations.
4. Definitions
Protection System Maintenance Program (PSMP) – An ongoing program by which Protection System
components are kept in working order and proper operation of malfunctioning components is restored. A
maintenance program can includefor a specific component includes one or more of the following
activities:
An ongoing program by which Protection System components are kept in working order and where
malfunction components are restored to working order
Verification – A means of determining that the component is functioning correctly.
•
Monitoring – Observation of the routine in-service operation of the component.
•
Testing – Application of signals to a component to observe functional performance or output
behavior, or to diagnose problems.
•
Physical Inspection – To detect visible signs of component failure, reduced performance and
degradation.
•
Calibration – Adjustment of the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
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Page 6
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
•
Upkeep – Routine activities necessary to assure that the component remains in good working
order and implementation of any manufacturer’s hardware and software service advisories which
are relevant to the application of the device.
•
Restoration – The actions to restore proper operation of malfunctioning components.
5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which protection systems are maintained or verified according
to a time schedule. The scheduled program often calls for technicians to travel to the physical site and
perform a functional test on protection system components. However, some components of a TBM
program may be conducted from a remote location - for example, tripping a circuit breaker by
communicating a trip command to a microprocessor relay to determine if the entire protection system
tripping chain is able to operate the breaker.
Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have been
developed from prior experience or manufacturers’ recommendations. The TBM verification
interval is based on a variety of factors, including experience of the particular asset owner,
collective experiences of several asset owners who are members of a country or regional council,
etc. The maintenance intervals are fixed, and may range in number of months or in years.
TBM can include review of recent power system events near the particular terminal. Operating
records may proveverify that some portion of the protection system has operated correctly since
the last test occurred. If specific protection scheme components have demonstrated correct
performance within specifications, the maintenance test time clock is reset for those components.
•
PBM – performance-based maintenance — maintenance- intervals are established based on
analytical or historical results of TBM failure rates on a statistically significant population of
similar components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBM-developed
extended intervals when test failures or in-service failures occur infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from nondisruptive self monitoring of components demonstrate operational status as those components
remain in service. Whatever is verified by CBM does not require manual testing, but taking
advantage of this requires precise technical focus on exactly what parts are included as part of the
self diagnostics.
Microprocessor based protective relays that perform continuous self-monitoring verify correct
operation of most components within the device. Self-monitoring capabilities may include the ac
signal inputs, analog measuring circuits, processors and memory for measurement, protection,
and data communications, trip circuit monitoring, and protection or data communications signals.
For those conditions, failure of a self-monitoring routine generates an alarm and may inhibit
operation to avoid false trips. When internal components, such as critical output relay contacts,
are not equipped with self-monitoring, they can be manually tested. The method of testing may
be local or remote, or through inherent performance of the scheme during a system event.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
The TBM is the overarching maintenance process of which the other types are subsets. Unlike TBM,
PBM intervals are adjusted based on good or bad experiences. The CBM verification intervals can be
hours or even milliseconds between non-disruptive self monitoring checks within or around components
as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete Protection
System. The following diagram illustrates the relationship between various types of maintenance
practices described in this section. In the Venn diagram the overlapping regions show the relationship of
TBM with PBM historical information and the inherent continuous monitoring offered through CBM.
This figure shows:
•
•
•
Region 1: The TBM intervals that are increased based on known reported operational condition of
individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been subject to
TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
5.1 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly established to
assure proper functioning of each component of the protection system, when data on the reliability of the
components is not available other than observations from time-based maintenance. The following factors
may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from relay self
monitoring, for example), the intervals may be extended or manual testing may be eliminated.
This is referred to as condition-based maintenance or CBM. CBM is valid only for precisely the
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Page 8
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
components subject to monitoring. In the case of microprocessor-based relays, self-monitoring
may not include automated diagnostics of every component within a microprocessor.
•
Previous maintenance history for a group of components of a common type may indicate that the
maintenance intervals can be extended while still achieving the desired level of performance. This
is referred to as performance-based maintenance or PBM. It is also sometimes also referred to as
reliability-centered maintenance or RCM, but PBM is used in this document.
•
Observed proper operation of a component may be regarded as a maintenance verification of the
respective component or element in a microprocessor-based device. For such an observation, the
maintenance interval may be reset only to the degree that can be verified by data available on the
operation. For example, the trip of an electromechanical relay for a fault verifies the trip contact
and trip path, but only through the relays in series that actually operated; one operation of this
relay cannot proveverify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is not unusual
to cause failure of a component by removing it from service and restoring it. The improper application of
test signals may cause failure of a component. For example, in electromechanical overcurrent relays, test
currents have been known to destroy convolution springs.
In addition, maintenance usually takes the component out of service, during which time it is not able to
perform its function. Cutout switch failures, or failure to restore switch position, commonly lead to
protection failures.
6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information available from
modern microprocessor-based relays and other intelligent electronic devices (IEDs) that monitor
protection system elements. These relays and IEDs generate monitoring information during normal
operation, and the information can be assessed at a convenient location remote from the substation. The
information from these relays and IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in relay logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillograph records for
faults and disturbances, metered values, and binary input status reports. Some of these are
available on the relay front panel display, but may be available via data communications
ports. Large files of fault information can only be retrieved via data communications.
These results comprise a mass of data that must be further analyzed for evidence of the
operational condition of the protection system.
Using these two types of information, the user can develop an effective maintenance program carried out
mostly from a central location remote from the substation. This approach offers the following advantages:
1. Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
2. Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some relays will show health problems by
incorrect relaying before being caught in the next test round. The frequent or continuous
nature of CBM makes the effective verification interval far shorter than any required
TBM maximum interval.
7. Time-Based versus Condition-Based Maintenance
Time-based and condition-based maintenance programs are both acceptable, if implemented according
to technically sound requirements. Practical programs can employ a combination of time-based and
condition-based maintenance. The standard requirements introduce the concept of optionally using
condition monitoring as a documented element of a maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule dated March
16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability Standards for the BulkPower System, directed NERC to submit a modification to PRC-005-1 that includes a requirement that
maintenance and testing of a protection system must be carried out within a maximum allowable interval
that is appropriate to the type of the protection system and its impact on the reliability of the Bulk Power
System. Accordingly, this Supplementary Reference Paper refers to the specific maximum allowable
intervals in PRC-005-2. The defined time limits allow for longer time intervals if the maintained device is
monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay between the
moment of a protection failure and time the protection system owner knows about it, for the monitored
segments of the protection system. In some cases, the verification is practically continuous - the time
interval between verifications is minutes or seconds. Thus, technically sound, condition-based verification
(as specified in the header and the “Monitoring Attributes” column of Tables 1a, 1b and 1c of PRC-0052), meets the verification requirements of the FERC order even more effectively than the strictly timebased tests of the same system elements as contained in Table 1a.
The result is that:
This NERC standards permits utilities to use a technically sound approach and to take advantage of
remote monitoring, data analysis, and control capabilities of modern protection systems to reduce the
need for periodic site visits and invasive testing of components by on-site technicians. This periodic
testing must be conducted within maximum time intervals specified in Tables 1a, 1b and 1c of PRC-0052.
8. Maximum Allowable Verification Intervals
The Table of Maximum Allowable Testing Intervals and Maintenance Activities and Maximum Interval
requirements showsshow how CBM with newer relay types can reduce the need for many of the tests and
site visits that older protection systems require. As explained below, there are some sections of the
protection system that monitoring or data analysis may not verify. Verifying these sections of the
Protection Systems requires some persistent TBM activity in the maintenance program. However, some
of this TBM can be carried out remotely - for example, exercising a circuit breaker through the relay
tripping circuits using the relay remote control capabilities via data communicationscan be used to verify
function of one tripping path and proper trip coil operation, if there has been no fault or routine operation
to demonstrate performance of relay tripping circuits.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is operating
correctly after a time period of time of field installation. These tests may be used to ensure that individual
components are still operating within acceptable performance parameters - this type of test is needed for
components susceptible to degraded or changing characteristics due to aging and wear. Full system
performance tests may be used to confirm that the total protection system functions from measurement of
power system values, to properly identifying fault characteristics, to the operation of the interrupting
devices.
8.1 Table of Maximum Allowable Verification Intervals
Table 1, in the standard, specifies maximum allowable verification intervals for various generations of
protection systems and categories of equipment that comprise protection systems. The right column
indicates verification or testingmaintenance activities required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1 shows an
example of telecommunications-assisted line protection system comprising substation equipment at each
terminal and a telecommunications channel for relaying between the two substations. Figure 2 shows a
typical Generation station layout. The various subsystems of a Protection System that need to be verified
are shown. UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated in these
Figures.
While it is easy to associate protective relays to the three levels of monitoring, it is also true that most of
the components that can make up a Protection System can also have technological advancements that
place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables (Tables 1a, 1b and 1c collectively Tables) from
PRC-005-2:
• First check the table header description to verify that your equipment meets the monitoring
requirements. If your equipment does not meet the monitoring requirements of Table 1c then
check Table 1b. If your equipment does not meet the requirements of Table 1b then use Table 1a.
•
If you find a piece of equipment that meets the monitoring requirements of Table 1b or 1c then
you can take advantage of the extended time intervals allowed by Table 1b and 1c. Your
maintenance plan must document that this category of equipmentcomponent can be maintained
by the requirements of Table 1b or 1c because it has the necessary attributes required within that
Table.
•
Once you determine which table applies to your equipment’s monitoring requirements then check
the Maintenance Activity that is required for that particular category of equipment.component.
This Maintenance Activity is the minimum maintenance activity that must be documented.
•
If your PSMP (plan) requires more then you must document more.
•
After the maintenance activity is known, check the Maximum Maintenance Interval; this time is
the maximum time allowed between hands-on maintenance activity cycles of this category of
your equipmentcomponent.
•
If your PSMP (plan) requires activities more often than the Tables maximum then you must
document those activities more often.
•
Any given set of Protection System equipment can be maintained with any combination of Tables
1a, 1b and 1c. An entity does not have to stick to Table 1a just because some of its equipment is
un-monitored.
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
•
An entity does not have to utilize the extended time intervals in Tables 1b or 1c. An easy choice
to make is to simply utilize Table 1a. While the maintenance activities resulting from choosing to
use only Table 1a would require more maintenance man-hours, the maintenance requirements
may be simpler to document and the resulting maintenance plans may be easier to create.
For each Protection System component, Table 1 shows maximum allowable testing intervals for
unmonitored, partially monitored and fully monitored protection systems:
Table 1 Maximum Allowable Testing Intervals and Maintenance Activities and Maximum Intervals
Level 1 Monitoring (Unmonitored) Table 1a
This table applies to electromechanical, analog solid state and other un-monitored Protection Systems
components. This table represents the starting point for all required maintenance activities. The object of
this group of requirements is to have specific activities accomplished at maximum set time intervals.
From this group of activities it follows that CBM or PBM can increase the time intervals between the
hands-on maintenance actions.
Level 2 Monitoring (Partially Monitored) Table 1b
This table applies to microprocessor relays and other associated Protection System components whose
self-monitoring alarms are transmitted to a location (at least daily) where action can be taken for alarmed
failures. The attributes of the monitoring system must meet the requirements specified in the header of the
Table 1b. Given these advanced monitoring capabilities, it is known that there are specific and routine
testing functions occurring within the device. Because of this ongoing monitoring hands-on action is
required less often because routine testing is automated. However, there is now an additional task that
must be accomplished during the hands-on process – the monitoring and alarming functions must be
shown to work.
Level 3 Monitoring (Fully Monitored) Table 1c
This table applies to microprocessor relays and other associated Protection System components in which
every element or function required for correct operation of the Protection System component is monitored
continuously and verified, including verification of the means by which failure alarms or indicators are
transmitted to a central location for immediate action.location within 1 hour or less of the maintenancecorrectable issue occurring. This is the highest level of monitoring and if it is available then this gives an
entity the ability to have continuous testing of their (Level 3 Monitored) Protection System Component
and thus does not have to manually intervene to accomplish routine testing chores. Level 3 Fully
Monitored yields continuous monitoring advantages but has substantial technical hurdles that must be
overcome; namely that monitoring also verifies the failure of the monitoring and alarming equipment.
Without this important ingredient a device that is thought to be continuously monitored could be in an
alarm state without the central locationasset owner being made aware of this alarm state.
Additional Notes for Table 1a, Table 1b, and Table 1c
1. For electro-mechanical relays, adjustment is required to bring measurement accuracy within the
tolerance needed by the asset owner. Microprocessor-relays with no remote monitoring of alarm
contacts, etc, are un-monitored relays and need to be verified within the Table interval as other
un-monitored relays but may be verified as functional by means other than testing by simulated
inputs.
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2. Microprocessor relays typically are specified by manufacturers as not requiring calibration, but
acceptable measurement of power system input values must be verified (verification of the
Analog to Digital [A/D] converters) within the Table intervals. The integrity of the digital inputs
and outputs must be verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a protection system or
SPS (as opposed to a monitoring task) must be verified as a component in a protection system.
4. In addition to verifying the circuitry that supplies dc to the protection system, the owner must
maintain the station dc supply. The most widespread station dc supply is the station battery and
charger. Unlike most Protection System elements physical inspection of station batteries for
signs of component failure, reduced performance, and degradation are required to ensure that the
station battery is reliable enough to deliver dc power when required. IEEE Standards 450, 1188,
and 1106 for Vented Lead-Acid, Valve-Regulated Lead-Acid, and Nickel-Cadmium batteries,
respectively (which are the most commonly used substation batteries on the NERC BES) have
been developed as an important reference source of maintenance recommendations. The
Protection System owner should attempt tomight use the applicable IEEE recommended practice
which contains information and recommendations concerning the maintenance, testing and
replacement of its substation battery. However, the methods prescribed in these IEEE
recommendations cannot be specifically required because they do not apply to all battery
applications.
5. Aggregated small entities will naturallymight distribute the testing of the population of
UFLS/UVLS systems, and large entities will usually maintain a portion of these systems in any
given year. Additionally, if relatively small quantities of such systems do not perform properly, it
will not affect the integrity of the overall program.
6. Voltage & Current Sensing Device circuit input connections to the protection system relays can
be verified by comparison of knownmeasured values of other sources on live circuits or by using
test currents and voltages on equipment out of service for maintenance. The verification process
can be automated or manual. The values should be verified to be as expected, (phase value and
phase relationships are both equally important to proveverify).
7. Verify the protection system tripping function by performing an operational trip test on all
components contained in the trip circuit. This includes circuit breaker or circuit switcher trip
coils, auxiliary tripping relays (94), lock-out relays (86), and communications-assisted trip
scheme elements. Each control circuit path that carries trip signal must be verified, although each
path must be checked only once. A maintenance program may include performing an overall test
for the entire system at one time, or several split system tests with overlapping trip verification.
Trip coil continuity and aux-contact verification may be accomplished by inspection for the
proper control panel light indication. Remote alarm monitoring of the trip coil and aux-contact
continuity eliminates the need for tri-monthly inspections of trip coil indications. A documented
real-time trip of any given trip path is acceptable in lieu of a functional trip test.
8. “End-to-end test” as used in this supplementary reference is any testing procedure that creates a
remote input to the local communications-assisted trip scheme. While this can be interpreted as a
GPS-type functional test it is not limited to testing via GPS. Any remote scheme manipulation
that can cause action at the local trip path can be used to functionally-test the dc Control
Circuitry. A documented real-time trip of any given trip path is acceptable in lieu of a functional
trip test. It is possible, with sufficient monitoring, to be able to proveverify each and every
parallel trip path that participated in any given dc Control Circuit trip. Or, another possible
solution is that a single trip path from a single monitored relay can be provenverified to be the trip
path that successfully tripped during a real-time operation. The variations are only limited by the
degree of engineering and monitoring that an entity desires to pursue.
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9. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus feeder
currents) can be used for comparison if calibration requirements assure acceptable measurement
of power system input values.
10. Notes 1-9 attempt to describe the testing activities they do not represent the only methods to
achieve these activities but rather some possible methods.
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three years.
However, with a three year retention cycle, the records of verification for a protection system will
typically be discarded before the next verification, leaving no record of what was done if a
misoperationMisoperation or failure is to be analyzed.
PRC-005-2 corrects this by requiring that the :
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation
be retained for of the two most recent performances of each distinct maintenance intervals. Additionally,
thisactivity for the Protection System components, or to the previous on-site audit date, whichever is
longer.
This requirement assures that the documentation shows that the interval between maintenance cycles
correctly meets the maintenance interval limits.
8.3 Basis for Table 1 Intervals
SPCTF authors collected all available data from Regional Entities (REs) on time intervals recommended
for maintenance and test programs. The recommendations vary widely in categorization of relays, defined
maintenance actions, and time intervals, precluding development of intervals by averaging. SPCTF also
reviewed the 2005 Report [2] of the IEEE Power System Relaying Committee Working Group I-17
(Transmission Relay System Performance Comparison). Review of the I-17 report shows data from a
small number of utilities, with no company identification or means of investigating the significance of
particular results.
To develop a solid current base of practice, SPCTF surveyed its members regarding their maintenance
intervals for electromechanical and microprocessor relays, and asked the members to also provide
definitively-known data for other entities. The survey represented 470 GW of peak load, or 64% of the
NERC peak load. Maintenance interval averages were compiled by weighting reported intervals
according to the size (based on peak load) of the reporting utility. Thus, the averages more accurately
represent practices for the large populations of protection systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of 5 years for
electromechanical or solid state relays, and 7 years for un-monitored microprocessor relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond 7 years,
based on favorable experience with the particular products they have installed. To provide a technical
basis for such extension, SPCTF authors developed a recommendation of 10 years using the Markov
modeling approach from [1] as summarized in Section 8.4. The results of this modeling depend on the
completeness of self-testing or monitoring. Accordingly, this extended interval is allowed by Table 1 only
when such relays are monitored as specified in the header of Table 1b. Monitoring is capable of reporting
protection system health issues that are likely to affect performance within the 10 year time interval
between verifications.
It is important to note that, according to modeling results, protection system availability barely changes as
the maintenance interval is varied below the 10-year mark. Thus, reducing the maintenance interval does
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
not improve protection system availability. With the assumptions of the model regarding how
maintenance is carried out, reducing the maintenance interval actually degrades protection system
availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level. The industry
has experience with self-monitoring microprocessor relays that leads to the Table 1 value for partial
monitoring as explained in Section 8.3. To develop a basis for the maximum interval for monitored
relays in their Protection System Maintenance – A Technical Reference, the SPCTF used the
methodology of Reference [1], which specifically addresses optimum routine maintenance intervals. The
Markov modeling approach of [1] is judged to be valid for the design and typical failure modes of
microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability measures:
• Relay Unavailability - the probability that the relay is out of service due to failure or maintenance
activity while the power system element to be protected is in service.
• Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a fault occurs, leading to failure to operate for the fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test). ST = 0 if
there is no self-monitoring; ST = 1 for full monitoring. Practical STvaluesST values are estimated to
range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that were the
same as those used in [1] with the following exceptions:
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal fault clearing time of 10 cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup fault clearing time of 50 cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a protection system)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a protection system repair after failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to these
parameter adjustments.
The resulting curves for Relay Unavailability and Abnormal Unavailability versus maintenance interval
showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years – the curve is flat,
with no significant change in either unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years, much lower than MTBF values
typically published for these relays. Also, the Markov modeling indicates that both the relay
unavailability and abnormal unavailability actually become higher with more frequent testing. This
shows that the time spent on these more frequent tests yields no failure discoveries that approach the
negative impact of removing the relays from service and running the tests.
PSMT SDT further notes that the SPCTF also allowed 25% extensions to the “maximum time intervals”.
With a 5 year time interval established between manual maintenance activities and a 25% time extension
then this equates to a 6.25 year maximum time interval. It is the belief of the PSMT SDT that the SPCTF
understood that 6.25 years was thereby an adequate maximum time interval between manual maintenance
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activities. The PSMT SDT has followed the FERC directive for a maximum time interval and has
determined that no extensions will be allowed. Six years has been set for the maximum time interval
between manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval between
maintenance activities. A 10 year interval with a 25% allowed extension equates to a maximum allowed
interval of 12.5 years between manual maintenance activities. The Standard does not allow extensions on
any component of the protection system; thus the maximum allowed interval for these devices has been
set to12 years. Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum Maintenance
Interval”. The PSMT SDT deemed it necessary to include the term “Calendar” to facilitate annual
maintenance planning, scheduling and implementation. This need is the result of known occurrences of
system requirements that could cause maintenance schedules to be missed by a few days or weeks. The
PSMT SDT chose the term “Calendar” to preclude the need to have schedules be met to the day. An
electro-mechanical protective relay that is maintained in year #1 need not be revisited until 6 years later
(year #7). For example: a relay was maintained December 15April 10, 2008; it would be due for
maintenance againwould need to be completed no later than December 31, 2014.
Section 9 describes a performance-based maintenance process which can be used to justify maintenance
intervals other than those described in Table 1.
Section 10 describes sections of the protection system, and overlapping considerations for full verification
of the protection system by segments. Segments refer to pieces of the protection system, which can range
from a single device to a panel to an entire substation.
Section 11 describes how relay operating records can serve as a basis for verification, reducing the
frequency of manual testing.
Section 13 describes how a cooperative effort of relay manufacturers and protection system users can
improve the coverage of self-monitoring functions, leading to full monitoring of the bulk of the protection
system, and eventual elimination of manual verification or testing.
9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a performance-based maintenance process may be used to establish
maintenance intervals. (PRC-005 Attachment A Criteria for a Performance-Based Protection System
Maintenance Program). A performance-based maintenance process may justify longer maintenance
intervals, or require shorter intervals relative to Table 1. In order to use a performance-based maintenance
process, the documented maintenance program must include records of repairs, adjustments, and
corrections to covered protection systems in order to provide historical justification for intervals other
than those established in Table 1. Furthermore, the asset owner must regularly analyze these records of
corrective actions to develop a ranking of causes. Recurrent problems are to be highlighted, and remedial
action plans are to be documented to mitigate or eliminate recurrent problems.
Utilities with performance-based maintenance track performance of protection systems, demonstrate how
they analyze findings of performance failures and aberrations, and implement continuous improvement
actions. Since no maintenance program can ever guarantee that no malfunction can possibly occur,
documentation of a performance-based maintenance program would serve the utility well in explaining to
regulators and the public a misoperationMisoperation leading to a major system outage event.
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A performance-based maintenance program requires auditing processes like those included in widely used
industrial quality systems (such as ISO 9001-2000, Quality management systems — Requirements; or
applicable parts of the NIST Baldridge National Quality Program). The audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance Based-based Maintenance (PBM) program the asset owner must first
sort the various Protection System components into population segments. Any population segment must
be comprised of at least 60 individual units; if any asset owner opts for PBM but does not own 60 units to
comprise a population then that asset owner may combine data from other asset owners until the needed
60 units is aggregated. Each population segment must be composed of like devices from the same
manufacturer and subjected to similar environmental factors. For example: One segment cannot be
comprised of both GE & Westinghouse electro-mechanical lock-out relays; likewise, one segment cannot
be comprised of 60 GE lock-out relays, 30 of which are in a dirty environment and the remaining 30 from
a clean environment.
9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling distribution of the
sample mean can be approximated by a normal probability distribution.” The Central Limit Theorem
states: “In selecting simple random samples of size n from a population, the sampling distribution of the
sample mean x can be approximated by a normal probability distribution as the sample size becomes
large.” (Essentials of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003)
To use the Central Limit Theorem in statistics, the population size should be large. The references below
are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30), the
central limit theorem enables us to conclude that the sampling distribution of the sample
mean can be approximated by a normal distribution.” (Essentials of Statistics for
Business and Economics, Anderson, Sweeney, Williams, 2003)
“If samples of size n, when n>=30, are drawn from any population with a mean u and a
standard deviation σ, the sampling distribution of sample means approximates a normal
distribution. The greater the sample size, the better the approximation.” (Elementary
Statistics - Picturing the World, Larson, Farber, 2003)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005)
“… the normal is often used as an approximation to the t distribution in a test of a null
hypothesis about the mean of a normally distributed population when the population
variance is estimated from a relatively large sample. A sample size exceeding 30 is often
given as a minimal size in this connection.” (Statistical Analysis for Business Decisions,
Peters, Summers, 1968)
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Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated using the
bound on the Error of Distribution Formula when the expected result is of a “Pass/Fail” format and will
be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
Β = bound on the error of distribution (allowable error)
z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
z
n = π(1 − π)
Β
2
Minimum Population Size to use Performance Based-based Program
One entity’s population of components should be large enough to represent a sizeable sample of a
vendor’s overall population of manufactured devices. For this reason the following assumptions are
made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance Based-based Program
The number of components that should be included in a sample size for evaluation of the appropriate
testing interval can be smaller because a lower confidence level is acceptable since the sample testing is
repeated or updated annually. For this reason, the following assumptions are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
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Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation mentioned.
Using this and the results of the equation, the following numbers are recommended:
Minimum Population Size to use Performance Based-based Maintenance Program = 60
Minimum Sample Size to evaluate Performance Based-based Program = 30.
Once the population segment is defined then maintenance must begin within the intervals as outlined for
Level 1 monitoring, (Table 1a). Time intervals can be lengthened provided the last year’s worth of
devices tested (or the last 30 units maintained, whichever is more) had fewer than 4% countable events. It
is notable that 4% is specifically chosen because an entity with a small population (60 units) would have
to adjust its time intervals between maintenance if more than 1 countable event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to adjust the time
interval between maintenance activities if even one unit is found out of tolerance or causes a misoperation.
The minimum number of units that can be tested in any given year is 5% of the population. Note that this
5% threshold sets a practical limitation on total length of time between intervals at 20 years.
If at any time the number of countable events equals or exceeds 4% of the last year’s tested-devices (or
the last 30 units maintained, whichever is more) then the time period between manual maintenance
activities must be decreased. There is a time limit on reaching the decreased time at which the countable
events is less than 4%; this must be attained within three years.
This additional time period of three years to restore segment performance to <4% countable events is
mandated to keep entities from “gaming the PBM system”. It is believed that this requirement provides
the economic disincentives to discourage asset owners from arbitrarily pushing the PBM time intervals
out to 20 years as subsequent analysis might show that an excessive number of countable events could
then require that the entire population segment be re-tested and re-evaluated within 3 years.up to 20 years
without proper statistical data.
10. Overlapping the Verification of Sections of the Protection System
Table 1 requires that every protection system element be periodically verified. One approach is to test the
entire protection scheme as a unit, from voltage and current sources to breaker tripping. For practical
ongoing verification, sections of the protection system may be tested or monitored individually. The
boundaries of the verified sections must overlap to ensure that there are no gaps in the verification. See
Appendix A for additional discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as appropriate, to
establish and operate a maintenance program. For example, a protection system may be divided into
multiple overlapping sections with a different maintenance methodology for each section:
•
•
Time-based maintenance with appropriate maximum verification intervals for categories
of equipment as given in the Unmonitored, Partially Monitored, or Fully Monitored
Tables;
Full monitoring as described in header of Table 1c;
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•
•
A performance-based maintenance program as described in Section 9;
Opportunistic verification using analysis of fault records as described in Section 11
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve fault event records and oscillographic records by data
communications after a fault. They analyze the data closely if there has been an apparent
misoperationMisoperation, as NERC standards require. Some advanced users have commissioned
automatic fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome seems to be
correct. The relay data may be augmented with independently captured digital fault recorder (DFR) data
retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for a manual
time-interval based check on protection systems whose operations are analyzed. Even electromechanical
protection systems instrumented with DFR channels may achieve some CBM benefit. The completeness
of the verification then depends on the number and variety of faults in the vicinity of the relay that
produce relay response records, and the specific data captured.
A typical fault record will verify particular parts of certain protection systems in the vicinity of the fault.
For a given protection system installation, it may or may not be possible to gather within a reasonable
amount of time an ensemble of internal and external fault records that completely verify the protection
system.
For example, fault records may verify that the particular relays that tripped are able to trip via the control
circuit path that was specifically used to clear that fault. A relay or DFR record may indicate correct
operation of the protection communications channel. Furthermore, other nearby protection systems may
verify that they restrain from tripping for a fault just outside their respective zones of protection. The
ensemble of internal fault and nearby external fault event data can verify major portions of the protection
system, and reset the time clock for the Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel with
multiple relays, only the specific relay(s) whose operation can be observed without ambiguity in the
record and the associated wiring paths are verified. Be careful about using fault response data to verify
that settings or calibration are correct. Unless records have been captured for multiple faults close to
either side of a setting boundary, setting or calibration could still be incorrect.
If fault record data is used to show that portions or all of a protection system have been verified to meet
Table 1 requirements, the owner must retain the fault records used, and the maintenance related
conclusions drawn from this data and used to defer Table 1 tests, for at least the retention time interval
given in Section 8.2.
12. Importance of Relay Settings in Maintenance Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to show that
the relays have correct settings and calibration. Microprocessor relays, by contrast, provide the means for
continuously monitoring measurement accuracy. Furthermore, the relay digitizes inputs from one set of
signals to perform all measurement functions in a single self-monitoring microprocessor system. These
relays do not require testing or calibration of each setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older relays. Some
microprocessor relays have hundreds or thousands of settings, many of which are critical to protection
system performance.
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Monitoring does not check measuring element settings. Analysis of fault records may or may not reveal
setting problems. To minimize risk of setting errors after commissioning, the user should enforce strict
settings data base management, with reconfirmation (manual or automatic) that the installed settings are
correct whenever maintenance activity might have changed them. For background and guidance, see [5].
Table 1 requires that settings must be verified to be as specified. The reason for this requirement is
simple. With legacy relays (non-microprocessor protective relays) it is necessary to know the value of the
intended setting in order to test, adjust and calibrate the relay. Proving that the relay works per specified
setting was the de facto procedure. However, with the advanced microprocessor relays it is possible to
change relay settings for the purpose of verifying specific functions and then neglect to return the settings
to the specified values. While there is no specific requirement to maintain a settings management process
there remains a need to verify that the settings left in the relay are the intended, specified settings. This
need may manifest itself after any of the following:
•
•
•
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products for nearly
20 years. Theoretically, any element that is monitored does not need a periodic manual test. A problem
today is that the community of manufacturers and users has not created clear documentation of exactly
what is and is not monitored. Some unmonitored but critical elements are buried in installed systems that
are described as self-monitoring.
Until users are able to document how all parts of a system which are required for the protective functions
are monitored or verified (with help from manufacturers), they must continue with the unmonitored or
partially monitored intervals established in Table 1.
Going forward, manufacturers and users can develop mappings of the monitoring within relays, and
monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of full monitoring, the manufacturers of the microprocessor-based self-monitoring
components in the protection system should publish for the user a document or map that shows:
•
How all internal elements of the product are monitored for any failure that could
impact protection system performance.
•
Which connected circuits are monitored by checks implemented within the product;
how to connect and set the product to assure monitoring of these connected circuits;
and what circuits or potential problems are not monitored.
With this information in hand, the user can document full monitoring for some or all sections by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component and
circuit that is critical to protection is monitored by the microprocessor product(s) or by
other design features.
•
Extending the monitoring to include the alarm transmission facilities through which
failures are reported to remote centers for immediate actionwithin a given time frame to
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
allocate where action can be taken to initiate resolution of the alarm attributed to a
maintenance correctable issue, so that failures of monitoring or alarming systems also
lead to alarms and action.
•
Documenting the plans for verification of any unmonitored elements according to the
requirements of Table 1.
14. Notification of Protection System Failures
When a failure occurs in a protection system, power system security may be compromised, and
notification of the failure must be conducted in accordance with relevant NERC standard(s). Knowledge
of the failure may impact the system operator’s decisions on acceptable loading conditions.
This formal reporting of the failure and repair status to the system operator by the protection system
owner also encourages the system owner to execute repairs as rapidly as possible. In some cases, a
microprocessor relay or carrier set can be replaced in hours; wiring termination failures may be repaired
in a similar time frame. On the other hand, a component in an electromechanical or early-generation
electronic relay may be difficult to find and may hold up repair for weeks. In some situations, the owner
may have to resort to a temporary protection panel, or complete panel replacement.
15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would be that a
BES entity could be prudent in its protective relay maintenance but if its battery maintenance program is
lacking then reliability could still suffer. The NERC glossary outlines a Protection System as containing
specific components. PRC-005-02 requires specific maintenance activities be accomplished within a
specific time interval. As noted previously, higher technology equipment can contain integral monitoring
capability that actually performs maintenance verification activities routinely and often; therefore manual
intervention to perform certain activities on these type devices may not be needed.
15.1 Protective Relays
These relays are defined as the devices that receive the input signal from the current and voltage sensing
devices and are used to isolate a faulted portion of the BES. Devices that sense thermal, vibration,
seismic, pressure, gas or any other non-electrical inputinputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor based equipment in the
following ways, but the relays mustshould meet the calibration requirements of the asset ownerowners’
tolerances.
•
•
Non-microprocessor devices must be tested with voltage and/or current applied to the device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test mandated.
o There is no specific documentation mandated.
15.2 Voltage & Current Sensing Devices
These are the current and voltage sensing devices, usually known as instrument transformers. There is
presently a technology available (fiber-optic Hall-effect) that does not utilize conventional transformer
technology; these devices and other technologies that produce quantities that represent the primary values
of voltage and current are considered to be a type of voltage and current sensing devices included in this
standard.
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
The intent of the maintenance activity is to verify the input to the protective relay from the device that
produces the current or voltage signal sample.
There is no specific test mandated for these devices. The important thing about these signals is to know
that the expected output from these devices actually reaches the protective relay. Therefore, the proof of
the proper operation of these devices also demonstrates the integrity of the wiring (or other medium used
to convey the signal) from the current and voltage sensing device all the way to the protective relay. The
following observations apply.
• There is no specific ratio test, routine test or commissioning test mandated.
• There is no specific documentation mandated.
• It is required that the signal be present at the relay.
• This expectation can be arrived at from any of a number of means; by calculation, by comparison
to other circuits, by commissioning tests, by thorough inspection, or by any means needed to
proveverify the circuit to the satisfaction ofmeets the asset ownerowner’s protection system
maintenance program.
• An example of testing might be a saturation test of a CT with the test values applied at the relay
panel; this therefore tests the CT as well as the wiring from the relay all the back to the CT.
• Another possible test is to measure the signal from the voltage and/or current sensing devices,
during load conditions, at the input to the relay.
• Another example of testing the various voltage and/or current sensing devices is to query the
microprocessor relay for the real-time loading; this can then be compared to other devices to
verify the quantities applied to this relay. Since the input devices have supplied the proper values
to the protective relay then the verification activity has been satisfied. Thus event reports (and
oscillographs) can be used to proveverify that the voltage and current sensing devices are
performing satisfactorily.
• Still another method is to measure total watts and vars around the entire bus; this should add up to
zero watts and zero vars thus proving the voltage and/or current sensing devices system
throughout the bus.
• Another method for proving the voltage and/or current sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
• Other methods that provide documentation that the expected transformer values areas applied to
the inputs to the protective relays are acceptable.
15.3 DC Control Circuitry
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit switcher or
any other interrupting device. It includes the wiring from the batteries to the relays. It includes the wiring
(or other signal conveyance) from every trip output to every trip coil. It includes any device needed for
the correct processing of the needed trip signal to the trip coil of the interrupting device. In short, every
trip path must be verified; the method of verification is optional to the asset owner. An example of testing
methods to accomplish this might be to verify, with a volt-meter, the existence of the proper voltage at the
open contacts and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker (or other
interrupting device) at least once. There is a requirement to operate the circuit breaker (or other
interrupting device) at least once every six years as part of the complete functional test. If a monitoring
system is installed that verifies every parallel trip path then the manual-intervention testing of those
parallel trip paths can be extended to twelve years, however the actual operation of the circuit breaker
must still occur at least once every six years. This 6-year tripping requirement can be completed as easily
as tracking the real-time fault-clearing operations on the circuit breaker.
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
The circuit-interrupting device should not be confused with a motor-operated disconnect. The intent of
this standard is to require maintenance intervals and activities on Protection Systems equipment and not
just all equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground switch as an
interrupting device if this ground switch is utilized in a Protection System and forces a ground fault to
occur that then results in an expected Protection System operation to clear the forced ground fault.
Distribution circuit breakers that participate in the UFLS scheme are excluded from the trip-testing
requirements. There are many circuit interrupting devices in the distribution system that will be operating
for any given under-frequency event that requires tripping for that event. A failure in the tripping-action
of a single distribution breaker will be far less significant than, for example, any single Transmission
Protection System failure such as a failure of a Bus Differential Lock-Out Relay. While many failures of
these distribution breakers could add up to be significant, it is also believed that distribution breakers are
operated often on just fault clearing duty and therefore the distribution circuit breakers are operated at
least as frequently as any requirements that might have appeared in this standard.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay (86) in
any given trip scheme. These electro-mechanical devices must be trip tested. The PSMT SDT considers
these devices to share some similarities in failure modes as electro-mechanical protective relays; as such
there is a six year maximum interval between mandated maintenance tasks.
When verifying the operation of the 94 and 86 relays each normally-open contact that closes to pass a trip
signal must be verified as operating correctly. Normally-open contacts that are not used to pass a trip
signal and normally-closed contacts do not have to be verified. Verification of the tripping paths is the
requirement.
New technology is also accommodated here; there are some tripping systems that have replaced the
traditional hard-wired trip circuitry with other methods of trip-signal conveyance such as fiber-optics. It is
the intent of the PSMT SDT to include this, and any other, technology that is used to convey a trip signal
from a protective relay to a circuit breaker (or other interrupting device) within this category of
equipment.
15.4 Batteries and DC Supplies
IEEE guidelines were usedconsulted to mandatearrive at the maintenance activities for batteries. The
following guidelines were used: IEEE 450 (for Vented Lead-Acid batteries), IEEE 1188 (for ValveRegulated Lead-Acid batteries) and IEEE 1106 (for Nickel-Cadmium batteries).
The present NERC definition of a Protection System is “protective relays, associated communication
systems, voltage and current sensing devices, station batteries and dc control circuitry.” The station
battery is not the only component that provides dc power to a Protection System. In the new definition
for Protection System “station batteries” are replaced with “station dc supply” to make the battery charger
and dc producing stored energy devices (that are not a battery) part of the Protection System that must be
maintained.
To insure that there are no open circuits in a lead acid battery string, IEEE 450-2002 recommends that
during the monthly inspection “battery float charging current or pilot cell specific gravity” should be
measured and recorded. Similarly IEEE 1188-2005 states that during the monthly general inspection, the
“dc float current (per string)” should be checked and recorded “using equipment that is accurate at low
(typically less than 1 A) currents.” These tests are recommended by the IEEE standards for lead acid
batteries to detect an open circuit in a battery set that will make a battery unable to deliver dc power.
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
The PSMT SDT recognizes that there are several technological advances in equipment and testing
procedures that allow the owner to choose how to verify that a battery string is free of open circuits. The
term “continuity” was introduced into the standard to allow the owner to choose how to verify continuity
of a battery set by various methods, and not to limit the owner to the two methods recommended in the
IEEE standards. Continuity as used in Table 1 of the standard refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative terminal.
Without verifying continuity of a station battery, there is no way to determine that the station battery is
available to supply dc power to the station.
Batteries cannot be a unique population segment of a Performance Based-based Maintenance Program
(PBM) because there are too many variables in the electro-chemical process to completely isolate all of
the performance-changing criteria necessary for using PBM on battery systems.
15.5 Tele-protection equipment
This is also known as associated telecommunications equipment. The equipment used for tripping in a
communications assisted trip scheme is a vital piece of the trip circuit. Remote action causing a local trip
can be thought of as another parallel trip path to the trip coil that must be tested.
Besides the trip output and wiring to the trip coil(s) there is also a communications medium that must be
maintained.
Newer technologies now exist that achieve communications-assisted tripping without the conventional
wiring practices of older technology.
For example: older technologies may have included Frequency Shift Key methods. This technology
requires that guard and trip levels be maintained.
The actual tripping path(s) to the trip coil(s) may be tested as a parallel trip path within the dc control
circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are then
interpreted locally as trip signals.
The requirements apply to the communicated signal needed for the proper operation of the protective
relay trip logic or scheme. Therefore this standard is applied to equipment used to convey both trip signals
and block signals.
It was the intent of this standard to require that a test be made of any communications-assisted trip
scheme regardless of the vintage of the technology. The essential element is that the tripping occurs
locally when the remote action has been asserted.
Evidence of operational test or documentation of measurement of signal level, reflected power or dataerror rates is needed.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the control
house to the circuit interrupting device in the yard. This method of tripping the circuit breaker, even
though it might be considered communications, must be maintained per the dc control circuitry
maintenance requirements.
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
15.6 Examples of Evidence of Compliance
To comply with the requirements of this Standard an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team recognizes
that there are concurrent evidence requirements of other standards that could, at times fulfill
evidence requirements of this standard.
For example: maintaining evidence for operation of Special Protection Systems could
concurrently be utilized as proof of the operation of the associated trip coil (provided one can be
certain of the trip coil involved). Thus the reporting requirements that one may have to do for the
misoperation of a Special Protection Scheme under PRC-016 could work for the activity tracking
requirements under this PRC-005-2.
Another example might be:
Some entities maintain records of all interruptions. These records can be concurrently utilized, if
the entity desires, as DC Trip Path verifications.
Analysis of Event Recordings can provide details that can eliminate some hands-on maintenance
activities; however, merely printing out the event report provides limited benefit of verification of
specific maintenance items.
Standardized-forms, hard or soft copy, can be created, filled out and archived. These forms can be
of the entities’ design and can be aimed at answering the specific requirements of the Standard as
well as additional requirements as needed by the entity.
Fill-in blanks, check-boxes, drop-down lists, auto-date formats, etc. can all be used as the primary
action is the maintenance activity; the secondary action is to verify that the maintenance activity
was performed.
Other evidence of compliance might be, but is not limited to:
Prints, maintenance plans, training materials, policies, procedures, data print-outs or exhibits,
correspondence, reports, data-base records, etc.
There is the legacy method of paper trail for everything, this is acceptable. There are also
paperless systems existing and evolving that are also acceptable.
Proof of compliance should simply be the entities’ records of maintenance completed.
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
16. References
NERC/SPCTF/Relay_Maintenance_Tech_Ref_approved_by_PC.pdf
1. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J. Kumm, M.S.
Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power Delivery, Vol. 10,
No. 2, April 1995.
2. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003, 2004
and 2005,” Working Group I17 of Power System Relaying Committee of IEEE Power
Engineering Society, May 2006.
3. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System Relaying
Committee of IEEE Power Engineering Society, September 16, 1999.
4. “Transmission Protective Relay System Performance Measuring Methodology,” Working
Group I3 of Power System Relaying Committee of IEEE Power Engineering Society, January
2002.
5. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3 of
Power System Relaying Committee of IEEE Power Engineering Society, December 2006.
6. “Proposed Statistical Performance Measures for Microprocessor-Based Transmission-Line
Protective Relays, Part I - Explanation of the Statistics, and Part II - Collection and Uses of
Data,” Working Group D5 of Power System Relaying Committee of IEEE Power
Engineering Society, May 1995; Papers 96WM 016-6 PWRD and 96WM 127-1 PWRD,
1996 IEEE Power Engineering Society Winter Meeting.
7. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
8. “Use of Preventative Maintenance and System Performance Data to Optimize Scheduled
Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia Tech Protective
Relay Conference, May 1996.
PSMT SDT References
9. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams, 2003
10. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore, 2005
11. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Figures
Figure 1: Typical Transmission System
For information on numbered components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Figure 2: Typical Generation System
For information on numbered components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
Draft 1: July, 20092: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Figure 1 and& 2 Legend —– Components of Protection Systems
Number In
Figure
Component of Protection
System
Includes
Excludes
1
Protective relays
All protective relays that use current and/or voltage
inputs from current & voltage sensors and that trip the
86, 94 or trip coil.
Devices that use non-electrical methods of operation
including thermal, pressure, gas accumulation, and
vibration. Any ancillary equipment not specified in the
definition of Protection systems. Control and/or
monitoring equipment that is not a part of the automatic
tripping action of the Protection System
2
Voltage & Current &
voltage sensorsSensing
Devices and associated
circuitry
Transformers or otherThe signals from the voltage &
current & voltage sensing devices that produce signals
for protective relays as well as the wiring (or other
medium) used to convey signal output from the sensor
to the protective relay input.
Voltage & current sensing devices that are not a part of
the Protection System, including sync-check systems,
metering systems and data acquisition systems.
3
DC Circuitry
All control wiring (or other medium for conveying trip
signals) associated with the tripping action of 86
devices, 94 devices or trip coils (from all parallel trip
paths). This would include fiber-optic systems that
carry a trip signal as well as hard-wired systems that
carry trip current. Also, it includes auxiliary contacts
providing breaker position data that is necessary for the
proper operation of the Protection System.
Closing circuits, SCADA circuits
4
DC SupplyStation
dc supply
Batteries and battery chargers and any control
power system which has the function of
supplying power to the protective relays,
associated trip circuits and trip coils.
Any power supplies that are not used to power
protective relays or their associated trip circuits
and trip coils.
5
Associated
communications
equipmentsystems
Tele-protection equipment used to convey
remote tripping action to a local trip coil or
blocking signal to the trip logic (if applicable)).
Any communications equipment that is not used
for remote tripping action to a local trip coil or
blocking signal to the trip logic (if applicable)).
(Return)
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Figure 3: Requirements Flowchart
Draft 1: July, 2009
Page 31
PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Requirements
Flowchart
Start
PRC-005-2
Each GO, DP, & TO
shall establish a
maintenance
program (R1)
PerformanceBased
Maintenance
Time -Based or
Condition-Based
Maintenance
Identify components using
TBM, CBM, PBM or
combination (R1.1)
•
Ensure components have
attributes that allow CBM
(Table 1b or Table 1c) or
default to Table 1a
(R2)
•
•
Separate components into segments of 60 or
more
Maintain components for each segment per
Table 1 until at least 30 components have been
tested
Analyze data to determine appropriate interval
for segment(s)
(R3, Attachment A)
Note: GO, DP, & TO
may use one or both
programs
•
•
•
Maintain components per
Table One Intervals and
Activities (R4.1)
•
•
•
Perform maintenance activities from Table 1 for
each segment
Use interval from analysis above
Collect data for future analysis
(R4.2, R3, Attachment A)
Collect countable events from maintenance and
failures
Analyze data from maintenance of last 30
components and/or last year (whichever is
more) to verify countable events are less than
4% threshold
Adjust maintenance interval to keep countable
events below 4%
(R3, Attachment A)
Initiate
corrective
actions as
needed (R4.3)
End
Draft 2: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in Section 10
of the paper. As an example, Figure A-1 shows protection for a critical transmission line by carrier
blocking directional comparison pilot relaying. The goal is to verify the ability of the entire two-terminal
pilot protection scheme to protect for line faults, and to avoid over-tripping for faults external to the
transmission line zone of protection bounded by the current transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays themselves,
the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of internal
electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report the
state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of other
relays, meters, or DFRs. The other readings may be from redundant relaying or measurement
systems or they may be derived from values in other protection zones. Comparison with other
such readings to within required relaying accuracy verifies Voltage & Current Sensing
Draft 2: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
Devices, wiring, and analog signal input processing of the relays. One effective way to do
this is to utilize the relay metered values directly in SCADA, where they can be compared
with other references or state estimator values.
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the protection
system, so each carrier set has a connected or integrated automatic checkback test unit. The
automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation or
noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the protection
system elements that experience tells us are the most prone to fail. But, does this comprise a complete
verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded regions
show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
Draft 2: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
2. Within each line relay, all the microprocessors that participate in the trip decision have been
verified by internal monitoring. However, the trip circuit is actually energized by the contacts
of a small telephone-type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a fault.
3. The check-back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying circuit
or the carrier receiver output state. These connections include microprocessor I/O ports,
electronic driver circuits, wiring, and sometimes telephone-type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but this
does not confirm that the state change indication is correct when the breaker or switch opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified maximum time
interval between trip tests. Clearing of naturally-occurring faults are demonstrations of operation that
reset the time interval clock for testing of each breaker tripped in this way. If faults do not occur, manual
tripping of the breaker through the relay trip output via data communications to the relay microprocessor
meets the requirement for periodic testing.
PRC-005 does not address breaker maintenance, and its protection system test requirements can be met by
energizing the trip circuit in a test mode (breaker disconnected) through the relay microprocessor. This
can be done via a front-panel button command to the relay logic, or application of a simulated fault with a
relay test set. However, utilities have found that breakers often show problems during protection system
tests. It is recommended that protection system verification include periodic testing of the actual tripping
of connected circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and that the
other relay demonstrate reception of that blocking carrier. This can be observed from relay or DFR
records during naturally occurring faults, or by a manual test. If the checkback test sequence were
incorporated in the relay logic, the carrier sets and carrier channel are then included in the overlapping
segments monitored by the two relays, and the monitoring gap is completely eliminated.
Draft 2: April, 2010
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PRC-005-2 Protection — System Maintenance Supplementary Reference (Draft 1)
PRC-005-2
Appendix B — Protection SystemsSystem Maintenance &
Testing Standard Drafting Team
Charles W. Rogers – Chair
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle E. Ashton
Tri-State Generation & Transmission Assn,
Inc.G&T
Bob Bentert
Florida Power & Light Co.Company
Mark Lukas
ComEd
John Ciufo
Hydro One, Inc
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
Richard Ferner
Power Administration
Western Area
Mark Peterson
Great River Energy
Sam Francis
Oncor
Carol A Gerou
Midwest Reliability Organization.
Roger D Green
William
Shultz
Southern Company Generation
Russell C Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
John Kruse
Edison Co.
Draft 2: April, 2010
Commonwealth
William D Shultz
Southern Company Generation
Leonard Swanson, Jr
.
National Grid USA
Eric A Udren
Quanta Technology
Philip B Winston
Georgia Power Company
John A Zipp
ITC Holdings
Page 36
Protection System Definition
Current Approved Definition:
Protective relays, associated communication systems, voltage and current sensing
devices, station batteries and DC control circuitry.
The drafting team initially proposed changes to the definition as shown below:
Protective relays, associated communication systems necessary for correct operation
of protective devices, voltage and current sensing inputs to protective relays devices,
station DC supply batteries, and DC control circuitry from the station DC supply
through the trip coil(s) of the circuit breakers or other interrupting devices.
Based on stakeholder comments, the drafting team made minor changes to the
proposed definition as shown below.
Protective relays, associated communication systems necessary for correct operation
of protective devicesfunctions, voltage and current sensing inputs to protective
relays and associated circuitry from the voltage and current sensing devices, station
dc supply, and DC control circuitry associated with protective functions from the
station dc supply through the trip coil(s) of the circuit breakers or other interrupting
devices.
The proposed definition of Protection System reads as follows:
Protective relays, communication systems necessary for correct operation of
protective functions, voltage and current sensing inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station dc supply,
and control circuitry associated with protective functions from the station dc supply
through the trip coil(s) of the circuit breakers or other interrupting devices.
Original
Source
Inde
x
Directive Language
(including pg #)
Final
Project Standard Coordinato
No
No.
r
Transfer Reason
or
Disposition
Coordinato Project
Standard No.
r
No
Met
Section
and/or
Requirement(s)
Issues/Directives Resolution
Regulatory Filing Status
YES
Standard - ongoing
(expected completion)
2007-17 PRC-0051
McMeekin Specific maximum
allowable intervals are
included in the draft
standard for time-based
programs. Also adding
requirement allowing
either time-based or
condition-based
maintenance period
Specific time intervals
are included in the draft
standard.
McMeekin 2007-17 PRC-005-2
R4.1 and Table 1a,
Table 1b, and Table 1c
Yes
12/19/2012
FERC
1083 1475. We further direct the ERO to consider
2007-17 PRC-005Order 693
FirstEnergy’s and ISO-NE’s suggestion to combine
1
PRC-005-1, PRC-008-0, PRC-011-0 and PRC-017-0
into a single Reliability Standard through the Reliability
Standards development process.
McMeekin These suggestions were
adopted. The SDT is
combining the four
legacy standards into
one.
McMeekin 2007-17 PRC-005-2
R4.1 and Table 1a,
Table 1b, and Table 1c
Yes
12/19/2012
FERC
1088 1492. In addition, the Commission directs the ERO to 2007-17 PRC-008Order 693
develop a modification to PRC-008-0 through the
0
Reliability Standards development process that
includes a requirement that maintenance and testing of
a protection system must be carried out within a
maximum allowable interval that is appropriate to the
type of the protection system and its impact on the
reliability of the Bulk-Power System.
McMeekin Specific maximum
allowable intervals are
included in the draft
standard for time-based
programs. Also adding
requirement allowing
either time-based or
condition-based
maintenance period.
Specific time intervals
are included in the draft
standard.
McMeekin 2007-17 PRC-005-2
R4.1 and Table 1a,
Table 1b, and Table 1c
Yes
12/19/2012
2007-17 PRC-011FERC
1093 1516. The Commission believes that the proposal is
0
Order 693
presently part of the process. The Commission
approves Reliability Standard PRC-011-0 as mandatory
and enforceable. In addition, the Commission directs
the ERO to submit a modification to PRC-011-0
through the Reliability Standards development process
that includes a requirement that maintenance and
testing of a protection system must be carried out
within a maximum allowable interval that is appropriate
to the type of the protection system and its impact on
the reliability of the Bulk-Power System.
McMeekin Specific maximum
allowable intervals are
included in the draft
standard for time-based
programs. Also adding
requirement allowing
either time-based or
condition-based
maintenance period.
Specific time intervals
are included in the draft
standard.
McMeekin 2007-17 PRC-005-2
R4.1 and Table 1a,
Table 1b, and Table 1c
Yes
12/19/2012
FERC
1082 1475. In addition, for the reasons discussed in the
Order 693
NOPR, the Commission directs the ERO to develop a
modification to PRC-005-1 through the Reliability
Standards development process that includes a
requirement that maintenance and testing of a
protection system must be carried out within a
maximum allowable interval that is appropriate to the
type of the protection system and its impact on the
reliability of the Bulk-Power System.
Source
Inde
x
Directive Language
(including pg #)
Project Standard Coordinato
No
No.
r
FERC
1103 1546. The Commission approves Reliability Standard 2007-17 PRC-017Order 693
PRC-017-0 as mandatory and enforceable. In addition,
0
the Commission directs the ERO to develop a
modification to PRC-017-0 through the Reliability
Standards development process, that includes: (1) a
requirement that maintenance and testing of a
protection system must be carried out within a
maximum allowable interval that is appropriate for the
type of the protection system...
FERC
1104 1546. In addition, the Commission directs the ERO to 2007-17 PRC-017Order 693
develop a modification to PRC-017-0 through the
0
Reliability Standards development process, that
includes: ...(2) a requirement that documentation
identified in Requirement R2 shall be routinely provided
to the ERO or Regional Entity.
Transfer Reason
or
Disposition
Coordinato Project
Standard No.
r
No
McMeekin 2007-17 PRC-005-2
McMeekin Specific maximum
allowable intervals are
included in the draft
standard for time-based
programs. Also adding
requirement allowing
either time-based or
condition-based
maintenance period.
Specific time intervals
are included in the draft
standard
McMeekin Transferred within Issues Unknown 2010-05 PRC-012-0
Database to Project
2010-05 that will address
PRC-012-0 and other
SPS standards. The
directive is referencing
documentation of the
actual SPSs – primarily
their design and
R4.1 and Table 1a,
Table 1b, and Table 1c
McMeekin 2007-17 PRC-005-2
McMeekin The SDT is combining
the four legacy standards
into one
McMeekin Breakers/switches are
McMeekin 2007-17 PRC-005-2
specifically NOT included
in the Protection System
definition, and therefore
are NOT addressed in
the draft standard.
R4.1 and Table 1a,
Table 1b, and Table 1c
YES
Standard - ongoing
(expected completion)
Yes
12/19/2012
12/19/2012
Yes
12/19/2012
Yes
12/19/2012
M1, M2, M3, and M4 all
contain examples of
evidence
Yes
12/19/2012
McMeekin Requirement R4 states
McMeekin 2007-17 PRC-005-2
that the program must be
implemented. Evidence
that the program is
implemented is included
in the Measure M4.
M1, M2, M3, and M4 all
contain examples of
evidence
Yes
12/19/2012
McMeekin 2007-17 PRC-005-2
McMeekin The SDT is combining
the four legacy standards
into one
McMeekin 2007-17 PRC-005-2
McMeekin UV Relays on shunt
reactors is not UVLS;
these relays would be
included as pertinent to
relays "applied on or to
protect the BES".
R4.1 and Table 1a,
Table 1b, and Table 1c
Yes
12/19/2012
Yes
12/19/2012
Version 0
Team
Not a standalone standard
2007-17 PRC-0051
Version 0
Team
Include breakers/switches in list
2007-17 PRC-0051
Version 0
Team
Define evidence
2007-17 PRC-0051
McMeekin Requirement R4 states
McMeekin 2007-17 PRC-005-2
that the program must be
implemented. Evidence
that the program is
implemented is included
in the Measure M4.
Version 0
Team
Definition of evidence required
2007-17 PRC-0080
Version 0
Team
Consistent wording from standard to standard required 2007-17 PRC-0080
Version 0
Team
Exemptions for those with shunt reactors
2007-17 PRC-0110
Section
and/or
Requirement(s)
Source
Inde
x
Directive Language
(including pg #)
Project Standard Coordinato
No
No.
r
Transfer Reason
or
Disposition
Coordinato Project
Standard No.
r
No
Section
and/or
Requirement(s)
YES
Standard - ongoing
(expected completion)
Version 0
Team
Define evidence
2007-17 PRC-0110
McMeekin Requirement R4 states
McMeekin 2007-17 PRC-005-2
that the program must be
implemented. Evidence
that the program is
implemented is included
in the Measure M4.
M1, M2, M3, and M4 all
contain examples of
evidence
Yes
12/19/2012
Version 0
Team
Need to retain two dates
2007-17 PRC-0170
See data retention
clause
Yes
12/19/2012
Version 0
Team
Define evidence
2007-17 PRC-0170
McMeekin 2007-17 PRC-005-2
McMeekin The Standard requires
that data be retained for
the last two maintenance
intervals or to the last
audit, whichever is
longer.
McMeekin Requirement R4 states
McMeekin 2007-17 PRC-005-2
that the program must be
implemented. Evidence
that the program is
implemented is included
in the Measure M4.
M1, M2, M3, and M4 all
contain examples of
evidence
Yes
12/19/2012
NERC
Audit
Observatio
n Team
How do you verify compliance for for cts/pts? How do
you audit these within a scheduled maintenance
program. As part of the procedure, most have
accepted visual inspection. Some entities state that
testing of the relays verify functionality of the ct/pt.
2007-17 PRC-0051
McMeekin Records must be
McMeekin 2007-17 PRC-005-2
maintained -- records
only means of proof it
was done. Verification
activities in Table 1
establishes the activities
required for the voltage
and current sensing
inputs to protective relays
and associated circuitry
from the voltage and
current sensing devices.
Specific activities have
been defined within
Table 1a, Table 1b, and
Table 1c.
Yes
12/19/2012
NERC
Audit
Observatio
n Team
How do you verify DC control power? All regions
require functional testing of the breaker. This should
include functional relay & station battery checks,
including breaker tripping, not just a visual inspection.
2007-17 PRC-0051
McMeekin Specific verification
activities are establised
in Table 1.
McMeekin 2007-17 PRC-005-2
Specific activities have
been defined within
Table 1a, Table 1b, and
Table 1c.
Yes
12/19/2012
NERC
Audit
Observatio
n Team
Determine what on schedule means. Is an entity who 2007-17 PRC-005maintained/tested 95% of their relays at the same level
1
of non-compliance as an entity who maintained/tested
10% of their relays?
McMeekin The VSL for maintenance McMeekin 2007-17 PRC-005-2
program implementation
(Requirement R4)
establishes different
VSLs depending on the
degree to which the
program is implemented.
See Phased=in VSLs for
R4
Yes
12/19/2012
NERC
All
Audit
Observatio
n Team
As applicable, each TO,DP and GOP shall have a
2007-17 PRC-005protection system maintenance and testing program for
1
protection systems that affect the reliability of the BES.
Does this include major equipment like circuit breakers
and transformers?
McMeekin Maintenance of
Protection Systems on
all BES equipment are
included within this
standard.
See definition of
Protecton System.
Yes
12/19/2012
McMeekin 2007-17 PRC-005-2
Source
Inde
x
Directive Language
(including pg #)
Project Standard Coordinato
No
No.
r
Transfer Reason
or
Disposition
Coordinato Project
Standard No.
r
No
Fill in the
Blank
Team
Okay if PRC-006 is fixed
2007-17 PRC-0080
McMeekin Applicability section of
PRC-005-2 (4.2.2)
establishes applicability
to UFLS established in
accordance with ERO
requirements.
McMeekin 2007-17 PRC-005-2
Phase
III/IV
Team
All protection systems on the bulk electric system.
2007-17 PRC-0051
McMeekin The Applicabilty section
of the standard defines
the facilities to which the
standard applies.
McMeekin 2007-17 PRC-005-2
Phase
III/IV
Team
PRC 003 to 005 only address generator (and
transmission) protective systems, without defining this
term.
2007-17 PRC-0051
McMeekin The applicability section
addresses Protection
Systems that are
"applied on, or designed
to protect the BES", and
provides additional
specificity regarding
applicable generator
Protection Systems.
McMeekin 2007-17 PRC-005-2
Phase
III/IV
Team
Need to add language to ensure the Regional
Requirements focus on the most impactive scenarios
2007-17 PRC-0051
Phase
III/IV
Team
Phase
III/IV
Team
Modify applicability to clarfify that the requirements are 2007-17 PRC-005applicable to the following:
1
McMeekin 2007-17 PRC-005-2
McMeekin The draft standard
establishes minimim
ERO-wide requirements;
any Regional
requirements would have
to exceed the ERO
requirements.
McMeekin The applicability section
McMeekin 2007-17 PRC-005-2
has been modified.
Phase
III/IV
Team
There is no performance requirement or measure of
effectiveness of a
maintenance program required by the standard
Section
and/or
Requirement(s)
R4.1 and Table 1a,
Table 1b, and Table 1c
YES
Standard - ongoing
(expected completion)
Yes
12/19/2012
Yes
12/19/2012
Yes
12/19/2012
Yes
12/19/2012
Yes
12/19/2012
Yes
12/19/2012
Yes
12/19/2012
Applicability
Applicability
Applicability
All generation protection systems whose misoperations 2007-17 PRC-005impact the bulk
1
electric system
2007-17 PRC-0051
McMeekin Specificity is provided in
4.2.5 addressing
Protection Systems for
generator facilities.
McMeekin For Time-Based (or
Condition-Based)
maintenance, minimum
activities and maximum
intervals are specified;
for performance-based
maintenance,
performance (or
effectiveness) goals are
established.
McMeekin 2007-17 PRC-005-2
R4.2.5
McMeekin 2007-17 PRC-005-2
R3 and Attachment A
Standards Announcement
Initial Ballot Windows Open
July 8–17, 2010
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-17: Protection System Maintenance and Testing
An initial ballot window for standard PRC-005-2 — Protection System Maintenance and Testing
and a separate initial ballot for the definition of “Protection System” are now open until 8 p.m.
Eastern on July 17, 2010.
In addition, members of the ballot pool associated with the standard will be able to vote in a
concurrent non-binding poll on the standard’s Violation Risk Factors (VRFs) and Violation
Severity Levels (VSLs). Members who joined the ballot pool to vote on the standard were
automatically entered in a separate pool to participate in the non-binding poll for the VRFs and
VSLs. The non-binding poll will appear in your list of current ballots, and is labeled
accordingly. (As a reminder, this new approach for VRFs and VSLs is one of the updates
reflected in the recently FERC-approved Reliability Standards Development Procedure —
Version 7.)
Instructions
Members of the ballot pools associated with this project may log in and submit their votes from
the following page: https://standards.nerc.net/CurrentBallots.aspx
Next Steps
Voting results will be posted and announced after the ballot windows close.
Project Background
The draft standard combines the following previous standards:
•
•
•
•
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
The proposed standard addresses FERC directives from FERC Order 693 as well as issues
identified by stakeholders. In accordance with the FERC directives, this draft standard
establishes requirements for a time-based maintenance program, where all relevant devices are
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
maintained according to prescribed maximum intervals. It further establishes requirements for a
condition-based maintenance program, where the hands-on maintenance intervals are adjusted to
reflect the known and reported condition of the relevant devices, and for a performance-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect the
historical performance of the relevant devices.
Project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Special Notes:
On March 18, 2010, FERC issued several orders and notices of proposed rulemakings pertaining
to standards development activities and processes, suggesting a lack of progress in responding to
directives from Order 693 as well in the timeliness of standards development in general. At the
May 2010 NERC Board meeting, Gerry Cauley, NERC’s President, also expressed these
concerns, indicating that the resolution to these concerns is one of NERC’s top priorities in the
near term. As a result, the Standards Committee has authorized deviations from the normal
standards development process for the Protection System Maintenance and Testing project, as
well as other projects that have been through significant stakeholder review through the
development process, to demonstrate that the NERC enterprise is responsive to FERC directives,
and is making progress in developing new standards.
The Standards Committee approved the following deviations from the standards development
process:
•
The proposed changes to the standard and definition will be posted for 35-day comment
periods (rather than 45-day comment periods). The ballot pools will be formed during
the first 21 days of the 35-day comment periods;
•
The initial ballots will be conducted during the last 10 days of the 35-day comment
periods; and
•
The drafting team may make modifications between the initial and recirculation ballots
based on stakeholder comments to improve the overall quality of the standard and
definition.
Applicability of Standards in Project
Transmission Owners
Generator Owners
Distribution Providers
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
-2-
Standards Announcement
Ballot Pools and Pre-ballot Windows (with Comment Periods)
Project 2007-17: Protection System Maintenance and Testing
Project 2007-17: Protection System Maintenance and Testing
On March 18, 2010, FERC issued several orders and notices of proposed rulemakings pertaining
to standards development activities and processes, suggesting a lack of progress in responding to
directives from Order 693 as well in the timeliness of standards development in general. At the
May 2010 NERC Board meeting, Gerry Cauley, NERC’s President, also expressed these
concerns, indicating that the resolution to these concerns is one of NERC’s top priorities in the
near term. As a result, the Standards Committee has authorized deviations from the normal
standards development process for the Protection System Maintenance and Testing project, as
well as other projects that have been through significant stakeholder review through the
development process, to demonstrate that the NERC enterprise is responsive to FERC directives,
and is making progress in developing new standards.
The Standards Committee approved the following deviations from the standards development
process:
•
The proposed changes to the standard and definition will be posted for 35-day comment
periods (rather than 45-day comment periods). The ballot pools will be formed during
the first 21 days of the 35-day comment periods;
•
The initial ballots will be conducted during the last 10 days of the 35-day comment
periods; and
•
The drafting team may make modifications between the initial and recirculation ballots
based on stakeholder comments to improve the overall quality of the standard and
definition.
Ballot Pools (through July 2, 2010)
• There will be two ballot pools: one for the standard (PRC-005-2), which includes the
proposed definition of “Protection System Maintenance Program” and a separate ballot
pool for the proposed definition of “Protection System.”
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
•
Registered Ballot Body members may join the ballot pools until 8 a.m. Eastern on July
2, 2010 to be eligible to vote in the upcoming ballots at the following page:
https://standards.nerc.net/BallotPool.aspx. Members who join the ballot pool to vote on
the standard (PRC-005-2) will automatically be entered in a separate pool to participate
in the non-binding poll of the associated violation risk factors (VRFs) and violation
severity levels (VSLs). (As a reminder, this new approach for VRFs and VSLs is one of
the updates reflected in the recently FERC-approved Reliability Standards Development
Procedure – Version 7.)
•
During the pre-ballot window, members of the ballot pools may communicate with one
another by using their “ballot pool list server.” (Once the balloting begins, ballot pool
members are prohibited from using the ballot pool list servers.) The ballot pool list
server for PRC-005-2 and “Protection System Maintenance Program” is: [email protected]. The ballot pool list server for the proposed definition of
“Protection System” is: [email protected].
Comment Periods (through July 16, 2010)
There will also be two comment periods: one for the standard (PRC-005-2), which includes the
proposed definition of “Protection System Maintenance Program” and a separate comment
period for the proposed definition of “Protection System.”
Please use this electronic form to submit comments on PRC-005-2 and “Protection System
Maintenance Program.” Please use this electronic form to submit comments on “Protection
System.” If you experience any difficulties in using the electronic forms, please contact Lauren
Koller at 609-524-7047.
Documents for this project — including an off-line, unofficial copy of the questions listed in the
comment forms — are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Project Background
The draft standard combines the following previous standards:
•
•
•
•
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
The proposed standard addresses FERC directives from FERC Order 693 as well as issues
identified by stakeholders. In accordance with the FERC directives, this draft standard
establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a
condition-based maintenance program, where the hands-on maintenance intervals are adjusted to
reflect the known and reported condition of the relevant devices, and for a performance-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect the
historical performance of the relevant devices.
Further details are available on the project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
-2-
Applicability of Standards in Project:
Transmission Owners
Generator Owners
Distribution Providers
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Courtney Camburn at
[email protected]
-3-
Standards Announcement
Ballot Pools and Pre-ballot Windows (with Comment Periods)
Project 2007-17: Protection System Maintenance and Testing
Project 2007-17: Protection System Maintenance and Testing
On March 18, 2010, FERC issued several orders and notices of proposed rulemakings pertaining
to standards development activities and processes, suggesting a lack of progress in responding to
directives from Order 693 as well in the timeliness of standards development in general. At the
May 2010 NERC Board meeting, Gerry Cauley, NERC’s President, also expressed these
concerns, indicating that the resolution to these concerns is one of NERC’s top priorities in the
near term. As a result, the Standards Committee has authorized deviations from the normal
standards development process for the Protection System Maintenance and Testing project, as
well as other projects that have been through significant stakeholder review through the
development process, to demonstrate that the NERC enterprise is responsive to FERC directives,
and is making progress in developing new standards.
The Standards Committee approved the following deviations from the standards development
process:
•
The proposed changes to the standard and definition will be posted for 35-day comment
periods (rather than 45-day comment periods). The ballot pools will be formed during
the first 21 days of the 35-day comment periods;
•
The initial ballots will be conducted during the last 10 days of the 35-day comment
periods; and
•
The drafting team may make modifications between the initial and recirculation ballots
based on stakeholder comments to improve the overall quality of the standard and
definition.
Ballot Pools (through July 2, 2010)
• There will be two ballot pools: one for the standard (PRC-005-2), which includes the
proposed definition of “Protection System Maintenance Program” and a separate ballot
pool for the proposed definition of “Protection System.”
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
•
Registered Ballot Body members may join the ballot pools until 8 a.m. Eastern on July
2, 2010 to be eligible to vote in the upcoming ballots at the following page:
https://standards.nerc.net/BallotPool.aspx. Members who join the ballot pool to vote on
the standard (PRC-005-2) will automatically be entered in a separate pool to participate
in the non-binding poll of the associated violation risk factors (VRFs) and violation
severity levels (VSLs). (As a reminder, this new approach for VRFs and VSLs is one of
the updates reflected in the recently FERC-approved Reliability Standards Development
Procedure – Version 7.)
•
During the pre-ballot window, members of the ballot pools may communicate with one
another by using their “ballot pool list server.” (Once the balloting begins, ballot pool
members are prohibited from using the ballot pool list servers.) The ballot pool list
server for PRC-005-2 and “Protection System Maintenance Program” is: [email protected]. The ballot pool list server for the proposed definition of
“Protection System” is: [email protected].
Comment Periods (through July 16, 2010)
There will also be two comment periods: one for the standard (PRC-005-2), which includes the
proposed definition of “Protection System Maintenance Program” and a separate comment
period for the proposed definition of “Protection System.”
Please use this electronic form to submit comments on PRC-005-2 and “Protection System
Maintenance Program.” Please use this electronic form to submit comments on “Protection
System.” If you experience any difficulties in using the electronic forms, please contact Lauren
Koller at 609-524-7047.
Documents for this project — including an off-line, unofficial copy of the questions listed in the
comment forms — are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Project Background
The draft standard combines the following previous standards:
•
•
•
•
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
The proposed standard addresses FERC directives from FERC Order 693 as well as issues
identified by stakeholders. In accordance with the FERC directives, this draft standard
establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a
condition-based maintenance program, where the hands-on maintenance intervals are adjusted to
reflect the known and reported condition of the relevant devices, and for a performance-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect the
historical performance of the relevant devices.
Further details are available on the project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
-2-
Applicability of Standards in Project:
Transmission Owners
Generator Owners
Distribution Providers
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Courtney Camburn at
[email protected]
-3-
Standards Announcement
Initial Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
Project 2007-17: Protection System Maintenance and Testing
The initial ballot for standard PRC-005-2 — Protection System Maintenance and Testing and a separate initial
ballot for the definition of “Protection System” ended on July 17, 2010.
Ballot Results for Standard
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum:
Approval:
91.12 %
22.91 %
Since at least one negative ballot included a comment, these results are not final. A second (or recirculation)
ballot must be conducted. Ballot criteria are listed at the end of the announcement.
Ballot Results for Definition
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum:
Approval:
87.85 %
39.35 %
Since at least one negative ballot included a comment, these results are not final. A second (or recirculation)
ballot must be conducted. Ballot criteria are listed at the end of the announcement.
Violation Risk Factor (VRF) and Violation Severity Level (VSL) Non-binding Poll Results
For the non-binding poll, 86 % of those registered to participate provided an opinion; 28 % of those who
provided an opinion indicated support for the VRFs and VSLs that were proposed.
Next Steps
As part of the recirculation ballot process, the drafting team must draft and post responses to voter comments.
The drafting team will also determine whether or not to make revisions to the balloted item(s). Should the
team decide to make revisions, the revised item(s) will return to the initial ballot phase.
Project Background
The draft standard combines the following previous standards:
•
•
•
•
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
The proposed standard addresses FERC directives from FERC Order 693 as well as issues identified by
stakeholders. In accordance with the FERC directives, this draft standard establishes requirements for a timebased maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a conditionbased maintenance program, where the hands-on maintenance intervals are adjusted to reflect the known and
reported condition of the relevant devices, and for a performance-based maintenance program, where the
hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant devices.
More information is available on the project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
Ballot Criteria
Approval requires both a (1) quorum, which is established by at least 75% of the members of the ballot pool
for submitting either an affirmative vote, a negative vote, or an abstention, and (2) A two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and
negative votes, excluding abstentions and nonresponses. If there are no negative votes with reasons from the
first ballot, the results of the first ballot shall stand. If, however, one or more members submit negative votes
with reasons, a second ballot shall be conducted.
For more information or assistance,
please contact Lauren Koller at [email protected]
NERC Standards
Newsroom • Site Map • Contact NERC
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User Name
Ballot Results
Project 2007-17 Protection System Maintenance and Testing (PRC-005Ballot Name:
2)_in
Password
Ballot Period: 7/8/2010 - 7/17/2010
Log in
Ballot Type: Initial
Register
Total # Votes: 318
Total Ballot Pool: 349
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Quorum: 91.12 % The Quorum has been reached
Weighted Segment
22.91 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
91
9
91
24
73
36
0
11
7
7
349
#
Votes
1
0.2
1
1
1
1
0
0.8
0.6
0.4
7
#
Votes
Fraction
19
1
9
3
17
8
0
2
3
0
62
Negative
Fraction
0.238
0.1
0.111
0.15
0.27
0.235
0
0.2
0.3
0
1.604
Abstain
No
# Votes Vote
61
1
72
17
46
26
0
6
3
4
236
0.763
0.1
0.889
0.85
0.73
0.765
0
0.6
0.3
0.4
5.397
3
6
3
2
3
1
0
1
0
1
20
8
1
7
2
7
1
0
2
1
2
31
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Robert D Smith
John Bussman
Scott Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=33b83659-4a18-493c-b127-1fbd7003baf4[7/19/2010 11:03:03 AM]
Ballot
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Comments
View
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View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New York Power Authority
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Puget Sound Energy, Inc.
John J. Moraski
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Ronald D. Schellberg
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
View
View
View
View
View
View
Michael Moltane
Affirmative
View
Negative
Negative
Negative
Negative
Negative
View
View
View
View
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Martyn Turner
Michelle Rheault
Ernest Hahn
Terry Harbour
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Michael T. Quinn
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
Frank F. Afranji
Richard J Kafka
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Chad Bowman
Catherine Koch
https://standards.nerc.net/BallotResults.aspx?BallotGUID=33b83659-4a18-493c-b127-1fbd7003baf4[7/19/2010 11:03:03 AM]
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
View
View
View
View
View
View
View
View
View
View
View
View
View
Negative
Negative
View
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
View
View
View
View
View
View
Negative
Negative
Negative
Negative
Negative
View
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Arizona Public Service Co.
Atlantic City Electric Company
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Leesburg
Clearwater Power Co.
Cleco Utility Group
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Solutions
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Tim Kelley
Robert Kondziolka
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V. Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Jason L. Murray
Faramarz Amjadi
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Thomas R. Glock
James V. Petrella
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Dave Markham
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Dave Hagen
Bryan Y Harper
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Roman Gillen
Roger Meader
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Dave Sabala
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Bryan Case
Kevin Querry
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=33b83659-4a18-493c-b127-1fbd7003baf4[7/19/2010 11:03:03 AM]
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Negative
Abstain
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Abstain
Abstain
Affirmative
Abstain
Abstain
Abstain
Negative
Negative
Negative
Negative
Negative
Abstain
Negative
Negative
View
View
View
View
View
View
View
View
View
View
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
Gulf Power Company
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Lost River Electric Cooperative
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
North Carolina Municipal Power Agency #1
Northern Indiana Public Service Co.
Northern Lights Inc.
Ocala Electric Utility
Okanogan County Electric Cooperative, Inc.
Orlando Utilities Commission
OTP Wholesale Marketing
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Raft River Rural Electric Cooperative
Sacramento Municipal Utility District
Salem Electric
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
South Mississippi Electric Power Association
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Tri-State G & T Association Inc.
Umatilla Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Integrys Energy Group, Inc.
Gwen S Frazier
Michael D. Penstone
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Rick Crinklaw
Michael Henry
Bruce Merrill
Kenneth Silver
Richard Reynolds
Charles A. Freibert
Greg C Parent
Steven Grego
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John Bos
Marilyn Brown
Michael Schiavone
Denise Roeder
William SeDoris
Jon Shelby
David T. Anderson
Ray Ellis
Ballard Keith Mutters
Bradley Tollerson
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
Heber Carpenter
James Leigh-Kendall
Anthony Schacher
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
Gary Hutson
David Schiada
Jeff Nelson
Ronald L Donahey
Janelle Marriott
Steve Eldrige
Marc Farmer
James R. Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
View
View
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
View
Negative
Negative
Negative
Negative
Abstain
Negative
Negative
Affirmative
Negative
View
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Abstain
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Abstain
Negative
Timothy Beyrle
Negative
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Christopher Plante
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Abstain
https://standards.nerc.net/BallotResults.aspx?BallotGUID=33b83659-4a18-493c-b127-1fbd7003baf4[7/19/2010 11:03:03 AM]
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Madison Gas and Electric Co.
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
Y-W Electric Association, Inc.
AEP Service Corp.
Amerenue
APS
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Entergy Corporation
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Horizon Wind Energy
Indeck Energy Services, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
New Harquahala Generating Co. LLC
New York Power Authority
Northern Indiana Public Service Co.
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Public Utility District No. 1 of Lewis County
Reedy Creek Energy Services
RRI Energy
Joseph G. DePoorter
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Negative
Affirmative
Negative
Affirmative
View
View
View
John D. Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
James A Ziebarth
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
Clement Ma
George Tatar
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
Amir Y Hammad
James B Lewis
Bob Essex
Mike Garton
Robert Smith
Dan Roethemeyer
Stephen Ricker
Doug Ramey
Kenneth Parker
Stanley M Jaskot
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Cynthia E Sulzer
Greg Froehling
Brent Hebert
Rex A Roehl
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Daniel Duff
Dennis Florom
Charlie Martin
Mike Laney
Mark Aikens
David Gordon
Nicholas Q Hayes
Gerald Mannarino
Michael K Wilkerson
Stacie Hebert
Richard J. Padilla
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A. Heimbach
Wayne Lewis
David Murray
Steven Grega
Bernie Budnik
Thomas J. Bradish
https://standards.nerc.net/BallotResults.aspx?BallotGUID=33b83659-4a18-493c-b127-1fbd7003baf4[7/19/2010 11:03:03 AM]
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
View
View
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
View
View
View
View
View
View
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
View
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern Company Generation
SRW Cogeneration Limited Partnership
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Centralia Generation, LLC
Tri-State G & T Association Inc.
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Energy
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
OTP Wholesale Marketing
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Ascendant Energy Services, LLC
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
SPS Consulting Group Inc.
Utility Services, Inc.
Bethany Wright
Glen Reeves
Daniel Baerman
Michael J. Haynes
Brenda K. Atkins
Richard Jones
Jerry W Johnson
William D Shultz
Michael Albosta
RJames Rocha
Scott M. Helyer
George T. Ballew
Joanna Luong-Tran
Barry Ingold
Affirmative
Negative
Negative
Negative
Karl Bryan
Affirmative
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
Terri F Benoit
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Thomas E Washburn
Silvia P Mitchell
Donna Stephenson
Thomas Saitta
Paul Shipps
Eric Ruskamp
Daryn Barker
Brad Jones
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
David Ried
Bruce Glorvigen
James Eckelkamp
James D. Hebson
Hugh A. Owen
Trent Carlson
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
John Stonebarger
Affirmative
David F. Lemmons
Merle Ashton
Roger C Zaklukiewicz
James A Maenner
Kristina M. Loudermilk
Raymond Tran
Jim D. Cyrulewski
Margaret Ryan
Peggy Abbadini
Jim R Stanton
Brian Evans-Mongeon
https://standards.nerc.net/BallotResults.aspx?BallotGUID=33b83659-4a18-493c-b127-1fbd7003baf4[7/19/2010 11:03:03 AM]
View
Negative
Negative
View
View
Negative
Affirmative
Abstain
Negative
View
View
View
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View
View
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View
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View
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Negative
View
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
View
Negative
Negative
View
View
NERC Standards
8
9
9
9
9
9
9
9
10
10
10
10
10
10
10
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
North Carolina Utilities Commission
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council
Terry Volkmann
William Mitchell Chamberlain
Negative
Negative
Donald E. Nelson
Affirmative
Diane J. Barney
Negative
Kimberly J. Jones
Jerome Murray
Philip Riley
Ric Campbell
Linda Campbell
Dan R. Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B Edge
Louise McCarren
Negative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=33b83659-4a18-493c-b127-1fbd7003baf4[7/19/2010 11:03:03 AM]
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View
View
Negative
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User Name
Ballot Results
Project 2007-17 Protection System Maintenance and Testing (Protection
Ballot Name:
System definition)_in
Password
Ballot Period: 7/8/2010 - 7/17/2010
Log in
Ballot Type: Initial
Register
Total # Votes: 282
Total Ballot Pool: 321
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Quorum: 87.85 % The Quorum has been reached
Weighted Segment
39.35 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
89
9
71
24
67
37
0
11
6
7
321
#
Votes
1
0.2
1
1
1
1
0
0.7
0.5
0.3
6.7
#
Votes
Fraction
31
1
22
7
17
10
0
3
4
0
95
Negative
Fraction
0.425
0.1
0.393
0.368
0.327
0.323
0
0.3
0.4
0
2.636
Abstain
No
# Votes Vote
42
1
34
12
35
21
0
4
1
3
153
0.575
0.1
0.607
0.632
0.673
0.677
0
0.4
0.1
0.3
4.064
4
6
7
2
7
3
0
2
1
2
34
12
1
8
3
8
3
0
2
0
2
39
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Robert D Smith
John Bussman
Scott Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=721ceddb-9323-4021-9bcc-d65ad6aa2f31[7/19/2010 11:05:32 AM]
Ballot
Comments
Affirmative
Negative
Negative
Affirmative
Negative
View
View
View
View
Negative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnesota Power, Inc.
National Grid
Nebraska Public Power District
New York Power Authority
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
John J. Moraski
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Ronald D. Schellberg
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Michael Moltane
Affirmative
View
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
Doug Bantam
Robert Ganley
Martyn Turner
Michelle Rheault
Negative
Negative
Negative
Affirmative
View
View
View
View
Ernest Hahn
Terry Harbour
Randi Woodward
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
Richard J Kafka
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Chad Bowman
Catherine Koch
Tim Kelley
Robert Kondziolka
https://standards.nerc.net/BallotResults.aspx?BallotGUID=721ceddb-9323-4021-9bcc-d65ad6aa2f31[7/19/2010 11:05:32 AM]
Affirmative
Negative
Negative
View
View
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
View
View
Affirmative
Negative
Affirmative
View
View
View
View
View
View
View
View
View
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
View
View
View
View
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Santee Cooper
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Arizona Public Service Co.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Leesburg
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V. Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Jason L. Murray
Faramarz Amjadi
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Thomas R. Glock
James V. Petrella
Pat G. Harrington
Rebecca Berdahl
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C Parent
Steven Grego
https://standards.nerc.net/BallotResults.aspx?BallotGUID=721ceddb-9323-4021-9bcc-d65ad6aa2f31[7/19/2010 11:05:32 AM]
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Abstain
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Negative
Negative
Abstain
Negative
Abstain
Negative
Abstain
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salem Electric
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Tri-State G & T Association Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
Y-W Electric Association, Inc.
AEP Service Corp.
Amerenue
APS
Avista Corp.
Black Hills Corp
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David T. Anderson
Ballard Keith Mutters
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Anthony Schacher
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
David Schiada
Jeff Nelson
Ronald L Donahey
Janelle Marriott
James R. Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Timothy Beyrle
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Christopher Plante
Joseph G. DePoorter
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
View
View
View
View
View
View
View
View
View
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
John D. Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
James A Ziebarth
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
George Tatar
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
https://standards.nerc.net/BallotResults.aspx?BallotGUID=721ceddb-9323-4021-9bcc-d65ad6aa2f31[7/19/2010 11:05:32 AM]
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Entergy Corporation
FirstEnergy Solutions
Florida Municipal Power Agency
Green Country Energy
Horizon Wind Energy
Indeck Energy Services, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
New Harquahala Generating Co. LLC
New York Power Authority
Northern Indiana Public Service Co.
Otter Tail Power Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Public Utility District No. 1 of Lewis County
Reedy Creek Energy Services
RRI Energy
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Centralia Generation, LLC
Tri-State G & T Association Inc.
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Amir Y Hammad
James B Lewis
Bob Essex
Mike Garton
Robert Smith
Dan Roethemeyer
Stephen Ricker
Doug Ramey
Kenneth Parker
Stanley M Jaskot
Kenneth Dresner
David Schumann
Greg Froehling
Brent Hebert
Rex A Roehl
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Daniel Duff
Dennis Florom
Charlie Martin
Mike Laney
Mark Aikens
David Gordon
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Karl Bryan
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=721ceddb-9323-4021-9bcc-d65ad6aa2f31[7/19/2010 11:05:32 AM]
View
View
View
View
View
Abstain
Nicholas Q Hayes
Gerald Mannarino
Michael K Wilkerson
Stacie Hebert
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A. Heimbach
Wayne Lewis
David Murray
Steven Grega
Bernie Budnik
Thomas J. Bradish
Bethany Wright
Glen Reeves
Daniel Baerman
Michael J. Haynes
Brenda K. Atkins
Richard Jones
Jerry W Johnson
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Joanna Luong-Tran
Barry Ingold
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
Terri F Benoit
View
View
Negative
Negative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
View
View
View
View
View
Abstain
Affirmative
Abstain
Negative
Negative
Negative
Negative
View
View
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Energy
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
OTP Wholesale Marketing
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Ascendant Energy Services, LLC
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
SPS Consulting Group Inc.
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P Mitchell
Donna Stephenson
Thomas Saitta
Paul Shipps
Eric Ruskamp
Daryn Barker
Brad Jones
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
David Ried
Bruce Glorvigen
James Eckelkamp
James D. Hebson
Hugh A. Owen
Trent Carlson
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Affirmative
Affirmative
Affirmative
John Stonebarger
Affirmative
View
Negative
Negative
Negative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
View
View
View
View
View
View
View
Affirmative
Abstain
Negative
View
Abstain
Affirmative
David F. Lemmons
Negative
Roger C Zaklukiewicz
Affirmative
James A Maenner
Abstain
Kristina M. Loudermilk
Affirmative
Merle Ashton
Raymond Tran
Affirmative
Jim D. Cyrulewski
Negative
Margaret Ryan
Abstain
Peggy Abbadini
Jim R Stanton
Negative
Brian Evans-Mongeon
Negative
Terry Volkmann
Negative
William Mitchell Chamberlain Negative
Donald E. Nelson
Affirmative
Diane J. Barney
Affirmative
Jerome Murray
Philip Riley
Ric Campbell
Linda Campbell
Dan R. Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B Edge
Louise McCarren
Abstain
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
View
View
View
Abstain
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Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
https://standards.nerc.net/BallotResults.aspx?BallotGUID=721ceddb-9323-4021-9bcc-d65ad6aa2f31[7/19/2010 11:05:32 AM]
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NERC Standards
Copyright © 2009 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=721ceddb-9323-4021-9bcc-d65ad6aa2f31[7/19/2010 11:05:32 AM]
Non-binding Poll Project 2007-17 Protection System Maintenance - Non-binding Poll
Name: for VRFs and VSLs
Poll Period: 7/8/2010 - 7/17/2010
Total # Opinions: 300
Total Ballot Pool: 349
86% of those who registered to participate provided an opinion;
Summary Results: 28% of those who provided an opinion indicated support for the
VRFs and VSLs that were proposed
Individual Ballot Pool Results
Segment
Organization
Member
Ballot
Comments
1
Allegheny Power
Rodney Phillips
Negative
1
Ameren Services
Kirit S. Shah
Negative
View
1
American Electric Power
Paul B. Johnson
Negative
View
1
American Transmission Company,
LLC
Jason Shaver
1
Arizona Public Service Co.
Robert D Smith
1
Associated Electric Cooperative, Inc. John Bussman
1
Avista Corp.
Scott Kinney
Abstain
1
Baltimore Gas & Electric Company
John J. Moraski
Abstain
1
BC Transmission Corporation
Gordon Rawlings
Negative
1
Beaches Energy Services
Joseph S. Stonecipher
Negative
1
Black Hills Corp
Eric Egge
1
Bonneville Power Administration
Donald S. Watkins
1
CenterPoint Energy
Paul Rocha
1
Central Maine Power Company
Brian Conroy
1
City of Vero Beach
Randall McCamish
1
City Utilities of Springfield, Missouri
Jeff Knottek
Abstain
View
Affirmative
Negative
Abstain
Negative
Abstain
1
1
Clark Public Utilities
Jack Stamper
1
Cleco Power LLC
Danny McDaniel
Negative
1
Colorado Springs Utilities
Paul Morland
Negative
1
Commonwealth Edison Co.
Daniel Brotzman
Affirmative
1
Consolidated Edison Co. of New York
Christopher L de
Graffenried
Negative
1
Dairyland Power Coop.
Robert W. Roddy
Abstain
1
Dayton Power & Light Co.
Hertzel Shamash
1
Deseret Power
James Tucker
Affirmative
1
Dominion Virginia Power
John K Loftis
Abstain
1
Duke Energy Carolina
Douglas E. Hils
Negative
1
East Kentucky Power Coop.
George S. Carruba
Negative
1
Empire District Electric Co.
Ralph Frederick Meyer
Negative
1
Entergy Corporation
George R. Bartlett
1
FirstEnergy Energy Delivery
Robert Martinko
Negative
1
Florida Keys Electric Cooperative
Assoc.
Dennis Minton
Negative
1
Gainesville Regional Utilities
Luther E. Fair
Abstain
1
GDS Associates, Inc.
Claudiu Cadar
Abstain
1
Georgia Transmission Corporation
Harold Taylor, II
1
Great River Energy
Gordon Pietsch
1
Hydro One Networks, Inc.
Ajay Garg
1
Idaho Power Company
Ronald D. Schellberg
1
International Transmission Company
Michael Moltane
Holdings Corp
1
Kansas City Power & Light Co.
Michael Gammon
Abstain
View
Affirmative
Negative
View
View
Affirmative
Negative
Affirmative
Negative
View
2
1
Keys Energy Services
Stan T. Rzad
Negative
View
1
Lake Worth Utilities
Walt Gill
Negative
View
1
Lakeland Electric
Larry E Watt
1
Lee County Electric Cooperative
John W Delucca
1
Lincoln Electric System
Doug Bantam
1
Long Island Power Authority
Robert Ganley
1
Lower Colorado River Authority
Martyn Turner
1
Manitoba Hydro
Michelle Rheault
1
Metropolitan Water District of
Southern California
Ernest Hahn
1
MidAmerican Energy Co.
Terry Harbour
Negative
1
National Grid
Saurabh Saksena
Negative
1
Nebraska Public Power District
Richard L. Koch
Abstain
1
New York Power Authority
Arnold J. Schuff
Negative
1
Northeast Utilities
David H. Boguslawski
Affirmative
1
NorthWestern Energy
John Canavan
Affirmative
1
Ohio Valley Electric Corp.
Robert Mattey
Negative
1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
1
Omaha Public Power District
Douglas G Peterchuck
1
Oncor Electric Delivery
Michael T. Quinn
Affirmative
1
Orlando Utilities Commission
Brad Chase
Affirmative
1
Otter Tail Power Company
Lawrence R. Larson
Negative
1
Pacific Gas and Electric Company
Chifong L. Thomas
Negative
1
PacifiCorp
Mark Sampson
Negative
1
PECO Energy
Ronald Schloendorn
Abstain
Negative
Negative
Abstain
View
Affirmative
Negative
View
Affirmative
3
1
Platte River Power Authority
John C. Collins
Negative
View
1
Portland General Electric Co.
Frank F. Afranji
1
Potomac Electric Power Co.
Richard J Kafka
1
PowerSouth Energy Cooperative
Larry D. Avery
1
PPL Electric Utilities Corp.
Brenda L Truhe
Negative
View
1
Public Service Company of New
Mexico
Laurie Williams
Negative
View
1
Public Service Electric and Gas Co.
Kenneth D. Brown
1
Public Utility District No. 1 of Chelan
Chad Bowman
County
1
Puget Sound Energy, Inc.
1
Sacramento Municipal Utility District Tim Kelley
1
Salt River Project
Robert Kondziolka
1
Santee Cooper
Terry L. Blackwell
1
SCE&G
Henry Delk, Jr.
Negative
1
Seattle City Light
Pawel Krupa
Negative
1
South Texas Electric Cooperative
Richard McLeon
Negative
1
Southern California Edison Co.
Dana Cabbell
1
Southern Company Services, Inc.
Horace Stephen
Williamson
1
Southern Illinois Power Coop.
William G. Hutchison
1
Southwest Transmission
Cooperative, Inc.
James L. Jones
1
Southwestern Power Administration
Gary W Cox
1
Sunflower Electric Power Corporation Noman Lee Williams
1
Tennessee Valley Authority
Larry Akens
Negative
1
Tri-State G & T Association Inc.
Keith V. Carman
Negative
Abstain
Abstain
Abstain
Catherine Koch
Abstain
Abstain
Affirmative
Abstain
View
Negative
Abstain
Negative
View
4
1
Tucson Electric Power Co.
John Tolo
Affirmative
1
United Illuminating Co.
Jonathan Appelbaum
1
Westar Energy
Allen Klassen
1
Western Area Power Administration
Brandy A Dunn
1
Xcel Energy, Inc.
Gregory L Pieper
Negative
2
Alberta Electric System Operator
Jason L. Murray
Abstain
2
BC Transmission Corporation
Faramarz Amjadi
Abstain
2
Electric Reliability Council of Texas,
Inc.
Chuck B Manning
Abstain
2
Independent Electricity System
Operator
Kim Warren
Abstain
2
ISO New England, Inc.
Kathleen Goodman
2
Midwest ISO, Inc.
Jason L Marshall
Abstain
View
2
New York Independent System
Operator
Gregory Campoli
Negative
View
2
PJM Interconnection, L.L.C.
Tom Bowe
Abstain
2
Southwest Power Pool
Charles H Yeung
Abstain
3
Alabama Power Company
Richard J. Mandes
Abstain
View
3
Allegheny Power
Bob Reeping
Negative
View
3
Ameren Services
Mark Peters
Negative
3
American Electric Power
Raj Rana
3
Arizona Public Service Co.
Thomas R. Glock
Abstain
3
Atlantic City Electric Company
James V. Petrella
Affirmative
3
BC Hydro and Power Authority
Pat G. Harrington
Abstain
3
Blachly-Lane Electric Co-op
Bud Tracy
3
Bonneville Power Administration
Rebecca Berdahl
Negative
View
Affirmative
View
Negative
Affirmative
5
3
Central Electric Cooperative, Inc.
(Redmond, Oregon)
Dave Markham
Negative
3
Central Lincoln PUD
Steve Alexanderson
Negative
View
3
City of Bartow, Florida
Matt Culverhouse
Negative
View
3
City of Clewiston
Lynne Mila
Negative
3
City of Farmington
Linda R. Jacobson
Negative
3
City of Green Cove Springs
Gregg R Griffin
Negative
3
City of Leesburg
Phil Janik
Negative
3
Clearwater Power Co.
Dave Hagen
Negative
3
Cleco Utility Group
Bryan Y Harper
Negative
3
ComEd
Bruce Krawczyk
Affirmative
3
Consolidated Edison Co. of New York Peter T Yost
3
Consumers Energy
David A. Lapinski
3
Consumers Power Inc.
Roman Gillen
3
Coos-Curry Electric Cooperative, Inc Roger Meader
Negative
3
Cowlitz County PUD
Russell A Noble
Negative
3
Delmarva Power & Light Co.
Michael R. Mayer
Affirmative
3
Detroit Edison Company
Kent Kujala
Affirmative
3
Dominion Resources Services
Michael F Gildea
3
Douglas Electric Cooperative
Dave Sabala
Negative
3
Duke Energy Carolina
Henry Ernst-Jr
Negative
3
East Kentucky Power Coop.
Sally Witt
Negative
3
Entergy
Joel T Plessinger
Negative
3
Fall River Rural Electric Cooperative
Bryan Case
Negative
3
FirstEnergy Solutions
Kevin Querry
Negative
Negative
View
Abstain
Negative
View
Abstain
View
View
6
3
Florida Power Corporation
Lee Schuster
3
Gainesville Regional Utilities
Kenneth Simmons
Negative
3
Georgia Power Company
Anthony L Wilson
Abstain
View
3
Georgia System Operations
Corporation
R Scott S. BarfieldMcGinnis
Negative
View
3
Great River Energy
Sam Kokkinen
Negative
3
Gulf Power Company
Gwen S Frazier
Abstain
3
Hydro One Networks, Inc.
Michael D. Penstone
3
JEA
Garry Baker
3
Kansas City Power & Light Co.
Charles Locke
Negative
3
Kissimmee Utility Authority
Gregory David
Woessner
Negative
3
Lakeland Electric
Mace Hunter
Abstain
3
Lane Electric Cooperative, Inc.
Rick Crinklaw
Negative
3
Lincoln Electric Cooperative, Inc.
Michael Henry
Negative
3
Lincoln Electric System
Bruce Merrill
3
Los Angeles Department of Water &
Power
Kenneth Silver
3
Lost River Electric Cooperative
Richard Reynolds
3
Louisville Gas and Electric Co.
Charles A. Freibert
3
Manitoba Hydro
Greg C Parent
Negative
3
MEAG Power
Steven Grego
Affirmative
3
MidAmerican Energy Co.
Thomas C. Mielnik
3
Mississippi Power
Don Horsley
3
Municipal Electric Authority of
Georgia
Steven M. Jackson
Affirmative
3
Muscatine Power & Water
John Bos
Affirmative
View
Affirmative
View
Abstain
Negative
Affirmative
View
Negative
Abstain
View
7
3
New York Power Authority
Marilyn Brown
Negative
3
Niagara Mohawk (National Grid
Company)
Michael Schiavone
Negative
3
North Carolina Municipal Power
Agency #1
Denise Roeder
3
Northern Indiana Public Service Co.
William SeDoris
Negative
3
Northern Lights Inc.
Jon Shelby
Negative
3
Ocala Electric Utility
David T. Anderson
Negative
3
Okanogan County Electric
Cooperative, Inc.
Ray Ellis
Negative
3
Orlando Utilities Commission
Ballard Keith Mutters
3
OTP Wholesale Marketing
Bradley Tollerson
3
PacifiCorp
John Apperson
Affirmative
3
PECO Energy an Exelon Co.
Vincent J. Catania
Affirmative
3
Platte River Power Authority
Terry L Baker
3
Potomac Electric Power Co.
Robert Reuter
3
Progress Energy Carolinas
Sam Waters
3
Public Service Electric and Gas Co.
Jeffrey Mueller
3
Public Utility District No. 1 of Chelan
Kenneth R. Johnson
County
3
Public Utility District No. 2 of Grant
County
3
Raft River Rural Electric Cooperative Heber Carpenter
3
Sacramento Municipal Utility District James Leigh-Kendall
3
Salem Electric
Anthony Schacher
Negative
3
Salmon River Electric Cooperative
Ken Dizes
Negative
3
Salt River Project
John T. Underhill
Greg Lange
View
Abstain
Negative
Negative
View
Abstain
Abstain
Negative
Negative
Abstain
8
3
San Diego Gas & Electric
Scott Peterson
3
Santee Cooper
Zack Dusenbury
Abstain
3
Seattle City Light
Dana Wheelock
Negative
3
South Mississippi Electric Power
Association
Gary Hutson
3
Southern California Edison Co.
David Schiada
3
Springfield Utility Board
Jeff Nelson
Negative
3
Tampa Electric Co.
Ronald L Donahey
Negative
3
Tri-State G & T Association Inc.
Janelle Marriott
Negative
3
Umatilla Electric Cooperative
Steve Eldrige
Negative
3
West Oregon Electric Cooperative,
Inc.
Marc Farmer
Negative
3
Wisconsin Electric Power Marketing
James R. Keller
3
Wisconsin Public Service Corp.
Gregory J Le Grave
Abstain
3
Xcel Energy, Inc.
Michael Ibold
Abstain
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Abstain
4
American Municipal Power - Ohio
Kevin Koloini
Negative
4
American Public Power Association
Allen Mosher
Abstain
4
City of Clewiston
Kevin McCarthy
Negative
4
City of New Smyrna Beach Utilities
Commission
Timothy Beyrle
Negative
4
Consumers Energy
David Frank Ronk
4
Cowlitz County PUD
Rick Syring
Negative
4
Detroit Edison Company
Daniel Herring
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
Fort Pierce Utilities Authority
Thomas W. Richards
Abstain
Affirmative
View
View
Affirmative
Affirmative
View
View
Abstain
9
4
Georgia System Operations
Corporation
Guy Andrews
4
Illinois Municipal Electric Agency
Bob C. Thomas
Abstain
4
Integrys Energy Group, Inc.
Christopher Plante
Abstain
4
Madison Gas and Electric Co.
Joseph G. DePoorter
Abstain
4
Ohio Edison Company
Douglas Hohlbaugh
Negative
4
Old Dominion Electric Coop.
Mark Ringhausen
Abstain
4
Public Utility District No. 1 of
Douglas County
Henry E. LuBean
Affirmative
4
Public Utility District No. 1 of
Snohomish County
John D. Martinsen
4
Sacramento Municipal Utility District Mike Ramirez
4
Seattle City Light
Hao Li
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
4
South Mississippi Electric Power
Association
Steve McElhaney
4
Wisconsin Energy Corp.
Anthony Jankowski
4
Y-W Electric Association, Inc.
James A Ziebarth
Affirmative
5
AEP Service Corp.
Brock Ondayko
Affirmative
5
Amerenue
Sam Dwyer
Negative
5
APS
Mel Jensen
Abstain
5
Avista Corp.
Edward F. Groce
Abstain
5
BC Hydro and Power Authority
Clement Ma
5
Black Hills Corp
George Tatar
5
Bonneville Power Administration
Francis J. Halpin
5
Chelan County Public Utility District
#1
John Yale
Negative
View
View
Abstain
Negative
Abstain
Negative
View
View
Affirmative
Negative
Affirmative
10
5
City of Grand Island
Jeff Mead
Abstain
5
City of Tallahassee
Alan Gale
Negative
5
City Water, Light & Power of
Springfield
Karl E. Kohlrus
5
Consolidated Edison Co. of New York Wilket (Jack) Ng
Negative
5
Constellation Power Source
Generation, Inc.
Amir Y Hammad
Negative
View
5
Consumers Energy
James B Lewis
Negative
View
5
Cowlitz County PUD
Bob Essex
Negative
View
5
Dominion Resources, Inc.
Mike Garton
Abstain
5
Duke Energy
Robert Smith
Negative
5
Dynegy Inc.
Dan Roethemeyer
5
East Kentucky Power Coop.
Stephen Ricker
5
Energy Northwest - Columbia
Generating Station
Doug Ramey
Abstain
5
Entegra Power Group, LLC
Kenneth Parker
Abstain
5
Entergy Corporation
Stanley M Jaskot
5
Exelon Nuclear
Michael Korchynsky
5
ExxonMobil Research and
Engineering
Martin Kaufman
Negative
5
FirstEnergy Solutions
Kenneth Dresner
Negative
View
5
Florida Municipal Power Agency
David Schumann
Negative
View
5
Great River Energy
Cynthia E Sulzer
5
Green Country Energy
Greg Froehling
Affirmative
5
Horizon Wind Energy
Brent Hebert
Affirmative
5
Indeck Energy Services, Inc.
Rex A Roehl
Negative
5
JEA
Donald Gilbert
Affirmative
Affirmative
Negative
Negative
View
Affirmative
Abstain
11
5
Kansas City Power & Light Co.
Scott Heidtbrink
Negative
View
5
Kissimmee Utility Authority
Mike Blough
5
Lakeland Electric
Thomas J Trickey
5
Liberty Electric Power LLC
Daniel Duff
Negative
View
5
Lincoln Electric System
Dennis Florom
Abstain
5
Louisville Gas and Electric Co.
Charlie Martin
Affirmative
5
Luminant Generation Company LLC
Mike Laney
Affirmative
5
Manitoba Hydro
Mark Aikens
Negative
5
Massachusetts Municipal Wholesale
Electric Company
David Gordon
5
New Harquahala Generating Co. LLC Nicholas Q Hayes
5
New York Power Authority
Gerald Mannarino
5
Northern Indiana Public Service Co.
Michael K Wilkerson
Negative
5
Otter Tail Power Company
Stacie Hebert
Negative
5
Pacific Gas and Electric Company
Richard J. Padilla
Negative
5
PacifiCorp
Sandra L. Shaffer
Affirmative
5
Portland General Electric Co.
Gary L Tingley
5
PowerSouth Energy Cooperative
Tim Hattaway
5
PPL Generation LLC
Mark A. Heimbach
5
Progress Energy Carolinas
Wayne Lewis
Negative
5
PSEG Power LLC
David Murray
Abstain
5
Public Utility District No. 1 of Lewis
County
Steven Grega
Negative
5
Reedy Creek Energy Services
Bernie Budnik
Negative
5
RRI Energy
Thomas J. Bradish
5
Sacramento Municipal Utility District Bethany Wright
Abstain
Abstain
View
Negative
Abstain
Affirmative
Abstain
12
5
Salt River Project
Glen Reeves
Negative
5
San Diego Gas & Electric
Daniel Baerman
Negative
5
Seattle City Light
Michael J. Haynes
5
Seminole Electric Cooperative, Inc.
Brenda K. Atkins
5
South Carolina Electric & Gas Co.
Richard Jones
5
South Mississippi Electric Power
Association
Jerry W Johnson
Negative
5
Southern Company Generation
William D Shultz
Abstain
5
SRW Cogeneration Limited
Partnership
Michael Albosta
Negative
5
Tampa Electric Co.
RJames Rocha
5
Tenaska, Inc.
Scott M. Helyer
5
Tennessee Valley Authority
George T. Ballew
5
TransAlta Centralia Generation, LLC
Joanna Luong-Tran
5
Tri-State G & T Association Inc.
Barry Ingold
Affirmative
5
U.S. Army Corps of Engineers
Northwestern Division
Karl Bryan
Affirmative
5
U.S. Bureau of Reclamation
Martin Bauer P.E.
5
Wisconsin Electric Power Co.
Linda Horn
5
Wisconsin Public Service Corp.
Leonard Rentmeester
5
Xcel Energy, Inc.
Liam Noailles
6
AEP Marketing
Edward P. Cox
Negative
6
Ameren Energy Marketing Co.
Jennifer Richardson
Negative
6
Bonneville Power Administration
Brenda S. Anderson
Affirmative
6
Cleco Power LLC
Matthew D Cripps
Negative
6
Consolidated Edison Co. of New York Nickesha P Carrol
Negative
View
Affirmative
View
Abstain
Negative
View
Abstain
Negative
View
Affirmative
View
13
6
Constellation Energy Commodities
Group
Brenda Powell
Negative
6
Dominion Resources, Inc.
Louis S Slade
Abstain
6
Duke Energy Carolina
Walter Yeager
Negative
6
Entergy Services, Inc.
Terri F Benoit
Negative
6
Eugene Water & Electric Board
Daniel Mark Bedbury
Affirmative
6
Exelon Power Team
Pulin Shah
Affirmative
6
FirstEnergy Solutions
Mark S Travaglianti
Negative
6
Florida Municipal Power Pool
Thomas E Washburn
Abstain
6
Florida Power & Light Co.
Silvia P Mitchell
6
Great River Energy
Donna Stephenson
6
Kansas City Power & Light Co.
Thomas Saitta
6
Lakeland Electric
Paul Shipps
Abstain
6
Lincoln Electric System
Eric Ruskamp
Abstain
6
Louisville Gas and Electric Co.
Daryn Barker
6
Luminant Energy
Brad Jones
6
Manitoba Hydro
Daniel Prowse
Negative
6
New York Power Authority
Thomas Papadopoulos
Negative
6
Northern Indiana Public Service Co.
Joseph O'Brien
Negative
6
Omaha Public Power District
David Ried
Negative
6
OTP Wholesale Marketing
Bruce Glorvigen
6
Progress Energy
James Eckelkamp
6
PSEG Energy Resources & Trade LLC James D. Hebson
6
Public Utility District No. 1 of Chelan
Hugh A. Owen
County
6
RRI Energy
Trent Carlson
Negative
View
View
View
Affirmative
Abstain
Negative
Abstain
Affirmative
14
6
Santee Cooper
Suzanne Ritter
Abstain
6
Seattle City Light
Dennis Sismaet
Negative
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
6
South Carolina Electric & Gas Co.
Matt H Bullard
6
Tennessee Valley Authority
Marjorie S. Parsons
6
Western Area Power Administration John Stonebarger
UGP Marketing
6
Xcel Energy, Inc.
David F. Lemmons
View
Abstain
Negative
View
Affirmative
Abstain
8
Merle Ashton
8
Roger C Zaklukiewicz
8
James A Maenner
8
Kristina M. Loudermilk
Affirmative
Affirmative
Affirmative
Abstain
8
Ascendant Energy Services, LLC
Raymond Tran
8
JDRJC Associates
Jim D. Cyrulewski
Negative
8
Pacific Northwest Generating
Cooperative
Margaret Ryan
Negative
8
Power Energy Group LLC
Peggy Abbadini
8
SPS Consulting Group Inc.
Jim R Stanton
8
Utility Services, Inc.
Brian Evans-Mongeon
8
Volkmann Consulting, Inc.
Terry Volkmann
Negative
9
California Energy Commission
William Mitchell
Chamberlain
Negative
9
Commonwealth of Massachusetts
Department of Public Utilities
Donald E. Nelson
Abstain
9
National Association of Regulatory
Utility Commissioners
Diane J. Barney
Abstain
9
North Carolina Utilities Commission
Kimberly J. Jones
Abstain
15
9
Oregon Public Utility Commission
Jerome Murray
Abstain
9
Public Service Commission of South
Carolina
Philip Riley
Affirmative
9
Utah Public Service Commission
Ric Campbell
Affirmative
10
Florida Reliability Coordinating
Council
Linda Campbell
10
Midwest Reliability Organization
Dan R. Schoenecker
10
New York State Reliability Council
Alan Adamson
Affirmative
10
Northeast Power Coordinating
Council, Inc.
Guy V. Zito
Affirmative
10
ReliabilityFirst Corporation
Jacquie Smith
10
SERC Reliability Corporation
Carter B Edge
10
Western Electricity Coordinating
Council
Louise McCarren
Abstain
Negative
View
16
Checkbox® 4.4
Newsroom Site Map Contact NERC
Individual or group. (58 Responses)
Name (36 Responses)
Organization (36 Responses)
Group Name (22 Responses)
Lead Contact (22 Responses)
Contact Organization (22 Responses)
Question 1 (51 Responses)
Question 1 Comments (58 Responses)
Question 2 (46 Responses)
Question 2 Comments (58 Responses)
Question 3 (48 Responses)
Question 3 Comments (58 Responses)
Question 4 (48 Responses)
Question 4 Comments (58 Responses)
Question 5 (46 Responses)
Question 5 Comments (58 Responses)
Question 6 (44 Responses)
Question 6 Comments (58 Responses)
Question 7 (0 Responses)
Question 7 Comments (58 Responses)
Group
MRO’s NERC Standards Review Subcommittee (NSRS)
Joseph DePoorter
Midwest Reliability Organization
No
The NSRS feels additional changes are needed. The functional testing requirement should be
altered or removed as it increases the amount of hands-on involvement and the opportunity for
human error related outages to occur, thereby introducing a greater risk to decrease system
reliability. As noted on p. 8 in the supplementary reference document, “Experience has shown
that keeping human hands away from equipment known to be working correctly enhances
reliability.” By removing circuits from service on the proposed timelines for functional testing, the
chance for human error is greater than a mis-operation from faulty wiring. Alternatively, entities
may choose to schedule more planned outages to conduct their functional testing in order to
limit the risk of unplanned outages resulting from human error. Under this scenario, more
elements will be scheduled out of service on a regular basis, thereby reducing transmission
system availability and weakening the system making it more challenging to withstand each
subsequent contingency (N-1). Thus testing an in-tact system is more desirable than taking it
out of service for testing. While the SDT has included language in the draft standard to use fault
analysis to complete maintenance obligations, in practicality, this option does not offer any relief
to taking outages to perform functional tests. Nearly all BES circuit breakers are equipped with
dual trip coils. Identifying which trip coil operated for a fault only covers the one trip coil.
Functional tests would still be needed on the other. The likelihood of having multiple trips on a
given line in the course of several years is very low. Given it can take a year to schedule some
outages; planning maintenance with random faults is unpractical and will create unacceptable
risk to compliance violations. A better approach is to use the basis in schedule A, but extend this
to cover the entire protection schemes. The document should establish target goals for misoperation rates (dependability and security). This would allow the utilities to develop cost
effective programs to increase reliability. The utilities would have incentives to replace poorly
performing communications systems; they would be able to quantify the value of upgrading relay
systems.
No
The NSRS disagrees with the VRFs as specified in the standard. R1 VRF would more likely be
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classified as “medium” and R2 through R4 should be classified as a “High” VRF.
No
The NERC standard assigns a retention period for the two most recent performances of
maintenance activity which implies two intervals of documentation being maintained. The NSRS
does not agree that requiring all data for two full cycles is warranted. The volume and length of
data retention is unreasonable. The NSRS recommends that the entity retain the last test date
with the associated data, plus the prior cycle test date only without retaining the test data.
Yes
Yes
No
The FAQs are helpful, however, with the revised standard as written, The NSRS has issues with
the answers provided. Please refer to Question #7 for areas of concern.
The NSRS does not support the existing 2nd Draft of PRC-005-2 Standard because it is our
opinion that: • There is a high probability that system reliability will be reduced with this revised
standard. • The utility industry is in the business of keeping the lights on, but these
requirements will force the industry to take customers out of service in order to fulfill these
requirements. A possible solution is to increase the test intervals, set performance targets, test
set on a basis of past performance, etc. • The number of unplanned outages due to human error
will increase considerably. • The requirement of a complete functional trip test will reduce the
level of reliability and all levels of the BES to include distribution systems. • Availability of the
BES will be reduced due to an increased need to schedule planned outages for test purposes (to
avoid unplanned outages due to human error). • To implement this standard, an entity will need
to hire additional skilled resources that are not readily available. (May require adjustments to the
implementation timeline.) • The cost of implementing the revised standard will approximately
double our existing cost to perform this work. Requests that relevant reliability performance data
(based on actual data and/or lessons learned from past operating incidents, Criteria for
Approving Reliability Standards per FERC Order 672) be provided to justify the additional cost
and reliability risks associated with functional testing. Under a Performance-Based Program,
what happens if the population of components drops below 60 (as all will eventually)? Is there an
implementation period to default to TBM? Please clarify. In R1, the statement “or are designed to
provide protection for the BES” re-opens the argument about transformer protection or breaker
failure protection for transformer high-side breakers tripping BES breakers being included in the
transmission protection systems. Also, for Table 1b “Verify that each breaker trip coil, each
auxiliary relay, and each lockout relay is electrically operated within this time interval” should be
changed from a 6 year interval to a 12 year interval similar to the relay input and outputs.
Experience has shown that these both have very similar reliability. The standard as currently
drafted raises concern as it relates to the identification of all Protection System components,
particularly those with associated communications equipment. In the case of leased lines, a
utility would be expected to maintain equipment they do not own. Recommend revising the
standard to consider maintenance activities on a communications channel basis in which
intermediate device functioning can be verified by sending a signal from one relay to another.
Clarification should be given as to the reason for stating control circuitry separately, such as in
“Control and trip circuits”. As currently stated, this implies that close circuit DC paths are now
subject to a protection system maintenance program when reclosing and closing of breakers
have never before been considered part of a Protection System. Statements 3 (For
microprocessor relays, check the relay inputs and outputs that are essential to proper functioning
of the Protection System. )and 6(Verify correct operation of output actions that are used for
tripping. in Table 1b for Protective Relays essentially address the same issue. Please clarify if
these are addressing the same issue or not. If the purpose is to describe the functionality of the
protection system, that should be covered under another section in the table, such as DC
circuitry. How one identifies a voltage and current sensing input is not well defined. In most
cases, this should already be identified with the relay. Also, the scope of detail required is
ambiguous. Would individual cables, terminal blocks, etc. need to be identified as would be
implied by “associated circuitry”? Please clarify. The NSRS recommends that individual cables,
terminal blocks, etc are not included in this program. Recommend removing “proper functioning
of” from the maintenance activities for voltage and current sensing inputs in Table 1b. A utility is
not verifying the functionality of the signal(s), they are verifying the signals themselves. Any
functioning of the signals, which is related to ensuring proper relay interpretation, would be
covered under the protective relay section. In general, has thought been put into the possibility
of degrading reliability by implementing such a rigorous maintenance program? To implement
such a program, the number of scheduled outages would greatly increase resulting in scheduling
conflicts that will increase, as well as degrading system conditions by taking lines, transformers,
etc. out of service. Because of past design practices many of the requirements for maintenance
will only be able to be performed by lifting wires to isolated trip paths. Potential error is
introduced anytime a wire is lifted, especially numerous wires, by means of ensuring they are put
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back in the correct place. Redundancy is one thing that has been implemented in great detail
throughout the history of protection systems to ensure that they work as intended. Diligent
commissioning may need to be given its due credit.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
Clarification is needed for “to a location where action can be taken”. Some examples in the FAQ
will help in this clarification. What type of documentation is required to show compliance that
maintenance correctable issue has been reported? Clarify the removal of requirement (see
redline version, third row of Table 1a) for testing of unmonitored breaker trip coils. Is it the
intention of the SDT to remove a requirement that would drive the industry to install TC
monitors on breakers to improve reliability? UFLS/UVLS DC control and trip circuits (Rows 5 and
6 of Table 1a) – Due to the distributed nature of this program, random failures to trip are not
impactive to the overall operation of the UFLS protection. There should be no requirement to
check the DC portion of these protections any more often than the DC circuit checks associated
with that LV breaker. Since it is clear the requirement does not include the need to trip the
breakers why the need to check the trip paths? Deletion of this requirement leaves the
requirement to check only the relays and relay trip outputs from the protections every 6 years
(or as often as the protective relay component type). Should the maintenance activities for
“UVLS and UFLS relays that comprise a protection scheme distributed over the power system”
not be the same as “Protective Relays”? V and I sensing to relays have a 12 year Maximum
Maintenance Interval listed. It is good work practice to have this activity done the same time as
maintenance activities associated with relay maintenance. What is the basis for the various
Maximum Maintenance Intervals listed in Table 1a? From page 12 of the redline version, for
"Station dc Supply (used only for UFLS and UVLS)", is the requirement applicable to distribution
substations only? For “Control and trip circuits with unmonitored solid-state trip or auxiliary
contacts (UFLS/UVLS Systems only)” under Maintenance Activities - the word “complete: may be
removed as it requires to actually trip the breakers. The sentence that tripping of the circuit
breakers is not required contradicts with the word “complete”. More specifics are required to
spell out the adequate testing e.g. up to the lockout with the trip paths isolated etc. See Page 12
of the redline version. For “Station dc Supply” having 18 calendar months as the Maximum
Maintenance Interval, a battery has a 20 year life. IEEE standard PM is on a quarterly basis.
What is the basis of the 18 calendar month interval? See page 12 of the redline version. For
“Associated communications systems” with a Maximum Maintenance Interval of 6 Calendar years,
why is this required? The text "Verify proper functioning of communications equipment inputs
and outputs that are essential to proper functioning of the Protection System. Verify the signals
to/from the associated protective relay(s)" seems sufficient to ensure reliability. See page 15 of
the redline version. For “Relay sensing for Centralized UFLS or UVLS systems UVLS and UFLS
relays that comprise a protection scheme distributed over the power system” under maintenance
activities, clarify “overlapping segments”. What is the specified interval? Is actual breaker
tripping required? See page 15 of the redline version. On the row for Associated communications
systems in Table 1c, in the Level 3 Monitoring Attributes for Component column, suggest a
change in wording to: Evaluating the performance and quality of the channel as well as the
performance of any interface to connected protective relays and alarming if the
channel/protective relay connections do not meet performance criteria. In Table 1c it is required
to report the detected maintenance correctable issues within 1 hour or less to a location where
action can be taken to initiate resolution of that issue. Even for a fully monitored protection
system component it can be difficult to report the action in 1 hour. A 24 hour period for both
Level 2 and Level 3 reporting of maintenance correctable issues is recommended.
Yes
No
Clarification is needed for “on-site audit” – does it include audits by any of the following NPCC/NERC/FERC. Several small entities do not have on-site audits and participate in off-site
audits. Hence, suggest deleting “on-site” from the requirement. Further clarification is required
to the Data Retention section to coordinate with the statement in FAQ (Section IV.d p. 22
redline). Suggest the following revised Data Retention requirement consistent with the statement
and example given in FAQ: “The Transmission Owner, Generator Owner, and Distribution
Provider shall each retain at least two maintenance test records or statistical data to demonstrate
compliance with test interval required for each distinct maintenance activity for the Protection
System components. The Compliance Enforcement Authority shall keep the last periodic audit
report and all requested and submitted subsequent compliance records.”
No
R4 under Severe VSL mentions – Entity has failed to initiate resolution of maintenance-
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correctable issues. What proof will satisfy the requirement that the entity has initiated the
resolution? R1 under Severe VSL – Move the first criteria “The entity’s PSMP failed to address
one or more of the type of components included in the definition of ‘Protection System’” under
High VSL since this criteria cannot have the same VSL level as “Entity has not established a
PSMP”.
No
There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an entity can
count components. However; an example in the reference document will provide clarity. Page 7
of the redline version of Supplemental Reference – bullet 1 under Maintenance Services,
paragraph 2 states “ If specific protection scheme components have demonstrated correct
performance within specifications, the maintenance test time clock is reset for those
components.” Resetting the time clock will make tracking difficult (unless entities have a
sophisticated automated tool for tracking). Another option where an entity can take credit for a
correct performance within specifications at the time of the maintenance cycle should be
included.
Yes
UFLS systems by design can suffer random failures to trip. A requirement should exist that
stipulates to perform maintenance on the UFLS relay as their failure to operate may affect
numerous distribution level feeders. However maintenance on associated DC schemes connected
to the devices should only be done on the same frequency as maintenance on the relevant
interrupting devices. Consideration should be given to exempting schemes that have a
maintenance program in place on those distribution level devices from PRC-005 Standardspecified maintenance intervals. Such Standard-specified intervals could apply to interrupting
devices that have no maintenance program in place. This standard is overly prescriptive. Owners
of protection system equipment establish maintenance procedures and timelines based on
manufacturers’ recommendations and experiences to ensure reliability. Maintenance intervals
change with improved practices and equipment designs, and whenever that occurs PRC-005 will
have to go through the revision process, which would be frequent and unnecessary if the
standard were more general.
Group
Southern Company Transmission
JT Wood
Southern Company
No
1)Comment on Control Circuitry – Below in Figure 1 is a previous version of Table 1. It clearly
shows 3 levels of monitoring for Control Circuitry. For Unmonitored schemes such as EM, SS,
unmonitored MP relays, you must do a complete functional trip test every 6 years. For partially
monitored schemes such as MP relays with continuous trip coil/circuit monitoring, you must do a
complete functional trip test every 12 years. For fully monitored schemes where all trip paths are
monitored, you do not have to trip test the scheme but you still have to operate the breaker trip
coils, EM aux/lockout relays every 6 years. This is very clear and reasonable. The latest version
of Table 1 is not very clear or reasonable. The previous Partially Monitored control circuit
monitoring requirements were deleted and the Fully Monitored control circuit monitoring
requirements were moved to Partially Monitored requirements. We are not sure why this major
change in philosophy was made?? This makes all of our MP relay control schemes that
continuously monitor trip coils/circuits fall into the unmonitored category and therefore requires a
6 year full functional trip test. For a scheme that monitors 99+% of the control scheme (and
probably 100% of the control scheme that actually has problems) to be considered Unmonitored
does not seem logical or reasonable to us. This puts these “highly monitored” schemes in the
same category and requires the same maintenance requirements / intervals as EM relays with no
alarms whatsoever. This also seems to contradict the intent of the following statement from the
Supplementary Reference doc on page 9: Level 2 Monitoring (Partially Monitored) Table 1b This
table applies to microprocessor relays and other associated Protection System components
whose self-monitoring alarms are transmitted to a location (at least daily) where action can be
taken for alarmed failures. The attributes of the monitoring system must meet the requirements
specified in the header of the Table 1b. Given these advanced monitoring capabilities, it is known
that there are specific and routine testing functions occurring within the device. Because of this
ongoing monitoring hands-on action is required less often because routine testing is automated.
However, there is now an additional task that must be accomplished during the hands-on
process – the monitoring and alarming functions must be shown to work. Recommendation Please consider going back to the previous table as shown below in Figure 1. It seems much
clearer and reasonable. Feel free to convert the old wording to the latest wording. Figure 1 Previous Table – Control Circuitry See Figure 1 in email documentation sent to Al McMeekin.
Current Table – Control Circuitry (see pdf file) See pdf file PRC-005-2_clean_20
10June88131418.pdf in email documentation sent to Al McMeekin. 2) Comments: The comments
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below are grouped by component type. The following (5) comments pertain to the maintenance
intervals for protective relays: 1.Is the “verify acceptable measurement of power system input
values” activity listed in the protective relay 6 year interval in Table 1a the same activity as the
12-year activity for Voltage and Current Sensing Inputs in the same table? 2.Please clarify the
meaning of “check the relay inputs and outputs” that are specified to be checked for
microprocessor relays at the following table locations: the protective relay 6 year interval in Table
1a, the protective relay 12-year interval in Table 1b. Is this referring to a check of the relay
internal input recognition and output control ending at the relay case terminals, or is this
referring to a check extending to the source (and target) of all inputs and outputs to the relay?
The latter interpretation results in a repeat of the maintenance required for dc control circuitry.
3.Are the second, third, and fourth maintenance activities in the Table 1a Protective Relay, 6year row those activities that apply to microprocessor relays? If so, we suggest rewording these
items as follows: For microprocessor relays, verify that the settings are as specified, check the
relay digital inputs and outputs that are essential to proper functioning of the Protection System,
and verify acceptable measurement of power system analog input values.” 4.Please clarify the
meaning of “Verify proper functioning of the relay trip contacts” found in protective relays with
trip contacts 12 year interval in Table 1c. Is this verification a check of the relay internal contact
to the relay case terminals or is this meant to be a trip check functional test? This category of
component does not appear in table 1a or 1b. Should it? Is this activity the same as the
protective relay Table 1b maintenance activity “output actions used for tripping”? If so, please
make the wording match exactly to clarify. 5.Table 1c introduces the use of “Continuous”
Maximum Maintenance Intervals. This is inconsistent with the Table 1a and Table 1b usage of the
interval. In Tables 1a and 1b this interval is used to describe the maximum time frame within
which the activities shown in “Maintenance Activities” must be completed. The table column
“Maintenance Activities” has been used to identify those activities which must be performed in
addition to those accomplished by the monitoring attributes. To maintain consistency in use of
the interval and activity columns of Tables 1a, 1b, and 1c, each entry that uses the “Continuous”
interval should be changed to N/A and the Maintenance Activities should be changed to either
“No additional activities required” or “None, due to continuous automatic verification of the status
of the relays and alarming on change of settings” [example given for Table 1c, Protective Relays]
The following (8) comments apply to Maintenance Tables 1a, 1b, and 1c for Station DC supplies.
1)In Table 1a, Station dc supply, 18 calendar month, the verify item “Float voltage of battery
charger” is not listed in Table 1b. Is this requirement independent of the level of monitoring and
always required? If so, should it be added in to Table 1b and 1c, Station dc supply, 18 calendar
months above the “Inspect:” section? 2)The 6 year interval maintenance activity for NiCad
batteries in Table 1a and Table 1b should read “station battery” rather than “substation battery”.
3)It is recommended to simplify the Station dc supply sections in each of the three maintenance
tables by relocating the common items that do not change dependent upon the level of
monitoring. Specifically, the following rows of each of the three tables have identical
maintenance requirements that are independent of the level of monitoring. The tables would be
significantly simplified if these “monitor level independent” requirements are moved outside of
the table: a.Station dc supply; 18 calendar months; Inspect: “ b.Station dc supply (that has a s
a component Valve Regulated Lead Acid batteries) c.Station dc supply (that has as a component
Vented Lead Acid batteries) d.Station dc supply (that has as a component Nickel Cadmium
batteries) e.Station dc supply (battery is not used) 4)Table 1a has 18 calendar month
requirements for “Station dc supply (battery is not used)”. This category is missing from Table 1b
– was this intentional? 5)Table 1a has 6 calendar year and 18 calendar month requirements for
“Station dc supply (battery is not used)”. This category is missing from Table 1c – was this
intentional? 6)Please clarify the meaning of “Battery terminal connection resistance”. Does this
apply only to multi-terminal batteries? Is this referring to the cables external to the battery (to
the charger and load panel)? 7)Table 1c contains a Type of Protection System Component not
found in any of the other tables: “Station dc supply (any battery technology). Is this the same as
“Station dc supply” found in Tables 1a and 1b? 8)The Level 3 Monitoring Attributes for “Station
dc supply (any battery technology)” are identical to the Level 2 Monitoring Attributes for “Station
dc supply”. This appears to be duplicative in description with two different “maximum
maintenance intervals” and “maintenance activities” listed. The following (3) comments pertain
to the Voltage and Current Sensing Input component type: 1)Why is “signals” bolded in the
Table 1a row for this component type? 2)Are the Table 1a, 12 year maintenance activities for
this component type a duplication of the Table 1a, Protective relay, 6 year maintenance activity
for microprocessor relays (verify acceptable measurement of power system input values)? 3)Why
is this component type highlighted in bold in Table 1c? The following (8) comments pertain to the
Control and Trip Circuit component type: 1)Why are microprocessor relay initiated tripping
schemes excluded from the 6 year complete functional testing? The auxiliary relay operations
resulting from these initiating devices are just as likely to stick (mis-operate) as those initiated
from electromechanical devices. 2)We propose simplifying Table 1a for this component type by
grouping the two 6 year and the two 12 year interval maintenance lines into two rather than four
table rows. The 6 year interval maintenance activities for the UFLS/UVLS systems could be
addressed in the table row above using a parenthetical adder to the existing text = (for
UFLS/UVLS systems, the verification does not require actual tripping of circuit breakers or
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interrupting devices). All of the other text in the UFLS/UVLS table row matches that found two
rows above. The same parenthetical adder in the first 12 year interval row for this component
type would eliminate the need for the (UFLS/UVLS Systems Only) row for 12 year intervals. 3)If
the two rows are combined as suggested previously – this comment is irrelevant: The Table 1a 6
year interval activity for UFLS/UVLS Systems Only is missing the word “contacts” after auxiliary.
4)There appears to be no difference in the 6 year interval maintenance activities for this
component type in Table 1a and Table 1b. Table 1b monitoring attributes include “Monitoring and
alarming of continuity of trip circuits”, but the interval between electrically operating each
breaker trip coil, auxiliary relay, and lockout relay remains at 6 years. What maintenance activity
advantage do the Level 1b monitoring attributes provide? 5)The difference between the two DC
Control Circuits in Table 1b (on page 14) is unclear. What is the difference between the “Control
Circuitry (Trip Circuits)” and the “Control and trip circuitry”? We propose combing the multiple
table rows for this component type into a single line item for this component type, as it takes a
combination of the protective relay action, any auxiliary relay, and the circuit breaker to
comprise a complete tripping system. 6)We have three questions on the monitoring attributes
given for this component type on page 14: a) Does the attribute beginning “Monitoring of
Protection …” indicate a requirement to monitor every input, every output, and every connection
of every Protection System Component involved in each tripping scheme? b) Does the attribute
beginning “Connection paths…” related to monitoring of communication paths? c) Does the
attribute beginning “Monitoring of the continuity…” require the presence of coil monitoring of any
auxiliary relay whose contact is encountered when tracing a tripping path from a protective relay
to a breaker? 7)Are the Table 1c attributes for this component type different from the monitoring
described in Table 1b beginning “Connection paths…”? 8)Are there no requirements to operate
any relays functionally for “Protection System control and trip circuitry” in Table 1c? The devices
need to be exercised some or they will not be reliable. The following (1) comment pertains to the
Associated communications system component type: 1)The Table 1b monitoring attribute for this
component type (communications channel monitor and alarm) clearly should (and does)
eliminate the Table 1a, 3 month interval activity (verifying the communication system is
functional). The common maintenance activities found in Table 1a (6 year) and Table 1b (12
year) should be same interval – either 6 or 12.
Yes
Yes
Yes
Yes
General FAQ 1)Attached is an elementary drawing showing a typical transmission line relay
protection scheme utilizing SEL-351S and SEL-321 microprocessor relays. Does this qualify as
partially monitored control circuitry? See pdf file Control Elementary_1-07-13 & Control
Elementary_2-07-13in email documentation sent to Al McMeekin. •If not, and this is an
unmonitored circuit, what would be the appropriate maintenance interval (6 years or 12 years)
for the Control and Trip Circuits from page 9 of PRC-005-2? The description of the two choices is
ambiguous See pdf file PRC-005-2_clean_2 010June8.pdf in email documentation sent to Al
McMeekin. •If not, what would it take to make this circuit partially monitored (including inputs)?
2) Table 1a, page 9, row 2 (Voltage and Current Sensing Inputs) Question – Does this mean
secondary quantities from CT’s and VT’s only? If so, please consider changing the wording from
“Voltage and Current Sensing Inputs” to “CT and VT secondary quantities”. 3) Table 1a, page 9,
row 3 (Control and trip circuits with EM contacts) Question - Does "electromechanical trip or
auxiliary contacts" mean EM protective relay outputs and EM tripping/lockout tripping contacts
only? Or does it also include any part of the trip circuitry such as cutout switch contacts and
breaker trip coils plus associated aux. breaker contacts. For example, the schematic with a
microprocessor relay described in the first bulleted item could be considered an unmonitored EM
control circuitry (6 year interval). Is this because of the mechanical breaker aux contacts,
breaker maintenance switch, and FT-1 test switch? If so, how could any control circuitry fall in
the solid state trip contacts category (12 year interval)? 4) Table 1a, page 9, rows 3, 4, 5, 6 –
Please consider rewording these to make it clear where control schemes with MP relays that do
have trip coil / circuit monitors but don’t meet the Partially Monitored requirements fit. (Does
this type scheme fit in the 6 year trip test category or the 12 year category?) 5) Table 1a, page
12, row 1 – The maintenance requirements are not the latest wording used for all other
Protective Relays. Please consider changing for consistency. 6) Table 1b, page 13, row 1
(Protective Relays) - Line three of the maintenance activities requires us to check inputs and
outputs. The last maintenance item is to verify correct operation of output actions that are used
for tripping. Question - How is this different than the line three maintenance requirements to
check inputs and “outputs”? 7) Table 1b, page 14, rows 1 and 2 – Consider combining these into
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one row. The maintenance intervals and maintenance activities are these same. Please specify
what is required for UFLS and UVLS control schemes). 8) Table 1b, page 14, rows 1 – The first
sentence is very general for a monitoring attribute. (“Monitoring of Protection System component
inputs, outputs, and connections with reporting of monitoring alarms to a location where action
can be taken.”) Consider deleting this row or make it more specific. 9) Table 1b, page 14, row 2
[Control Circuitry (Trip Circuits) (except for UFLS/UVLS)] Question: Should there be a 12 year
functional trip test requirement for this partially monitored control circuitry? Should this be added
to Table 1b? 10) Table 1b, page 14, row 1 [Control Circuitry (Trip Circuits) (except for
UFLS/UVLS)] - It states Monitoring of Protection System component inputs, outputs, and
connections … Question – what does “inputs” mean? There are Protection System components
such as protective relays, control circuitry, station dc supply, associated communications
systems, etc. Does this mean we must monitor inputs to any or all of these Protection System
components? How would this be accomplished? 11) Table 1c, page 18, row 4 – Should there still
be a requirement to trip breakers by all trip coils every 6 years? Supplementary Reference
Document 12) Question on Figure 1, page 27 - Box 1 denoting Protection Relays includes Aux
devices, Test or Blocking Switches. The Aux devices, Test or Blocking Switches should be part of
Box 3 (Control Circuitry). Please correct or note accordingly. FAQ Document 13) On Page 30,
please add an Example with Partially Monitored (Level 2) Control Circuit. 14) On the Control
Circuit Decision Tree on page 36, the flow chart does not match the current Table 1
requirements. They match the previous version which is described in the first question of this
document. We still propose leaving the flow chart on page 36 as is and change Table 1 to match
the original requirements. 15) Please consider adding a diagram /elementary drawing of a
Partially Monitored Control Circuit showing the trip output contacts, inputs, etc that must be
monitored to meet the Monitoring Attributes / Requirements. A diagram showing an Unmonitored
control scheme and what it would take to make it Partially Monitored would be helpful too.
Additional General FAQ 16)PRC-005-2, R1 requires the Functional Entity to establish a Protection
System Maintenance Program (PSMP). It is not clear if this standard establishes a specified
frequency for reviewing and updating the PSMP itself or the PSMP criteria outlined in subparts 1.1
through 1.4. By comparison, EOP-005-1 System Restoration Plans, requires the Functional Entity
to (a) have a restoration plan and (b) to review and update the restoration plan annually (see
EOP-005-1, R1 and R2). This approach to a comprehensive and periodic review considers the
PSMP as a whole and is independent of the specific maintenance methods (time-based,
condition-based, or performance-based) and maintenance intervals for those respective
methods. It is noted however that PRC-005 Attachment A mentions annual updates to the list of
Protection System component. According to the Attachment’s subtitle, Criteria for a
Performance-Based Protection System Maintenance Program, this annual update seems limited
to performance-based maintenance and not inclusive of other maintenance methods. The
recommendation is to evaluate the need for a periodic review of the PSMP as a whole. 17)R1,
Criteria 1.1, and companion VSL. This Criterion requires the identification of all Protection System
components. The VSL for R1 uses a percent-based approach to parse out different quantities of
components across the four VSL categories. This implies that a Functional Entity must have the
ability to put a numerical quantity on its various components and should be able to demonstrate
within certain tolerances that its components are included (or counted). If the number of
components within scope amount to hundreds or thousands of individual items, the PSMT SDT
should consider the Functional Entities’ ability to track and quantify the items for a compliance
demonstration. If an entity is not able to reasonably quantify which components are in scope,
demonstrating compliance on a percent-basis may prove difficult or impossible. Further review
may indicate the need to reformat the VSL. Similar concerns are noted in other VSLs (R2, R3,
and R4) and in Attachment A where percentage-of-components are mentioned. 18)R4 essentially
requires the Functional Entity to implement its PSMP. R4 takes care to highlight the specific task
of “identification of the resolution of all maintenance correctable issues.” It is noted that other
“identification tasks” are included as criterion for the PSMP in R1. If these tasks are all
appropriately categorized as identification-type tasks, it may be more efficient to restructure the
standard by incorporating this task into R1 with the other criteria. R4 could remain as a basic
implementation requirement with more detail provided in subparts 4.1, 4.2, and 4.3. 19)Footnote
No. 2 describes maintenance correctable issues and could be interpreted as a potential new term
for inclusion in NERC’s Glossary of Terms. The PSMT SDT should conduct further review of this
terminology as a potential new Glossary term. 20)At R4, subpart 4.3, insert “design” such that it
reads as follows: “Ensure that the components are within acceptable design parameters at the…”
Also, this subpart duplicates Footnote No. 3 which describes “maintenance correctable issues”
and was established in the main requirement R4 at Footnote No. 2.
Group
SERC Protection and Control Sub-committee (PCS)
Joe Spencer - SERC staff and Phil Winston - PCS co-chair
SERC Relaibility Corp.
No
Clarifications need to be made on testing requirements on trip contacts relative to
microprocessor vs. EM relays. There appears to be an inconsistency in the use of “check” vs.
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“verify” in the tables. Also, Table 1B, in the second to last row, should be referring to UFLS
rather than SPS. Also, note that M2 incorrectly excludes distribution provider. In battery
maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
The SERC PCS expresses no opinion on this question.
Yes
The SERC PCS expresses no comments on this question.
No
In R1, a “Failure to specify whether a component is being addressed by time-based, conditionbased, or performance-based maintenance” by itself is a documentation issue and not an
equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of
the required components can only be time based.
The SERC PCS expresses no opinion on this question.
The SERC PCS expresses no opinion on this question.
Descriptors in the "type of the protection system component" column need to be consistent
between 1A, 1B and 1C. Also, in the tables, please clarify “complete functional trip test” for UVLS
and UVLS trip tests since the breaker is not being tripped. Facilities Section 4.2.1 “or designed to
provide protection for the BES” needs to be clarified so that it incorporates the latest Project
2009-17 interpretation. The industry has deliberated and reached a conclusion that provides a
meaningful and appropriate border for the transmission Protection System; this needs to be
acknowledged in PRC-005-2 and carried forward. We commend the SDT for developing such a
clear and well documented second draft. The SDT considered and adopted many industry
comments on the first draft. It generally provides a well reasoned and balanced view of
Protection System Maintenance, and good justification for its maximum intervals. The SERC
Protection & Control Subcommittee generally agrees that this second draft will be beneficial to
BES reliability.
Individual
John Canavan
NorthWestern Corporation
No
Table 1a - Rows 3 & 4 (control and trip circuits) - add language in the Maintenance Activities "except that verification does not require actual tripping of circuit breakers or interrupting
devices"
Individual
Dan Roethemeyer
Dynegy Inc.
No
We agree with all proposed intervals in Tables 1a, 1b, and 1c except the 3 calender month
interval for Associated Communication Systems in Table 1a. We suggest using a 1 year interval
because all other elements of the Protection System are being verified a minimum of every 3
years. Therefore, we believe annual verification of Associated Communication Systems is
sufficient.
Yes
Yes
Yes
Yes
Yes
For protection system component verification, flexibility is needed subsequent to a system event
to allow the analysis of a protection system operation to be utilized as a protection system
component verification. We believe this flexibility is needed and should be incorporated in
Requirement R4.
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Individual
Robert Ganley
Long Island Power Authority
No
In Table 1c it is required to report the detected maintenance correctable issues within 1 hour or
less to a location where action can be taken to initiate resolution of that issue. Even for a fully
monitored protection system component it can be difficult to report the action in 1 hour. LIPA
recommends a 24 hour period for both Level 2 and Level 3 reporting of maintenance correctable
issues. The time identified is report time and not response time to correct issue. LIPA seeks
clarification on “to a location where action can be taken”. Some examples in the FAQ will help in
this clarification. What type of documentation is required to show compliance that maintenance
correctable issues have been reported? What is the basis of the various Maximum Maintenance
Intervals tabulated in Table 1a-Time based maintenance?
Yes
No
Two most recent performances of each distinct maintenance activity for the Protection System
components will require data retention for an extended period of time. For example, in certain
cases, battery maintenance is on a 12 year cycle which suggests that records need to be
retained for 24 years. LIPA suggests retaining data for the most recent maintenance activity.
LIPA seeks clarification on “on-site audit” – does it include audits by any of the following NPCC/NERC/FERC. Also, several small entities do not have on-site audits and participate in offsite audits. Hence, LIPA suggests deleting “on-site” from the requirement. In addition further
clarification is required to the Data Retention section to coordinate with the statement in FAQ
(Section IV.d p. 22 redline).
No
R4 under Severe VSL mentions – Entity has failed to initiate resolution of maintenancecorrectable issues. What proofs will satisfy the requirement that the entity has initiated the
resolution. R1 under Severe VSL – LIPA suggests moving the first criteria “The entity’s PSMP
failed to address one or more of the type of components included in the definition of “Protection
System” under High VSL since this criteria cannot have the same VSL level as “Entity has not
established a PSMP”.
No
There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an entity can
count components however; an example in the reference document will provide clarity. Page 7 of
the redline version of Supplemental Reference – bullet 1 under Maintenance Services, paragraph
2, it says “ If specific protection scheme components have demonstrated correct performance
within specifications, the maintenance test time clock is reset for those components. LIPA
believes that resetting the time clock will make tracking difficult (unless entities have a
sophisticated automated tool for tracking). Another option where an entity can take credit for a
correct performance within specifications at the time of the maintenance cycle should be
included.
Yes
Table 1a under Maintenance Activities for Control and trip circuits with unmonitored solid-state
trip or auxiliary contacts (UFLS/UVLS Systems Only) states: Perform a complete functional trip
test that includes all sections of the Protection System control and trip circuit, including all solidstate trip and auxiliary contacts (e.g. paths with no moving parts), devices, and connections
essential to proper functioning of the Protection System., except that verification does not require
actual tripping of circuit breakers or interrupting devices. The word complete may be removed as
it requires actually tripping the breakers. The sentence that tripping of the circuit breakers is not
required contradicts with the word complete. More specifics are required to spell out the
adequate testing e.g. up to the lockout with the trip paths isolated etc. Table 1a under
Maintenance Activities for Station dc Supply (used only for UVLS or UFLS) states: Verify proper
voltage of the dc supply. Is this requirement applicable to the distribution substations only?
Table 1a under Maintenance Activities for Station dc supply (battery is not used) – states Verify
that the dc supply can perform as designed when the ac power from the grid is not present. Please clarify this requirement. Table 1a for Associated communications systems - specify the
group for the applicability of this requirement. BPS,BES,UFLS etc. Table 1a under Maintenance
Activities for Associated communications systems states – Verify that the performance of the
channel meets performance criteria, such as via measurement of signal level, reflected power, or
data error rate. Why is this required? The requirement "Verify proper functioning of
communications equipment inputs and outputs that are essential to proper functioning of the
Protection System. Verify the signals to/from the associated protective relays seems sufficient to
ensure reliability. Table 1a under Maintenance Activities for Relay sensing for Centralized UFLS
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OR UVLS systems UVLS and UFLS relays that comprise a protection scheme distributed over the
power system states: Perform all of the Maintenance activities listed above as established for
components of the UFLS or UVLS systems at the intervals established for those individual
components. The output action may be breaker tripping, or other control action that must be
verified, but may be verified in overlapping segments. A grouped output control action need be
verified only once within the specified time interval, but all of the UFLS or UVLS components
whose operation leads to that control action must each be verified. Clarify what is meant by
overlapping segments? What is the specified interval? Is actual breaker tripping required?
Group
Pacific Northwest Small Public Power Utility Comment Group
Steve Alexanderson
Central Lincoln
No
We agree with most of the changes from the last draft. However, the phrase “Verify Battery cellto-cell connection resistance” has entered the table where it did not exist before. On some types
of stationary battery units, this internal connection is inaccessible. On other types the
connections are accessible, but there is no way to repair them based on a bad reading. And bad
cell-to-cell connections within units will be detected by the other required tests. This requirement
will cause entities to scrap perfectly good batteries just so this test can be performed, with no
corresponding increase in bulk electric system reliability while taking an unnecessary risk to
personnel and the environment. And because buying battery units composed of multiple cells
allows space saving designs, entities may be forced to buy smaller capacity batteries to fit
existing spaces. This may end up having a negative effect on reliability. Suggest substituting
“unit-to-unit” wherever “cell-to-cell” is used in the table now.
Yes
Yes
No
is possible that a component that failed to be individually identified per R1.1 was included by
entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B that
identified a component without maintaining it. We suggest the R1 VSL be change to Low, since
we believe lack of maintenance to be more severe than documentation issues.
Yes
Yes
The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities
are to be used, but then goes on to give a list of Maintenance Activities that don’t match those in
level 1. Which activities shall we use? Same situation for Station DC Supply (battery is not used)
where the 18 month interval is missing. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid noncompliance for an interval that might extend past three calendar months due to storms and
outages must set a target interval of two months thereby increasing the number of inspections
each year by half again. This is unnecessarily frequent. We suggest changing the maximum
interval for battery inspections to 4 calendar months. For consistency, we also suggest that all
intervals expressed as 3 calendar months be changed to 4 calendar months. We are concerned
over R1.1, where all components must be identified, without a definition for the word component
or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. We believe this will allow REs to
claim non-compliance for every three inch long terminal jumper wire not identified in a trip
circuit path. We suggest that the FAQ definitions be included within the standard.
Group
PNGC Power
Margaret Ryan
PNGC Power
No
We agree with most of the changes from the last draft. However, the phrase “Verify Battery cellto-cell connection resistance” has entered the table where it did not exist before. On some types
of stationary battery units, this internal connection is inaccessible. On other types the
connections are accessible, but there is no way to repair them based on a bad reading. And bad
cell-to-cell connections within units will be detected by the other required tests. This requirement
will cause entities to scrap perfectly good batteries just so this test can be performed, with no
corresponding increase in bulk electric system reliability while taking an unnecessary risk to
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personnel and the environment. And because buying battery units composed of multiple cells
allows space saving designs, entities may be forced to buy smaller capacity batteries to fit
existing spaces. This may end up having a negative effect on reliability. Suggest substituting
“unit-to-unit” wherever “cell-to-cell” is used in the table now.
Yes
Yes
No
It is possible that a component that failed to be individually identified per R1.1 was included by
entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B that
identified a component without maintaining it. We suggest the R1 VSL be change to Low, since
we believe lack of maintenance to be more severe than documentation issues.
Yes
Yes
The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities
are to be used, but then goes on to give a list of Maintenance Activities that don’t match those in
level 1. Which activities shall we use? Same situation for Station DC Supply (battery is not used)
where the 18 month interval is missing.
Individual
Terry Harbour
MidAmerican Energy Company
No
In the tables trip circuit has been replaced by “control and trip circuit”. From the context of the
standard and the reference and frequently asked question documents it is clear that the
requirement is to test the trip circuit only. Adding the word “control’ introduces ambiguity and
the potential to imply the closing circuit of the interrupting device also requires testing under the
standard. The word “control” should be removed. On this same subject the nomenclature in
Table 1b for type of protection system component is not consistent with Table 1a. In Table 1b in
the Level 2 Monitoring Attributes for Component column for Relay sensing for centralized UFLS or
UVLS systems there is a reference to SPS. This reference should likely be to UFLS/UVLS. In Table
1a functional testing of associated communications systems is included with a maximum
maintenance interval of 3 calendar months. Testing of this equipment at that frequency is not
believed to be necessary. It is suggested that the interval be changed to 12 calendar months.
For control and trip circuit maintenance the requirement includes “a complete functional trip
test”. In order to accomplish this type of testing given current design of lock-out relay and
interrupting device trip circuitry multiple breakers and line terminal outages would be required
simultaneously. In addition complete functional testing has the potential to result in unintentional
tripping of equipment that could cause equipment damage and customer outages. Segmentation
of trip circuits by lifting wires has the potential for incorrect restoration following testing. This
type of testing has the potential to degrade system reliability as multiple entities schedule this
work. An alternate to complete functional testing that does not potentially degrade system
reliability should be substituted.
Yes
No
Verification of compliance with the maximum time intervals for testing only needs to include
retention of the documentation of the two most recent maintenance activities. The phrase “or to
the previous on-site audit (whichever is longer)” should be deleted.
No
The lower VSL specification for R4 should allow for a small level of incomplete testing. Suggest
changing “5% or less” to “from 1% to 5%”.
Yes
Yes
From the compliance registry criteria for generator owner/operator and the language in 4.2.5.3 it
is implied that the intent is that protection systems for individual generators less than 20 MVA
would not be covered by PRC-005. To make this clear in the PRC-005-2 standard, the following
footnote to section 4.2.5.3 is recommended: Protection systems for individual generating units
rated at less than 20 MVA in aggregated generation facilities are not included within the scope of
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this standard. The Request for Interpretation of a Reliability Standard submitted March 25, 2009
indicates that a protection system is only subject to the NERC standards if the protection system
interrupts the BES and is in place to protect the BES. The following changes are recommended to
clarify this in the standard: A.3. Purpose: To ensure all transmission and generation Protection
Systems protecting and affecting the reliability of the Bulk Electric System (BES) are maintained.
A.4.2.1. Protection Systems applied on, or and designed to provide protection for the BES. B.R1.
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a PSMP for
its Protection Systems that use measurements of voltage, current, frequency and/or phase angle
to determine anomalies and to trip a portion of the BES and that are applied on, or and are
designed to provide…….. FERC Order 693 includes the directive that “testing of a protection
system must be carried out within a maximum allowable interval that is appropriate to the type
of the protection system and its impact on the reliability of the Bulk-Power System”. If
unanticipated conditions (e.g. force majeure) of the bulk-power system do not allow outages to
complete protection system maintenance as required by the standard without compromising the
reliability of the system delay of the particular maintenance activity should be allowed. This
provision should be included in the standard in R4.
Individual
Jonathan Appelbaum
The United Illuminating Company
Yes
In general yes. There are concerns with verifying cell-to-cell resistance in Batteries. On some
battery sets this is not possible to do.
No
: The VRF for R1 should be Low. It is administrative to create an inventory list. If R1 failed to be
executed but the other requirements wee executed fully then the BES would be properly
secured. Compare this against the scenario of performing R1 but failing to perform the other
tasks; in which case the BES is at risk. UI recognizes that the SDT considers the inventory as the
foundation of the PSMP but it is not the element of the PSMP that provides for the level of
reliability sought. R1 should be VERF Low and R2 thru R4 VRF is Medium. UI agrees with the
Time Horizon.
Yes
Yes
No
Include a detailed example of an Inventory list. Allow for different means of maintaining the lists
electornically, that is, as spreadsheets, or databases.
No
What actions are taken if the owner can not perform a specific activity elaborated on the tables
due to the design of the equipment? Is the owner in non-compliance? Must the owner only
accept equipment solutions that allow the maintenance activities elaborated in the standard to
be performed?
Individual
Lauri Dayton
Grant County PUD
PRC005-02 Comment We offer some comment for your consideration for incorporation into the
Standard PRC-005-02 (draft) as presented in the May 27th 2010 PRC 005-02 “Standard
Development Roadmap.” RE: Comment on the 2nd Draft of the Standard for Protection System
Maintenance and Testing” 1) The term “The Protection System Maintenance Program” (Page 2)
appears to be centered on the concept of maintaining specific components as stand alone
objects, and therefore infers that the resultant documentation be organized in a similar fashion.
Neither is optimal from a practical or a functional perspective. Many rational work practices
combine components (example, meggering from the relay input test switch through the cables
and the CTs) in the interest of minimizing circuit intrusion and human error. For this reason, such
maintenance practices are superior from a reliability standpoint. The t emphasis on “components”
in the current draft is, at best, tangential to NERC’s stated goal and purpose of PRC-005 to
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improve reliability. How would we fix this? We would insert the phrase “or Element”—as defined
in NERC’s Glossary of Terms to include “one or more components / devices with terminals that
measures voltage, current, frequency and/or phase angle” to determine anomalies and to trip a
portion of the BES” immediately after any occurrence of the word “component” in each of the
Requirements or in a Definition paragraph, intending it to be applied globally to R-1 through R4.
This would foster the validity of maintenance activities being applied to aggregations of
components — “Elements”—such as would occur during Verification of DC control circuitry or
through the employment of fault data analysis. 2) Protection System Maintenance Program. The
categorization of maintenance into 7 maintenance activities is welcomed as advancing practices
which foster BES reliability. Likewise we find the clarifications denoted by superscripts 1 and 2
helpful. However….under C: MEASURES: M1, the last sentence of the paragraph provides: “For
each protection system component, the documentation shall include the type of maintenance
program applied (time based, etc), maintenance activities (1 or more of the 7 identified) and
maintenance intervals…..” This measure goes beyond the requirements of the standard and
should be revised consistent with the deletion of the previous R.1.1 as shown in track changes
under the version 2 draft which had included the identification of the maintenance activity
associated with each component. COMMENT: It should be apparent in reviewing the evidence
that one or more of the 7 listed activity categories are represented. The proscription to explicitly
call out these categories is thus redundant---the requirement being that at least one has to be
identifiable in the program—and will cause unnecessary complications to the Entity and
interpretation issues in the Compliance monitoring effort. We recommend that the words
“maintenance activities” be removed from the last sentence in the paragraph pertaining to C:
MEASURES: M1. We also believe it is unnecessary to restate the definition of “Protection
System” in the Measure. 3) A fundamental incompatibility exists between NERC’s proposition of
“maximum maintenance (time based) interval” and the typical CMMS PM generation algorithm.
SPCTF members and regional compliance engineers have verbally represented that the
“maximum maintenance interval” is a precise term “not to exceed—even by one day---“
maximum, otherwise generating a fine-able Violation and that fixed intervals plus or minus a
certain additional period of time to account for other operational exigencies are no longer going
to be permitted. There is always an interval between the time a CMMS PM is issued and its
completion. The time interval between the issue date and the completion date is normally a
period of time to allow maintenance staff to schedule their work in an orderly fashion. The
maximum time based interval is fixed by the time period specified for issuance of the planned
maintenance (PM) work order (e.g. every 3 years) and the defined period of time to complete
the work (usually described as a percentage of the PM interval e.g. 25%). So predicating a PM
issue date based on the last issue date plus a percentage of the interval time to complete the
work is not inconsistent with a fixed time interval. Under the proposed tables, however, there is
no accommodation for this predominate maintenance practice. Even if maintenance intervals
were shortened to ensure that the required completion date as defined by program intervals
does not exceed the NERC maximum interval as described in the tables, this will not be sufficient
because auditors may conclude that the tables permit the use of only a single defined interval
and not permit an additional defined period of time to schedule and complete the work.
Remember, it is immaterial whether the Entity’s interval is more stringent than the NERC
maximum, a violation may occur if the maintenance is not performed within the Entity’s
maintenance interval, even if it is shorter than the NERC maximum. A precise maximum interval
requires constant managerial intervention on the part of the Entity to ensure that operational
exigencies do not cause violations on a component-by component (or element) basis. The
shortened interval would tend to destroy the sense of rhythm and pattern which should be
manifest in a time based program. Further, after one or more iterations, seasonal restrictions on
outages begin to impinge requiring adjustments to be made to the Maintenance Program
document to adjust the interval or maintenance activity. At best, it results in a clumsy way of
doing business and requiring significantly more oversight into keeping the maintenance program
document updated for presentation to auditors rather than focusing on prudent maintenance
activities as desired by FERC Order 693. Auditing is not any more difficult if the Maintenance
Program also specifies that a percentage of a fixed target / time interval is allowed to schedule
and complete the work—as meeting the interval requirements of a time based maintenance
program. This method allows for a fixed time for issuance of the work order and maintenance
personnel some flexibility to schedule and complete their work within a defined period of time.
We recommend to vote against adoption until some more workable solution is identified and
disseminated, satisfying both the Compliance Authority and the affected Entities. Specifically, we
recommend that the drafting team adopt “target” intervals with a +/- range of acceptability,
based on percentage or a fixed time per interval, which can be global for the Program or specific
to the elements or components in question. The target intervals must be stated in the PSMP, the
range of acceptability easily calculable and enforceable, and within the maximum intervals to be
identified in the tables 1a, b, and c, satisfying compliance issues. This also allows the Entities to
rationally plan their maintenance using existing CMMS technologies. 4) Within the Violation
Security levels, we are aware of no activity by NERC to differentiate the relative criticalitiy of
components or Elements of the BES system. For example, protection system components or
Elements in a regional switchyard may present a larger potential for disruption of the BES in the
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event of a mis-operation than does one associated with one generator among fifteen others and
which is more electrically remote from and of less consequence to the BES. Unless and until this
issue is addressed, both the PRC-005 maintenance and documentation will be less effective and
more expensive than it could be. 5) PRC-005-02’s proposed effective date is “See
Implementation Plan.” This is not adequate to provide regulated entities with appropriate notice
of the Effective Date of PRC-005-2 standard. ” Additionally, NERC has not posted the
“Implementation Plan” for comment in the same manner as the proposed standard and thus we
are not able to comment on the schedule provided in the Plan. We understand that the retention
and documentation cycles go back three years and that a regulated entity, depending on the
effective date of this standard and the entity’s audit cycle, will be audited to both PRC-005-1 and
PRC-005-2 during the same audit period. Some further discussion should be given to allowing
comment on the Implementation Plan because of the potential overlapping requirements during a
single audit cycle.
Individual
Mark Fletcher
Nebraska Public Power District
No
It would be very helpful in Table 1a, 1b, and 1c to reference the FAQ or Supplemental Reference
by page number and section number for the corresponding Maintenance Actiivity statements.
Table 1a, Control and Trip Circuits with electromechanical trip or auxiliary contact – how is the
control and trip circuit functional trip test performed without affecting the BES or without tripping
more than just the breaker (trip coil)? What is the basis for an actual trip of the breaker that will
affect the BES. Functional trip testing will require extensive analysis and could involve an
extensive testing evolution to ensure the correct circuit is tested without unexpected trip of other
components, particularly for generator protection systems. The complexity of the system and the
test would be conducive to an erro that resulted in excessive tripping, thus affecting the
reliability of the BES. It would seem that the potential for an adverse affect from this test would
be greater than the benefit gained of testing the circuit. In addition, scheduling outages to
perform the functional trip testing in conjunction with other outages required to perform
maintenance and other construction activities will be difficult due to the large number of outage
requiremetns for the fucntional testing. This will challenge the BES more often and thus reduce
reliability. Table 1a, Control and Trip circuits with electromechanical trip or auxiliary contacts What is the differentiation between control and trip circuits? The FAQ appears to use the term
interchangeably. • Table 1a, Associated communication systems - What is the basis for checking
that the associated communication equipment is functioning every 3 calendar months for
unmonitored components?. NPPDs experience indicates that a check every 6 months is sufficient.
Yes
Please provide an example of how the compliane percentage will be calculated for the
implementation plan.
Yes
Additional guidance on what is accepatable evidence is always good.
Yes
Yes
Is this document considered part of the standard and may be referenced during audit and selfcertification as an authentic source of informaiton?
No
FAQ 2.G, page 24 – NPPD believes system reliablity will be decresed if an entity is considered
non-compliant for exceeding a PSMP stated interval that is within the PRC-005-2 Maximum
Maintenance Interval. Considering an entity non-compliant for such a situation will encourage
establishment of intervals that only meet the minimum standard. There should be one standard
interval that all entities must be monitored against. If an entity wants to perform maintenance
more frequently, it should not be subject to non-compliance if it misses its target but meets the
Maximum Maintenance Interval in the standard. There are definitions at the beginning of the FAQ
that should be contained in the NERC definitions and not in an FAQ. Placing these in an approved
definition will help avoid interpretation issues that would arise during future audits.
4.2.5.1 (And elsewhere in the standard) Please define auxiliary tripping relays. 4.2.5.5 Do station
“system connected” service transformers that do not supply house load for the generating unit,
other than during start up or emergency conditions, fall under this clause? If so, can these
transformers be eliminated if the house load can be back-fed from “generator connected” service
transformer switchgear? What if there are redundant “system connected” feeds? R1 1.4
Clarification requested. This wording would suggest all battery activities fall under Table 1.a.
exclusively. R4 4.3 Does initiation of activities require documentation, or is inclusion of
“initiation” in the testing procedure sufficient evidence? Tables 1b &1c: Suggestion: If at all
possible, combine and simplify. The number of sub clauses and nuances that are being described
in these sections (with little change to interval or procedures for that matter) is overwhelming.
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These two tables are setting RE’s and System Owners up for making errors. Implementation and
auditability should be the focus of this standard, SIMPLIFY. • SPS – Does the output signal need
to be verified, or does the actual expected action need to be verified. Actual expected action
would affect electrical generation production for NPPD’s SPS.
Group
Tennessee Valley Authority
Dave Davidson
Transmission Operations and Maintenance (TOM) Support Group
No
The requirement to measure internal ohmic values of the station dc supply batteries every 18
months is excessive. The interval should be 36 months. Our experience from performing our
routine maintenance program including cell impedance testing at 3-year intervals has been that
the program is fully adequate in monitoring bank condition.
Yes
No
The Violation Severity Level Table listing for Requirement R4 lists the following under “Severe
VSL”. “Entity has failed to initiate resolution of maintenance-correctable issues” The threshold for
a Severe Violation in this case is too broad and too subjective. The threshold needs to be clearly
defined with low, medium, and high criteria.
No
There needs to be a defined method of deferral when equipment can’t be gotten out of service
until a scheduled outage. Give some examples of what “inputs and outputs that are essential to
proper functioning of the Protection System” are. Define what a “Control and Trip Circuit” is. Is
there one per relay? Do I have to have a list of them in my work management system?
No
If a relay is tested during a generator outage, what date is allowed to be used for compliance actual test date or date equipment was returned to service? These are usually only a few weeks
apart, but may be as much as three months different.
Individual
Brian Evans-Mongeon
Utility Services
With regard to DPs who own transmission Protection Systems, the standard is still very unclear
on when a DP owns a transmission Protection System. Many DPs own equipment that is included
within the definition of a Protection System; however, ownership of such equipment does not
necessarily translate directly into a transmission Protection System under the compliance
obligations of this standard. DPs need to know if this standard applies to them and right now,
there is no certain way of determining that from within this language or previous versions of this
standard. Additionally, the NPCC Regional Standards Committee withdrew a SAR on this very
subject as we informed the question would be addressed in this proposal.
Group
Corporate Compliance
Silvia Parada Mitchell
NextEra Energy, Inc.
No
Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s leadcalcium batteries are relatively stable for a 6 month period compared to lead-antimony batteries
used in the past.
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Individual
Charles J.Jensen
JEA
No
1. R1.1 What is a Protection System component? Could the SDT provide a better understanding
of what is meant by component? R4: A “Failure to specify whether a component is being
addressed by time-based, condition-based, or performance-based maintenance” by itself is a
documentation issue and not an equipment maintenance issue. Suggest this warrants only a
lower VSL, especially when one of the required components can only be time based. 2. R4:
Suggest a stepped VSL for “Entity has failed to initiate resolution of maintenance-correctable
issues”. While we understand the importance of addressing a correctable issue, it seems like
there should be some allowance for an isolated unintentional failure to address a correctable
issue.
No
2. What role with the Supplementary Reference and FAQ play with reference to the proposed
standard? We have a concern that the standard will stand-alone and not include the
interpretations, examples and expalnations that are needed to properly apply these values in a
compliance envoironment. There needs to be a method to include the FAQ and Supplementary
Reference. The method will also need to allow for future modifications as the standard is revised,
etc.
No
Data retention becomes a complex issue for maintenance intervals of 12 years where the last
two test intervals are required to be kept, i.e. 24 years. It would seem much more reasonable to
set a limt of two test intervals or the last regional audit, not having to keep some 24 years of
documentation with maintenance systems changing and archival records somewhat problematic
to keep.
No
We could find no rational provided for the % associated with each VSL, or component rationale
used to determine the proposed values listed. Is this included in some documentation that is
available but not included as part of this review?
No
The Supplementary Reference document is critical in our current compliance environment to be
approved as part of ths standard and any standard modifications need to be kept in
synchronization with the FAQ and the Supplementary Reference.
No
Yes the FAQ is also a very immportant document to be approved along with the standard. There
must be a way to have the standard and the FAQ go hand-in-hand or the standard must be
revised to include much of the FAQ.
The current interpretation by the SDT of paritally monitored is set at a higher bar than most
uttilities use in the their current designs today. We all wish to take advantage of the
microprocessor relays and their renowned and improved montoring capability. If TC1 is
monitored by primary relay A and TC2 is monitored by primary relay B, and these relays in turn
monitor their DC supplies, the vast majority of the system is monitored - (partially monitored),
including all the control cable out to the remote breakers and their trip coils. To add to this some
additional contacts within the scheme, located very near the primary relays, is extending the
partially monitored bar to a higher level than most designs incorporate today. If you know that
98% of the DC control system is monitored - isn't that paritally monitored? Please consider
changes to the SDT's current view of a paritally monitored protection systems.
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
Arizona Public Service Company
No
The associated maintenance activities are too prescriptive. The activities needed to ensure the
reliable service of the relay or device should be left up to the discretion of the utility.
Yes
No
The change to the Protection System definition and establishing a PSMP with prescriptive
maintenance activities relative to the voltage and current sensing devices has created a situation
where data from original or prior verification not being available or not at the interval to meet
the data retention requirement. Although, methods of determining the integrity of the voltage
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and current inputs into the relays were used to ensure reliability of the devices meets the utilities
requirements, they may not meet the interval requirement and would then be considered a
violation due to changes in the standard. Recommend a single exemption of the two recent most
recent performances of maintenance activities to the most recent performance of maintenance
activity in the first maintenance interval for this component due to the long maintenance interval,
the changes in the standard definitions and the prescriptive maintenance activities.
Yes
Yes
Yes
The generator Facilities subsections 4.2.5.1 through 5 are too prescriptive and inconsistent with
sections 4.2.1 through 4. Recommend this section be limited to description of the function as in
the preceding sections. Clarification is needed on how the “Note 1” in Table 1a, which appears to
be used in to define a calibration failure would be used in Time Based Maintenance. In PRC-0052 Attachment A: Criteria for a Performance-Based Protection System Maintenance Program, a
calibration failure would be considered an event to be used in determining the effectiveness of
Performance Based Maintenance. It is unclear in how it will be used in time based maintenance.
Individual
Scott Berry
Indiana Municipal Power Agency
The proposed effective date working is confusing and maybe incorrect. It looks like the second
part of the paragraph refers to the additional maintenance and testing required by requirement 2
of the current version of PRC-005-1. PRC-005-2 will be adding additional maintenance and
testing. Since the current wording is confusing, we are not sure when we have to ensure the new
testing is done on the protection equipment. When it comes to battery maintenance, the battery
cell to cell connection resistance has to be verified. IMPA is not sure how the SDT wants this
maintenace performed. Some battery banks are made up of individual battery cases with two
posts at each end that contain two to four individual battery cells inside of each case. To actually
tear down the individual cells in a case would be extremely hard and maybe impossible on the
sealed cases without destroying the cases. It would be nice to describe how the SDT wants the
connection resistance of battery cell to cell verified in the FAQ guide. In the same guide, the SDT
might give insight on what is meant by verifing the state of charge of the individual battery
cell/units (table 1A). It seems like measuring the voltage level of the individual battery would
work for this verification, but addditional information of what the SDT wants for this verification
would eliminate any doubt and help with being in compliant with this requirement.
Individual
Fred Shelby
MEAG Power
No
1. The descriptoins for the "type of protection system components" do not appear to be
consistent between Tables, 1a, 1b and 1c. 2. The maximum maintenance interval for a lead-acid
vented battery is listed at 6 calendar years for performing a capacity test.This type of test has
been proven to reduce battery life and an interval of 10 to 12 years would be better. 3. The
maximum maintenance interval for "Station DC supply" was set at 3 months. This is too short of
a period and 6 months would be better. 4. The control and trip circuits associated with UVLS and
UFLS do not require tripping of the breakers but all other protection systems require tripping of
the breakers, this appears to be inconsistent? 5. Digital relays have electromagnetic output
relays. Do they fall into the electromechanical trip or solid state trip? 6. Need for clarification:
The standard indicates that only voltage and current signals need to be verified. Does this mean
that voltage and current transformers do not need to be tested by applying a primary signal and
verifying the secondary output?
Yes
Yes
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Yes
It would be good to have the basis of the 5%, 10% and 15% defined. With time and experience
these percentages may need to be changed.
No
Further clarification is needed. The information provided on verifying outputs of voltage and
current sensing devices is confusing. In one part, it indicates that the intent is to verify that
intended voltages and currents are getting to the relay apparently without regards to acccuracy.
A pactical method of verifying the output of VTs and CTs is not identified and need to be
identified.
No comment.
No comment.
Individual
James A. Ziebarth
Y-W Electric Association, Inc.
No
Many of the changes to the proposed standard are reasonable and improve the clarity of the
standard and its requirements. However, Y-WEA concurs with Central Lincoln and FMPA on their
comments regarding the testing of battery cell-to-cell connection resistance. Many types of
stationary batteries are actually blocks of two or more cells that are internally connected. This
requirement would necessitate either some sort of feasibility exception process (which, as shown
by the TFE process with the CIP standards can be very difficult, cumbersome, and timeconsuming to develop and administer) or replacement of the batteries in question, which would
pose enormous burdens on small entities that must comply with this standard. The language in
this requirement should be changed from “cell-to-cell” to “unit-to-unit” in order to avoid these
issues.
Yes
Yes
Yes
Yes
Yes
Y-WEA concurs with Central Lincoln regarding the timing of required battery tests. The IEEE
standards referenced indicate target maintenance intervals. In order to remain reasonable, then,
this compliance standard needs to allow some buffer between a targeted maintenance and
inspection interval and a maximum enforceable maintenance and inspection interval. Central
Lincoln’s suggestion of a four-month maximum window is reasonable and should be incorporated
into the standard. Y-WEA is also concerned with R1.1’s language indicating that all components
must be identified with no defined “floor” for the significance of a component to the Protection
System. The SDT cannot possibly expect that a parts list containing every terminal block, wire
and jumper, screw, and lug is going to be maintained with every single part having all the
compliance data assigned to it, but without clearly stating this, that is exactly the degree of
record-keeping that some overzealous auditor could attempt to hold the registered entity to. The
FAQ is much clearer as to what is and is not a component and should be considered for the
standard. Y-WEA also concurs with FMPA’s comments regarding the testing of batteries and DC
control circuits associated with UFLS relaying. Many UFLS relays are installed on distribution
equipment. Furthermore, many distribution equipment vendors are including UFLS functions in
their distribution equipment. For example, many recloser controls incorporate a UFLS function in
them. These controls and the reclosers they are attached to, however, are strictly distribution
equipment. 16 USC 824o (a)(1) limits the definition of the Bulk-Power System to “not include
facilities used in the local distribution of electric energy.” A distribution recloser and its control
clearly fall into this exclusion. 16 USC 824o (i)(1) prohibits the ERO from developing standards
that cover more than the Bulk-Power System. As such, the DC control circuitry and batteries
associated with many UFLS relaying installations are precluded from regulation under NERC’s
reliability standards and may not be included in this standard because they are distribution
equipment and therefore not part of the Bulk-Power System. The proposed standard needs to be
rewritten to allow for this exclusion and to allow for the testing of only the UFLS function of any
distribution class controls or relays.
Individual
Armin Klusman
CenterPoint Energy
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CenterPoint Energy believes the proposed Standard is overly prescriptive and too complex to be
practically implemented. An entity making a good faith effort to comply will have to navigate
through the complexities and nuances, as illustrated by the extensive set of documents the SDT
has provided in an attempt to explain all the requirements and nuances. The need for an
extensive “Supplementary Reference Document” and an extensive “Frequently Asked Questions
Document”, in addition to 13 pages of tables and an attachment in the standard itself, illustrate
that the proposal is too prescriptive and complex for most entities to practically implement.
CenterPoint Energy is opposed to approving a standard that imposes unnecessary burden and
reliability risk by imposing an overly prescriptive approach that in many cases would “fix” nonexistent problems. To clarify this point, CenterPoint Energy is not asserting that maintenance
problems do not exist. However, requiring all entities to modify their practices to conform to the
inflexible approach embodied in this proposal, regardless of how existing practices are working, is
not an appropriate solution. Among other things, requiring entities to modify practices that are
working well to conform to the rigid requirements proposed herein carries the downside risk that
the revised practices, made solely to comply with the rigid requirements, degrade reliability.
Individual
Kasia Mihalchuk
Manitoba Hydro
No
The monitoring attributes required to achieve level 2 monitoring of Station DC supply seem
excessive. We are not aware of any other utilities doing automatic monitoring all 6 attributes
required. In particular automatic monitoring of electrolyte level & battery terminal resistance
does not seem practical. There is inconsistency between Table 1 and the FAQ. In the Group by
Monitoring Level section of the FAQ it indicates that a battery with low voltage alarm would be
considered to have level 2 monitoring. In Table 1C under the heading "Maximum Maintenance
Interval" some of the entries are stated as being "Continuous". In the case of other maintenance
activities the descriptor for Maintenance Interval indentifies the maximum period of time that
may elapse before action must be taken. "Continuous" implies continuous action, however, in
reality continuous monitoring enables no maintenance action to be taken until such time as
trends indicate the need to do so. Therefore we recommend that where the maintenance interval
be changed to read "Not Applicable".
No
Time horizons to change from present 6 months to 3 months maintenance time intervals within
proposed implementation time period is not realistic.
Yes
No issues or concerns at present
Yes
There is no rational provided for the % associated with each VSL, or component rationale used to
determine the proposed values listed.
Yes
Yes
Once the new Standard is approved, NERC must allow for a greater implementation stage and no
further changes proposed for the foreseeable future. It does take a lot of resources for a Utility
to make the required changes in maintenance frequency templates or type of maintenance
required as per the proposed "Standard". Regarding the use of the term “Calendar” (i.e. end of
calendar year) for maximum maintenance interval. Our utility uses end of fiscal year as our
cutoff date for completing maintenance tasks for a given year. It would be considerable work for
us to have to switch to end of calendar year with zero improvement in our overall reliability. We
suggest it be left up to each utility to define their calendar yearly maintenance cycle when all
tasks for that year must be completed.
Individual
Edward Davis
Entergy Services
No
1. Table 1a has a “Control and trip circuits with electromechanical trip or auxiliary contacts
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(except for microprocessor relays, UFLS or UVLS)” component type listed, and there is a “Control
and trip circuits with electromechanical trip or auxiliary [editorial comment: add ‘contacts’]
(UFLS/UVLS systems only)” component type listed. Suggest a “Control and trip circuits with
electromechanical trip or auxiliary contacts” for a microprocessor relay application should be
addressed since it seems to be missing. 2. The term “check” has replaced “verify” for some of
the maintenance activities in this draft version. What is the difference between these two terms,
and shouldn’t “check” be defined if it is to be included as a PSMP activity term? 3. Assuming the
term “check” replaced “verify proper functioning” in order to allow for the completion of a
maintenance activity within the required interval and yet account for a maintenance correctable
issue being present, suggest the other remaining activities in the tables where the term “verify
proper functioning” is used, also be replaced with “check”. 4. Consider modifying the definition of
“verification” to “A means of determining or checking that the component is functioning properly
or maintenance correctable issues are identified”, eliminate use of the term “verify proper
functioning” (which seems to be redundant by PRC-005-2 standard definition), and simply use
the term “verify”.
Yes
Yes
No
1. R4: A “Failure to specify whether a component is being addressed by time-based, conditionbased, or performance-based maintenance” by itself is a documentation issue and not an
equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of
the required components can only be time based. 2. R4: Suggest a stepped VSL for “Entity has
failed to initiate resolution of maintenance-correctable issues”. While we understand the
importance of addressing a correctable issue, it seems like there should be some allowance for
an isolated unintentional failure to address a correctable issue. If possible, consider the potential
impact to the system. For example, a failure to address a pilot scheme correctable issue for an
entity that only employs pilot schemes for system stability applications should not necessarily
have the same VSL consequence as an entity which employs pilot schemes everywhere on their
system as a standard practice.
Yes
Yes
We support this project and believe it is a positive step towards BES reliability. However, we
believe the draft document needs additional work as per our comments. Also, as indicated by the
amount of industry input on the last version draft comments, we believe revisions are still needed
to properly address this technically complex standard. If this standard is to deviate from the
original project schedule and follow a fast track timeline for approval, then we disagree with the
3 month implementation for Requirement 1 and ask for at least 12 months. The original schedule
provided sufficient advance notice to work on an implementation plan and it included the typical
time required for NERC Board of Trustees and regulatory approvals. If the project schedule and
typical NERC Board of Trustees and regulatory approval times are to be accelerated, the
implementation plan should be extended.
Individual
James Sharpe
South Carolina Electric and Gas
Yes
Please provide clarity on why Table 1b for “Station dc supply” has a double entry that appears to
be contradictory. The table provides monitoring attributes for a maximum maintenance interval
of 6 calendar years and the next row says to refer to level 1 maintenance activities.
Yes
Yes
(Note that Section C.M2 leaves off "Distribution Provider" but references Requirement R2 at the
end of the Section. "R2 applies to the Distribution Provider.")
Yes
Yes
No
Question/Answer 4-C (Pg. 10 of FAQ) seems to indicate that by documenting breaker operations
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for fault conditions the table 1b requirements for control circuitry (Trip Coils and Auxiliary relays)
can be satisfied. It is possible that even though a breaker successfully operates for a fault
condition one trip coil of a primary/backup design can be inoperable and “masked” by the good
trip coil. Although it is likely that a faulty trip coil would be caught by monitoring of continuity it
is not a certainty that both trip coils actually operated to clear a fault (example-mechanical
binding)
R1.1 states “Identify all Protection System Components”. To avoid confusion this should be
clarified. It could be interpreted that discreet components must be individually identified. An
example would be as individual aux relays used in the tripping path.
Individual
Jon Kapitz
Xcel Energy
The current language is not aligned with the FAQ concerning the level of maintenance required
for Dc Systems, in particular the FAQ states that with only 1 element of the Table 1b attributes
in place the DC Supply can be maintained using the Table 1b activities, the table itself is clear
that ALL of the elements must be present to classify the DC Supply as applicable to Table 1b.
The FAQ needs to be aligned with the tables. The FAQ also contains a duplicate decision tree
chart for DC Supply. The FAQ contains a note on the Decision tree that reads, "Note: Physical
inspection of the battery is required regardless of level of monitoring used", this statement
should be placed on the table itself, and should include the word quarterly to define the
inspection period.
No comments
No comments
No comments
No
As we commented on in the previous draft of the standard that proposed the Supplementary
Reference and FAQ, we are concerned as to what role these documents will play in
compliance/auditing. It is also unclear how these documents will be controlled (i.e. Revised and
Approved, if at all). Inconsistencies have been identified between proposed standard and the
documents (e.g. page 29 of FAQ example 1).
No
As we commented on in the previous draft of the standard that proposed the Supplementary
Reference and FAQ, we are concerned as to what role these documents will play in
compliance/auditing. It is also unclear how these documents will be controlled (i.e. Revised and
approved, if at all). Inconsistencies have been identified between proposed standard and the
documents (e.g. page 29 of FAQ example 1).
R1.1 “Identify all Protection System Components” – does this mean that the PSMP must contain
a “list”? Please explain what this means. If it is a list, then essentially it will be a dynamic
database, not necessarily a “program” as defined in the PSMP R1.3 “include all maintenance
activities…” seems to be an indirect way of indicating that the entities PSMP must comply with
the tables. Tables – the components related to DC Supply and battery are confusing. It the
battery is the specific component then state “battery". If the charger is the specific component,
then state “charger”. As currently written, one must sort through all of the different “Station DC
Supply” line items to figure out what is required. – In tables 1b and above, it is written “no level
2 monitoring attributes are defined – use level 1 maintenance activities” but then maintenance
activities are listed that don’t match with Level 1 maintenance activities. Please clarify what
exactly needs to be done if using Table 1 b and above.
Individual
Rex Roehl
Indeck Energy Services
No
No
The VRF's are highly arbitrary because they treat all registered entities and all protective systems
alike. They're not. For example, under-frequency relays for generators protect the equipment
needed to restore the system after a blackout. The under-frequency load relays prevent a
cascading outage. As discussed at the FERC Technical Conference on Standards Development,
the goal of the standards program is to avoid or prevent cascading outages--specifically not loss
of load. That would make under-frequency load relays more important to prevent cascading
outages.
No
Measure 1 is complete overkill for a small generating facility. The maintenance program is to
inspect and test the equipment within the intervals. A qualified contractor applies industry
standard methods to maintain the equipment. Trying to have each entity define the maintenance
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program down to the component level does not improve reliability.
No
The VSL's treat all entities, components and problems alike. By combining 4 protection
maintenance standards, it elevates the VSL on otherwise minor problems to the highest levels of
any of the predecessor standards. The threshold percentages are very arbitrary. Severe VSL
doesn't in any way relate to reliability. For a small generator to miss or mis-categorize 1 out of 7
relays is unlikely to have any impact on reliability, much less deserving a severe VSL. The R2 &
R4 VSL's don't care about results of the program, only whether all components are covered. Half
of the components could fail annually and its not a Severe VSL. The R3 VSL allows 4% countable
events, which can be hundreds for a large entity and only allows a few for a small entity.
No
In 2.3, the applicability is stated to have been modified. As discussed at the FERC Technical
Conference on Standards Development, the goal of the standards program is to avoid or prevent
cascading outages--specifically not loss of load. The modified applicablity moves away from the
purpose of the standards program to an undefined fuzzy concept. Applicable Relays ignore the
fact that some relays, or even some entities, have little to no affect on reliability. The global
definition of Protective System encompasses all equipment, and doesn't differentiate the
components that meet the purpose of the standards program. The Supplementary Reference
doesn't overcome the inherent shortcomings of the standard.
No
The standard should include an assessment of, and criteria for, determining whether a Protective
System is important to reliability. It presently treats a fault current relay on a 345 kV or higher
voltage transformer the same as one on a small generator on the 115 kV system. The impact of
failures on both on a hot summer day like we've had recently in NY, would be very different. As
discussed at the FERC Technical Conference on Standards Development, the goal of the
standards program is to avoid or prevent cascading outages--specifically not loss of load. This
seems to have been lost in the drafting process. Much of the effort expended on complying with
the existing PRC maintenance standards, as well as that to be expended on PRC-005-2, has little
to no significant in terms of improving reliability. That effort could be better utilized if focussed
on activities that could significantly improve reliability. As one of the Commissioners at the FERC
Technical Conference on Standards Development characterized the relationship between FERC
and NERC as a wheel off the track. The whole standards program, and especially PRC-005-2, is
off the track.
Individual
Jeff Nelson
Springfield Utility Board
No
SUB appreciates the effort to try to strike a balance between specificity around a specific
standard and flexibility to meet the requirement under the standard. The maximum allowable
intervals don't seem unreasonable combined with the implementation schedule. However, it
seems that the proposed changes stray toward a proscriptive set of maintenance that 1) does
not allow for an alternate method of testing and 2)sets unrealistic testing requirements. For
example, battery terminal to terminal testing is not feasible with all battery systems. This is a
consistent message SUB has heard from others as well. First and foremost - a test or
maintenance must be done for each device within the defined interval. With that in mind... SUB's
preference would be that the maintenance activities focus on what specifically must be done for
a device (may be type specific) vs. what could be done for a device for compliance (as an
example of what an auditor could look for when conducting an audit) vs. alternative bestpractices for testing and maintenance that the entity demonstrates constitutes as maintenance or
test. With regard to the first (maintenance activities focus on what specifically must be done for
a device) - it seems that this would apply to a limited number of devices With regard to the
second (maintenance activities focus on what specifically can be done for a device) - it seems
that this would apply broad number of devices and the list of what can be done should be broad
to cover a range of different devices that provide the same function. With regard to the last
(alternative best-practices for testing and maintenance that the entity demonstrates constitutes
as maintenance or test), it would be helpful to have a mechanism outside the standard itself to
either have a NERC technical group craft a series of criteria that must be met for an acceptable
alternative maintenance or the entity document the criteria used to determine an adequate test
and provide for a test that meets that set of criteria). It would be anticipated that these would
fall under a minority of devices.
No
Time horizons for implementation seem adequate and SUB appreciates the attention to putting
together a reasonable but assertive implementation plan. The Violation Risk Factors are
problematic. With all due respect, it seems that NERC still operates in a "BIG UTILITY" mind set.
There are "PROTECTION SYSTEMS" and there are "Protection Systems" - some Protection
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Systems are may significantly impact system reliability and others may not. This not promote
reliability in that if an entity was thinking about installing a minor system or installing an
improvement that enhances reliability (but is not required) that it might back away because of
the risk associated with somehow being out of compliance. Reliability runds the risk of being
diminished through the standards approach. SUB suggests stepping back and putting more
granularity on VRFs and there needs to be more perspective on the purpose of the device when
arriving at a risk factor. Perhaps a voltage threshold could be attached to the VRFs. For example
language could be added to say "For Elements at 200kV and above, or for Critical Assets, the risk
factor is higher" and "For Elements operating at 100kV and above, the risk factor is medium" and
"For Elements below 100kV, the risk factor is lower" In SUB's view, a discussion on VRF's needs
to coupled with Violation Severity Levels. SUB discusses VRF's later in this comment form. SUB
would be supportive of a Medium VRF designation if there were a more balanced VLF structure
(please refer to the comments of VLFs)
No
The measures do not seem unreasonable. However the data retention states that documentation
must exist for the two most recent performances of each maintenance activity. Stepping back,
there is an implementation schedule that is designed to bring all devices into compliance with
ONE maintenance or test within (SUB's understanding is) 6 years. There may not be
documentation for more than one activity. Further, new or replacement components won't have
more than one activity for a number of years. The data retention schedule, left unchanged, will
promote non-compliance because it is impossible to have two records when only one may
possibly exist. Rather than promote a culture of compliance, the standard promotes a culture of
non-compliance by creating an standard that cannot be met. The FAQ addresses this issue, but
the Data Retention language seems to be less clear. SUB suggests that the Data Retention
language be clear that new components that do not replace existing components may have only
one record for maintenance if only one maintenance of the component could possibly exist. SUB
suggests that the Data Retention language also be clear that for new components that replace
existing components, that the Data Retention requirement reflect that the entity needs to retain
the last test for the pre-existing component and the test for the new component (for a total of
two tests).
No
The Violation Risk Factors are problematic. With all due respect, it seems that NERC still operates
in a "BIG UTILITY" mind set. Big utilities have potentially hundreds or thousands of components
under different device types. Looking at the VRFs, the percentages 5% or 15% as an example,
are looked at based on a deep pool of multiple devices so a "BIG UTILITY" that misses a
component or small number of components may not trigger a high severity level. However a
small utility may have only a handful of components under each type. Therefore if the small
utility were to miss one component all of a sudden the utility automatically triggers the 5% or
15% threshold. This type of dynamic unreasonable and not equitable. Therefore (in an attempt
to work within the framework proposed), SUB proposes that there be a minimum number of
components that might not be in compliance which result in a much lower Violation Severity
Level. SUB suggests that NERC try to create a level playing field. If 15% of a Big Utility's total
number of components averages at around 15 out of 100 total then perhaps a reasonable
outcome would be that up to 5 components (regardless of the total number of components an
entity has under each type) could be in violation without tripping into a high VSL. (the 5
components threshold may not apply to all types, this is just for illustrative purposes). Also, are
the missed components compounding? For example, if an entity missed 5 components on year
three and another 5 components in year 10 is the VSL based on 10 components or 5
components. There should be a time horizon attached to the VSL such that the VSL does not
count prior components that were brought into compliance through a past action. That intent
may be to not have the VSLs be based on compounding numbers of components, however that
should be made clear.
Yes
SUB appreciates that Time Based, Performance Based, and Condition Based programs can be
combined into one program. However it should be clear that a utility may include one, two or all
three of these types of programs for each individual device type. Currently the language reads:
"TBM, PBM, and CBM can be combined for individual components, or within a complete Protection
System." The "and" requires all three to be combined if they are combined. SUB suggests the
and be changed to "or". Language Change: "TBM, PBM, or CBM can be combined for individual
components, or within a complete Protection System."
Yes
SUB is supportive of the intent behind the standard and appreciates the ability to provide input
into this process. The following is a repeat of the comment in Question #5 with regard to the
supplemental reference. SUB appreciates that Time Based, Performance Based, and Condition
Based programs can be combined into one program. However it should be clear that a utility
may include one, two or all three of these types of programs for each individual device type.
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Currently the language reads: "TBM, PBM, and CBM can be combined for individual components,
or within a complete Protection System." The "and" requires all three to be combined if they are
combined. SUB suggests the and be changed to "or". Language Change: "TBM, PBM, or CBM can
be combined for individual components, or within a complete Protection System."
Group
Bonneville Power Administration
Denise Koehn
BPA, Transmission Reliability Program
No
The requirements pertaining to dc control circuitry are confusing. To start with, a definition or
further explanation is required for the term “auxiliary contact”. Is this strictly a breaker “a” or “b”
switch, or does this include lockout relay contacts, etc.? Another confusing point is that the term
trip circuit is used in several places throughout the tables, but it is not included in the definition
of Protection System, where the term dc control circuitry is used. It is important to use
consistent terminology throughout the definition and the standard. The requirements for (dc)
control circuits in Table 1a are fairly straightforward, but in Table 1b control circuits are broken
down into three parts: trip coils and auxiliary relays; trip circuits; and control and trip circuitry.
It is very unclear exactly what each of these three parts includes. In Table 1c, control circuitry is
covered as a single element. Please provide clarity to what is included in each part of a control
circuit in Table 1b and the monitoring attributes of each. Also, please be consistent in the
treatment of control circuits throughout the three tables. Table 1a, SPS, BPA does not
understand the following segment of this paragraph “The output action may be breaker tripping,
or other control action that must be verified, but may be verified in overlapping segments. A
grouped output control action need be verified only once within the specified time interval,..." In
one sentence, it says you can test a SPS in segments - and in the next sentence it says you have
to verify the grouped output control action at least once within the specified time interval. It
seems that the sentences contradict themselves. Table 1b, Control and trip circuitry - "Monitoring
of the continuity of breaker trip circuits along with the presence of tripping voltage supply all the
way from relay terminals (or from inside the relay) through to the trip coil(s)..." To monitor the
trip path as proposed in this Standard would cost some serious time and $$. BPA does not
believe there is a way to meet level two monitoring for batteries. In addition, some of the
maintenance tasks need to be defined: - monitoring the electrolyte level is not commercially
available. - the state of charge of each individual cell may need to be better defined. There are
means to verify the state of charge of the entire bank, but not each individual cell. Since a
device to provide level 2 monitoring is not commercially available, we would be forced to follow
level 1 maintenance guides, which would require maintenance of comm batteries every three
months. Many of these batteries are not accessible during 9 months of the year except via snocat or helicopter. We currently monitor for some of the level 2 requirements, but not all. Our
current practices of monitoring and yearly maintenance supplemented by opportunity inspections
have successfully identified problems before we lost DC power to any of our comm facilities.
VRLA type batteries: - battery continuity needs to be defined. In regards to the maximum
allowable intervals; the frequency with which BPA performs the 18 month maintenance tasks as
prescribed in the standard are on a 24 month interval along with visual inspections and voltage
measurements weekly to bi-weekly. BPA has seen success with this maintenance program with
the ability to identify suspect cells or entire banks with adequate time to perform corrective
actions such as repairs or replacements. BPA also does not perform routine capacity testing, this
is an as required maintenance task to confirm/validate our other test results if needed. Our
suggestion would be to extend the maintenance intervals beyond 18 months, and to provide
some clarity on the above items.
Yes
Yes
Yes
The term “maintenance correctable issue” used in Requirement 4 seems to be at odds with the
definition given for it. It seems that an issue that cannot be resolved by repair or calibration
during the maintenance activity would be a maintenance non-correctable issue. Also, in
Requirement 4, the term “identification of the resolution” is ambiguous. Suggested changes for
Requirements 4 and 4.1 are: R4. Each Transmission Owner, Generator Owner, and Distribution
Provider shall implement its PSMP, and resolve any performance problems as follows: 4.3 Ensure
either that the components are within acceptable parameters at the conclusion of the
maintenance activities or initiate actions to replace the component or restore its performance to
within acceptable parameters.
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Individual
Amir Hammad
Constellation Power Generation
No
Constellation Power Generation (CPG) does not agree with the maximum maintenance interval
for associated communication systems and station dc supply that has as a component any type
of battery, which is 3 months. If the intent of the drafting team was to make this test quarterly
(as recommended in IEEE-450), than the maximum interval should be 4 months. As written, for
a registered entity to ensure they complete this test in an interval less than 3 months, they will
most likely complete this test every 2 months. This causes two additional and unwarranted tests
every year. CPG recommends an alternate formulation for intervals if the nominal interval is less
than one year. Some possible alternatives (assuming a three month nominal interval): Once per
calendar quarter no later than the end of the quarter no earlier than one month before it. Four
times per year, no more than 120 days apart no less than 60. CPG does not agree with
differentiating between the different battery types. A suggestion would be to take the maximum
maintenance interval for all the battery types, which is 6 years, and apply them across all types
of batteries, eliminating the need to differentiate between them. Furthermore, multiple cell units
do not provide the ability to measure cell-cell resistance, and so that requirement should be
removed. CPG is not clear why electromechanical tip contacts in microprocessor relays are
excluded in Table 1a.
No
Constellation Power Generation questions why the VRF for R1 is High while all other requirements
are Medium. This VRF should be changed to Medium to follow suit with the other requirements.
No
Constellation Power Generation does not agree with the proposed data retention section.
Retaining and providing evidence of the two most recent performances of each distinct
maintenance activity should be sufficient. For entities that have not been audited since June of
2007, having to retain evidence from that date to the date of an audit could contain numerous
cycles, which is cumbersome and does not improve the reliability of the BES.
No
Constellation Power Generation does not agree with the proposed data retention section.
Retaining and providing evidence of the two most recent performances of each distinct
maintenance activity should be sufficient. For entities that have not been audited since June of
2007, having to retain evidence from that date to the date of an audit could contain numerous
cycles, which is cumbersome and does not improve the reliability of the BES.
Yes
No
The PT/CT testing section is implying that the testing must be completed while energized, which
is counter to industry practice at generation facilities. Leeway should be given to the entities to
devise their own methods for testing voltage and current sensing devices and wiring to the
protection system.
Constellation Power Generation does not agree with the changes to Voltage and Current Sensing
inputs to protective relays in Table 1a. It is inferring that the only way to complete testing on
these components to satisfy NERC is to complete online testing, which is dangerous and does
not improve the reliability of the BES. In fact, it can be argued that it decreases the reliability of
the BES. The verbiage should be changed back to what was originally proposed to allow for
offline testing. Furthermore, Constellation Power Generation does not agree with several of the
inclusions of generator Facilities in this standard. For example, in 4.2.5.1, the proposed standard
looks to include any components that can trip the generator. At a nuclear facility, this could
include protection of motors at the 4 kV level that may trip the generator due to NRC regulated
safety issues. This should not fall under NERC jurisdiction. The inclusion of station service
transformers is another inclusion that should not be in this standard. There is no difference
between a station service transformer and a transformer serving load on the distribution system.
This has no impact on the BES, which is defined as the system greater than 100 kV. Additionally,
CPG has concerns regarding the vague language of R1.1, which requires the identification of all
protection systems components. It provides no elaboration on the level of granularity expected or
acceptable means of identification. It is unlikely that the SDT expected the unique identification
of every discrete component down to individual test switches or dc fuses. In the case of current
transformers, several of which, or even dozens of which may be connected to a single relay there
is no apparent reliability benefit that comes from identifying them uniquely so long as it is
proven that a protection system is receiving accurate current signals from the aggregate
connection. (It may be argued that the revised definition of “protection stems” eliminates the
need to include CT’s under R1.1 but that’s just one interpretation.) Some discrete components of
communication systems may exist in an environment that is not owned by or known to the
protection system owner. Additionally all protection system components may be identified in
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documents that are current and maintained but not in the form of a specific search-able list that
is limited to components that are within the scope of PRC-005. Examples may be indexed
engineering drawings that identify relays and other components for each protection systems or
scanned relay setting and calibration documents that are current but not attached to search-able
meta data. It is unclear whether or not these would be considered acceptable identification
meeting R1.1. If they are not then the implementation plan for R1 is in all probability
unachievable. CPG requests that the SDT provide more elaboration on R1.1 in the standard and
in the supporting documents. In that vein, to clarify footnote 1 to R1 which excludes devices that
sense non-electrical signals, it should explicitly say that the auxiliary relays, lockout relays and
other control circuitry components associated with such devices are included. The matter is welladdressed in the FAQ’s but could easily be misunderstood if not included here. Lastly,
Constellation Power Generation would like to voice concern over the expedited process in which
this standard is being developed. Voting within a week of submitting comments does not leave
enough time for the drafting team to thoroughly vet through the issues and identify much
needed changes, let alone implement them.
Group
WECC
Tom Schneider
Western Electricity Coordinating Council
Yes
Compliance agrees with the changes as they add clarity though the Tables do not define what is
actually required to demonstrate compliance without reading the Supplementary Reference and
the FAQs.
Compliance agrees with the measures. Compliance recommends making the Supplementary
Reference part of the standard and that it be referenced appropriately in Table 1a, 1b, 1c and
Attachment A. Compliance does not agree with the Data Retention as provided in the draft. In
order for an entity to demonstrate that they have maintained system protection elements within
their defined intervals retention of documentation will be required for many years. This is in order
to establish bookends for the maintenance interval. Maintenance intervals commonly span 5
years or more. Entities should be required to retain data for the entire period of the maintenance
interval. Data Retention should be changed to: The Transmission Owner and any Distribution
Provider that owns a transmission Protection System and each Generation Owner that owns a
generation Protection System, shall retain evidence of the implementation of its Protection
System maintenance and testing program for a minimum of the duration of one maintenance
interval as defined in the maintenance and testing program.
No
Compliance does not agree. The R1 VSL allows too much to interpret. What does no more than
5% of the component actually use to define the percentage; it should be specific if it is referring
to the weight of each component and how many components are there. For example, Protective
Relay is one component of five. In addition the VSL for Lower, Moderate and High states in the
first paragraph that the entity included all of the “Types” of components according to the
definition, though failed to “Identify the Component”. It needs clarity on how it can be included
though not specifically identified like the next two bullets. The same concern applies to R2 and
R4. Be specific about what is included (or not) to calculate those percentages.
Yes
Compliance does agree with the clarity and the Supplementary Reference should be specially
referenced where appropriate the Tables 1a, 1b, 1c and Attachment A that are included with the
Standard. But this reference is not a part of the approved standard and there are no controls
which prevent changes in the reference document that could impact the scope or intent of the
standard. If the standard is approved with reference to the Supplementary Reference then future
changes to the Supplementary Reference should not be allowed without due process. Only the
version in existence at the time of approval of the standard could be used to clarify or explain
the standard.
Yes
Compliance does agree with the clarity. The FAQ answers should be referenced specifically to the
Standard and the Supplementary Reference to further understand those two documents.
However, endorsement of the Standard should not imply endorsement of the FAQ and vice
versa.
Compliance believes it will be difficult to demonstrate compliance when an entity chooses
Condition Based Level 2 or Level 3 maintenance as the details of the requirements are still open
to interpretation. The FAQ has answers to specific questions that are multiple choices. Breaking
down this standard into this level of granularity requires supplementary documents to understand
it and for auditors to understand how to determine compliance. Industry standards are specific
to equipment types and should be allowed to set intervals and maintenance tasks rather than a
one-size fitting all approach.
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Group
Western Area Power Administration
Brandy A. Dunn
Western Area Power Administration - Corp Services Office
No
1) Standard, Table 1a, “Control and trip circuits with electromechanical trip or aux contacts
(except for microprocessor relays, UFLS or UVLS)”: Where would un-monitored control and trip
circuits connected to a microprocessor relay fall, and what is the associated interval and
maintenance activity? 2) Standard, Table 1a, “Control and trip circuits with electromechanical
trip or aux contacts (except for microprocessor relays, UFLS or UVLS)”: Please confirm that the
defined Maintenance Activity requires actual tripping of circuit breakers or interrupting devices.
3) Standard, Table 1a, “Control and trip circuits with unmonitored solid state trip or auxiliary
contacts (except UFLS or UVLS)”: Please confirm that the defined Maintenance Activity requires
actual tripping of circuit breakers or interrupting devices. 4) Standard, Table 1b. On page 13, for
Protective Relays, please clarify the intent of “Conversion of samples to numeric values for
measurement calculations by microprocessor electronics that are also performing self diagnosis
and alarming.” 5) Standard, Table 1b. On page 13, for Protective Relays, please clarify the intent
of “Verify correct operation of output actions that used for tripping.” Does this require functional
testing of a microprocessor relay, i.e., using a relay test set to simulate a fault condition? 6)
Standard, Tables 1a and 1b: Would it be possible to provide an interval credit for full parallel
redundancy from relay to trip coil? 7) Table 1a (page 9) Voltage and Current Sensing Inputs to
Protective Relays and associated circuitry – This maintenance activity statement implies that
signal tests to prove the voltage and current are present is all that is required. Can this be
accomplished by adding a step to the Relay Maintenance Job Plan to take a snapshot of the
currents and potentials (In-Service Read) with piece of test equipment? 8) Table 1b (Page 14)
Control and Trip Circuitry – Level 2 Monitoring Attributes for Component is too wordy and hard to
understand the meaning. Does this whole paragraph mean that the dc circuits need to be
monitored and alarmed? At what level does the dc control circuits need the alarming? Can this be
at the control panel dc breaker output? 9) Table 1b (Page 15) Station Dc Supply – Should this be
in Table 1c because the attributes indicate that the station dc supply cells and electrolyte levels
are monitored remotely. To do a fully monitored battery system would be cost prohibitive and
require a tremendous amount of engineering. 10) Table 1a and 1b (Page 11 and 16) Associated
communications system - Western has monitoring capability on all Microwave Radio and Fiber
Optics communications systems with the Communications Alarm System that monitors and
annunciates trouble with all communications equipment in the communications network. The
protective relays that use a communications channel on these systems have alarm capability to
the remote terminal units in the substation. Since these are digital channels how does an entity
prove channel performance on a digital system?
Yes
Yes
Yes
Yes
Yes
Clarification 1) FAQ, page 36, Control Circuit Monitor Level Decision Tree: It’s not clear if the
note on Level 1 device operation is required for Level 3 monitoring.
1) Standard, Page 4, R 4.3: Is the utility free to define its own “acceptable limits”? 2) Standard,
Page 4, R 4.3: Must the “acceptable limits” be stated in the PSMP? 3) Standard, Page 4,
Footnotes 2 and 3 are the same. 4) Attachment A says we can go to a performance based
program; does this apply to every part of the standard? In other words, does this apply to
component testing, functional testing, etc., and do we define the intervals of the test. That is, do
we determine how long we test the sample of at least 30 units that Attachment A discusses?
Group
Public Service Enterprise Group ("PSEG Companies")
Kenneth D. Brown
Public Service Electric and Gas Company
No
The SDT is to be commended for the work and details included in the most recent draft revision.
The standard – with associated references is easier to interpret. The sections on DC supply are
too restrictive. Quartile checks of VLA electrolyte levels for unmonitored systems is reasonable,
however the option of checking the electrolyte levels and voltages with less frequency is not an
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option with systems that have voltage alarm notification and ground detection monitoring alarm
notification unless all level 2 attributes are followed. The level 2 monitoring attributes are too
comprehensive to allow for a suggested alternative less restrictive interval of 6 months to a year.
Suggest there be an additional option for level 2 monitoring that includes voltage level and
ground alarms with a 6 month maintenance activity interval. The perception of table 1a page 12
for station DC supply – “used for UVLS and UFLS” is a maintenance activity to verify proper DC
supply voltage when the UVLS and UFLS system is maintained. This is the only DC supply
maintenance activity for those applications and the other more rigorous maintenance activities
do not apply? If this is a correct interpretation specifically list that as such in the maintenance
activity description (State the other DC supply maintenance activities are not applicable for UVLS
and UFLS). The maintenance intervals for station DC supply for level 1 and 2 monitoring does
not appear to be consistent and is somewhat confusing. A battery system with level 2 monitoring
attributes for components has intervals of 6 years, and then in next section states that no level 2
attributes are defined - use level 1 maintenance activities. Suggest that all DC supply / batteries
be broken out all be included in one separate -stand alone table with varied maintenance
requirements based on monitoring attributes. The maintenance activities shown on table 1b on
page 19 for Station DC supply is intended for VLA batteries? If so add that in component
definition. For DC systems that use a storage battery, suggest that chargers be eliminated as
other required maintenance activities will expose any problems with the charger. The
requirements of performing a capacity test every 6 years during the initial service life of a VLA
battery in addition to the other maintenance activities are too restrictive and will cause extensive
outages of the affected equipment. Suggest that this frequency be extended to 10 years for VLA
batteries for the first iteration if all the other maintenance activities are followed. Failure rate of
VLA in first 10 years is extremely low. Other maintenance activities will expose significant issues.
Yes
No
Data retention for battery capacity test should be most recent performance, not last 2. The other
maintenance activities documentation with one iteration of capacity test is sufficient
documentation
Yes
No
Suggest that figure 2 has a line of demarcation added that shows components specifically not
part of the standard requirements. (Medium voltage bus). Battery charger should be removed
from table of components when a storage battery is used for the DC supply.
No
This is a very useful document and provides a good source of additional information; there are
some cases where it could be interpreted as a standard requirement that can lead to confusion if
conflicts exist. For example, the group by monitoring level example V.1.A shown on page 29
describes a level 2 partial monitoring as circuits alerting a 24Hr staffed operations center, page
38 shows level 2 monitoring as detected issues are reported daily. The actual standard table 1b
level 2 monitor describes alarms are automatically provided daily to a location where action can
be taken for alarmed failures within 1 day or less. This is listed as a supplemental reference
document in the standard. The FAQ document “supports” the standard but is or is not an official
interpretation tool, or if it is state as such.
Individual
Gerry Schmitt
BGE
No
Comment 1.1: In its decision to use “calendar years” with the maintenance intervals prescribed
for most components the SDT has provided a framework that is consistent with a well-run PSMP
but with enough flexibility to be practical. However BGE believes the application of this approach
to short maintenance intervals, like three months for some battery maintenance will risk
numerous violations due to practical scheduling constraints that are not a realistic threat to
reliability. As the requirements are presently defined the inherent flexibility for battery
maintenance that is nominally done on three month intervals may be as long as 1/3 of the
interval or as short as one day (Our interpretation: Maintenance last done on January 1 is next
due on April 1 and can be done no later than April 30. Maintenance done on Jan 31 is next due
on April 30 and is overdue if done on May 1). The only practical solution is to increase the
frequency so that the average intervals are significantly shorter than the nominal requirement.
BGE recommends an alternate formulation for intervals if the nominal interval is less than one
year. Some possible alternatives (assuming a three month nominal interval): Once per calendar
quarter no later than the end of the quarter no earlier than one month before it. Four times per
year, no more than 120 days apart no less than 60. Comment 1.2: On page 11, Row-3/Columnfile:///C|/Documents%20and%20Settings/bensonm/Desktop/2007-17%20full%20docs%20110112/39_RunAnalysis.htm[11/2/2012 1:48:24 PM]
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1 of Table-1a includes the following entry for functional trip testing: "Control and trip circuits
with electromechanical trip or auxiliary contacts (except for microprocessor relays, UFLS or
UVLS)". It is not clear why electromechanical trip contacts in microprocessor relays are excluded.
Comment 1.3: On page 12, Row-3/Column-3 of Table-1a includes the following Verification Task
for Station DC Supplies: "Verify Battery cell-to-cell connection resistance". Multiple cell units do
not provide the ability to measure cell-cell resistance.
No
See comments under 7 regarding the ambiguity of R1.1. A high VRF for some interpretations of
R1.1 may not be reasonable. A program may be structured so that sufficient maintenance to
ensure reliability is taking place even though a specific component is not identified. Contrasting
the high VRF for R1 with the medium VRF for R4 seems backwards.
Yes
No
The VSL’s as proposed may be reasonable but it is difficult to endorse them until the ambiguity
in R1.1 is reduced.
Yes
No
The FAQ is a very helpful document. A few more changes would be beneficial. See comments
regarding manufactures’ advisories and R1.1 under section 7 below. It is our recommendation
that manufacturers service advisories not be an implied part of the PMSP requirements and that
the expectations for R1.1 be more explicitly described in the FAQ.
Comment 7.1 The standard, FAQs, and supplementary reference all make references to upkeep
and include in “upkeep” changes associated with manufacturer’s service advisories. The FAQs
include statements that the entity should assure the relay continues to function after
implementation of firmware changes. This statement is uncontestable as general principle but is
problematic in its inclusion in an enforceable standard because there is no elaboration on what
the standard expects, if anything, as demonstration of an entity’s execution of this responsibility.
PRC-005-2 appropriately focuses on implementation of time-based, condition based, or
performance based PSMPs; but addressing service advisories does not fit well with any of these
ongoing preventive maintenance activities. It is instead episodic, more like commissioning after
upgrades, or corrective maintenance work generated by condition-based alarms or anomalies
discovered by analyzing operations. The standard appropriately steers clear of imposing
requirements for these latter responsibilities as long as execution of an ongoing maintenance
program is being demonstrated. BGE recommends that implied inclusion of service advisories
should be removed from the standard and supporting documents. Comment 7.2 R1.1 Requires
the identification of all protection systems components. But it provides no elaboration on the
level of granularity expected or acceptable means of identification. It is unlikely that the SDT
expected the unique identification of every discrete component down to individual test switches
or dc fuses. In the case of current transformers, several of which, or even dozens of which may
be connected to a single relay there is no apparent reliability benefit that comes from
indentifying them uniquely so long as it is proven that a protection system is receiving accurate
current signals from the aggregate connection. (It may be argued that the revised definition of
“protection systems” eliminates the need to include CT’s under R1.1 but that’s just one
interpretation.) Some discrete components of communication systems may exist in an
environment that is not owned by or known to the protection system owner. Additionally all
protection system components may be indentified in documents that are current and maintained
but not in the form of a specific searchable list that is limited to components that are within the
scope of PRC-005. Examples may be indexed engineering drawings that indentify relays and
other components for each protection systems or scanned relay setting and calibration
documents that are current but not attached to searchable metadata. It is unclear whether or not
these would be considered acceptable identification meeting R1.1. If they are not then the
implementation plan for R1 is in all probability unachievable. BGE requests that the SDT provide
more elaboration on R1.1 in the standard and in the supporting documents. Comment 7.3 For
clarity footnote 1 to R1 which excludes devices that sense non-electrical signals should explicitly
say that the auxiliary relays, lockout relays and other control circuitry components associated
with such devices are included. The matter is well-addressed in the FAQ’s but could easily be
misunderstood if not included here.
Individual
Michael R. Lombardi
Northeast Utilities
No
In Table 1c it is required to report the detected maintenance correctable issues within 1 hour or
less to a location where action can be taken to initiate resolution of that issue. Even for a fully
monitored protection system component it can be difficult to report the action in 1 hour.
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Recommend a 24 hour period for both Level 2 and Level 3 reporting of maintenance correctable
issues. Additionally, please clarify meaning of “to a location where action can be taken”.
Yes
No
Two most recent performances of each distinct maintenance activity for the Protection System
components will require data retention for an extended period of time. From the FAQ, it is
understood that “the intent is not to have three test result providing two time intervals, but
rather have two test results proving the last interval”. However two intervals still results in an
extended period of time. For example, for a twelve year interval, data would need to be retained
for ~24 years. During that period of time a number of on-site audits would have been completed
- it is not clear why the requirement is the longer of the two most recent performances or to the
previous on site audit date.
No
For R1 under Severe VSL – suggest moving the first criteria “The entity’s PSMP failed to address
one or more of the type of components included in the definition of “Protection System” under
High VSL since this criteria cannot have the same VSL level as “Entity has not established a
PSMP”.
No
There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an entity can
count components however; an example in the reference document will provide clarity.
No
Page 2 under Component definition, term “somewhat arbitrary” is used by the drafting team to
address what constitutes a dc control circuit. Though the drafting team has provided entities with
flexibility to define as per their methodologies, it is recommended to clearly determine “what
constitutes a dc control circuit” since it will be used to determine compliance.
R1.1 It is not clear what would constitute “all Protection System components”. Suggest the
addition of a definition for “Protection System components”. R1.4 Suggest revise to read: “all
batteries or dc sources” Table 1a vented lead acid -- “Verify that the station battery can perform
as designed by evaluating …” -- Please define evaluating, including: • What is the basis for the
evaluation? • Is 5% 10% 20% etc acceptable? • Where does baseline come from for older
batteries? Request clarification of 2.3 Applicability of New Protection System Maintenance
Standards from Supplementary Reference. Specifically, please clarify if a functional trip test is
needed to be performed on the distribution circuit breakers to protect the Bulk Electric System
(BES) if these low side breakers are not part of the transmission path. (A diagram identifying the
applicable breakers would be helpful in the Supplementary Reference)
Individual
Jeff Kukla
Black Hills Power
No
-For Protective Relays, Table 1a Maintenance Activities has no requirement for verifying output
contacts on non-microprocessor based relays. The actual contacts used for tripping should be
verified by this activity. -For Protective Relays, Table 1b Maintenance Activities states “Verify
correct operation of output actions that are used for tripping”. This requirement is vague and
needs to define whether all protection logic or conditions that would initiate a relay trip output
are required to be simulated and tested to the relay tripping output contact. -For Voltage and
Current Sensing Inputs to Protective Relays and associated circuitry, Table 1a references
“current and voltage signals” and Table 1b references “current and voltage circuit signals”. Need
consistency or definitions to meet this requirement. -For Control and trip circuits with
electromechanical trip or auxiliary (UFLS/UVLS Systems Only), Table 1a states “..except that
verification does not require actual tripping of circuit breakers or interrupting devices.” This
exception to the requirement seems to defeat the whole purpose of the standard and leaves a
huge gap open to interpretation and conflict. -For Control and trip circuits with unmonitored
solid-state trip or auxiliary contacts (UFLS/UVLS Systems Only), Table 1a states “..except that
verification does not require actual tripping of circuit breakers or interrupting devices.” This
exception to the requirement seems to defeat the whole purpose of the standard and leaves a
huge gap open to interpretation and conflict. -For Station dc supply, Table 1a requirement
includes “Inspect: The condition of non-battery-based dc supply.” This is redundant with the
requirements of the section Station dc supply (battery is not used) and should be removed from
this section. -For Voltage and Current Sensing Inputs to Protective Relays and associated
circuitry, a maximum interval of verification of 12 years seems to contradict the intent of the
rest of the Maintenance standard which dictates 6 years on all of the other components. The
requirement for these components should fall in line with the rest of the standard.
No
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-Why would R1 (PSMP Program Establishment) be a HIGH VRF and R4 (the actual
implementation of the plan) be a medium VRF? These two requirements need to have the same
implementation and severity.
Yes
No
-VSL's are based on percentages of components, where the definition of a 'component' is in many
cases up to the entity to interpret (see PRC-005-2 FAQ sheet, Page 2). Basing VSL's on an
entities interpretation (or count) of 'components' is not an equitable measure of severity level.
Yes
Yes
Individual
John Bee
Exelon
No
Exelon does not completely agree with the minimum maintenance activities and maximum
allowable intervals as suggested by SDT. Comments on minimum maintenance activities:
Reference Table 1a (Page 11) of Standard PRC-005-2: With regard to the maintenance activity:
"Verify that the station battery can perform as designed by conducting a performance ……". The
standard should clearly define what is meant by "perform as designed" to eliminate ambiguity in
future interpretations. Also, Table 1a Station dc supply (that has as a component Vented
Regulated Lead-Acid batteries) discusses “modified performance capacity test of the entire
battery bank”. This needs additional clarification or should be reworded because modified test
includes both the performance test (which is the capacity test) and the service test. Should be
reworded to be “modified performance test”. Comments on maximum allowable intervals:
Nuclear generating stations have refueling outage schedule windows of approximately 18 months
or 24 months (based on reactor type). If for some reason the schedule window shifts by even a
few days, an issue of potential non-compliance could occur for scheduled outage-required tasks.
The possibility exists that a nuclear generator may be faced with a potential forced maintenance
outage in order to maintain compliance with the proposed standard. For the requirements with a
maximum allowable interval that vary from months to years (including 18 Months surveillance
activities), the SDT should consider an allowance for NRC-licensed generating units to default to
existing Operating License Technical Specification Surveillance Requirements if there is a
maintenance interval that would force shutting down a unit prematurely or face non-compliance
with a PRC-005 required interval. Therefore, Tables 1a, 1b & 1c should include an allowance for
any equipment specifically controlled within each licensee’s plant specific Technical Specifications
to implement existing Operating License requirements if such a conflict were to occur. Please see
additional comments under Q7.
Yes
Yes
Yes
Yes
Yes
Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission
(NRC). Each licensee operates in accordance with plant specific Technical Specifications (TS)
issued by the NRC which are part of the stations’ Operating License. TS allow for a 25% grace
period that may be applied to TS Surveillance Requirements. Referencing NRC issued NUREGs for
Standard Issued Technical Specifications (NUREG-143 through NUREG-1434) Section 3.0,
"Surveillance Requirement (SR) Applicability," SR 3.02 states the following: "The specified
Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval
specified in the Frequency, as measured from the previous performance or as measured from the
time a specified condition of the Frequency is met." The NRC Maintenance Rule (10 CFR 50.65)
requires monitoring the effectiveness of maintenance to ensure reliable operation of equipment
within the scope of the Rule. Adjustments are made to the PM (preventative maintenance)
program based on equipment performance. The Maintenance Rule program should provide an
acceptable level of reliability and availability for equipment within its scope. The NRC has
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provided grace periods for certain maintenance and surveillance activities. Exelon strongly
believes that SDT should consider providing this grace period to be in agreement and be
consistent with the NRC methodology. Not providing this grace period will directly affect the
existing nuclear station practices (i.e., how stations schedule and perform the maintenance
activities) and may lead to confusion as implementing dual requirements is not the normal
station process. Nuclear generating stations have refueling outage schedule windows of
approximately 18 months or 24 months (based on reactor type). If for some reason the schedule
window shifts by even a few days, an issue of potential non-compliance could occur for
scheduled outage-required tasks. The possibility exists that a nuclear generator may be faced
with a potential forced maintenance outage in order to maintain compliance with the proposed
standard. For the requirements with a maximum allowable interval that vary from months to
years (including 18 Months surveillance activities), the SDT should consider an allowance for
NRC-licensed generating units to default to existing Operating License Technical Specification
Surveillance Requirements if there is a maintenance interval that would force shutting down a
unit prematurely or face non-compliance with a PRC-005 required interval. Therefore, at a
minimum, maintenance intervals should include an allowance for any equipment specifically
controlled within each licensee’s plant specific Technical Specifications to implement existing
Operating License requirements if such a conflict were to occur. PECO would like to have the
implementation plan provide at least 1 year for full implementation of the new standard. This will
provide adequate time for development of documentation, training for all personnel, and testing
then implementation of the new process (es).
Individual
Andrew Z.Pusztai
American Transmission Company
No
ATC feels additional changes are needed. The functional testing requirement should be altered or
removed as it increases the amount of hands-on involvement and the opportunity for human
error related outages to occur, thereby introducing more opportunities to decrease system
reliability. As noted on p. 8 in the supplementary reference document, “Experience has shown
that keeping human hands away from equipment known to be working correctly enhances
reliability.” By removing circuits from service on the proposed timelines for functional testing, the
chance for human error is greater than a mis-operation from faulty wiring. Alternatively, entities
may choose to schedule more planned outages to conduct their functional testing in order to
limit the risk of unplanned outages resulting from human error. Under this scenario, more
elements will be scheduled out of service on a regular basis, thereby reducing transmission
system availability and weakening the system making it more challenging to withstand each
subsequent contingency (N-1). Thus testing an in-tact system is more desirable than taking it
out of service for testing. While the SDT has included language in the draft standard to use fault
analysis to complete maintenance obligations, in practicality, this option does not offer any relief
to taking outages to perform functional tests. Nearly all BES circuit breakers are equipped with
dual trip coils. Identifying which trip coil operated for a fault only covers the one trip coil.
Functional tests would still be needed on the other. The likelihood of having multiple trips on a
given line in the course of several years is very low. Given it can take a year to schedule some
outages, planning maintenance with random faults is unpractical and will create unacceptable
risk to compliance violations. A better approach is to use the basis in schedule A, but extend this
to cover the entire protection schemes. The document should establish target goals for misoperation rates (dependability and security). This would allow the utilities to develop cost
effective programs to increase reliability. The utilities would have incentives to replace poorly
performing communications systems; they would be able to quantify the value of upgrading relay
systems.
No
ATC disagrees with the VRFs as specified in the standard. R1 VRF would more likely be classified
as “medium” and R2 through R4 should be classified as a “High” VRF. ATC is O.K. with the Time
Horizons specified.
No
The NERC standard assigns a retention period for the two most recent performances of
maintenance activity which implies two intervals of documentation be maintained. ATC does not
agree that requiring all data for two full cycles is warranted. The volume and length of data
retention is unreasonable. ATC recommends that the entity retain the last test date with the
associated data, plus the prior cycle test date only without retaining the test data. ATC agrees
with assignment of the measures.
Yes
Yes
No
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The FAQs are helpful, however, with the revised standard as written, ATC has issues with the
answers provided. Please refer to Question #7 for areas of concern.
It is appreciated that the SDT is attempting to provide options for maintenance and testing
programs. Practically speaking, it will be difficult to perform any type of program outside of
Time-Based Maintenance (TBM). Too many circuits are a mix of technology. For example, a line
may have microprocessor relays for detecting and tripping line faults, but the bus differential
lockout could also trip the line breaker. One may be partially monitored and the other
unmonitored. It will force the utility to perform maintenance at the shorter of the maintenance
cycles. Additional time and cost will be required to organize and switch out the applicable
equipment for the outage, approximately doubling the cost associated with performing these trip
tests. When entities are required to maintain tens of thousands of these devices, the simplest
approach will be to revert to TBM. ATC does not support the existing 2nd Draft of PRC-005-2
Standard because it is our opinion that: • There is a high probability that system reliability will
be reduced with this revised standard. • The number of unplanned outages due to human error
will increase considerably. • Availability of the BES will be reduced due to an increased need to
schedule planned outages for test purposes (to avoid unplanned outages due to human error). •
To implement this standard, an entity will need to hire additional skilled resources that are not
readily available. (May require adjustments to the implementation timeline.) • The cost of
implementing the revised standard will approximately double our existing cost to perform this
work. ATC requests that relevant reliability performance data (based on actual data and/or
lessons learned from past operating incidents, Criteria for Approving Reliability Standards per
FERC Order 672) be provided to justify the additional cost and reliability risks associated with
functional testing. Under a Performance-Based Program, what happens if the population of
components drops below 60 (as all will eventually)? Is there an implementation period to default
to TBM? Are the internal relays and timers associated with a circuit breaker included as part of
the protection scheme? In the Independent Pole Operation breakers (IPO), there are various
internal schemes built to protect for pole discordance (one pole open, two closed, event
measured over time frame (milliseconds)), these schemes may re-trip the breaker, initiate
breaker failure protection or trip a bus lock out relay. In DC control schemes fuses and panel
circuit breakers protect for wiring faults. Do these devices need to be tested? Is there an
obligation to test the distribution circuit breakers for correct operation points? Is there an
obligation to replace fuses after a defined time period?
Individual
Thad Ness
American Electric Power
No
In Table 1a for the component “Station dc Supply (used only for UVLS and UFLS)”, the interval
prescribed is "(when the associated UVLS or UFLS system is maintained)" and the activity is to
"verify the proper voltage of the dc supply". The description of the interval "(when the associated
UVLS or UFLS system is maintained)" needs to be changed. Relay personnel do not generally
take battery readings. The interval should read “according to the maximum maintenance interval
in table 1a for the various types of UFLS or UVLS relays". The testing does not need to be in
conjunction with the relay testing, it is only the test interval that is important, although relay
operation during relay testing is a good indicator of sufficient voltage of the battery. The
monitoring and/or maintenance activities listed for batteries are not appropriate in Tables 1b and
1c. There are no commercial battery monitors that monitor and alarm for electrolyte level of all
cells. Why not move the electrolyte level to the 18 month inspection and actually open the
possibility of condition monitoring to commercially available devices? Or give an option to do the
electrolyte check at other time intervals (perhaps 12 months) by visual electrolyte inspection and
still allow the monitoring of other functions on the listed 6 year schedule using condition
monitoring. It makes no sense to prescribe an unattainable condition monitoring solution. The
way that the tables are written, there is no advantage to use the charger alarms since battery
maintenance requirements are not reduced in any way.
Yes
No
The measure includes the entire definition of "Protection System". Remove the definition from
the measure and let the definition stand alone in the NERC glossary. 1.3 Data Retention This
calls for past 2 distinct maintenance records to be kept. Since UFLS interval can be 12 years, this
would mean that we would need to keep records for 24 years. This is not realistic and
consideration should be given to choosing a reasonable retention threshold.
Yes
Yes
Yes
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The "Supplementary Reference" and the "Frequently-Asked Questions" document should be
combined into a single document. This document needs to be issued as a controlled NERC
approved document. AEP suggests that the document be appended to the standard so it is clear
that following directions provided by NERC via the document are acceptable, and to avoid an
entity being penalized during an audit if the auditor disagrees with the document’s contents.
NiCAD batteries should not be treated differently from Lead-Acid batteries. NiCAD battery
condition can be detected by trending cell voltage values. Ohmic testing will also trend battery
conditions and locate failed cells (although will usually lag behind cell voltages). A required load
test is detrimental to the NiCAD manufacturer's business, and will definitely hurt the NiCAD
business for T&D applications. Historically NiCADs may have been put into service because of
greater reliability, smaller space constraints, and wider temperature operation range. “Individual
cell state of charge” is a bad term because it implies specific gravity testing. Specific gravity
cannot be measured automatically (without voiding battery warranty or using an experimental
system), and when it is measured, it is unreliable due to stratification of the electrolyte and
differing depths of electrolyte taken for samples. “Battery state of charge” can be verified by
measuring float current. Once the charging cycle is over the battery current drops dramatically,
and the battery is on float, signaling that the battery has returned to full state of charge. This is
an appropriate measure for Level 3 monitoring as float current monitoring is a commercially
viable option and electrolyte level monitoring is not. In Table 2b, why is Ohmic testing required if
the battery terminal resistance is monitored? Cell to cell and battery terminal resistance should
not be monitored because they will be taken in 18 month intervals. This further supports the
argument that the battery charger alarms would be sufficient for level 2 monitoring, while
keeping an 18 month requirement for Ohmic testing, electrolyte level verification, and battery
continuity (state of charge). Automatic monitoring of the float current should be sufficient for
level 3 monitoring as it gives state of charge of the string, and battery continuity (detect open
cells). Shorted cells will still be found during the Ohmic testing and a greater interval is sufficient
to locate these problems.
Individual
Barb Kedrowski
We Energies
No
Table 1a, Protective Relays: Change 1st line to: “Test and calibrate if necessary the relays…”
Table 1a, Protective Relays: 3rd line: Change “check the relay inputs…” to “verify the relay
inputs…”. The term “check” is not defined, whereas “verify” is. Tables 1a & 1b We agree that six
/ twelve years is an acceptable interval for relay maintenance. Table 1a & 1b, Control & Trip
Circuits: The proposed addition to require tripping circuit breakers during Protection System
maintenance is detrimental to BES reliability and should be removed. Generating unit
protection system maintenance is done during scheduled outages. The high voltage breaker on a
generating unit often remains energized to backfeed and supply station auxiliaries when the
generator is offline. The proposed requirement will increase the amount of equipment requiring
an outage for maintenance, and possibly the length of the outage, resulting in significantly more
equipment out of service as well as increased costs. This requirement also results in greater
maintenance efforts and costs when there are redundant protection system equipment (breaker
trip coils, lockout relays, etc), which is contrary to good practice and reliability. Many of the
breakers that We Energies, as the Distribution Provider, trips from its BES protection systems are
not owned by We Energies and are owned by a separate transmission company. The trip testing
and maintenance of the transmission company may not coincide with our relay maintenance
testing program. The standard shall have allowances for the entity to ONLY test or maintain
equipment that it OWNS! Table 1a, Station dc supply: The activity to verify the state of charge
of battery cells is too vague, and requires more specific action. We assume that the drafting
committee is recommending specific gravity measurements. Specific gravity measurements have
not been shown to an accurate indicator on state of charge. In addition, as shown in the nuclear
power industry, there is no established corrective action that is taken based on specific gravity
results (eg. Don’t require a test where there is no acceptable corrective action). The activities
to “verify battery continuity” and “check station dc supply voltage” are also vague and need to
be more clearly specified what is intended. The 3 month time interval for battery impedance
testing is too frequent. 18 month or annual testing is more appropriate. The 3 calendar year
performance or service test is too frequent and will actually remove life from a battery and
reduce reliability. Recommend capacity testing no more that every 5 years and more frequent
test if the capacity is within 10% of the end of life or design. This is consistent with the nuclear
power industry. Table 1b, Station dc supply: Recommend a change or addition to Table 1b Recommend a level 2 monitoring (not just a default to the level 1 maintenance activities) which
allows for the removal of quarterly “check” of electrolyte levels, DC supply voltage, and DC
grounds - if station DC supply (charger) voltage is continuously monitored (eg. one should not
have detrimental gassing of a battery if the float voltage of the battery is properly set and
monitored). Table 1a, Associated communications systems: The requirement to verify
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functionality every three months is excessive; verifying this every twelve months is adequate.
Tables 1a & 1b – Although the latest standard provided some additional clarification, more
clarification is required on what maintenance / testing is ONLY required for UFLS/UVLS protection
systems vs. BES protection systems (eg. UFLS / UVLS systems – Is a verification of proper
voltage of the DC supply the only battery or DC supply required (eg. no state of charge, float
voltage, terminal resistance, electrolyte level, grounds, impedance or performance test, etc.)?
Yes
No
The requirement to retain data for the two most recent maintenance cycles is excessive. The
required data should be limited to the complete data for the most recent cycle, and only the test
date for the previous cycle.
Yes
Yes
Yes
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
No
We support most of the maintenance activities detailed in the Tables, but question the
verification of battery cell-to-cell resistance. On some types of battery units, this internal
connection is inaccessible. We suggest substituting "unit-to-unit" in place of "cell-to-cell".
No
Although we agree that Requirement 1 is important because it establishes a sound PSMP, a
HIGH VRF assignment is not appropriate and it should be changed to LOWER. By definition, a
requirement with a LOWER VRF is administrative in nature, and documentation of a program is
administrative. Assigning a LOWER VRF to R1 is more logical since R4, which is the requirement
to implement the PSMP, is assigned a MEDIUM VRF because, if violated, it could directly affect
the electrical state or the capability of the bulk electric system. Additionally, revising the VRF to
LOWER would provide a consistent assignment to a VRF on a similar requirement in the proposed
FAC-003-2 standard.
Yes
We agree with the Measures but suggest some improvements: 1. In Measures M2 and M3, the
term "should" must be changed to "shall" 2. In Measure M2, the Distribution Provider entity is
missing
Yes
Yes
We support the reference document and appreciate the SDT's hard work developing this
document. We offer the following suggestions for possible improvements: 1. The reference
document should be linked in Section F of the standard. Otherwise it may be difficult for someone
to navigate the NERC website in search of the document. 2. Section 2.2 – It would be helpful if a
short discussion of the reasons for the changes to the definition of Protection System was
included in this reference document. In addition, it would be beneficial to discuss what is
included in "dc supply" components, such as "dc supplies include battery chargers which are
required to be maintained per the Tables in PRC-005-2." 3. Section 8.1 – The fourth bullet which
reads "If your PSMP (plan) requires more then you must document more." Should be removed.
This is already covered in the sixth bullet which states "If your PSMP (plan) requires activities
more often than the Tables maximum then you must document those activities more often."
Yes
We support the FAQ document and appreciate the SDT's hard work developing this document.
The reference document should be linked in Section F of the standard. Otherwise it may be
difficult for someone to navigate the NERC website in search of the document.
Implementation Plan a. We do not support the 3 month implementation timeframe for
Requirement 1. For many entities, it will take some time to develop a sound PSMP that meets
the new PRC-005-2 standard. We suggest a 12 month implementation which we believe is more
logical and in alignment with the implementation timeframe for Protection System Components
with maximum allowable intervals of less than 1 year, as established in Table 1a. b. Although we
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support the implementation timeframes for Requirements R2, R3, and R4, we do not support the
required periodic percentages of protections systems to be completed. There could be numerous
reasons where an entity has to adjust its program schedule which could lead to noncompliance
with these percentage milestones. We suggest simply requiring 100% completion of the
maintenance per the maximum maintenance intervals. Alternatively an entity should have the
flexibility to indicate they have fully transitioned to the new standard during the early stages of
the implementation plan if their existing maintenance practices meet or exceed the standards
minimum expectations. Doing so should negate the need to produce the "% complete"
implementation status.
Individual
Jianmei Chai
Consumers Energy Company
No
1. If multiple redundant Protection System components, with associated parallel tripping paths,
are provided, Table 1a, 1b, and 1c require that each parallel path be maintained, and that the
maintenance be documented. Often, these multiple schemes are provided not to meet specific
reliability-related requirements, but instead to provide operating flexibility. Testing these likely
will require outages, and those outages may result in decreased reliability. Further, the
documentation related to maintenance of all paths will be very cumbersome, and will lead to
increased compliance exposure simply by its volume. This may perversely lead to entities NOT
installing the redundant schemes, resulting in decreased reliability. 2. Many of the activities
described in the Tables are not, by themselves, clear. The standard should include sufficient
detail such that entities are clear as to what must be done for compliance, rather that relying on
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station
DC Supply), what is meant by, “Verify that the dc supply can perform as designed when the ac
power from the grid is not present.” Similarly, it isn’t clear from the general description within
the Tables that components possessing different monitoring attributes within a single scheme,
may be distinguished such that differing relevant tables can be used for the separate
components. 3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that
the station battery can perform as designed by evaluating the measured cell/unit internal ohmic
values to station battery baseline. Battery assemblies supplied by some manufacturers have the
connections made internally, making this option unavailable. Experience with ASME standards
show that NERC and SDT members may be jointly and separately liable for litigation by
specifying methods that either prefer or prohibit use of certain technologies. 4. Two of the four
Maintenance Activities that begin with “Perform a complete functional trip …“ conclude with “…
does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
such activities therefore require tripping of circuit breakers or other interrupting devices? 5.
Performance of the minimum activities specified within Table 1a for legacy systems, particularly
regarding control circuits, will require considerable disconnection and reconnection of portions of
the circuits. Such activities will likely cause far more problems on restoration-to-service than
they will locate and correct. We suggest that the SDT reconsider these activities with regard for
this concern.
Yes
Yes
Yes
Yes
No
1. FAQ II.3A attempts to clarify the requirements of “Verify the proper functioning of the current
and voltage signals necessary for Protection System operation from the voltage and current
sensing devices to the protective relays” suggesting that “simplicity can be achieved” by
verifying that the protective relays are receiving “expected values.” It concludes with a
statement of the need to “ensure that all of the individual components are functioning properly
…” implying that just verifying “expected values” at the protective relay end of the circuit may be
inadequate. 2. FAQ II.4D describes what is required for testing of aux relays to include, “that
their trip output(s) perform as expected”. Does that include timing tests? (Example – high speed
ABB AR relays vs. standard AR relays). 3. The SDT responses to the Draft 1 comments regarding
“grace periods” essentially says, “Absolutely not”. However, FAQ IV.1.D reflects data retention
requirements relative to an entities’ program which includes a grace period!
1. In the Standard, Footnote 2 and Footnote 3 are identical. We presume that some information
has been omitted. 2. We do not agree that Footnotes are an appropriate method of providing
information that is important to the application of the Standard. Important information should be
provided within the standard text.
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Group
Santee Cooper
Terry L. Blackwell
SC Public Service Authority
No comment.
Yes
Yes
We are concerned with the long-term implementation of the data retention requirements for
activities with long maximum intervals. For example, if you are performing an activity that is
required every 12 years, the implementation plan says that you should be 100% compliant in 12
years following regulatory approval. However, assuming that 100% compliant meant that you
got through all of your components once, you still would not be able to show the last two test
dates. 12 years from now, would you still have to discuss the program you were using prior to
12 years ago for those components to have a complete audit, because of having to address the
last 2 test dates?
No
In R1, a “Failure to specify whether a component is being addressed by time-based, conditionbased, or performance-based maintenance” by itself is a documentation issue and not an
equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of
the required components can only be time based.
No Comment.
No comment.
There is some discussion in the documents, such as the definition of component in the
Frequently-Asked Questions, about the idea that an entity has some latitude in determining the
level of “protection system component” that they use to identify protection systems in their
program and documentation. The example given is about DC control circuitry. There are
requirements in this standard that are specific to a component, such as R1.1 – Identify all
protection system components. Historically, if your maintenance and testing program is defined
as (say, for relays) testing all the relays in a station at one time, your program, test dates, etc.
could be identified by the station. There needs to be some addition, possibly to the Frequently
asked questions, to explain what kind of documentation will be required with this new standard.
For example, if your program is to test all the relays at a station every 4 years, and all the
relays are tested at the same time, can your documentation of your schedule (the “date last
tested” and previous date) be listed by station (accepting that you should have the backup data
to show the testing was thorough) or must you be able to provide a list by each relay. Without
some clarification, it seems like this could get confusing at an audit with many of the
requirements pertaining to “each component.”
Individual
Art Buanno
ReliabilityFirst Corp.
Yes
The SDT has made significant and worthwhile changes to these tables. However, these tables
still seem overly complex and should be simplified. One possibility would be to eliminate Table 1c
and use Table 1b for those components that meet certain monitoring attributes. There are some
errors in Table 1a in rows 5 and 6. In row 5 in the component column the word “contact” is
missing. In the same row in the third column, there is an extra period. In row 6 in the third
column, “circuit” should be “circuits” as in the other rows. The maintenance intervals seem to
give preference to solid-state outputs but there is no evidence given that these are truly more
reliable than an electromechanical trip at least not sufficient to double the maintenance interval.
No
R4 is the implementation of a maintenance program which is extremely important. Effective
operation of the BES is so dependent on adequate maintenance that requirement R4 warrants a
High VRF. It seems that requirement R3 may actually be better categorized as having an
Operations Assessment Time Horizon as the entity needs to review events to analyze the
adequacy of maintenance periods.
Yes
Yes
Yes
Yes
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The SDT should be congratulated on its hard work in making substantial improvements to an
existing standard. In revising the draft standard, the SDT should consider the difficulty an entity
will have in providing the evidence required to show compliance. R1 unnecessarily limits PSMPs
to “Protection Systems that use measurements of voltage, current, frequency and or phase angle
to determine anomalies.” However, if an entity applies devices that protect equipment based on
other non-electrical quantities or principles such as temperature or changes in pressure, the
entity is not required to maintain them. These types of devices have long been considered by
many organizations as important forms of protection and therefore in some instances are
connected to trip. There are also many organizations that consider these types of devices too
unreliable to use as protection and therefore only connect them for monitoring (and not to trip).
If protection based on non-electrical quantities is not properly maintained, it will Misoperate and
will negatively impact reliability. The standard cannot simply ignore a type of protection that can
ultimately affect the reliability of the BES.
Group
PacifiCorp
Sandra Shaffer
PacifiCorp
Yes
Yes
Agree with the exception that the time horizon for implementation needs to recognize that
documentation for maintenance tasks performed prior to this standard may not match current
requirements and there should be no penalty for this.
No
Data retention requirements need to be modified. The need to maintain records of two previous
tasks is excessive, one should be adequate. Per the two previous task requirements an entity
may need to maintain records for 35 years.
Yes
Yes
Yes
R1.1: Please clarify what the requirements for “identify” means. Does each component need to
be “identified” in our maintenance system, or at least referenced in the maintenance program or
labeled in the field??? R4.3: Please provide guidance on what will be required to prove
compliance that “maintenance correctable issues” have been identified and corrective actions
initiated. What is the implication of finding maintenance correctable issues as it relates to other
requirements for no single points of failure? In other words, if during maintenance a relay is
found to have failed, is there an acceptable time period under which we may operate the system
without redundancy until a repair can be made? Similarly, if part of a redundant relay system is
taken out of service for maintenance, may the facility it was protecting be left in service? If not,
then is the implication that protection systems must be triple redundant in order to do relay
maintenance on in service equipment? Otherwise facilities would always have to be removed
from service to do relay maintenance. Section D / 1.3: The data retention requirement for the
two most recent performances of each maintenance activity is excessive. The requirement should
be limited to the most recent or all activities since the last on-site audit. At the worse case an
entity would have to retain records for up to 35 years for maintenance performed on a 12 year
cycle. Table 1a “Protective Relay” entry: The last maintenance activity is listed as “for
microprocessor relays verify acceptable measurement of power system input values ” for which a
6 year interval is provided”. How is this different than the next item “Voltage and Current
Sensing Inputs to Protective Relays and associated circuitry” which is on a 12 year interval??
Please clarify this. Implementation Plan: This revised standard will drive significant revisions in
existing maintenance programs. 3 months is not adequate time after approval to ensure
compliance with R1. A minimum of 6 months should be utilized after regulatory approval. The
Implementation plan requirements should also recognize that if the requirement to maintain
records of the two previous maintenance tasks is implemented, it may not be possible to produce
this information upon implementation. The implementation plan should be structured that the
requirement to produce previous maintenance records should be phased in as the maintenance is
performed. (ie. The requirement to produce two previous records for maintenance performed on
a two year cycle should not be enforced until four years after implementation).
Individual
Tyge Legier
San Diego Gas & Electric
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No
Proofing of CT circuits is not always trivial. Given this function is not presently being performed
and documented by the company, a reasonable grace period would be required to achieve
compliance. The company believes present practice, such as verification that relay current inputs
are not zero and that phases are balanced, is a reasonable indication individual CTs are
functioning properly. An entities protection system maintenance program is a Time Based
Maintenance program. The protection system maintenance program describes the maintenance
intervals and states that the protection system maintenance is triggered every 4 years. The
maintenance program describes that the due date for compliance is 6 months past the trigger
date to allow for planning and scheduling of the maintenance activity. Therefore the actual due
date for the 4 year maintenance interval is 4 years and six months from the last maintenance
completion date. The four year six month time based interval is within the six year maximum
time based interval as required by PRC-005-2. Given the above, is the four year six month
interval as described in the entities maintenance program compliant with PRC-005-2?
No
No
No
No
No
Group
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency
No
Will the Standard Introduce Technical Feasibility Exceptions to PRC Standards? A large proportion
of the batteries (as high as 50% as reported by some SMEs) are not able to accommodate all of
the tests prescribed in the draft standard. The phrase “Verify Battery cell-to-cell connection
resistance” has entered the table where it did not exist before. On some types of stationary
battery units, this internal connection is inaccessible. On other types the connections are
accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell
connections within units will be detected by the other required tests. This requirement will cause
entities to scrap perfectly good batteries just so this test can be performed, with no
corresponding increase in bulk electric system reliability while taking an unnecessary risk to
personnel and the environment. And because buying battery units composed of multiple cells
allows space saving designs, entities may be forced to buy smaller capacity batteries to fit
existing spaces. This may end up having a negative effect on reliability. Suggest substituting
“unit-to-unit” wherever “cell-to-cell” is used in the table now. The Standard Reaches Beyond the
Statutory Scope of the Reliability Standards As written, the standard requires testing of
batteries, DC control circuits, etc., of distribution level protection components associated with
UFLS and UVLS. UFLS and UVLS are different than protection systems used to clear a fault from
the BES. An uncleared fault on the BES can have an Adverse Reliability Impact and hence; the
focus on making sure the fault is cleared is important and appropriate. However, a UFLs or UVLS
event happens after the fault is cleared and is an inexact science of trying to automatically
restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable levels. If a
few UFLS or UVLS relays fail to operate out of potentially thousands of relays with the same
function, there is no significant impact to the function of UFLS or UVLS. Hence, there is no
corresponding need to focus on every little aspect of the UFLS or UVLS systems. Therefore, the
only component of UFLS or UVLS that ought to be focused on in the new PRF-005 standard is the
UFLS or UVLS relay itself and not distribution class equipment such as batteries, DC control
circuitry, etc., and these latter ought to be removed from the standard. In addition, most
distribution circuit are radial without substation arrangements that would allow functional testing
without putting customers out of service while the testing was underway, or at least without
momentary outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES reliability.
No
R1, R2 and R3 are administrative in nature and ought to be a Low VRF, not a High or Medium
VRF. R4 is doing the actual maintenance and testing and ought to be the highest VRF in the
standard. Medium VRF is appropriate for R4.
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Yes
M1 could be shortened to just a program in accordance with R1, rather than repeat the entire
requirement
No
For the VSLs of R1 and R2, we do not understand where the 5%, 10% come from. There are
only a few types of components, relays, batteries, current transformers and voltage
transformers, DC control circuitry, communication, that’s 6 component types by our count, so,
missing 1 component type in discussing the type of maintenance program is already a 17% error
and Low, Medium and High VSLs are meaningless as currently drafted and every violation would
be Severe, was the intention to apply this is a different fashion? Perfection is Not A Realistic Goal
R4 allows no mistakes. Even the famous six sigma quality management program allows for
defects and failures (i.e., six sigma is six standard deviations, which means that statistically,
there are events that fall outside of six standard deviations). PRC-005 has been drafted such
that any failure is a violation, e.g., 1 day late on a single relay test of tens of thousands of relays
is a violation. That is not in alignment with worldwide accepted quality management practices
(and also makes audits very painful because statistical, random sampling should be the mode of
audit, not 100% review as is currently being done in many instances). FMPA suggests considering
statistically based performance metrics as opposed to an unrealistic performance target that
does not allow for any failure ever. Due to the shear volume of relays, with 100% performance
required, if the standards remain this way, PRC-005 will likely be in the top ten most violated
standards for the forever. In other words, 1-2% of components outside of the program should be
allowed without a violation and Low VSL should start at a non-zero number, such as “Entity
failed to complete scheduled program for 3-6% of components based on a statistically significant
random sampling” or something to that affect. There is a fundamental flaw in thinking about
reliability of the BES. We are really not trying to eliminate the risk of a widespread blackout, we
are trying to reduce the risk of a widespread blackout. We plan and operate the system to single
and credible double contingencies and to finite operating and planning reserves. To eliminate the
risk, we would need to plan and operate to an infinite number of contingencies, and have an
infinite reserve margin, which is infeasible. Therefore, by definition, there is a finite risk of a
widespread blackout that we are trying to reduce, not eliminate, and, by definition, by planning
and operating to single and credible double contingencies and finite operating and planning
reserves, we are actually defining the level of risk from a statistical basis we are willing to take.
With that in mind, it does not make sense to require 100% compliance to avoid a smaller risk
(relays) when we are planning to a specified level of risk with more major risk factors (single and
credible double contingencies and finite planning and operating reserves).
Individual
Greg Rowland
Duke Energy
No
General comment – the draft changes the word “verify” to “check” in several places; should use
consistent phrasing throughout the standard. With regards to Table 1a, we have the following
comments: • Control and trip circuits with electromechanical trip or auxiliary contacts (except for
microprocessor relays. UVLS or UFLS) – We believe that while there may be value in a 6 calendar
year cycle, this will be difficult to accomplish, since you either have to get outages scheduled or
block protection, which risks reliability. Since this is essentially a re-commissioning check, the
cycle should be 12 calendar years. Also 6 years appears to be in conflict with the system
protection standard. • Control and trip circuits with unmonitored solid-state trip or auxiliary
contacts (except for UVLS or UFLS) – agree with 12 calendar years as consistent with
electromechanical above. • Control and trip circuits with electromechanical trip or auxiliary (UVLS
or UFLS Systems Only) – 6 year cycle should be changed to 12 calendar years (see comment
above on non-UVLS/UFLS). • Control and trip circuits with unmonitored solid-state trip or
auxiliary contacts (UVLS or UFLS Systems Only) – agree with change to 12 calendar years. •
Station dc Supply (used only for UVLS or UFLS) – Strike the word “Station”. We don’t
differentiate between dc supply used for UFLS and other protection. • Station dc supply –
Change 18 calendar months to 24 months, since this testing requires generator outages. Nuclear
plant fuel cycles can be longer than 18 months. • Associated communications systems – More
clarity is needed regarding what is to be included in the definition of “Associated”.
Yes
No
M4 states that entities shall have evidence such as maintenance records or maintenance
summaries (including dates that the components were maintained). We would like to see M4
revised/expanded to explicitly include the FAQ Section IV 1.B information which states that forms
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of evidence that are acceptable include, but are not limited to: • Process documents or plans •
Data (such as relay settings sheets, photos, SCADA, and test records) • Database screen shots
that demonstrate compliance information • Diagrams, engineering prints, schematics,
maintenance and testing records, etc. • Logs (operator, substation, and other types of log) •
Inspection forms • U.S. or Canadian mail, memos, or email proving the required information was
exchanged, coordinated, submitted or received • Database lists and records • Check-off forms
(paper or electronic) • Any record that demonstrates that the maintenance activity was known
and accounted for.
No
The VSLs for PRC-005-2 requirements R1, R2 and R4 have significantly tighter percentages than
the corresponding requirements in PRC-005-1. We believe that the Lower VSL should be up to
10%, the Moderate VSL should be 10%-15%, the High VSL should be 15% to 20%, and the
Severe VSL should be greater than 20%, which is still a lower percentage than the 25% Lower
VSL currently in PRC-005-1.
Yes
Yes
Group
The Detroit Edison Company
Daniel Herring
NERC Compliance
No
Suggest that the interval for cell ohmic testing on VRLA batteries be changed to 12 months. Also,
include ohmic testing of NiCad batteries at 18 mos as an option.
No
No
No
Yes
Yes
Suggest that the implementation plan for R1 (PSMP) be changed to 12 months. The statement in
R1.1, “Identify all Protection System components” regarding the PSMP should be clarified. Is a
complete list of every “component” of each specific protection system required to be included in
the PSMP?
Group
Hydro One Networks
Sasa Maljukan
Hydro One Networks, Inc.
No
Table 1a: o V and I sensing to relays – 12 years? Why not perform this activity with mtce
activities associated with relay mtce so that they line up? It would only be an incremental
amount of work to perform this with associated relay maintenance work o Removal of
requirement for testing of unmonitored breaker trip coils? Is it really the intention of the SDT to
remove a requirement that would drive the industry to install TC monitors on breakers to
improve reliability? o UFLS/UVLS DC control and trip circuits – Due to the distributed nature of
this program, random failures to trip are not impactive to the overall operation of the UFLS
protection. There should be no requirement to check the DC portion of these protections any
more often than the DC circuit checks associated with that LV breaker. Since it is clear the
requirement does not include the need to trip the breakers why the need to check the trip
paths? Deletion of this requirement leaves the requirement to check only the relays and relay
trip outputs from the protections every 6 years (or as often as the protective relay component
type). o Along the same lines as the above comment should the maintenance activities for “UVLS
and UFLS relays that comprise a protection scheme distributed over the power system” not be
the same as “Protective Relays” Table 1c: o Level 3 attributes for “Associated communications
systems” might better read “Evaluating the performance and quality of the channel as well as the
performance of any interface to connected protective relays and alarming if the
channel/protective relay connections do not meet performance criteria” o We believe that some
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of the proposed maintenance intervals for station DC supply are too stringent and that they
would not produce significant increase in reliability to justify associated incremental expenditure.
For example we suggest that the following changes are considered: - The interval for eelectrolyte
level check for all batteries except VRLAs and internal measured cell/unit Ohmic value for VRLAs
be extended to 6 months instead of current time period of 3 months. - The performance or
service capacity test of the VRLA battery banks to be extended from 3 years to 5 years.
Yes
Yes
Yes
Yes
Yes
o Footnotes 2 and 3 on page 4 are identical. Delete footnote 3. o UFLS systems by design can
suffer random failures to trip. It would make sense for a requirement to exist to perform
maintenance on the UFLS relay as their failure to operate may affect numerous distribution level
feeders. However maintenance on associated DC schemes connected to the devices should only
be done on the same frequency as maintenance on the relevant interrupting devices.
Consideration should be given to exempting schemes that have a maintenance program in place
on those distribution level devices from PRC-005 Standard-specified maintenance intervals. Such
Standard-specified intervals could apply to interrupting devices that have no maintenance
program in place.
Group
PPL Supply
Annette M. Bannon
PPL Generation, LLC
No
PPL Generation, on behalf of the entities listed above, has the following comments on the dc
entries in these tables: 1. Table 1a, Table 1b, Table 1c- Station DC supply - Maintenance
Activities – references substation batteries. For generators, shouldn't that reference be station
battery? Substation implies an association strictly with transmission, not generation. 2. Station
DC supply - verify Battery continuity. What is the technical basis for this requirement? Neither
battery installation and operation instructions nor technical reviews explain the basis for how this
verification is supposed to work. NERC's Protection System Maintenance: A Technical Reference
does not address this requirement. The Frequently-Asked Questions provides some ways that
this verification can be completed. However, one example is tied to the microprocessor battery
chargers. If there is a technical basis for this requirement, it should be provided. 3. Condition
based monitoring on station dc supply - it appears the Table 1b excludes any condition based
monitoring of the batteries because of the requirement for monitoring electrolyte level, individual
cell state of charge, cell to cell and battery terminal resistance. Most monitoring equipment does
not monitor those functions. 4. In general, the Tables are especially confusing in the dc system
area. The “lines” overlap and need to be labeled, so they can be referenced in a maintenance
document to show how the appropriate program can be followed. Each line should be separate in
the function stated, so one can identify what has to be done to comply. 5. Provide examples of
“non-battery-based dc equipment” that is covered under this standard. 6. For dc supply, the
changes from the Sept. 2007 NERC “Protection System Maintenance”, A Technical Reference
seem too restrictive. The Sept. 2007 document contained a solid maintenance program. What is
the basis for the change?
No comment.
No
Measurers M1 – requires having a maintenance program that addresses control circuitry
associated with protective functions from the station dc supply through the trip coil(s) of the
circuit breakers. Some generators do not own this equipment to the circuit breaker or other
interrupting devices. The requirement should be to maintain and test the equipment owned by
the generator. Data Retention 1.3 references on-site audits. Entities registered as GO and GOP
are not audited on-site.
No Comment.
No Comment.
No Comment.
1. For applicability to generators, the responsibility for a maintenance program will usually rest
with the plant operator when the operator and plant owner(s) are different entities. Consider
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changing the applicability as it applies to the generator in such situations. 2. Time-based
frequency should allow for flexibility; i.e. engineering analysis should allow the entity to exceed
the intervals noted in the table. An engineering evaluation that defines a test interval differently
than those intervals prescribed in the table should allow an entity to build a program with
different intervals. 3. A Grace Period should be defined. This allows a tolerance window to allow
for unforeseen occurrences. A grace period would allow for some schedule flexibility and reduce
the number of reports to the regulator for exceeding an interval by a reasonable about. 4. The
implementation plan for this revision should take into account that a generator outage may be
required to implement a new maintenance frequency. The implementation plan should account
for outage time, especially nuclear plants that have extended operating cycles. 5. Table 1b
Protective Relays Level 2 Monitoring Attributes includes input voltage or current waveform
sampling three or more times per power cycle. No further guidance is provided in the reference
documents. If this sampling rate is not provided in the specification by the manufacturer, what
can the entity use to demonstrate that the attribute is satisfied? Please provide additional
guidance. 6. Consider numbering the tables to improve cross-referencing the entries in program
documentation. This will allow entities to reference in program documents exactly which activities
are being implemented in accordance with the standard. 7. Requirement 1.1 states, “Identify all
Protection System components.” This is too broad and must be clarified.
Individual
Claudiu Cadar
GDS Associates
No
- Table 1a. Protective relays oFor microprocessor relays need guidance in how all the
inputs/outputs will be checked and how is determined which one are “essential to proper
functioning of the Protection System” oFor microprocessor relays need guidance in how the
acceptable measurement is physically determined. - Table 1a. Voltage and current sensing inputs
to Protective Relays and associated circuitry oHow verify the proper functioning? By ratio test
comparison? - Table 1a. Control and trip circuits with electromechanical trip or auxiliary contacts
(except for microprocessor relays, UFLS or UVLS) oThis can be dangerous if backup protection or
breaker failure protection schemes not disabled at the time of the functional trip test - Table 1a.
Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS systems only)
oMissing the word “contacts” in the naming of the type of PS component oIf distribution circuit
has no breaker bypass will require a tremendous amount of switching or customer outages. Table1a. Station dc supply (that has as a component Vented Lead-Acid batteries) oWhy is this
18 months when Regulated batteries are required to be verified every 3 months? - Table1a.
UVLS and UFLS relays that comprise a protection scheme distributed over the power system
oNeed to define this type of UVLS and UFLS relays
No
- We do agree with the majority of the assignments that have been made, however the standard
needs specific guidance so to be clearly evidentiated the components as included in the definition
of Protection System. The applicability of the standard does not address the current issues
regarding radial + load serving only situation when Protection System not designed to provide
protection for the BES. - Not sure if the percentages corresponding to the events and activities
are appropriately assigned. What were the criteria on which all these percentages are based
upon? - Requirement R3 Severe VSL note 3 allows smaller segment population than the Lower
VSL. How these segment limits were developed?
- Definition of Terms Used in the Standard. Protection System Maintenance Program oMonitoring.
Concerned about the interpretation of this activity description oUpkeep. Not sure about how this
activity will be enforced - A. Introduction. 4.2. Facilities. oThe applicability does not address the
current issues regarding radial + load serving only situation when Protection System not
designed to provide protection for the BES. Standard should clearly state this exemption. - B.
Requirements. o1.1. The standard does not provide guidance in how to identify the components
of a transmission Protection System (tPS). See prior comment referring to the case of a radial
load serving transmission topology. o1.3. Requirement should read “For each identified Protection
System component from Requirement 1, part 1.1, include all maintenance activities listed in
PSMP and specified in Tables 1a, 1b, or 1c associated with the maintenance method used per
Requirement 1, part 1.2.” o1.4. This requirement should be eliminated since already included in
Table 1a and covered through Requirement 1, part 1.3. o4.3. Footnote 3 shall be eliminated since
duplicates footnote 2 - C. Measures oM1. The added wording in the Protection System definition,
requirements and measures with respect to the inclusion of the “associated circuitry from the
voltage and current sensing devices” and control circuitry “through the trip coil(s) of the circuit
breakers or other interrupting devices” seem right but a bit excessive under current
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circumstances (form of the standard). The standard should clearly specify how the maintenance
program will address the verification, monitoring, etc. of the actual wiring and the trip coils. We
suggest that the wording of the standard to reflect that the maintenance activities on the wiring
will be conducted in a visual fashion without implying activities that require disconnecting the
primary equipment. We recommend to change the Protection System definition to read “up to
the trip coils(s)” instead the word “through” (see comment on the definition as well). We
consider that the gain in reliability by pursuing a thorough maintenance program that require to
take primary equipment out of service (which in many instances will lead to the entire substation
being put out of service) cannot counterweight the sole purpose of the standard and the
economics emerging from this program.
Individual
Kirit Shah
ameren
No
Ameren does agree that draft 2 is a considerable improvement from draft 1 of PRC-005-2;
however the following still need to be addressed. 1) Use “Control circuitry” to be consistent with
the proposed definition. If ‘and trip’ was included so that users would know this is a trip circuit,
then the definition should use ‘Trip circuitry’ instead of ‘Control circuitry’. It is important to use
consistent terminology throughout the definition and the standard. 2) Please add row numbers in
each of Tables 1a, 1b, and 1c, and arrange so that row 1 in each table corresponds, etc. (or
state which rows correspond to each other.) This would help clarify movement from table to
table. The number of sub clauses, nuances, and varied Type of Component descriptors among
rows in the same table as well as from table-to-table can be overwhelming. This would help keep
Regional Entities and System Owners from making errors. 3) Please clarify that the instrument
transformer itself is excluded. The standard indicates that only voltage and current signals need
to be verified. The FAQ seems to cover this, but see our comments on your question 6. 4)
Clarifications need to be made on testing requirements on trip contacts relative to
microprocessor vs. EM relays. Digital relays have electromagnetic output relays. Do they fall into
the electromechanical trip or solid state trip? 5) There appears to be an inconsistency in the use
of “check” vs. “verify” in the tables. Consider modifying the definition of “verification” to “A
means of determining or checking that the component is functioning properly or that the
maintenance correctable issues are identified”, eliminate use of the term “verify proper
functioning” (which seems to be redundant by PRC-005-2 standard definition), and simply use
the term “verify”. 6) Alternately if the term “check” replaced “verify proper functioning” in order
to allow for the completion of a maintenance activity within the required interval and yet account
for an outstanding maintenance correctable issue being present, suggest the other remaining
activities in the tables where the term “verify proper functioning” is used, also be replaced with
“check”. 7) If there is an intentional difference between “verify” and “check”, shouldn’t “check”
be defined if it is to be included as a PSMP activity term? 8) Functional trip testing will require
extensive analysis and could involve an extensive testing evolution to ensure the correct circuit is
tested without unexpected trip of other components, particularly for generator protection systems
and some transmission configurations. The complexity of the system and the test would be
conducive to an error that resulted in excessive tripping, thus affecting the reliability of the BES.
It would seem that the potential for an adverse affect from this test would be greater than the
benefit gained of testing the circuit. In addition, scheduling outages to perform the functional trip
testing in conjunction with other outages required to perform maintenance and other
construction activities will be difficult due to the large number of outage requirements for the
functional testing. This will challenge the BES more often and thus reduce reliability. For these
reasons functional trip testing is too frequent, and should be extended to twelve years. 9) In
battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.” Suggest
substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now. Many batteries are
packaged such that the individual cells are not accessible. 10) IEEE battery maintenance
standards call for quarterly inspections. These are targets, though, not maximums. An entity
wishing to avoid non-compliance for an interval that might extend past three calendar months
due to storms and outages must set a target interval of two months thereby increasing the
number of inspections each year by half again. This is unnecessarily frequent. We suggest
changing the maximum interval for battery inspections to 4 calendar months. For consistency,
we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar
months. 11) Replace “State of charge of the individual battery cells/units” with “Voltage of the
individual battery cells or units”. 12) The maximum maintenance interval for a lead-acid vented
battery is listed at 6 calendar years for performing a capacity test. This type of test has been
proven to reduce battery life and an interval of 10 to 12 years would be better. 13) The level 2
table regarding Protection Station dc supply states that level 1 maintenance activities are to be
used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1.
Which activities shall we use? Same situation for Station DC Supply (battery is not used) where
the 18 month interval is missing. 14) Also, Table 1B, in the second to last row, should be
referring to UFLS rather than SPS.
No
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The VRF for R1 should be Medium because the failure to do so is commensurate with the risks of
the other requirements. For example, failing to establish a PSMP for some portion of the entity’s
components could lead to their maintenance not meeting this standard; this is the same is
establishing the PSMP and then not performing the maintenance per the standard.
No
1) M2 incorrectly excludes Distribution Provider. 2) For those components with numerous cycles
between on-site audits, retaining and providing evidence of the two most recent distinct
maintenance performances and the date of the others should be sufficient. If an entity misses a
required maintenance, that results in a self report. We are subject to spot audits and inquiries at
any time between on-site audits as well. 3) For those components with cycles exceeding on-site
audit interval, retaining and providing evidence of the most recent distinct maintenance
performance and the date of the preceding one should be sufficient. Auditors will have reviewed
the preceding maintenance record. Retaining these additional records consumes resources with
no reliability gain. 4) FAQ II 2B final sentence states that documentation for replaced equipment
must be retained to prove the interval of its maintenance. We oppose this because: the replaced
equipment is gone and has no impact on BES reliability; and such retention clutters the data
base and could cause confusion. For example, it could result in saving lead acid battery load test
data beyond the life of its replacement.
No
1) The Lower VSL for all Requirements should begin above 1% of the components. For example
for R4: “Entity has failed to complete scheduled program on 1% to 5% of total Protection
System components.” PRC-005-2 unrealistically mandates perfection without providing technical
justification. A basic premise of engineering is to allow for reasonable tolerances, even Six Sigma
allows for defects. Requiring perfection may well harm reliability in that valuable resources will
be distracted from other duties. 2) In R1, a “Failure to specify whether a component is being
addressed by time-based, condition-based, or performance-based maintenance” by itself is a
documentation issue and not an equipment maintenance issue. Suggest this warrants only a
lower VSL, especially when one of the required components can only be time based. 3) It is
possible that a component that failed to be individually identified per R1.1 was included by entity
A’s maintenance plan. This documentation issue gets a higher VSL than entity B that identified a
component without maintaining it. We suggest the R1 VSL be change to Low, since we believe
lack of maintenance to be more severe than documentation issues.
No
1) Is this document considered part of the standard? We expect to use it as a reference in
developing our PSMP, during audits, and for self-certification as an authentic source of
information. It is also unclear how this document will be controlled (i.e. Revised and Approved, if
at all). 2) On page 22 please clarify that only applies to high speed ground switches associated
with BES elements. 3) We appreciate the SDT providing this valuable reference.
Yes
1) Is this document considered part of the standard? We expect to use it as a reference in
developing our PSMP, during audits, and for self-certification as an authentic source of
information. It is also unclear how this document will be controlled (i.e. Revised and Approved, if
at all). 2) The FAQ needs to be aligned with the tables. The FAQ also contains a duplicate
decision tree chart for DC Supply. The FAQ contains a note on the Decision tree that reads,
"Note: Physical inspection of the battery is required regardless of level of monitoring used", this
statement should be placed on the table itself, and should include the word quarterly to define
the inspection period. 3) We appreciate the SDT providing this valuable reference.
1) We commend the SDT for developing a generally clear and well documented second draft.
The SDT considered and adopted many industry comments from the first draft. It generally
provides a well reasoned and balanced view of Protection System Maintenance, and good
justification for its maximum intervals. Ameren generally agrees that this second draft will be
beneficial to BES reliability, but several inconsistencies, unclear items, and a couple issues need
to be addressed before we will be able to support it. 2) Facilities Section 4.2.1 “or designed to
provide protection for the BES” needs to be clarified so that it incorporates the latest Project
2009-17 interpretation. The industry has deliberated and reached a conclusion that provides a
meaningful and appropriate border for the transmission Protection System; this needs to be
acknowledged in PRC-005-2 and carried forward. 3) We are concerned over R1.1, where all
components must be identified, without a definition for the word component or the granularity
specified. While the FAQ gives a definition, and allows for entity latitude in determining the
granularity, the FAQ is not part of the standard. Certainly this could confuse an entity or an
auditor and lead to much wasted work and / or violations for unintended or insignificant issues.
We suggest that the FAQ definitions be included within the standard. 4) Implementation of the
PSMP must coincide with the beginning of a calendar year. 5) Generating Plant systemconnected Station Service transformers should not be included as a Facility because they are
serving load. Omit 4.2.5.5 from the standard. There is no difference between a station service
transformer and a transformer serving load on the distribution system. This has no impact on the
BES, which is defined as the system greater than 100 kV. 6) The term “maintenance correctable
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issue” used in Requirement 4 seems to be at odds with the definition given for it. It seems that
an issue that cannot be resolved by repair or calibration during the maintenance activity would
be a maintenance non-correctable issue. Also, in Requirement 4, the term “identification of the
resolution” is ambiguous. Suggested changes for Requirements 4 and 4.1 are: “R4. Each
Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, and
resolve any performance problems as follows: 4.3 Ensure either that the components are within
acceptable parameters at the conclusion of the maintenance activities or initiate actions to
replace the component or restore its performance to within acceptable parameters.”
Individual
Joe Knight
Great River Energy
No
In Table 1a section-Station DC Supply – 18 calendar months, under Maintenance Activities
column, suggest changing under Verify: Battery terminal connection resistance To: Entire battery
bank terminal connection resistance (This could have been interpreted as individual batteries)
And change: Battery cell-to-cell connection resistance To: Battery cell-to-cell connection
resistance, where an external mechanical connection is available. In Table 1a-Station dc supply
(that has a component Valve Regulated Lead-Acid batteries) suggest changing Max Maintenance
Interval=3 Calendar Years or 3 Calendar Months to 4 Calendar Years or 12 Calendar Months. Our
concern is that the insurance companies may push NERC maintenance intervals on all battery
banks not associated with the BES. Table 1a-Station dc supply (that has as a component LeadAcid batteries) Max Maintenance Interval=6 Calendar Years suggest changing to 10 Calendar
Years. Reason: performance tests may degrade the battery. Table 1a-Station dc supply (that has
as a component Nickel-Cadmium batteries) Max Maintenance Interval=6 Calendar Years suggest
changing to 10 Calendar Years. Reason: performance tests may degrade the battery. Table 1b Level 2 Monitoring Attributes for Component in the row labeled (Control and trip circuitry) we
suggest the following change: If a trip circuit comprises multiple paths, at least one of those
paths is monitored. Alarming for loss of continuity or dc supply for trip circuits is reported to a
location where action can be taken. While all tripping circuits are not completely monitored, the
trip coils and the outdoor cable runs are completely monitored. The only portion that would not
be monitored is a portion of inter and intra-panel wiring having no moving parts located in a
control house. Our company has extremely low failure rate of panel wiring and terminal lugging.
I don’t think that there is provision for moving control and trip circuitry to performance based
maintenance? This control circuitry should be maintained less frequent than un-monitored trip
circuits (6 years).
Yes
Yes
Yes
Yes
Yes
Individual
Terry Bowman
Progress Energy Carolinas
No
• The modified definition of “Protection System” (page 2 of the clean version of PRC-005-2) uses
the terminology “control circuitry associated with protective functions” whereas Table 1a rows 36, Table 1b Rows 3 and 5, and Table 1c Row 4 uses the terminology “control and trip circuits.”
This is a conflict. “Control” implies that the standard applies to closing/reclosing circuits as well.
We do not believe that is the intent. • Row 7 of Table 1a (page 10 of the clean version of PRC005-2) indicates that proper voltage of the station dc supply must be verified when the
associated UVLS or UFLS maintenance is performed. It is not clear whether this requirement is
over and above the quarterly and 18-month battery maintenance listed elsewhere in the table or
is it the only battery maintenance required for UVLS and UFLS systems? If the intent is to check
the station dc supply only when UVLS and UFLS maintenance is performed, the other rows
addressing station dc should be revised to exclude UVLS and UFLS. • Row 4 of Table 1b (page 14
of the clean version of PRC-005-2) indicates that remote alarms must be verified every twelve
calendar years for control circuitry (trip circuits) (except UFLS/UVLS) provided “Monitoring of
Protection System component inputs, outputs, and connections” exists. Clarification should be
made to indicate how to monitor inputs. For example, a breaker auxiliary switch is relied upon to
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communicate breaker status to a protective relay. If the switch is out of adjustment so that
incorrect breaker status is reported to the relay, the relay may not operate when needed. Could
proper operation of the auxiliary contacts be credited through in-service operation or the sixyear breaker operation maintenance? • The term “calendar years” is used to define the
maximum intervals. Does this mean that a six-year PM could go one-day shy of seven years? For
example, if a six-year maintenance PM was last performed on 1/1/2010, it would be due on
1/1/2016. Could this allow until 12/31/2016 to complete the maintenance? • Table 1b, Row 14
(Row 2 on page 17): Under the “Level 2 Monitoring Attributes for Component,” UFLS/UVLS
should be referenced instead of SPS. • Clarifications need to be made on testing requirements on
trip contacts relative to microprocessor vs. EM relays. • There appears to be an inconsistency in
the use of “check” vs. “verify” in the tables. • In battery maintenance table, we suggest that
“cell/unit” be changed to “cell or unit.”
Yes
No
M2 incorrectly excludes Distribution Provider.
No
In the VSL for R1, a failure to “specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue and not
an equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of
the required components can only be time based.
Yes
No
FAQ II.2.A: What degree of testing is required for a relay firmware upgrade? Complete
commissioning tests? FAQ V.1.A. There appears to be a typo in Example #1 for “Vented leadacid battery with low voltage alarm connected to SCADA (level 2)”: Table 1b does not list any
level 2 requirements. Rather, the table refers reader back to the Level 1 requirements. Same
comment for Example #2 as well. FAQ III.1.A: Project 2009-17 provides a response to a request
for interpretation of the term “transmission Protection System” as related to PRC-004-1 and
PRC-005-1. The interpretation addresses the boundaries of the transmission system. NERC
should investigate whether this same boundary should be defined within the new PRC-005-2.
Also, numerous potential boundary issues exist between entities which should be contemplated
and addressed. See the examples below: • Utility A may own equipment in Utility B’s substation.
Utility A contracts Utility B to perform maintenance on their equipment. However, the two
utilities have different maintenance programs and intervals for the same types of equipment.
Who is responsible for NERC compliance? Would Utility A be found in violation because their
equipment is being maintained under Utility B’s program which deviates from Utility A’s
maintenance basis? • EMC protection is fed from a utility’s instrument transformers. Who is
responsible for validation of the relay inputs and testing of the instrument transformers? •
Utility-owned communication units (used for transfer trip or carrier blocking) are coupled to the
utility’s power line using customer-owned CCVTs. Who is responsible for maintenance and testing
of these CCVTs? • Utility A owns all equipment at one end of line (line terminal A) and Utility B
owns all equipment at other end of line (line terminal B). Who is responsible for demonstrating
the carrier blocking scheme or POTT scheme works correctly?
• R1.1.1 states that “all” protection system components be identified. Does the term “all” refer to
the major components identified in the Protection System definition (protective relays,
communication systems, voltage and current sensing devices, station dc supply, and control
circuitry) or does it include all sub-components (jumpers, fuses, and auxiliary relays used in dc
control circuits and communication paths/wavetraps/tuners/filters)? We assume the former but
request clarification. • Draft Implementation Plan for PRC-005-02: The phased implementation
plan for R2, R3, and R4 seems reasonable. However, the three-month implementation plan for
R1 seems extremely short. Utilities will have to change procedures, job plans, basis documents,
provide training, and change intervals in their work tracking databases. In addition, if the utility
wants to take advantage of the longer intervals allowed by partial monitoring, significant print
work must be performed up front. • Descriptors in the type of the protection system column
needs to be consistent between 1A, 1B and 1C. In the tables, please clarify “complete functional
trip test” for UVLS and UVLS trip tests since the breaker is not being tripped.
Group
Pepco Holdings, Inc. - Affiliates
Richard Kafka
Pepco Holdings, Inc.
There were numerous comments submitted for Draft 1 indicating that the 3 month interval for
verifying unmonitored communication systems was much too short. The SDT declined to change
the interval and in their response stated: The 3 month intervals are for unmonitored equipment
and are based on experience of the relaying industry represented by the SDT, the SPCTF and
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review of IEEE PSRC work. Relay communications using power line carrier or leased audio tone
circuits are prone to channel failures and are proven to be less reliable than protective relays.
Statistics on the causes of BES protective system misoperations, however, do not support this
assertion. The PJM Relay Subcommittee has been tracking 230kV and above protective system
misoperations on the PJM system for many years. For the six year period from 2002 to 2007, the
number of protective system misoperations due to communication system problems were lower
(and in many cases significantly lower) than those caused by defective relays, in every year but
one. Similarly, RFC has conducted an analysis of BES protection system misoperations for 2008
and 2009, and found the number of misoperations caused by communication system problems to
be in line with the number attributed to relay related problems. If unmonitored protective relays
have a 6 year maximum maintenance/inspection interval, it does not seem reasonable to require
the associated communication system to be inspected 24 times more frequently, particularly
when relay failures are statistically more likely to cause protective system misoperations. As
such, a 12 or 18 calendar month interval for inspection of unmonitored communication systems
would seem to be more appropriate. FAQ II 6 B states that the concept should be that the entity
verify that the communication equipment...is operable through a cursory inspection and site visit.
However, unlike FSK schemes where channel integrity can easily be verified by the presence of a
guard signal, ON-OFF carrier schemes would require a check-back or loop-back test be initiated
to verify channel integrity. If the carrier set was not equipped with this feature, verification
would require personnel to be dispatched to each terminal to perform these manual checks. The
phrase “Verify Battery cell-to-cell connection resistance” has entered the table where it did not
exist before. On some types of stationary battery units, this internal connection is inaccessible.
On other types the connections are accessible, but there is no way to repair them based on a
bad reading. And bad cell-to-cell connections within units will be detected by the other required
tests. This requirement will cause entities to scrap perfectly good batteries just so this test can
be performed, with no corresponding increase in bulk electric system reliability while taking an
unnecessary risk to personnel and the environment.
No
An explanation is needed to justify why the VRF for R1 of the PSMP is High whereas the
implementing and following of the PSMP is Medium, R2, R3 & R4.
No
The present wording regarding data retention states - The Transmission Owner, Generator
Owner, and Distribution Provider shall each retain documentation of the two most recent
performances of each distinct maintenance activity for the Protection System components, or to
the previous on-site audit date, whichever is longer. This wording was changed by the SDT
following comments received from Draft 1. However, the present wording is somewhat confusing.
It is assumed that the intent of the SDT was to require documentation be retained for the two
most recent performances of each distinct maintenance activity, regardless of when they
occurred (i.e., whether prior to, or since the last audit), since the phrase whichever is longer was
used. In addition, for those activities requiring short maintenance intervals (such as battery
inspections), records must be kept for all performances (not just the last two) that have taken
place since the last on-site audit. For example: Assume a PSMP with a 6 year interval for relay
maintenance and 3 month interval for battery inspections. At a particular station assume the
batteries have been inspected every 3 months; the relays were last inspected 5 years ago, and
before that 11 years ago. The last audit was 2 years ago. Records from each 3 month battery
inspection going back to the last audit needs to be retained. Also, both relay maintenance
records from 5 and 11 years ago needs to be retained, despite the fact that this interval should
have been reviewed during the last audit. Documentation from the 11 year ago activity can be
discarded when the relays are next maintained. Is this what the SDT intended? If so, the
requirement should be re-worded to better explain the intent. Also, examples should be included
in either the FAQ or Supplemental Reference to demonstrate what is expected.
No
It is possible that a component that failed to be individually identified per R1.1 was included by
entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B that
identified a component without maintaining it. We suggest the R1 VSL be change to Low, since
we believe lack of maintenance to be more severe than documentation issues.
No
Figure 1 & 2 Legend (page 29), Row 5, Associated Communications Systems, includes Teleprotection equipment used to convey remote tripping action to a local trip coil or blocking signal
to the trip logic (if applicable). This description does not include all the various types of signals
communicated for proper operation of various protective schemes (i.e., DUTT, POTT, DCB,
Current Differential, Phase Comparison, synchro-phasors, etc.) A more inclusive and generic
description might be – Tele-protection equipment used to convey specific information, in the
form of analog or digital signals, necessary for the correct operation of protective functions. This
is also consistent with the revised definition of Protection System. Conversely, excluded
equipment would be - Any communications equipment that is not used to convey information
necessary for the correct operation of protective functions.
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No
The three month inspection interval for communication equipment mentioned in FAQ II 6 B
should be extended to 12 – 18 months (see response to Question #1). In addition, the example
used in this section should address what is expected for ON-OFF carrier systems. Checking that
the equipment is free from alarms and still powered up does not seem sufficient to verify
functionality. The FAQ states that the concept should be that the entity verify that the
communication equipment...is operable through a cursory inspection and site visit. However,
unlike FSK schemes where channel integrity can easily be verified by the presence of a guard
signal, ON-OFF carrier schemes would require a check-back or loop-back test be initiated to
verify channel integrity. If the carrier set was not equipped with this feature, verification would
require personnel to be dispatched to each terminal to perform these manual checks.
Dates of the Supplemental Reference Documents in Section F of the standard need to be
updated. The word “calendar” is used widely to define month and year intervals. Sometimes
causes confusion, need definition/examples. The level 2 table regarding Protection Station dc
supply states that level 1 maintenance activities are to be used, but then goes on to give a list of
Maintenance Activities that don’t match those in level 1. Which activities shall we use? Same
situation for Station DC Supply (battery is not used) where the 18 month interval is missing. Req
1.1: “All Components” wording should say something like all components covered in our plan
Individual
Martin Bauer
US Bureau of Reclamation
No
There is no reliability based justification to alter the standards to include allowable intervals. The
intervals prescription for performance based PSMP virtually eliminates the capability of smaller
utilities who do not have a large equipment database to justify a performance based system that
may be sound based on their experience. This overly prescriptive approach should be eliminated
and return to allowing utilities to justify their programs. The standard should return to
addressing real reliability impacts as required by law. This would be to develop a maintenance
required which identifies that if it is shown that an event in which reliability is impacted by the
utilities PSMP, as evidenced by disturbance reports, the utility would be required to submit to the
RRO a corrective action plan which addresses how the PSMP will be revised and when compliance
with that PSMP is to be achieved. Finally, the standard presumes that components within a BES
Element will cause a reliability impact to the BES. In numerous meeting with NERC and WECC it
was emphasized that a reliability impact has been described as causing cascading outages or
causing loss of service to load above a certain magnitude. The BES has an ability to absorb
element outages resulting from a variety of causes without impact load or resulting in cascading
outages.
No
The Time Horizons are too narrow for the implementation of the standard as written. The SDT
appears to have not accounted for the data analysis associated with performance based systems.
The data collection, analysis, and subsequent decisions associated development of a
maintenance program and its justification do not occur overnight especially with larger utilities.
In addition, this new standard will require complete rewrite of maintenance programs. The
internal processes associated with these vary based on the size of the utility. Since this standard
is so invasive into the internal decisions concerning maintenance, the standard should allow at
least 18 months for entities to rewrite their internal maintenance programs to meet the
requirements and 18 months to train the staff and implement the new program.
No
The measures M2, M3, and M4 are redundant to measure M1. Either eliminate M1 or M2 through
M4. The entity must provide documentation of its maintenance program in M1 irrespective of the
type used. As previsously mentioned there is not reliability based justification for the
documentation required. The Entity should be afforded the freedom to make intelligent
maintenance choices based on inumberable factors. These choices will be reviewed if a reliability
impact is determined to be related to the choices.
No
The VSL's use terms that are not tied back to a requirement and appear to be based on the
concept that every component will cause an impact on the BES. The VSL's use the term "coutable
event" to score the VSL; hoever, there is no requirement associated with the number of
"countable events". The VSL's should allow for minor gaps in maintennace documentation where
there is no impact to the BES if the component failed.
No
It is not reasonable to assert that a statistical analysis of survey data is a reliability based
justification for requiring specific maintenance intervals. The reference document admits that
intervals varied widely. To assert a postage stamp interval does not account for other variables
which optimize a specific maintenance program. That is not say that the reference documents is
worthless. Indeed it has many good suggestions. However, to impugn the maintenance programs
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in practice because they do not follow the "weighted average" is hardly scientific or credible. The
reference document should analyze the maintenance programs from the stand point of the
outages associated with those facilities. If a specific maintenance practice was shown to have
compromised the performance of the facility and the reliability of the BES, then it would added
to the statistical database of practices which would not be acceptable. Now the statistical
analysis of the database would show that certain practices have consequences which impact
reliability and a requirement can be constructed to disallow them.
The sub-requirements for R1, are not criteria, rather implementation requirements more suitable
to be included in R4. Examples of what the PSMP shall address which would be more consistent
with the language in R1 would be: How are changes to the PSMP administered? Who approves
the determination of the use of time-based, condition based or performance based maintenance.
Who reviews activities under the PSMP References used within the standard are not consistent.
In R1.2 Attachment as is referred to as Attachment A. In R3 Attachment A is referred to as PRC005 Attachment A. This implies a difference. Under a voluntary world, we could draft criteria and
procedures with this problems and interpret them correctly. Today in the compliance world, the
language must be precise and unambiguous. The reference must be the same it means
something different. The requirement in R1, which is consistent with the purpose, does not
support the applicability in R4.2.5.4. Protection systems associated with stations service are not
designed to provide protection for the BES. In particular we have been told that intent was not to
look at every device that tripped the generator but devises that sensed problems on the BES and
trip the generator. Hence we include such things as frequency relays, Differential relays, zone
relays, over current, and under voltage relays. Even a loss of field looks at the system as
included. Speed sensing devices were explicitly excluded. As such, if the stations service
transformer protection looks toward the BES (e.g. differential relays and zone relays) they would
be included. Over current would not as it would be on the station side. If a Station Service
transformer saw excess current, the system would in most cases fail over to other side. If not, it
would cause the generator to trip much like a generator thermal device which is also excluded.
Maintenance programs offer a unique problem to the FERC and regulatory world. The knee jerk
reaction is to define them. What happens if the solution is bad, who will accept the consequences
that narrow prescription was wrong and the interval caused a reliability impact. It would no
longer be the Entity. History is replete with examples of this type of micro managing. Rather
than fall into the same trap, and suffer the consequences of the unknown, allow Entities to
optimize their programs to ensure reliability of the BES and create a standard of disallowed
practices which have a demonstrated impact on reliability.
Group
NERC Staff
Mallory Huggins
NERC
Yes
Yes
Make sure that the use of verbs like “shall,” “should,” and “will” is consistent across
Requirements and Measures. In these four measures, all three verbs are used, and they should
be made uniform to avoid misinterpretation.
Yes
Yes
NERC staff is pleased with the current iteration of this standard. The staff understands that while
PRC-005-2 has historically been the most frequently violated standard, it has mostly been due to
documentation issues. The standard has not been much of a heavy hitter in causal or
contributive aspects, and with respect to relay operations, there have been very few times that
lack of maintenance has been the problem. NERC staff does propose a slight change to 4.2.5.1.
The concern is that 4.2.5.1 could be interpreted to apply to devices that protect the generator as
opposed to those that protect the Bulk Electric System. The suggested language is as follows:
“Protection System components that act to trip generators that are part of the BES, either
directly or via generator lockout or auxiliary tripping relays.” Additionally, staff suggests some
changes to R1. In that requirement, the PSMP covers “Protection Systems that use
measurements of voltage, current, frequency and/or phase angle to determine anomalies and to
trip a portion of the BES…” It probably would be better if the list was limited to voltage and
current or if the list was replaced with electrical quantities. The former would be okay since
voltage and current are the only two electrical quantities that relays measure directly. To remove
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ambiguity, the most inclusive way to rephrase this is probably the latter alternative, to change
the requirement to, “…that use measurements of electrical quantities to determine anomalies…”
Finally, Footnotes 2 and 3 (in Requirement 4) are identical. Unless that’s intentional, one should
be removed. (And note that Footnote 2 is missing a period.)
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Newsroom Site Map Contact NERC
Individual or group. (50 Responses)
Name (31 Responses)
Organization (31 Responses)
Group Name (19 Responses)
Lead Contact (19 Responses)
Contact Organization (19 Responses)
Question 1 (50 Responses)
Question 1 Comments (50 Responses)
Question 2 (47 Responses)
Question 2 Comments (50 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
Suggest adding “Protection System Components including” in the beginning. This is because the
word “components” has been used extensively throughout the standard and there is no mention
of what constitutes a protection system component in the standard. The word “component” does
find mention in FAQs, however, it is recommended to mention it in the body of the standard. The
revised definition should read as follows: Protection System Components including Protective
relays, communication systems necessary for correct operation of protective functions, voltage
and current sensing devices providing inputs to protective relays and associated circuitry from
the voltage and current sensing devices, station dc supply, and control circuitry associated with
protective functions from the station dc supply through the trip coil(s) of the circuit breakers or
other interrupting devices. An alternative definition for Protection System to eliminate the need
to capitalize “component”: The collective components comprised of protective relays,
communication systems necessary for correct operation of protective functions, voltage and
current sensing devices providing inputs to protective relays and associated circuitry from the
voltage and current sensing devices, station dc supply, and control circuitry associated with
protective functions from the station dc supply through the trip coil(s) of the circuit breakers or
other interrupting devices. There is not enough clarity on whether a Distribution Provider (DP)
will be able to clearly identify which protection system components it does own and needs to
maintain. Many DPs own and/or operate equipment identified in the existing or proposed
definition. However, not all such equipment translates into a transmission Protection System. The
definition needs clarification on when such equipment is a part of the transmission protection
system. This is critical since NPCC had proposed a SAR to this effect which was not accepted by
NERC citing that this concern will be incorporated in the revised standard. Also, reference should
be made to Project 2009-17 in which Y-W Electric Association, Inc. (Y-WEA) and Tri-State
Generation and Transmission Association, Inc. (Tri-State) requested an interpretation of the
term "transmission Protection System" and specifically whether protection for a radiallyconnected transformer protection system energized from the BES is considered a transmission
Protection System and is subject to these standards.
No
The time provided for the first phase “at least six months” is too open ended and does not give
entities a clear timeline. Suggest 1 year for the first phase. Suggest phasing out the second
phase in stages.
Group
SERC Protection and Control Sub-committee (PCS)
Joe Spencer - SERC staff and Phil Winston - PCS co-chair
SERC Reliability Corp.
Yes
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We agree that the definition provides clarity and will enhance the reliability of the Protection
Systems to which it is applicable; however, we believe there should be a direct linkage of the
definition’s effective date to the approval and implementation schedule of PRC-005-2. Since this
new definition is directly linked to the proposed revised standard, it would be premature to make
this definition effective prior to the effective date of the new standard.
No
As noted above, the implementation plan should be linked to the approval of PRC-005-2. Since
this new definition is directly linked to the proposed revised standard, it would be premature to
make this definition effective prior to the effective date of the new standard.
Individual
Jack Stamper
Clark Public Utilities
Yes
No
While the drafting team has done a great job of simplifying the implementation plan from the
original draft 1 language, the current language has some ambiguities. I do not understand what
the term “the end of the first calendar quarter six months following regulatory approvals” means.
What is wrong with just saying “within nine months (or six months or twelve months) following
regulatory approvals? Using the current language I would be inclined to assume it is six months
so I can avoid a dispute (and quite possibly a notice of alleged violation) over a date. Also, I am
not sure what the term “the end of the first complete maintenance and testing cycle described in
the entity’s program description” means. It is quite likely that a registered entity will make the
required definition change to its maintenance program (at approximately six months) and wind
up with devices that need to be tested. Is the implementation plan attempting to provide some
allowed time delay so the registered entity will not be out of compliance even though it has
devices that are now beyond the maximum testing interval due to the definition change? The
existing language implies that within approximately six months of regulatory approval, the
maintenance program needs to be changed to incorporate the revised definition for Protection
System. However, the effective date for the revised maintenance program is going to be some
date that corresponds with the end of the first complete maintenance and testing cycle in that
program. I really don’t understand what that time period is and I believe the drafting team
needs to put in something that clears up this confusion. By testing cycle do you mean “maximum
interval” as shown in the PRC-005 table? Do you mean the “maximum interval” that a registered
entity includes in their maintenance program? If so, do you intend the implementation to be a
different date for protection devices depending on the maximum testing interval? Or do you
envision some date beyond the six months where the entire maintenance program (with the
definition change) becomes effective and any registered entities with out-of-compliance issues
would need to file mitigation plans?
Individual
Dan Roethemeyer
Dynegy Inc.
Yes
Yes
Individual
Robert Ganley
Long Island Power Authority
No
LIPA suggests adding “Protection System Components including” in the beginning. This is
because the word “components” has been used extensively throughout the standard and there is
no mention of what constitutes a protection system component in the standard. The word
“component” does find mention in FAQs, however, it is recommended to mention it in the main
standard. Also, LIPA proposes a change in the proposed definition (changing "voltage and current
sensing inputs" to "voltage and current sensing devices providing inputs"). The revised definition
should read as follows: Protective System Components including Protective relays,
communication systems necessary for correct operation of protective functions, voltage and
current sensing devices providing inputs to protective relays and associated circuitry from the
voltage and current sensing devices, station dc supply, and control circuitry associated with
protective functions from the station dc supply through the trip coil(s) of the circuit breakers or
other interrupting devices. There is not enough clarity on whether a Distribution Provider (DP)
will be able to clearly identify all protection system components it owns and needs to maintain.
This is critical since NPCC had proposed a SAR to this effect which was not accepted by NERC
citing that this concern will be incorporated in the revised standard.
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No
The time provided for the first phase “at least six months” is too open ended and does not give
entities a clear timeline. LIPA suggests 1 year for the first phase. It is also suggested phasing
out the second phase in stages.
Group
PacifiCorp
Sandra Shaffer
PacifiCorp
Yes
Yes
Group
Pacific Northwest Small Public Power Utility Comment Group
Steve Alexanderson
Central Lincoln
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure
relays, are included in the proposed definition as protective relays. While PRC-005-2 R1 limits
the scope of that particular standard to protection systems that sense electrical quantities, it is
remains unclear in other standards that use the defined term whether mechanical input
protections are included. We suggest that “Protective Relay” also be defined, and that the
definition clearly exclude devices that respond to mechanical inputs in line with the NERC
interpretation of PRC-005-1 in response to the CMPWG request.
Yes
Group
PNGC Power
Margaret Ryan
PNGC Power
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure
relays, are included in the proposed definition as protective relays. While PRC-005-2 R1 limits
the scope of that particular standard to protection systems that sense electrical quantities, it is
remains unclear in other standards that use the defined term whether mechanical input
protections are included. We suggest that “Protective Relay” also be defined, and that the
definition clearly exclude devices that respond to mechanical inputs in line with the NERC
interpretation of PRC-005-1 in response to the CMPWG request.
Yes
Group
Southern Company Transmission
JT Wood
Southern Company
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection
Systems to which it is applicable. However, we feel that there needs to be a direct linkage of the
definition’s effective date to the approval and implementation schedule of PRC-005-2. Since this
new definition is directly linked to the proposed revised standard, it would be premature to make
this definition effective prior to the effective date of the new standard.
No
The revised definition should not be made effective until the revised PRC-005-2 is in effect.
There is no definite reliability benefit to balloting this definition prior to the revised standard. If
balloted and approved, entities would definitely have to modify their Protection System
Maintenance and Testing Program methodology, but there is no obligation to or guarantee of any
additional maintenance being performed. PRC-005-2 includes this definition, the maintenance
activities, and the intervals that will ensure execution of the maintenance and testing.
Individual
Lauri Dayton
Grant County PUD
No
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1) We note that the definition of a “Protection System” has been expanded to include the trip
coils and what used to be confined to batteries has now been expanded to “station DC supply.”
“Trip coils” is an improvement. Inasmuch as the mark-up changing “DC” to “dc” is intended to
communicate a more general term as opposed to a strict definition, it leaves room for differing
opinions among auditors as to what all should be included. We support the change to exclude
battery chargers since the rationale for their inclusion was never clear. The battery itself will be,
without exception, the “first responder” to provide DC power to a Protection System. However,
battery chargers have not been excluded under the FAQs. 2) The SPCTF’s effort to define
applicability in terms of “Facilities” is confusing. Additionally, it is unclear how the terms
“component,” “element” and “Facility” are intended to relate to one another. An assumption may
be that one or more components (which are physical assets) can comprise an “element,” one or
more of which can be associated with an identifiable function, aligning with the five Protection
System Equipment Categories, found in SPCTF’s “PROTECTION SYSTEM MAINTENANCE—A
Technical Reference, dated Sept. 13, 2007, and that “Facility” is as used in 4.2.1 of the Standard
Development Roadmap, dated May 27, 2010. Please provide guidance on the terms relate to one
another. 3) The structure of the proposed standard is less clear than the existing standard PRC005-1 because of the potential for ambiguity between the definition of Protection System and
how the term “Facilities” is applied. A suggested resolution would be to revise the definition of
Protection System to resolve this ambiguity or to delete reference to 86 lockouts and auxiliary
relays in the description of “Facilities.” If the 86 lockout relays are to be included, they should be
added as part of the DC Control Circuitry “element” (as found in the NERC Glossary) of the circuit
that energizes the 86 relay, thus placing it within the definition of a “Protection System.”—once
—and therefore in a manner that would require only one scheduled maintenance to be performed
if the testing schemes are properly set up. We do agree, however, that sudden pressure relays,
reclosing relays, and other non fault detecting relays such as loss of cooling relays should not be
referenced as part of the “dc control circuitry” Element.
No
There needs to be more clarity concerning the role of the 3 year audit during the implementation
phase. Do the audit tests consist of varying proportions of -1 criteria and -2 criteria?
Individual
Fred Shelby
MEAG Power
Yes
Yes
Individual
James A. Ziebarth
Y-W Electric Association, Inc
No
The application of this definition to Reliability Standards NUC-001-2, PER-005-1, PRC-001-1, and
PRC-004-1 results in confusion as to whether relays with mechanical inputs are included or
excluded from this definition. PRC-005-2_R1 contains language limiting its applicability to relays
operating on electrical inputs only, but the remaining standards that rely on this definition are not
so specific. This being the case, it would make much more sense to clearly define what devices
are actually meant in the glossary definition rather than leaving it up to each individual standard
to do so.
Yes
Individual
Armin Klusman
CenterPoint Energy
No
CenterPoint Energy believes the proposed definition of “Protection System” is technically
incorrect. The present definition does not include trip coils of interrupting devices, such as circuit
breakers; and correctly so, as trip coils are components of the interrupting device. A Protection
System has correctly performed its function if it provides tripping voltage up to the circuit
breaker trip coil. From that point, the circuit breaker can fail to timely interrupt fault current due
to several factors, such as a binding mechanism that affects breaker clearing time, a broken pull
rod, a bad insulating medium, or bad trip coils. Local breaker failure protection, or remote
backup protection, is installed to address the various possible causes of circuit breaker failure.
For correctness, the definition of “Protection System” should be “Protective relays,
communication systems necessary for correct operation of protective functions, voltage and
current sensing inputs to protective relays and associated circuitry from the voltage and current
sensing devices, station dc supply, and control circuitry associated with protective functions from
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the station dc supply UP TO THE TERMINALS OF the trip coil(s) of the circuit breakers or other
interrupting devices.”
Individual
Andrew Z.Pusztai
American Transmission Company
Yes
No
ATC does not agree to the implementation plan proposed. While it makes common sense to
proceed with R1 prior to proceeding with implementing R2, R3, and R4, the timeline to be
compliant for R1 is too short. It will take a considerable amount of resources to migrate the
maintenance plan from today’s standard to the new standard in phase one. ATC recommends
that time to develop and update the revised program be increased to at least one year followed
by a transition time for the entity to collect all the necessary field data for the protection system
within its first full cycle of testing. (In ATC’s case would be 6 years) To address phase two, ATC
believes human and technological resources will be overburdened to implement this revised
standard as written. The transition to implementing the new program will take another full
testing cycle once the program has been updated. Increased documentation and obtaining
additional resources to accomplish this will be challenging. Implementation of PRC-005-2 will
impact ATC in the following manner: a. Increase costs: double existing maintenance costs. b.
Since there will be a doubling of human interaction (or more), it is expected that failures due to
human error will increase, possibly proportionately. c. Breaker maintenance may need to be
aligned with protection scheme testing, which will always contain elements that are include in the
non-monitored table for 6 yr testing. d. ATC is developing standards for redundant bus and
transformer protection schemes. This would allow ATC to test the protection packages without
taking the equipment out of service. Further if one system fails, there is full redundancy
available. With the current version of PRC-005-2, ATC would need to take an outage to test the
protection schemes for a transformer or a bus, there is not an incentive to install redundant
schemes. ATC is working with a condition based breaker maintenance program. This program’s
value would be greatly diminished under PRC-005-2 as currently written. Consideration also
needs to be given for other NERC standards expected to be passed and in the implementation
stage at the same time, such as the CIP standards.
Individual
Eric Ruskamp
Lincoln Electric System
No
LES believes the proposed definition of Protection System as written remains open to
interpretation. LES offers the following Protection System definition for the SDT’s consideration:
“Protection System” is defined as: A system that uses measurements of voltage, current,
frequency and/or phase angle to determine anomalies and trips a portion of the BES and consists
of 1) Protective relays, and associated auxiliary relays, that initiate trip signals to trip coils, 2)
associated communications channels, 3) current and voltage transformers supplying protective
relay inputs, 4) dc station supply, excluding battery chargers, and 5) dc control trip path circuitry
to the trip coils of BES connected breakers, or equivalent interrupting device, and lockout relays.
Yes
Group
E.ON U.S.
Brent Inebrigtson
E.ON U.S.
Yes
No
The first phase is only 3 months (per Implementation Plan) to update the program, not the 6
months as listed in this question. E.ON U.S. recommends that it should be a minimum of 6
months, regardless.
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
No
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The proposed implementation stage of 6 months is much too stringent and an 18 month window
is suggested.
Individual
Edward Davis
Entergy Services
Yes
No
We agree with the definition, however we do not agree with the implementation plan. We believe
implementation of the definition needs to coincide with the implementation of Standard PRC005-2. To do otherwise, will cause entities to address equipment, documentation, work
management process, and employee training changes needed for compliance twice within an
unreasonably short timeframe. Additional time, 12 months minimum, will be needed to fully
assess and address the necessary maintenance program documentation changes, maintenance
system tool revisions, and personnel training needed to incorporate this new definition into our
program.
Individual
James Sharpe
South Carolina Electric and Gas
Yes
The new definition effective date should be directly linked to the approval and implementation
schedule of PRC-005-2 to avoid any possible compliance issues under the current PRC-005
standard.
Yes
Individual
Jon Kapitz
Xcel Energy
No
We recommend modifying the language to remove circuit breakers altogether: “…through the
trip coil(s) of the circuit breakers or other interrupting devices.”
No
The implementation plans for both the definition and standard are confusing. Does this imply a
"clean slate" approach can be used? i.e. do entities have up to the first interval window to
complete the maintenanceor must they have it complete on day 1 of the standard and again by
the first interval? It also appears that the implmentation plans are conflicting whereby one
requires full compliance and the other allows 6 months...the definition implmeentation plan also
refer to a basis document though the standard does not require one.
Group
Bonneville Power Administration
Denise Koehn
BPA, Transmission Reliability Program
Yes
Yes
Individual
Scott Kinney
Avista Corp
No
The modified definition of Protection System now refers to “functions” rather than “devices.”
What are the “functions?” This new term adds confusion without being defined in the standard.
Yes
Individual
Amir Hammad
Constellation Power Generation
No
Constellation believes that this definition is to verbose, which can lead to unintended
interpretations. Constellation is concerned with the term sensing inputs, which may infer that
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testing on instrument transformers must be completed while they are energized. This proves
difficult at a generating facility where most testing is completed during planned outages when
this equipment is not energized.
No
This does not match the implementation proposed for PRC-005-2. The implementation plan for
revising the program is 6 months based on the “definition implementation” but R1 in PRC-005-2
has a 3 month implementation plan.
Individual
Jeff Nelson
Springfield Utility Board
Yes
Yes
Group
Western Area Power Administration
Brandy A. Dunn
Western Area Power Administration - Corporate Services Office
Yes
Yes
Group
WECC
Tom Schneider
Western Electricity Coordinating Council
Yes
Compliance agrees only if the original “Protection System” definition is in place for the interim
implementation period, so that only the changes and or additions to the “Protection System”
definition are covered under the proposed implementation plan.
Individual
Michael R. Lombardi
Northeast Utilities
Yes
No
The time provided for the first phase “at least six months” is too open ended and does not give
entities a clear timeline. Northeast Utilities suggests 1 year for the first phase.
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
Arizona Public Service Company
No
The change to the definition relative to the voltage and current sensing devices is too
prescriptive. Methods of determining the integrity of the voltage and current inputs into the
relays to ensure reliability of the devices should be up to the discretion of the utility.
Yes
Individual
John Bee
Exelon
Yes
No
PECO would like to have the implementation plan provide at least 1 year for full implementation
of the new standard. This will provide adequate time for development of documentation, training
for all personnel, and testing then implementation of the new process (es).
Individual
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Barb Kedrowski
We Energies
Yes
No
Wisconsin Electric does not agree with the six-month implementation requirement in the first
phase. It is our position that a longer adjustment time is needed for entities to update their
maintenance programs to implement the new definition. The new definition results in a
significant increase in the scope of affected equipment and the documentation required to
implement the program, and requires additional resources beyond present levels, including hiring
and training. We estimate that this effort will require three years to fully implement.
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
Yes
The definition is ready for ballot with the addition of auxiliary relays to the definition of
protective relays. There is a potential for an entity to determine that auxiliary relays do not
perform a protection function since they typically do not sense fault current. Furthermore, one
could determine that the term "circuitry" only refers to the wiring to connect the various DC
devices together. We suggest adding "auxiliary relays necessary for correct operation of
protective devices" to improve clarity of the definition. With regard to the change from the
current definition phrase "station batteries" to the new definitions phrase "station DC supply", it
may not be clear to the reader that this includes battery chargers. To alleviate future
interpretation issues, we suggest adding a clarifying statement at the end of the definition, such
as "The station DC supply includes the battery, battery charger, and other DC components". The
acronym "dc" should be capitalized.
Yes
Individual
Jianmei Chai
Consumers Energy Company
No
1. It is unclear whether “voltage and current sensing inputs” include the instrument transformer
itself, or does it pertain to only the circuitry and input to the protective relays? 2. It is not clear
what is included in the component, “station dc supply” without referring to other documents (the
posted Supplementary Reference and/or FAQ) for clarification. The definition should be
sufficiently detailed to be clear. 3. If Protection Systems trip via AC methods, are those systems,
and the associated control circuitry included?
No
For entities that may not have included all elements reflected in the modified definition within
their PRC-005-1 program, 6-months following regulatory approvals may not be sufficient to
identify all relevant additional components, develop maintenance procedures, develop
maintenance and testing intervals, develop a defendable technical basis for both the procedures
and intervals, and train personnel on the newly implemented items. We propose that a 12-month
schedule following regulatory approvals may be more practical.
Group
Santee Cooper
Terry L. Blackwell
SC Public Service Authority
Yes
We agree with the proposed definition. However, the effective date of this definition should be
linked to the implementation schedule of PRC-005-2. This definition should not be made effective
prior to the new standard.
No
The implementation plan should be linked to the approval of PRC-005-2. The definition should
not be made effective prior to the new standard.
Individual
Art Buanno
ReliabilityFirst Corp.
Yes
The definition should probably include interrupting devices as the Protection System is of little
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value if the fault cannot be interrupted.
Yes
Group
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency
Yes
Because the definition changes the scope of what a protection system covers, increasing that
scope, the definition should not be balloted separately from PRC-005-2 so that the industry
knows what is being committed to. For instance, the circuitry connecting the voltage and current
sensing devices to the relays is a scope expansion. station DC supply increases the scope to
include the charger, etc. This scope increase needs to have an appropriate implementation
period.
No
As stated in response to Question 1, it is inappropriate to change the definition o Protection
System for PRC-005-1 and the new definition should wait for the new standard. In all honesty,
the new PRC-005-2 lays out the program anyway, so, any change to the definition needs to be
accompanied by a the commitment associated with that change.
Individual
Greg Rowland
Duke Energy
No
It is unclear whether the revised definition includes PTs and CTs, but it does include the wiring.
We don’t see a way to list the wiring in R1.1 and provide supporting compliance evidence. We
believe the phrase “and associated circuitry from the voltage and current sensing devices” should
be struck from the definition.
No
Definition should be implemented concurrently with PRC-005-2.
Group
Public Service Enterprise Group ("PSEG Companies")
Kenneth D. Brown
Public Service Electric and Gas Company
No
Based on review of ballot pool comments there are still too many questions that should be
resolved prior to submittal for ballot. It is suggested that a specific reference to the
supplementary reference document figures 1 & 2 and the legend be added. That would further
define the protection system components and scope boundary.
No
- The draft implementation plan general considerations have a requirement to identify all the
protection system components addressed under PRC-005-1 and PRC-005-2 for potential audits
while modifying the existing programs. The standard revision will require extensive reviews and
possibly add significant amounts of components to the program. This is listed as a requirement
without a specific deadline other than supplying the information as part of an audit. If an audit is
scheduled or announced early in the implementation period the evidence is required. The
requirement for identifying all the components in the implementation process should have a time
specified with bases for the starting point. - Where additional definition of a protection system
scope boundary is determined as a result of the standard revisions, the implementation plan
completion requirement should be at the end of next maintenance interval of that added
protection system component. There may be situations where additional scope as determined by
the additions or revisions to the standard and/or supporting reference material (e.g., an auxiliary
contact input in a tripping scheme) would require going back and taking equipment out of
service to perform that one check. To keep the maintenance and outage schedules coordinated
the new requirements should be at the end of current cycles, not beginning.
Group
The Detroit Edison Company
Daniel Herring
NERC Compliance
No
The definition should clarify whether current and voltage transformers themselves are included.
No
This implementation plan and the one for PRC-005-2 should be consistent.
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Individual
Thad Ness
American Electric Power
No
The term "station" should either be defined or removed from the definition, as it implies
transmission and distribution assets while the term "plant" is used to define generation assets. It
would suffice to simply refer to the "DC Supply".
No
As written, the implementation plan only specifies a time frame for entities to update their
documentation for PRC-005-1 and PRC-005-2 compliance. The implementation plan also needs
to give entities a time frame to address any required changes to their documentation for other
standards that use the term "Protection System", including but not limited to NUC-001-2, PER005-1, PRC-001-1, etc.
Individual
Rex Roehl
Indeck Energy Services
No
It presumes that all relays in a plant are Protective Systems that affect BES reliability. As
discussed at the FERC Technical Conference on Standards Development, the goal of the
standards program is to avoid or prevent cascading outages--specifically not loss of load. The
purpose of PRC-005-2 uses the term in its global sense but there is no subset of the Protection
Systems that affect reliability. PRC-005 R1 requires identification of all components. With the
broad definition proposed, and no separate term for only relays and other components that have
been identified as affecting reliability, confusion results. If this term has its global meaning, then
another term, such as Reliability Protection Systems, should be instituted to avoid confusion.
No
The definition should not be implemented separate from PRC-002-2. The PRC-002-2
implementation plan would be adequate.
Individual
Claudiu Cadar
GDS Associates
No
- The inserted wording “and associated circuitry from the voltage and current sensing devices”
implies that the maintenance program will include the verification, monitoring, etc. of the wiring
from the voltage/current sensing devices which requirement will be a bit excessive under current
presentation of the standard. See comment on the standard as well. - SDT’s additional wording
such as “from the station DC supply through the trip coil(s) of the circuit breakers or other
interrupting devices” can be a bit of an issue as the coils could be good at time of verification
and testing, but can fail right after or due to the testing. We recommend to change the
Protection System definition to read “up to the trip coils(s)” instead the word “through”
Individual
Terry Bowman
Progress Energy Carolinas
No
See comment associated with question 2.
No
Progress Energy does not believe that the definition should be implemented separately from and
prior to the implementation of PRC-005-2. We believe there should be a direct linkage between
the definition’s effective date to the approval and implementation schedule of PRC-005-2. Since
this new definition should be directly linked to the proposed revised standard, it would be
premature to make this new definition effective prior to the effective date of the new standard.
We believe that changes to the maintenance program should be driven by the revision of the
PRC standard, not by the revision of a definition.
Group
Hydro One
Sasa Maljukan
Hydro One Networks, Inc.
No
Hydro One suggests adding “Protection System Components including” in the beginning. This is
because the word “components” has been used extensively throughout the standard and there is
no mention of what constitutes a protection system component in the standard. The word
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“component” does find mention in FAQs, however, it is recommended to mention it in the main
standard. The revised definition should read as follows: Protective System Components including
Protective relays, communication systems necessary for correct operation of protective functions,
voltage and current sensing devices providing inputs to protective relays and associated circuitry
from the voltage and current sensing devices, station dc supply, and control circuitry associated
with protective functions from the station dc supply through the trip coil(s) of the circuit breakers
or other interrupting devices. There is not enough clarity on whether a Distribution Provider (DP)
will be able to clearly identify which all protection system components does it own and need to
maintain. This is critical since NPCC had proposed a SAR to this effect which was not accepted by
NERC citing that this concern will be incorporated in the revised standard. Also, reference should
be made to Project 2009-17 in which Y-W Electric Association, Inc. (Y-WEA) and Tri-State
Generation and Transmission Association, Inc. (Tri-State) requested an interpretation of the
term "transmission Protection System" and specifically whether protection for a radiallyconnected transformer protection system energized from the BES is considered a transmission
Protection System and is subject to these standards.
No
The time provided for the first phase “at least six months” is too open ended and does not give
entities a clear timeline. HYDRO ONE suggests 1 year for the first phase. Also, HYDRO ONE
suggests phasing out the second phase in stages.
Individual
Kirit Shah
Ameren
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection
Systems to which it is applicable; however, we suggest that a Glossary term for Protective Relay
be added in order to clarify in all standards inclusion of relays that measure voltage, current,
frequency and/or phase angle to determine anomalies, as stated in PRC-005-2 R1. We believe
there should be a direct linkage of the definition’s effective date to the approval and
implementation schedule of PRC-005-2. Since this new definition is directly linked to the
proposed revised standard, it would be premature to make this definition effective prior to the
effective date of the new standard. We agree that the voltage and current inputs at the
protective relays correctly identifies that component, that this excludes the instrument
transformer itself. We suggest replacing "to" with "at", and omitting "and associated circuitry
from the voltage and current sensing devices."
No
As noted above, the implementation plan should be linked to the approval of PRC-005-2. Since
this new definition is directly linked to the proposed revised standard, it would be premature to
make this definition effective prior to the effective date of the new standard. Otherwise, entities
must address equipment, documentation, work management process, and employee training
changes needed for compliance twice within an unreasonably short timeframe. If PRC-005-2
receives regulatory approval in 1st quarter 2011, PSMP implementation along with this revised
definition should be effective at the beginning of 2012 to coincide with the calendar year. These
nine months will be needed to fully assess and address the necessary maintenance program
documentation changes, maintenance system tool revisions, and personnel training needed to
incorporate this new definition into our program.
Group
Pepco Holdings, Inc. - Affiliates
Richard Kafka
Pepco Holdings, Inc.
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure
relays, are included in the proposed definition as protective relays. While PRC-005-2 R1 limits
the scope of that particular standard to protection systems that sense electrical quantities, it
remains unclear in other standards that use the term “Protection System” (such as PRC-004)
whether devices responding to mechanical inputs are included. As such, we suggest that the
term “Protective Relay” also be defined, and that the definition clearly exclude devices that
respond to mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to
the CMPWG request.
No
The 6 month time frame to update the revised maintenance and testing program is too short.
Specifically identifying and documenting each component not presently individually identified in
our maintenance databases, auxiliary relays, lock-out relays, etc. will require a major effort. We
recommend at least one year.
Individual
Hugh Conley
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Allegheny Power
Yes
Yes
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
No
The second part of the implementation effective date does not make sense and might be wrong.
The second part talks about implementing any addtional maintenance and testing (required in R2
of PRC-005-1- Transmission and Generation Protection system Maitenance and Testing); this is
refering to version 1 of the standard and there should be no additional maintenance and testing
added from version 1 of the standard, just version 2 which is the new version. Overall, the
wording on this implementation plan needs to be made more clear about how the
implementation plan will work.
Group
NERC Staff
Mallory Huggins
NERC
Yes
Still, to make sure the reference to dc supply is more generic than just “station dc supply,”
NERC staff suggests the following modified definition of Protection System: "Protective relays,
communication systems necessary for correct operation of protective functions, voltage and
current sensing inputs to protective relays and associated circuitry from the voltage and current
sensing devices, and any dc supply or control circuitry associated with the preceding devices."
Yes
Individual
Terry Habour
MidAmerican Energy Company
No
The definition is expanded and clarified in the language of PRC-005-2. These changes should be
incorporated in the definition to insure it is used consistently in PRC-005 and any other standards
where it appears. The following is a suggested revised definition: “Protection System” is defined
as: A system that uses measurements of voltage, current, frequency and/or phase angle to
determine anomalies and to trip a portion of the BES to provide protection for the BES and
consists of 1) Protective relays for BES elements and, 2) Communications systems necessary for
correct BES protection system operations and, 3) Current and voltage sensing devices supplying
BES protective relay input and, 4) Station DC supply to BES protection systems excluding
battery chargers, and 5) DC control trip paths to the trip coil(s) of the circuit breakers or other
interrupting devices for BES elements.
No
The protection system definition implementation plan should be consistent with the
implementation plan of PRC-005-2 R1. Actual maintenance requirements implementation should
be as required by the PRC-005-2 implementation plan and should not be included in the
implementation plan for the protection system definition.
Individual
Martin Bauer
US Bureau of Reclamation
Yes
No
The Time Horizons are too narrow for the implementation of the standard as written. The SDT
appears to have not accounted for the data analysis associated with performance based systems.
The data collection, analysis, and subsequent decisions associated development of a
maintenance program and its justification do not occur overnight especially with larger utilities.
In addition, this new standard will require complete rewrite of an entities internal maintenance
programs. The internal processes associated with these vary based on the size of the entity and
its organizational structure. Since this standard is so invasive into the internal decisions
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concerning maintenance, the standard should allow at least 18 months for entities to rewrite
their internal maintenance programs to meet the program development requirements and 18
months to train the staff in the new program, incorporate the program into the entities
compliance processes, and to implement the new program.
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Consideration of Comments on Initial Ballot of PRC-005-2 – Protection System Maintenance
The Protection System Maintenance Standard Drafting Team (PSM SDT) thanks all those who participated in the initial ballot for the
proposed revisions to PRC-005 - Protection System Maintenance.
•
87.85% quorum
•
39.35 % weighted segment approval
All comments received with affirmative and negative ballots are included in this report.
All balloters are advised to review the comments and responses in this report as an aid in determining how to participate in the
recirculation ballot.
Both a clean and a redline version of the standard that shows the conforming revisions are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Many commenters objected to the establishment of maximum allowable intervals and offered comments on virtually every
individual activity and interval within the Tables. The SDT responded that “FERC Order 693 and the approved SAR assigned the SDT
to develop a Standard with maximum allowable intervals and minimum maintenance activities.” In an effort to provide more clarity,
the SDT also completely revised the Tables of maximum maintenance intervals/minimum maintenance activities, and made
numerous other changes throughout the draft Standard. Many commenters also indicated a preference for much of the information
that is currently contained within the reference documents to be included within the Standard itself. The SDT responded by
including the definitions of terms exclusively used within this standard, specifically “component type”, “component”, “segment”,
“maintenance correctable issue”, and “countable event”, , within the body of the standard. Numerous comments were also offered,
proposing that the VSLs allow for some amount of non-compliance with the Standard before incurring a violation. The SDT
responded by stating that: “The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.”
November 17, 2010
1
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process! If you feel there has been an error or omission, you can contact the Vice President and Director of
Standards, Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
November 17, 2010
2
Segment:
Organization:
Member:
Comment:
1
International Transmission Company Holdings Corp
Michael Moltane
While voting affirmative due to the improvements over the existing standards, we do have the following
comments. We hope the Standards Team can take these comments and suggested improvements into account
although we did not get our comments in during the official comment period due to confusion over the
overlapping comment/ballot period. The following are ITC Holdings comments corresponding the questions
on the comment form:
Regarding Question #1: ITC Holdings does not agree with the 6 year time interval for functional testing of
the control and trip circuits. It has been our experience that trip failures are rare and that our present 10 year
control, trip tests, and other related testing are sufficient in verifying the integrity of the scheme. A scheme
that is 100% microprocessor relays except for 1 electromechanical AR or SG relay would be forced to a 6
year interval instead of a 12 year interval. This seems unreasonable for schemes that are otherwise identical.
Comments on Question #4: ITC Holdings agrees with the measure and data retention requirements assuming
that the requirements only apply to test data after the effective date of the approved standard.
Comments on Question #7: It should clearly state in the definition or elsewhere in the standard that automatic
ground switches intended to protect the BES are to be considered interrupting devices. This is stated in the
Supplemental Reference but the Supplemental Reference is not part of the standard. Please consider splitting
the first row in Table 1a (Protective Relays) into 2 separate rows, one for relays other than microprocessor
and the other for microprocessor relays.
• Include the sentence “Verify that settings are as specified.” In both rows to be clear that this applies to
both categories. (The following is intended to be helpful information only not to be included in the
comments)
The following provides a clue as to what Time Horizon means: From:
http://www.nerc.com/docs/pc/ris/Order_890-A_pro_forma_Attachment_C.doc (1) A detailed description of
the specific mathematical algorithm used to calculate firm and non-firm ATC (and AFC, if applicable) for its
November 17, 2010
3
scheduling horizon (same day and real-time), operating horizon (day ahead and pre-schedule) and planning
horizon (beyond the operating horizon); See Definition at: http://www.nerc.com/files/Time_Horizons.pdf
Copy below: Time Horizons Time Horizons are used as a factor in determining the size of a sanction. If an
entity violates a requirement and there is no time to mitigate the violation because the requirement takes place
in real-time, then the sanction associated with the violation is higher than it would be for violation of a
requirement that could be mitigated over a longer period of time. When establishing a time horizon for each
requirement, the following criteria should be used: 1. Long-term Planning — a planning horizon of one year
or longer. 2. Operations Planning — operating and resource plans from day-ahead up to and including
seasonal. 3. Same-day Operations — routine actions required within the timeframe of a day, but not realtime. 4. Real-time Operations — actions required within one hour or less to preserve the reliability of the
bulk electric system. 5. Operations Assessment — follow-up evaluations and reporting of real time
operations.
Response:
Thank you for your comment.
Question #1 - The Tables have been rearranged and considerably revised to improve clarity. Please see new
Table 1-5. The SDT believes that mechanical solenoid-operated devices share performance attributes (and
failure modes) with electromechanical relays and need to be tested at similar intervals. Performance-based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
Question #4 – The SDT believes that entities cannot be expected to initially have data for requirements that
did not previously exist.
Question #7 – From a mandatory perspective, this is dependent on the regional BES definitions and on what
those definitions may describe to be “transmission Protection Systems.”
• The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 11.
Time Horizon – Thank you for your input.
Segment:
Organization:
Member:
November 17, 2010
5
U.S. Bureau of Reclamation
Martin Bauer
4
1. There is no reliability based justification to alter the standards to require practices of a subset of entities as
allowable intervals. It is incredible that the standard would suppose that requiring the use of weighted average
practice of some subset of all entities could reasonable. The purpose of a reliability standard is to ensure the
reliability of the BES. There is no indication that the existing standard has posed a threat to the reliability of
the BES. There is no data which indicates that the BES reliability is impacted because of certain maintenance
practices. The SDT has chosen an approach which has statistical merit and is good information for entities to
consider in reviewing their maintenance program. To force an entity to enhance its maintenance program
because some subsets of entities have a different program is contrary to the purpose authorized by the Energy
Policy Act of 2005. The variables of each entity faces when developing their maintenance practice intervals
cannot be calculated through statistical analysis. To presume that the end result (the interval itself) can be
applied to other entities ignores the sound decisions made internally to each entity that results in final
interval. The standard should return to addressing real reliability impacts as required by law. The desire to
improve maintenance programs offers a unique problem to the FERC and regulatory world. The knee jerk
reaction is to define a "universal" interval based on some statistical method. What happens if the solution is
bad, who will accept the consequences that narrow prescription was wrong and the interval caused a
reliability impact. It would no longer be the Entity. The standard does not make such an allowance. History is
Comment: replete with examples of this type of micro managing. Rather than fall into the same trap, and suffer the
consequences of the unknown, it is suggested to allow Entities to optimize their programs to ensure reliability
of the BES. If the NERC wants to create a reliability based standard that addresses reliability impacts, the
SDT is encouraged to create a standard of "disallowed" practices. These would be practices which have a
demonstrated impact on reliability. The SDT should spend to analyzing maintenance practices which have a
known impact on reliability (as evidenced by disturbance reports) and develop requirements which disallow
such practices or range of practices. In addition, if it is shown that an event in which BES reliability was
impacted by the utilities PSMP (as evidenced by disturbance reports), the utility would be required to submit
to the RRO a corrective action plan which addresses how the PSMP will be revised and when compliance
with that PSMP is to be achieved.
2. The intervals prescription for performance based PSMP virtually eliminates the capability of smaller
utilities that do not have a large equipment database to justify a performance based system that may be sound
based on their experience. This overly prescriptive approach should be eliminated and return to allowing
utilities to justify their programs.
3. The Time Horizons are too narrow for the implementation of the standard as written. The SDT appears to
November 17, 2010
5
have not accounted for the data analysis associated with performance based systems. The data collection,
analysis, and subsequent decisions associated development of a maintenance program and its justification do
not occur overnight especially with larger utilities. In addition, this new standard will require complete
rewrite of an entities internal maintenance programs. The internal processes associated with these vary based
on the size of the entity and its organizational structure.
4. Since this standard is so invasive into the internal decisions concerning maintenance, the standard should
allow at least 18 months for entities to rewrite their internal maintenance programs to meet the program
development requirements and 18 months to train the staff in the new program, incorporate the program into
the entities compliance processes, and to implement the new program.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
Thank you for your comment.
1. FERC directed the SDT to establish maximum time intervals between maintenance activities. The
SDT recognized that different types of equipment, different generations of equipment, different
failure modes of equipment, and different versions of time-based maintenance had to be considered.
The SDT agrees with the commenter that the Standard allows statistical analysis, and performancebased maintenance allows an entity to create time intervals that could exceed any “weightedaverages” time-based intervals. The Supplementary Reference adds a Section 9 to show how an
entity can create a performance-based maintenance interval.
2. FERC directed the SDT to establish maximum time intervals between maintenance activities. Smaller
entities may aggregate their component populations with other entities having similar programs – see
Section 9 of the Supplementary Reference document and FAQ IV.3.A. Entities are not required to
use performance-based PSMPs; this option is made available to entities who wish to use it.
3. Your comment appears to address the Implementation Plan, not Time Horizons. The Implementation
Plan for Requirement R1 has been extended from three months to twelve months. For performancebased programs, Attachment A specifies that there must first be acceptable results, and that a timebased program (per the Tables) must be used until then. See FAQ IV.3.B.
4. The Implementation Plan for Requirement R1 has been extended from three months to twelve months.
5
South Mississippi Electric Power Association
Jerry W Johnson
The proposed Standard is overly prescriptive and too complex to be practically implemented. An entity
6
making a good faith effort to comply will have to navigate through the complexities and nuances, as
illustrated by the extensive set of documents the SDT has provided in an attempt to explain all the
requirements and nuances. The need for an extensive “Supplementary Reference Document” and an
extensive “Frequently Asked Questions Document”, in addition to 13 pages of tables and an attachment in the
standard itself, illustrate that the proposal is too prescriptive and complex for most entities to practically
implement.
1. The descriptions for the "type of protection system components" do not appear to be consistent between
Tables, 1a, 1b and 1c.
2. The maximum maintenance interval for a lead-acid vented battery is listed at 6 calendar years for
performing a capacity test. This type of test has been proven to reduce battery life and an interval of 10 to
12 years would be better.
3. The maximum maintenance interval for "Station DC supply" was set at 3 months. This is too short of a
period and 6 months would be better.
4. The control and trip circuits associated with UVLS and UFLS do not require tripping of the breakers but
all other protection systems require tripping of the breakers, this appears to be inconsistent?
5. Digital relays have electromagnetic output relays. Do they fall into the electromechanical trip or solid
state trip?
6. Need for clarification: The standard indicates that only voltage and current signals need to be verified.
Does this mean that voltage and current transformers do not need to be tested by applying a primary
signal and verifying the secondary output?
7. With regard to DPs who own transmission Protection Systems, the standard is still very unclear on when
a DP owns a transmission Protection System. Many DPs own equipment that is included within the
definition of a Protection System; however, ownership of such equipment does not necessarily translate
directly into a transmission Protection System under the compliance obligations of this standard. DPs
need to know if this standard applies to them and right now, there is no certain way of determining that
from within this language or previous versions of this standard.
November 17, 2010
7
8. The phrase “Verify Battery cell-to-cell connection resistance” has entered the table where it did not exist
before. On some types of stationary battery units, this internal connection is inaccessible. On other types
the connections are accessible, but there is no way to repair them based on a bad reading. And bad cellto-cell connections within units will be detected by the other required tests. This requirement will cause
entities to scrap perfectly good batteries just so this test can be performed, with no corresponding
increase in bulk electric system reliability while taking an unnecessary risk to personnel and the
environment. And because buying battery units composed of multiple cells allows space saving designs,
entities may be forced to buy smaller capacity batteries to fit existing spaces. This may end up having a
negative effect on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the
table now.
9. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be
used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which
activities shall we use?
10. Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing. IEEE
battery maintenance standards call for quarterly inspections. These are targets, though, not maximums.
An entity wishing to avoid non-compliance for an interval that might extend past three calendar months
due to storms and outages must set a target interval of two months thereby increasing the number of
inspections each year by half again. This is unnecessarily frequent.
Response:
November 17, 2010
Thank you for your comments. FERC Order 693 and the approved SAR assign the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
2. The SDT disagrees.
3. The SDT disagrees.
4. Your observation is correct. The Tables have been rearranged and considerably revised to improve
clarity. Please see new Table 1-5. This is an intentional difference between UFLS/UVLS and the
remainder of the Protection Systems addressed within the Standard, because of the distributed nature
of UFLS/UVLS and because these devices are usually tripping distribution system elements
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-1.
6. Your observation is correct.
7. Your concern seems to be primarily related to the applicable regional BES definition.
8
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. “Cell” has been replaced with “cell/unit” to address this concern.
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
10. The SDT disagrees. You should complete the activities within the intervals specified.
Segment:
Organization:
Member:
5
RRI Energy
Thomas J. Bradish
For PRC-005-2, while there is nothing inherently wrong with the requirements, RRI voted affirmative with
concern. Our concern is we believe that rather than fixing the issues that caused the 2003 blackout, there is a
continual drift to extensive micro-management to take control of every aspect of the entire industry through
regulation in the name of reliability.
I believe the documentation required to demonstrate 100% compliance to this standard will be a serious
challenge to achieve uniformly for so many components across a widely dispersed fleet, especially in the
Comment: punitive, zero-tolerance compliance world that presently exists. It only takes the things we are in short
supply: time, money, and people. It will drive industry to better systems and performance, but there will be a
painful price, especially on the development side. An example of the impact of this standard: station power
plant batteries are sized to carry large DC loads with the protection system as only a small fraction of the load
profile. Rather than performing a risk assessment for station with low capacity factors (for example RRI has a
two unit station that had an average capacity factor in 2009 of 1.72%) after the battery slightly crosses over
its degradation threshold, there will be no choice but an immediate and expensive replacement. This type of
requirement will push many units into pre-mature retirement or mothballing.
Response:
Segment:
Thank you for your comment.
3
Organization:
Tampa Electric Co.
Member:
Ronald L Donahey
The level of DC circuit testing required every time the relay is tested represents potentially a negative impact
Comment: to reliability given the complicated control circuitry in an energized station. Even though you take out an
element out of service, the DC control circuits are often interconnected for functions such as breaker failure,
November 17, 2010
9
bus and transformer lockouts, etc. This level of testing needs to be done when initial construction but this
increase in testing is not justifiable given the reliability risk and cost. TEC's record for misoperations do to
circuitry failure does not support this need.
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5. The SDT believes that mechanical solenoid-operated devices share performance
attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals.
Performance-based maintenance is an option to increase the intervals if the performance of these devices
supports those intervals.
5
Salt River Project
Glen Reeves
SRP believes the requirements of the Standard are confusing and may be problematic in determining
compliance.
Comment:
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
We also believe the required functional testing of the breaker trip coil may potentially increase maintenance
outages of circuit breakers. In most cases, circuit breaker maintenance outages can be coordinated such that
Protection System maintenance and testing can be done simultaneously. However, in some cases this may not
be possible. Outages of any BES facility whether planned or unplanned can impact system reliability. SRP
suggests that trip coil monitoring devices be included as an acceptable means of ensuring the trip coil is
functioning properly. This will help to avoid unnecessary outages.
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5. The SDT believes that mechanical solenoid-operated devices share performance
attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals.
Performance-based maintenance is an option to increase the intervals if the performance of these devices
supports those intervals.
1, 3, 4, 6
Seattle City Light
Pawel Krupa, Dana Wheelock, Hao Li, Dennis Sismaet
Functional testing is impractical.
10
Response:
Segment:
Organization:
Member:
Thank you for your comment. Functional testing is not the only means of completing the required
maintenance, although it may be the most practical.
3
JEA
Garry Baker
JEA does not believe the standard adequately addresses issues like component, FAQ, etc as identified below:
1.
R1.1 Identify all Protections System components. What is meant by Protection System component?
Is a component a wire, contact, device, etc. A list of components as intended by the SDT would be
illustrative in understanding the SDT’s intent of what a component includes.
2.
Are the FAQ and Supplemental Reference going to be adopted as part of this standard? These
documents contain information that is critical to the proper understanding and interpretation of the
standard, thus either the standard needs to be rewritten to include this information, or the FAQ and
Supplemental Reference need to be adopted as part of this standard. Any inconsistencies between the
FAQ and the standard, as written, would need to be corrected.
3.
The maximum maintenance interval for a lead-acid vented battery is listed as 6 calendar years for
performing a capacity test. This type of test has been proven to reduce battery life and a longer
capacity test interval of 10 to 12 years would be better, allowing for longer battery life.
4.
The implementation period for R1.1 of 3 months is too short and should be extended to one calendar
year; of course this is dependent on the complexity of items listed as part of the definition of
“Protection System component.”
Comment:
Response:
Thank you for your comment.
1. A definition of “Component” has been added to the draft Standard. The SDT’s intent is that this
definition will be used only in PRC-005-2, and thus will remain with the Standard when approved,
rather than being relocated to the Glossary of Terms.
2. These documents provide supporting discussion, but are not part of the Standard. The SDT intends that
these be posted as Reference Documents, accompanying the Standard.
November 17, 2010
11
3. The SDT disagrees.
4. The Implementation Plan for Requirement R1 has been modified from three months to twelve months.
Segment:
Organization:
Member:
5
Public Utility District No. 1 of Lewis County
Steven Grega
1. As written PRC-005-2 does not recognize or accommodate the many type of batteries in use at substations.
To accommodate many of the prescribed tests, the batteries would have to be disassembled to conduct the test
with little valuable information gained. Suggest wording only saying the batteries should be periodically test
to assure that they perform as designed. Let the entities' engineers decide on what is most appropriate for their
batteries.
Comment:
2. Having a standard that requires 100% compliance on 1000's of components is a good way of assuring
many violations. Most protective system can function with half the protection in service. Typically most
engineers over design and have backup upon backup on critical elements. Suggest standard require a lesser
compliance rate; say 90% to 95% during an audit. The elements not in compliance could be followed by a 12
month plan to bring other elements into compliance but the entity at 90% to 95% would still be found
compliant. In summary, this proposed standard has gone beyond the reasonably level of regulation by NERC.
Therefore, I am voting not to affirm the revision to this standard.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
Segment:
Organization:
Member:
Comment:
November 17, 2010
3
City of Farmington
Linda R. Jacobson
As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries are
not able to accommodate all of the tests proscribed in the draft standard as explained by Steve Alexanderson
in a prior e-mail to the ballot pool. The draft standard would cause NERC to regulate through the standards
12
battery testing, DC circuit testing, etc. on distribution elements with no significant improvement to BES
reliability, which is beyond the statutory scope of the standards
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-4. “Cell” has been replaced with “cell/unit” to address this concern. The Standard
only addresses distribution-located devices to the degree that they address BES issues. UFLS and UVLS per
the relevant NERC Standards are frequently implemented on the distribution system.
1
Pacific Gas and Electric Company
Chifong L. Thomas
The requirements in the latest draft are confusing and at times seem to be in conflict with other requirements.
From a compliance and enforcement perspective, this confusion would make the standard difficult to audit.
1. We are concerned over R1.1, where all components must be identified, without a definition for the word
component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. We are concerned whether identification is
required for every individual component, such as each auxiliary relay, or is it sufficient that the auxiliary
relays are included within the scheme that is being tested and documented. Do the auxiliary relays need to be
documented within the maintenance database and/or on the actual test reports of schemes being tested? We
suggest that the FAQ definitions be included within the standard.
Comment:
November 17, 2010
2. We agree with most of the changes from the last draft in Table 1a, 1b and 1c. However, the phrase “Verify
Battery cell-to-cell connection resistance” has entered the table where it did not exist before. On some types
of stationary battery units, this internal connection is inaccessible. On other types the connections are
accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell connections within
units will be detected by the other required tests. This requirement will cause entities to scrap perfectly good
batteries just so this test can be performed, with no corresponding increase in bulk electric system reliability
while taking an unnecessary risk to personnel and the environment. And because buying battery units
composed of multiple cells allows space saving designs, entities may be forced to buy smaller capacity
batteries to fit existing spaces. This may end up having a negative effect on reliability. Suggest substituting
“unit-to-unit” wherever “cell-to-cell” is used in the table now.
13
3. The level 1 table regarding Control and trip circuits with electromechanical trip or auxiliary contacts now
includes exception for microprocessor relays, but there is no listing for the requirements for microprocessor
relays.
4. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be
used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which
activities shall we use?
5. Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
in consideration of your comment.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. “Cell” has been replaced with “cell/unit” to address this concern.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 and 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
5
Pacific Gas and Electric Company
Richard J. Padilla
The level of detail of this standard is over the top and currently conflicts with other standards and is open for
future conflicts. We recommend that the standard DT evaluate the basic rational for the standard and limit its
scope. Some examples are:
Comment:
November 17, 2010
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard as explained by Steve
Alexanderson in a prior e-mail to the ballot pool. The draft standard would cause NERC to regulate
through the standards battery testing, DC circuit testing, etc. on distribution elements with no significant
14
improvement to BES reliability, which is beyond the statutory scope of the standards
2. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components as written, the standard requires testing of batteries, DC control circuits,
etc., of distribution level protection components associated with UFLS and UVLS. UFLS and UVLS are
different than protection systems used to clear a fault from the BES. An uncleared fault on the BES can
have an Adverse Reliability Impact and hence; the focus on making sure the fault is cleared is important
and appropriate. However, a UFLs or UVLS event happens after the fault is cleared and is an inexact
science of trying to automatically restore supply and demand balance (UFLS) or restore voltages (UVLS)
to acceptable levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays
with the same function, there is no significant impact to the function of UFLS or UVLS. Hence, there is
no corresponding need to focus on every little aspect of the UFLS or UVLS systems. Therefore, the only
component of UFLS or UVLS that ought to be focused on in the new PRF-005 standard is the UFLS or
UVLS relay itself and not distribution class equipment such as batteries, DC control circuitry, etc., and
these latter ought to be removed from the standard.
3. In addition, most distribution circuit are radial without substation arrangements that would allow
functional testing without putting customers out of service while the testing was underway, or at least
without momentary outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES reliability
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. “Cell” has been replaced with “cell/unit” to address this concern. The Standard only addresses
distribution-located devices to the degree that they address BES issues. UFLS and UVLS per the
relevant NERC Standards are frequently implemented on the distribution system.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
3. Functional testing is not the only means of completing the required maintenance, although it may be
the most practical.
5
Indeck Energy Services, Inc.
Rex A Roehl
As discussed at the FERC Technical Conference on Standards Development, the goal of the standards
15
program is to avoid or prevent cascading outages--specifically not loss of load. The expansion of this
standard deviates significantly from its purpose of maintaining protective systems that affect BES reliability.
It doesn't recognize that not all relays affect reliability. If reliability is measured by a Reportable Disturbance,
then the threshold varies by control area--largest contingency. The standard should include a process, not
unlike the risk based assessment in CIP-002-2 R1, to include as "identified components" only those affecting
reliability. All of the various reliability criteria should be considered.
Response:
Segment:
Organization:
Member:
Thank you for your comment. “BES reliability” is more than simply avoiding “cascading outages” – as
illustrated by the approved definition of “Adequate Level of Reliability” as promulgated by the NERC
Planning and Operating Committees in response to a directive from FERC, and as described in Section 215 of
the Federal Power Act.
5
Black Hills Corp
George Tatar
1. Draft is confusing & seems to conflict with other requirements. Table 1b Maint. Activities needs to define
whether all protection logic or conditions would initiate a relay trip output are required to be simulated &
Comment: tested to the relay tripping output contact.
2. The Attachment A definition of "common factors" is way too broad to be utilized in defining a grouping of
protection system devices.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
2. The SDT is not clear whether your concern is about “common factors” as used in the definition of
“Segment.” See Section 9 of the Supplementary Reference document for a discussion of
performance-based maintenance.
4
Wisconsin Energy Corp.
Anthony Jankowski
1. Table 1a, Protective Relays:
Change 1st line to: “Test and calibrate if necessary the relays…”
16
Table 1a & 1b, Protective Relays: 3rd line:
Change “check the relay inputs…” to “verify the relay inputs…”
The term “check” is not defined, whereas “verify” is.
Tables 1a & 1b We agree that six / twelve years is an acceptable interval for relay maintenance.
Table 1a & 1b, Control & Trip Circuits: The proposed addition to require tripping circuit breakers during
Protection System maintenance will require outages and is therefore detrimental to BES reliability and should
be removed.
− Generating unit protection system maintenance is done during scheduled outages. The high voltage
breaker on a generating unit often remains energized to back feed and supply station auxiliaries when
the generator is offline. The proposed requirement will increase the amount of equipment requiring an
outage for maintenance, and possibly the length of the outage, resulting in significantly more
equipment out of service as well as increased costs. This requirement also results in greater
maintenance efforts and costs when there are redundant protection system equipment (breaker trip
coils, lockout relays, etc), which is contrary to good practice and reliability.
− Many of the breakers that We Energies, as the Distribution Provider, trips from its BES protection
systems are not owned by We Energies and are owned by a separate transmission company. The trip
testing and maintenance of the transmission company may not coincide with our relay maintenance
testing program. The standard shall have allowances for the entity to ONLY test or maintain
equipment that it OWNS!
Table 1a, Station dc supply:
− The activity to verify the state of charge of battery cells is too vague, and requires more specific
action. We assume that the drafting committee is recommending specific gravity measurements.
Specific gravity measurements have not been shown to be an accurate indicator of state of charge. In
addition, as shown in the nuclear power industry, there is no established corrective action that is taken
based on specific gravity results (eg. Don’t require a test where there is no acceptable corrective
action).
− The activities to “verify battery continuity” and “check station dc supply voltage” are also vague and
need to be more clearly specified what is intended.
− The 3 month time interval for battery impedance testing is too frequent. 18 month or annual testing is
more appropriate.
November 17, 2010
17
− The 3 calendar year performance or service test is too frequent and will actually remove life from a
battery and reduce reliability. Recommend capacity testing no more that every 5 years and more
frequent test if the capacity is within 10% of the end of life or design. This is consistent with the
nuclear power industry.
Table 1b, Station dc supply:
− Recommend a change or addition to Table 1b - Recommend a level 2 monitoring (not just a default to
the level 1 maintenance activities) which allows for the removal of quarterly “check” of electrolyte
levels, DC supply voltage, and DC grounds - if station DC supply (charger) voltage is continuously
monitored (eg. one should not have detrimental gassing of a battery if the float voltage of the battery
is properly set and monitored).
Table 1a, Associated communications systems: The requirement to verify functionality every three months is
excessive; verifying this every twelve months is adequate.
Tables 1a & 1b – Although the latest standard provided some additional clarification, more clarification is
required on what maintenance / testing is ONLY required for UFLS/UVLS protection systems vs. BES
protection systems (eg. UFLS / UVLS systems – Is a verification of proper voltage of the DC supply the only
battery or DC supply test required (e.g. no state of charge, float voltage, terminal resistance, electrolyte level,
grounds, impedance or performance test, etc.)
− The requirement to retain data for the two most recent maintenance cycles is excessive. The required
data should be limited to the complete data for the most recent cycle, and only the test date for the
previous cycle.
2. We Energies does not agree to the implementation plan proposed. While it makes common sense to
proceed with R1 prior to proceeding with implementing R2, R3, and R4, the timeline to be compliant
for R1 is too short. It will take a considerable amount of resources to migrate the maintenance plan
from today’s standard to the new standard in phase one. ATC recommends that time to develop and
update the revised program be increased to at least one year followed by a transition time for the
entity to collect all the necessary field data for the protection system within its first full cycle of
testing. (In ATC’s case would be 6 years)
To address phase two, We Energies believes human and technological resources will be
November 17, 2010
18
overburdened to implement this revised standard as written. The transition to implementing the new
program will take another full testing cycle once the program has been updated. Increased
documentation and obtaining additional resources to accomplish this will be challenging.
Implementation of PRC-005-2 will impact We Energies in the following manner:
a. Increase costs: double existing maintenance costs.
b. Since there will be a doubling of human interaction (or more), it is expected that failures due to
human error will increase, possibly proportionately.
c. Breaker maintenance may need to be aligned with protection scheme testing, which will always
contain elements that are include in the non-monitored table for 6 yr testing.
d. We Energies is developing standards for redundant bus and transformer protection schemes. This
would allow We Energies to test the protection packages without taking the equipment out of service.
Further if one system fails, there is full redundancy available. With the current version of PRC-005-2,
We Energies would need to take an outage to test the protection schemes for a transformer or a bus;
there is not an incentive to install redundant schemes. We Energies is working with a condition based
breaker maintenance program. This program’s value would be greatly diminished under PRC-005-2
as currently written.
3. Consideration also needs to be given for other NERC standards expected to be passed and in the
implementation stage at the same time, such as the CIP standards.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
2. The Implementation Plan for Requirement R1 has been changed from three months to twelve months.
3. This issue should be presented to the NERC Standards Committee.
Segment:
Organization:
Member:
3, 5
Wisconsin Electric Power Marketing, Wisconsin Electric Power Co.
James R. Keller, Linda Horn
1. Table 1a, Protective Relays: Change 1st line to: “Test and calibrate if necessary the relays…”
Comment:
Table 1a & 1b, Protective Relays:
November 17, 2010
19
3rd line: Change “check the relay inputs…” to “verify the relay inputs…” The term “check” is not defined,
whereas “verify” is.
Tables 1a & 1b We agree that six / twelve years is an acceptable interval for relay maintenance.
Table 1a & 1b, Control & Trip Circuits: The proposed addition to require tripping circuit breakers during
Protection System maintenance will require outages and is therefore detrimental to BES reliability and should
be removed.
Generating unit protection system maintenance is done during scheduled outages. The high voltage breaker
on a generating unit often remains energized to back feed and supply station auxiliaries when the generator is
offline. The proposed requirement will increase the amount of equipment requiring an outage for
maintenance, and possibly the length of the outage, resulting in significantly more equipment out of service
as well as increased costs. This requirement also results in greater maintenance efforts and costs when there
are redundant protection system equipment (breaker trip coils, lockout relays, etc), which is contrary to good
practice and reliability.
Many of the breakers that We Energies, as the Distribution Provider, trips from its BES protection systems
are not owned by We Energies and are owned by a separate transmission company. The trip testing and
maintenance of the transmission company may not coincide with our relay maintenance testing program. The
standard shall have allowances for the entity to ONLY test or maintain equipment that it OWNS!
Table 1a, Station dc supply:
− The activity to verify the state of charge of battery cells is too vague, and requires more specific
action. We assume that the drafting committee is recommending specific gravity measurements.
Specific gravity measurements have not been shown to be an accurate indicator of state of charge. In
addition, as shown in the nuclear power industry, there is no established corrective action that is taken
based on specific gravity results (eg. Don’t require a test where there is no acceptable corrective
action).
− The activities to “verify battery continuity” and “check station dc supply voltage” are also vague and
need to be more clearly specified what is intended.
− The 3 month time interval for battery impedance testing is too frequent. 18 month or annual testing is
more appropriate.
November 17, 2010
20
− The 3 calendar year performance or service test is too frequent and will actually remove life from a
battery and reduce reliability. Recommend capacity testing no more that every 5 years and more
frequent test if the capacity is within 10% of the end of life or design. This is consistent with the
nuclear power industry.
Table 1b, Station dc supply:
− Recommend a change or addition to Table 1b - Recommend a level 2 monitoring (not just a default to
the level 1 maintenance activities) which allows for the removal of quarterly “check” of electrolyte
levels, DC supply voltage, and DC grounds - if station DC supply (charger) voltage is continuously
monitored (eg. one should not have detrimental gassing of a battery if the float voltage of the battery
is properly set and monitored).
Table 1a, Associated communications systems: The requirement to verify functionality every three months is
excessive; verifying this every twelve months is adequate.
Tables 1a & 1b – Although the latest standard provided some additional clarification, more clarification is
required on what maintenance / testing is ONLY required for UFLS/UVLS protection systems vs. BES
protection systems (e.g. UFLS / UVLS systems – Is a verification of proper voltage of the DC supply the only
battery or DC supply test required (e.g. no state of charge, float voltage, terminal resistance, electrolyte level,
grounds, impedance or performance test, etc.)
2. The requirement to retain data for the two most recent maintenance cycles is excessive. The required
data should be limited to the complete data for the most recent cycle, and only the test date for the
previous cycle.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
2. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the
Compliance Monitor will need the data of the most recent performance of the maintenance, as well as
the data of the preceding one, as well as data to validate that entities have been in compliance since the
last audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data
November 17, 2010
21
retention in the posted Standard to establish this level of documentation.
Segment:
Organization:
Member:
1, 6
Great River Energy
Gordon Pietsch, Donna Stephenson
1. In Table 1a section-Station DC Supply – 18 calendar months, under Maintenance Activities column,
suggest changing under Verify: Battery terminal connection resistance To: Entire battery bank terminal
connection resistance (This could have been interpreted as individual batteries) And change: Battery
cell-to-cell connection resistance To: Battery cell-to-cell connection resistance, where an external
mechanical connection is available.
2. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid batteries) suggest
changing Max Maintenance Interval=3 Calendar Years or 3 Calendar Months to 4 Calendar Years or 12
Calendar Months. Our concern is that the insurance companies may push NERC maintenance intervals
on all battery banks not associated with the BES.
3. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max Maintenance Interval=6
Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade the
battery.
4. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max Maintenance
Comment:
Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may
degrade the battery.
5. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and trip circuitry)
we suggest the following change: If a trip circuit comprises multiple paths, at least one of those paths is
monitored. Alarming for loss of continuity or dc supply for trip circuits is reported to a location where
action can be taken.
6. While all tripping circuits are not completely monitored, the trip coils and the outdoor cable runs are
completely monitored. The only portion that would not be monitored is a portion of inter and intra-panel
wiring having no moving parts located in a control house. Our company has extremely low failure rate
of panel wiring and terminal lugging. I don’t think that there is provision for moving control and trip
circuitry to performance based maintenance? This control circuitry should be maintained less frequent
than un-monitored trip circuits (6 years).
November 17, 2010
22
Response:
Thank you for your comment.
1.The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. NERC Standards are limited to facilities and equipment related to the BES. How the Standard may be
otherwise used is outside the scope of NERC Standards.
3. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Vented
Lead Acid and Ni-Cad batteries. A properly maintained battery, according to various credible references
(from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle multiple deep discharges over its
expected life.
4. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Ni-Cad
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI,
various manufacturers, etc.), can easily handle multiple deep discharges over its expected life.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 156. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15. Nothing in the draft Standard (including Attachment A) precludes an entity from using performancebased maintenance for dc control circuits.
Segment:
Organization:
Member:
3
Great River Energy
Sam Kokkinen
1. In Table 1a section-Station DC Supply – 18 calendar months, under Maintenance Activities column,
suggest changing under Verify: Battery terminal connection resistance To: Entire battery bank terminal
connection resistance (This could have been interpreted as individual batteries) And change: Battery cell-tocell connection resistance To: Battery cell-to-cell connection resistance, where an external mechanical
Comment: connection is available.
2. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid batteries) suggest
changing Max Maintenance Interval=3 Calendar Years or 3 Calendar Months to 4 Calendar Years or 12
Calendar Months. Our concern is that the insurance companies may push NERC maintenance intervals on all
November 17, 2010
23
battery banks not associated with the BES.
3. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max Maintenance Interval=6
Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade the battery.
4. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max Maintenance
Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade
the battery.
5. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and trip circuitry) we
suggest the following change: If a trip circuit comprises multiple paths, at least one of those paths is
monitored. Alarming for loss of continuity or dc supply for trip circuits is reported to a location where action
can be taken.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 14. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. NERC Standards are limited to facilities and equipment related to the BES. How the Standard may be
otherwise used is outside the scope of NERC Standards.
3. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Vented
Lead Acid and Ni-Cad batteries. A properly maintained battery, according to various credible references
(from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle multiple deep discharges over its
expected life.
4. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Ni-Cad
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI,
various manufacturers, etc.), can easily handle multiple deep discharges over its expected life.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
Segment:
Organization:
November 17, 2010
5
Great River Energy
24
Member:
Cynthia E Sulzer
1. In Table 1a section-Station DC Supply – 18 calendar months, under Maintenance Activities column,
suggest changing under Verify: Battery terminal connection resistance To: Entire battery bank terminal
connection resistance (This could have been interpreted as individual batteries) And change: Battery cell-tocell connection resistance To: Battery cell-to-cell connection resistance, where an external mechanical
connection is available.
2. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid batteries) suggest
changing Max Maintenance Interval=3 Calendar Years or 3 Calendar Months to 4 Calendar Years or 12
Calendar Months. Our concern is that the insurance companies may push NERC maintenance intervals on all
battery banks not associated with the BES.
3. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max Maintenance Interval=6
Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade the battery.
Comment:
4. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max Maintenance
Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade
the battery.
5. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and trip circuitry) we
suggest the following change: If a trip circuit comprises multiple paths, at least one of those paths is
monitored. Alarming for loss of continuity or dc supply for trip circuits is reported to a location where action
can be taken.
6. While all tripping circuits are not completely monitored, the trip coils and the outdoor cable runs are
completely monitored. The only portion that would not be monitored is a portion of inter and intra-panel
wiring having no moving parts located in a control house. Our company has extremely low failure rate of
panel wiring and terminal lugging. I don’t think that there is provision for moving control and trip circuitry to
performance based maintenance? This control circuitry should be maintained less frequent than un-monitored
trip circuits (6 years).
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-
November 17, 2010
25
4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. NERC Standards are limited to facilities and equipment related to the BES. How the Standard may be
otherwise used is outside the scope of NERC Standards.
3. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Vented
Lead Acid and Ni-Cad batteries. A properly maintained battery, according to various credible references
(from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle multiple deep discharges over its
expected life.
4. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Ni-Cad
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI,
various manufacturers, etc.), can easily handle multiple deep discharges over its expected life.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
Nothing in the draft Standard (including Attachment A) precludes an entity from using performance-based
maintenance for dc control circuits.
Segment:
Organization:
1, 3, 5, 6
Dominion Virginia Power, Dominion Resources Services, Dominion Resources, Dominion Resources Inc.
Member: John K Loftis, Michael
F Gildea, Mike Garton, Louis S Slade
1. There is not enough clarity to clearly identify which protection system components are necessary to protect
the BES. We suggest that 4.2.1 be revised to read “protection systems that are designed to provide protection
for the BES.”
2. The Standard does not provide a grace period if an entity is unable to meet the maintenance requirement
for extenuating circumstances. For example if an entity has to divert maintenance resources to storm
Comment:
restoration. We do not believe the reliability of the Bulk Electric System will be compromised if an entities'
maintenance program slips by a few months due to extreme events, especially if it is brought back on track
within a short time frame.
3. We are opposed to the six calendar year maximum maintenance interval for microprocessor relays that
have auxiliaries.
November 17, 2010
26
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The SDT disagrees and believes that the Applicability is correct as stated.
2. “Grace periods” within the Standard are not measurable, and would probably lead to persistently
increasing intervals. However, an entity may establish an internal program with grace-period allowance,
as long as the entire program (including grace periods) does not exceed the intervals within the Standard.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
3
Allegheny Power
Bob Reeping
The draft standard expects 100% compliance for millions of protection system components at all times. The
standard should consider a statistically based performance metric instead of a performance target that expects
100% compliance.
Thank you for your comment. The NERC criteria for VSLs do not currently permit them to allow some level
of non-performance without being in violation.
1
Public Service Company of New Mexico
Laurie Williams
Overall, the inclusion of several types of protective relay systems into one standard is reasonable and should
include those associated with UVLS and UFLS. Even so, the standard is unmanageably cumbersome with far
too many details.
Although it has been said that protection systems include the instrument transformers, DC system and
sometimes the breaker trip coils it is equally as true to say that the protective relay systems depend on those
Comment: to effectively respond to the anomaly, typically a short circuit fault. With that said it is those item’s
maintenance that should potentially be moved to different standards to improve clarity. Their inclusion into
this standard by size and complexity overwhelms this standard. This standard should include only those items
that utilize similar equipment and techniques to maintain. In this case and at this time that means computercontrolled test sets that also generate the records necessary to prove compliance.
Even after distilling the standard to only protective relay systems the complexities and details used to explain
November 17, 2010
27
the non-time-based methodologies contribute to the confusion. But the availability of those methodologies is
important and probably cannot be in a different standard. It therefore seems imperative with the inclusion of
those methodologies that the DC support system maintenance and instrument transformer maintenance have
different standards. The inclusion of so much explanation inside the standard is distracting and perhaps
contributes to the confusion.
PNM also offers the following specific feedback on the proposed standard:
1. -R1.1: Uniquely identifying ‘Protection System components’ as asked for in R1.1 may be problematic
given protective systems may be logged in maintenance databases as packages rather than individual
elements. Because the elements within each package are tested as a group, the requirement to individually list
the components of the package and track them as such would provide no additional benefit to system
reliability.
2. -The activities outlined in Tables which begin on Page 9 of the proposed Standard are difficult to align
with the VSLs given in the standard.
3. -The Tables suggest that test trips of equipment are required as part of the scheduled program, but test trips
of equipment may pose a hazard to the BES if the equipment fails due to multiple test trips or mis-operates to
remove additional BES facilities from service (ex., breaker failure mis-operation during line relay trip
testing), which may pose a potential risk to the BES. An example would be 8 test trips of a generator breaker
in order to make it through the testing of all of the system components that have the ability to trip the
generator lockout and therefore the breaker. Suggest wording to be added that would include some sort of
breaker tripping simulation (test box, lockout simulator, etc.) that could be built into the circuit?
4. -It is still unclear how the audit of an entity’s compliance which occurs during the transition time will be
viewed if it chooses to immediately transition all of its components to the intervals defined in the standard,
but were out of the interval defined by the entity under PRC-005-1?
5. -From the Table 1a – “Verify proper function of the current and voltage signals” is not defined. Is the
verification visual? How is this easily measured on circuits with EM relays still in service?
6. -If exposure to BES is evident during a testing interval, how does the TO or GO coordinate with its
November 17, 2010
28
Reliability Coordinator to delay or push out testing that may compromise the testing due date? Example –
critical transmission circuit is removed from service under forced outage, testing due on adjacent or other
critical circuit where test tripping could compromise BES. What is the documentation procedure to get an
exception or coordinate with RC to mitigate? This has been a big hole in any testing program; there is no way
to file an exception due to unforeseen circumstances like this one.
7. -Is it recommended that there be on PSMP per Company no matter how many Entities they may have or
should there be one PSMP for each entity? Standard is unclear on this issue.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
in consideration of your comment.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5. The VSLs have been modified to correspond.
3. The Standard allows functional testing, if used, to be done in overlapping segments to avoid
specifically the situations you cite.
4. This is a concern that should be submitted to the compliance monitor.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-3. Also please see Section 15.2 of the Supplementary Reference and FAQ II.3.A, II.3.B, II.3.C, and
II.3.D.
6. It would seem prudent to schedule your maintenance to allow for such contingencies. “Grace
periods” within the Standard are not measurable, and would probably lead to persistently increasing
intervals. However, an entity may establish an internal program with grace-period allowance, as long
as the entire program (including grace periods) does not exceed the intervals within the Standard.
7. This is up to the entity. For example, you may choose to have one PSMP for a transmission function
and a separate one for a generation function.
1
PPL Electric Utilities Corp.
Brenda L Truhe
Comment:
PPL EU is voting negative because the definition of Protective Relays is not limited to only those devices that
use electrical quantities as inputs (exclude pressure, temperature, gas, etc).
Response:
Thank you for your comment. The Standard does not preclude entities from maintaining such devices or
November 17, 2010
29
including them in their PSMP.
Segment:
Organization:
Member:
1, 3
Platte River Power Authority
John C. Collins, Terry L Baker
The standard is very difficult to interpret even with all of the supplemental documentation and we believe this
will lead to more non-compliance of the standard without any increase to system reliability and in some cases
Comment:
the required testing will actually reduce system reliability by putting the system at unnecessary risk to
complete the testing.
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5.
1
Nebraska Public Power District
Richard L. Koch
Comment:
The negative vote is based upon functional trip checking and the affect that it will have on the BES.
Response:
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5, which no longer includes any specific requirements for functional testing.
Performance-based maintenance can also be applied to these functions.
Segment:
Organization:
Member:
Comment:
1
National Grid
Saurabh Saksena
1. National Grid does not agree with the proposed implementation plan. The time provided for the first phase
“at least six months” is too open ended and does not give entities a clear timeline. National Grid suggests 1
year for the first phase. National Grid also suggests phasing out the second phase in stages.
2. National Grid does not support the VSL criteria based on "total number of components". Calculating total
number of components will be hugely costly and does not enhance any reliability. It will also take away the
much needed resources required for maintenance.
Response:
November 17, 2010
Thank you for your comment.
30
1. This comment appears to be related to the Implementation Plan for the definition (which was
independent to the Standard), not to the Standard.
2. The SDT believes that the only alternative to these criteria is to provide a binary VSL, which would
mean that any non-compliance would be “Severe”.
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
3
Niagara Mohawk (National Grid Company)
Michael Schiavone
National Grid does not agree with the proposed implementation plan. The time provided for the first phase
“at least six months” is too open ended and does not give entities a clear timeline. National Grid suggests 1
year for the first phase. National Grid also suggests phasing out the second phase in stages.
Thank you for your comment. This comment appears to be related to the Implementation Plan for the
definition (which was independent to the Standard), not to the Standard.
1, 3
MidAmerican Energy Co.
Terry Harbour, Thomas C. Mielnik
For control and trip circuit maintenance the requirement includes “a complete functional trip test”. In order to
accomplish this type of testing given current design of lock-out relay and interrupting device trip circuitry
multiple breakers and line terminal outages would be required simultaneously. In addition this type of testing
has the potential to result in unintentional tripping of equipment that could cause equipment damage and
Comment: customer outages. Segmentation of trip circuits by lifting wires has the potential for incorrect restoration
following testing. This type of testing has the potential to degrade system reliability as multiple entities
schedule this work. An alternate to complete functional testing that does not potentially degrade system
reliability should be substituted.
Response:
November 17, 2010
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5, which no longer includes any specific requirements for functional testing.
Performance-based maintenance can also be applied to these functions. Electromechanical devices such as
aux or lockout relays remains at 6 years, as these devices contain “moving parts” which must be periodically
exercised to remain reliable.
31
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
1
Idaho Power Company
Ronald D. Schellberg
Monitoring the state of charge using current measurement methods would increase the workload and staffing
requirements beyond what we feel is necessary with little additional value to reliability beyond specific
gravity measurements.
Thank you for your comment. The Standard is requiring that state-of-charge be determined, but does not
specify how. Specific gravity testing (no longer required within the Tables) would be one method.
1
Commonwealth Edison Co.
Daniel Brotzman
1. Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission
(NRC). Each licensee operates in accordance with plant specific Technical Specifications (TS) issued
by the NRC which are part of the stations’ Operating License. TS allow for a 25% grace period that
may be applied to TS Surveillance Requirements. Referencing NRC issued NUREGs for Standard
Issued Technical Specifications (NUREG-143 through NUREG-1434) Section 3.0, "Surveillance
Requirement (SR) Applicability," SR 3.02 states the following: "The specified Frequency for each SR
is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as
measured from the previous performance or as measured from the time a specified condition of the
Frequency is met." The NRC Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness
of maintenance to ensure reliable operation of equipment within the scope of the Rule. Adjustments
are made to the PM (preventative maintenance) program based on equipment performance. The
Maintenance Rule program should provide an acceptable level of reliability and availability for
equipment within its scope. The NRC has provided grace periods for certain maintenance and
surveillance activities. Exelon strongly believes that SDT should consider providing this grace period
to be in agreement and be consistent with the NRC methodology. Not providing this grace period will
directly affect the existing nuclear station practices (i.e., how stations schedule and perform the
maintenance activities) and may lead to confusion as implementing dual requirements is not the
normal station process. Nuclear generating stations have refueling outage schedule windows of
approximately 18 months or 24 months (based on reactor type). If for some reason the schedule
32
window shifts by even a few days, an issue of potential non-compliance could occur for scheduled
outage-required tasks. The possibility exists that a nuclear generator may be faced with a potential
forced maintenance outage in order to maintain compliance with the proposed standard.
For the requirements with a maximum allowable interval that vary from months to years (including 18
Months surveillance activities), the SDT should consider an allowance for NRC-licensed generating
units to default to existing Operating License Technical Specification Surveillance Requirements if
there is a maintenance interval that would force shutting down a unit prematurely or face noncompliance with a PRC-005 required interval. Therefore, at a minimum, maintenance intervals should
include an allowance for any equipment specifically controlled within each licensee’s plant specific
Technical Specifications to implement existing Operating License requirements if such a conflict were
to occur.
2. Additionally we are requesting to have the first phase of implementation extended from 6 months to 1
year. This will provide adequate time for development of documentation, training for all personnel,
and testing the implementation of the new process (es).
Response:
Thank you for your comments.
1. The SDT understands that nuclear power plants are licensed and regulated by the NRC, has a general
understanding of the role that plant Technical Specifications (TS) and associated Surveillance
Requirements (SR) play in the facilities’ operating licenses, and has tried to be sensitive to potential
conflicts between PRC-005-2 and NRC requirements.
The SDT believes that the majority of components making up the Protection Systems for in-scope
generating facilities as discussed in Section 4.2.5 of the Standard would be considered balance of plant
equipment and, therefore, not subject to NRC issued TS and associated SR requirements. While
availability of plant auxiliary sources to the plant’s safety related equipment is addressed by TS and
associated SR requirements, these documents are focused on the effects that the availability of these
transformers have on reactor safety rather than specifying maintenance and testing requirements for the
Protection Systems for these transformers.
The SDT recognizes that some battery systems may serve as a source of DC power to both reactor
November 17, 2010
33
safety systems and to protection systems discussed in Section 4.2.5. The SDT acknowledges that there
might be plant TS and SR applicable to these batteries. However, the SDT believes that the 3-month
and 18-month inspection requirements called for in PRC-005-2 would be no more onerous than plant
TS requirements for routine online safety system battery inspections and, furthermore, would not
necessitate a plant outage. The SDT recognizes that the PRC-005-2 requirement for validating battery
design capability via battery capacity testing would require a plant outage. However, it is the opinion
of the SDT that the maximum allowed battery capacity testing intervals of not to exceed 6 calendar
years for vented lead acid or NiCad batteries (not to exceed 3 calendar years for VRLA batteries) could
easily be integrated within the plant’s routine 18 month to 2 year interval refueling outage schedule.
The SDT believes that PRC-005-2 is complimentary to the NRC Maintenance Rule in that PRC-005-2
requirements allow for the leveraging of the entire electrical power industry experience in establishing
minimum maintenance activities and maximum allowed maintenance intervals necessary to ensure
reliable protection system performance.
Please see Supplemental Reference Section 8.4 for further discussion for the SDT’s rationale for
exclusion of grace periods.
Please see FAQ IV.2.C for further discussion of impact of PRC-005-2 testing requirements on power
plant outage schedules. The challenge of integrating PRC-005-2 testing requirements with a plant’s
outage schedule is not unique to nuclear plants.
Finally, the SDT notes that an entity may build grace periods into its own PSMP as long as the
maximum allowed time intervals of PRC-005-2 are not exceeded. If an entity wishes to build a 25%
grace period into its program, it may do so by setting its program maintenance and testing intervals at
<80% of the PRC-005-2 maximum allowable time interval.
2. The Implementation Plan for R1 has been modified to 12 months.
Segment:
Organization:
Member:
November 17, 2010
1, 3, 6
Cleco Power LLC, Cleco Utility Group, Cleco Power LLC
Danny McDaniel, Bryan Y Harper, Matthew D Cripps
34
1. The revised definition to Protection System should include the following exception. "Devices that sense
non electrical conditions, such as thermal or transformer sudden pressure relays are not included." The
Drafting Team has included this note in the standard, but not in the definition. For consistence across the
standards, see PRC-004, which references System Protection, the same definition should be used.
2. See Table 1a, Station dc supply. One of the checks is to verify battery cell-to-cell connection resistance.
Comment: This is not possible in all battery sets.
3. As written, the standard requires testing of batteries, DC control circuits, etc., of distribution level
protection components associated with UFLS and UVLS. This is beyond the scope of the Reliability
Standards which should focus on the BES. Only include the UFLS or UVLS relays in the program.
4. Revise M1 to reference Protection System definition.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The definition of “Protection System” has been modified essentially as you suggest.
2. “Cell” has been replaced with “cell/unit.”
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-4 and 1-5.
1
BC Transmission Corporation
Gordon Rawlings
1. - Purpose unclear “affecting the reliability of the BES” is open to interpretation should read “applied on or
designed to provide protection of the BES”
2. - Monitoring levels (1, 2 and 3) are not clear
Comment:
3. - Maintenance activities are not well defined
4. - Some utilities base their maintenance program on a fiscal year where all scheduled maintenance for the
fiscal year must be completed by the end of the fiscal year. It would take considerable effort to switch to end
of calendar year with zero improvement in overall reliability.
November 17, 2010
35
5. - For maintenance scheduled in terms of a number of months, requiring that maintenance be completed by
the end of scheduled month does not leave much margin if maintenance is delayed for a legitimate reason.
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
Thank you for your comment.
1. The purpose can be general; Requirement R1 is worded as you suggest.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5. Various sections of the FAQ have provided suggestions about how to conduct the
activities in the tables.
4. With the vast array of entities subject to compliance monitoring, it would be very difficult for the
ERO to assess compliance for varying “years.” Additionally, the SDT understands that most
compliance monitors currently request data on a calendar year basis when assessing compliance.
5. The entity is encouraged to schedule the maintenance activities to allow for contingencies.
1
Associated Electric Cooperative, Inc.
John Bussman
There needs to be grace periods for the battery testing of 3 months. Testing a complete transmission system
over 3 states in every 3 months and not be one day past due will b a challenge.
Thank you for your comment. The 3-month maintenance for station dc supply is comprised of inspections
that don’t require testing.
1, 3, 5
Arizona Public Service Co., APS
Robert D Smith, Thomas R. Glock, Mel Jensen
1. The generator Facilities subsections 4.2.5.1 through 5 are too prescriptive and inconsistent with sections
4.2.1 through 4. Recommend this section be limited to description of the function as in the preceding
sections.
2. In addition, the associated maintenance activities in Table 1 are too prescriptive.
November 17, 2010
36
3. The activities needed to ensure the reliable service of the relay or device should be left up to the discretion
of the utility. One example, due to the change to the Protection System definition and establishing a new
PSMP with prescriptive maintenance activities relative to the voltage and current sensing devices has created
a situation where data from original or prior verification is not available or not at the interval to meet the data
retention requirement. Although, methods of determining the integrity of the voltage and current inputs into
the relays were used to ensure reliability of the devices met the utilities performance requirements, they may
not meet the interval requirement and would then be considered a violation due to changes in the standard.
4. For data requirements, an initial exemption is recommended for the two recent most recent performances
of maintenance activities in the first maintenance interval for this component due to the long maintenance
interval, the changes in the standard definitions and the prescriptive maintenance activities.
5. Clarification is needed on “Note 1” in Table 1a, which appears to be used to define a calibration failure.
How would it be used in Time Based Maintenance? In PRC-005-2 Attachment A: Criteria for a PerformanceBased Protection System Maintenance Program, a calibration failure would be considered an event to be used
in determining the effectiveness of Performance Based Maintenance. It is unclear in how it will be used in
time based maintenance.
Response:
November 17, 2010
Thank you for your comment.
1. The SDT believes that transmission lines, UFLS, UVLS, and SPS are clear without additional
granularity, but that the additional granularity regarding generation plants is necessary. This is
illustrated by numerous questions regarding “what is included for generation facilities” relative to
PRC-005-1.
2. FERC Order 693 and the approved SAR assigned the SDT to develop a Standard with maximum
allowable intervals and minimum maintenance activities.
3. FERC Order 693 and the approved SAR assigned the SDT to develop a Standard with maximum
allowable intervals and minimum maintenance activities. It seems reasonable that you cannot be held
accountable for a requirement before it becomes effective.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the
Compliance Monitor will need the data of the most recent performance of the maintenance, as well as
the data of the preceding one, as well as data to validate that entities have been in compliance since
the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified the
data retention in the posted Standard to establish this level of documentation. The Tables have been
rearranged and considerably revised to improve clarity, and the cited note removed. Please see new
37
Tables 1-5.
Segment:
Organization:
Member:
1
American Transmission Company, LLC
Jason Shaver
ATC does not support the existing 2nd Draft of PRC-005-2 Standard because it is our opinion that:
• There is a high probability that system reliability will be reduced with this revised standard.
• The number of unplanned outages due to human error will increase considerably.
Comment:
• Availability of the BES will be reduced due to an increased need to schedule planned outages for test
purposes (to avoid unplanned outages due to human error).
• To implement this standard, an entity will need to hire additional skilled resources that are not readily
available. (May require adjustments to the implementation timeline.)
• The cost of implementing the revised standard will approximately double our existing cost to perform this
work. ATC requests that relevant reliability performance data (based on actual data and/or lessons learned
from past operating incidents, Criteria for Approving Reliability Standards per FERC Order 672) be provided
to justify the additional cost and reliability risks associated with functional testing.
Response:
Segment:
Organization:
Member:
Thank you for your comment. The SDT believes that performing these maintenance activities will benefit the
reliability of the BES.
1, 5, 6
American Electric Power, AEP Service Corp, AEP Marketing
Paul B. Johnson, Brock Ondayko, Edward P. Cox
AEP supports the progress of this draft standard, largely supports much of the elements within. However, we
provide the following summary of the comments provided in response to the most recent (2nd) draft, which
Comment: we suggest the SDT consider.
1. In Table 1a for the component “Station dc Supply (used only for UVLS and UFLS)”, the interval
November 17, 2010
38
prescribed is "(when the associated UVLS or UFLS system is maintained)" and the activity is to "verify the
proper voltage of the dc supply". The description of the interval "(when the associated UVLS or UFLS
system is maintained)" needs to be changed. Relay personnel do not generally take battery readings. The
interval should read “according to the maximum maintenance interval in table 1a for the various types of
UFLS or UVLS relays". The testing does not need to be in conjunction with the relay testing, it is only the
test interval that is important, although relay operation during relay testing is a good indicator of sufficient
voltage of the battery.
2. The monitoring and/or maintenance activities listed for batteries are not appropriate in Tables 1b and 1c.
There are no commercial battery monitors that monitor and alarm for electrolyte level of all cells. Why not
move the electrolyte level to the 18 month inspection and actually open the possibility of condition
monitoring to commercially available devices? Or give an option to do the electrolyte check at other time
intervals (perhaps 12 months) by visual electrolyte inspection and still allow the monitoring of other
functions on the listed 6 year schedule using condition monitoring. It makes no sense to prescribe an
unattainable condition monitoring solution. The way that the tables are written, there is no advantage to use
the charger alarms since battery maintenance requirements are not reduced in any way.
3. In regards to "Measures and Data Retention", the measure includes the entire definition of "Protection
System". Remove the definition from the measure and let the definition stand alone in the NERC glossary.
4. In regards to Data Retention, this calls for past 2 distinct maintenance records to be kept. Since UFLS
interval can be 12 years, this would mean that we would need to keep records for 24 years. This is not
realistic and consideration should be given to choosing a reasonable retention threshold.
5. The "Supplementary Reference" and the "Frequently-Asked Questions" document should be combined into
a single document. This document needs to be issued as a controlled NERC approved document. AEP
suggests that the document be appended to the standard so it is clear that following directions provided by
NERC via the document are acceptable, and to avoid an entity being penalized during an audit if the auditor
disagrees with the document’s contents.
6. NiCAD batteries should not be treated differently from Lead-Acid batteries. NiCAD battery condition can
be detected by trending cell voltage values. Ohmic testing will also trend battery conditions and locate failed
cells (although will usually lag behind cell voltages). A required load test is detrimental to the NiCAD
November 17, 2010
39
manufacturer's business, and will definitely hurt the NiCAD business for T&D applications. Historically
NiCADs may have been put into service because of greater reliability, smaller space constraints, and wider
temperature operation range. “Individual cell state of charge” is a bad term because it implies specific gravity
testing. Specific gravity cannot be measured automatically (without voiding battery warranty or using an
experimental system), and when it is measured, it is unreliable due to stratification of the electrolyte and
differing depths of electrolyte taken for samples. “Battery state of charge” can be verified by measuring float
current. Once the charging cycle is over the battery current drops dramatically, and the battery is on float,
signaling that the battery has returned to full state of charge. This is an appropriate measure for Level 3
monitoring as float current monitoring is a commercially viable option and electrolyte level monitoring is not.
7. In Table 2b, why is Ohmic testing required if the battery terminal resistance is monitored? Cell to cell and
battery terminal resistance should not be monitored because they will be taken in 18 month intervals. This
further supports the argument that the battery charger alarms would be sufficient for level 2 monitoring, while
keeping an 18 month requirement for Ohmic testing, electrolyte level verification, and battery continuity
(state of charge). Automatic monitoring of the float current should be sufficient for level 3 monitoring as it
gives state of charge of the string, and battery continuity (detect open cells). Shorted cells will still be found
during the Ohmic testing and a greater interval is sufficient to locate these problems.
Response:
November 17, 2010
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
3. The SDT modified the Measure as you suggested.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the
Compliance Monitor will need the data of the most recent performance of the maintenance, as well as
the data of the preceding one, as well as data to validate that entities have been in compliance since
the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified the
data retention in the posted Standard to establish this level of documentation. The SDT disagrees that
the documents should be combined. The Supplementary Reference is a holistic presentation of
rationale and basis for the various elements of the Standard – discussing mostly the “what” behind the
requirements. The FAQ, on the other hand, presents responses to specific frequently asked questions,
and, as such, offers more-focused advice on specific subjects, and is more of an example/how-to
discussion. The FAQ is primarily a means of capturing some of the most prevalent comments offered
40
on the Standard by various entities, with the SDT’s response. The SDT believes that the format of the
FAQ is a more effective means of presenting the included information than it would be to include this
information within the text of the Supplementary Reference document.
5. The SDT believes that since the IEEE Stationary Battery Committee has determined that VRLA
batteries and Ni-Cad batteries are different enough to require separate IEEE Standards (IEEE 1188
and IEEE 1106, respectively), these battery technologies are different enough to be treated separately
within PRC-005-2. The SDT has drawn upon these IEEE Standards, as well as other sources (EPRI,
etc) to develop the requirements of PRC-005-2. The trending activity cited has not been shown to be
effective for Ni-Cad batteries (see FAQ II.5.G), and thus a performance test must be performed; the
performance test may take many forms. The Tables have been rearranged and considerably revised to
improve clarity, and all references to specific gravity have been removed. Please see new Table 1-4.
Determining the “state of charge” by monitoring the float voltage may be relevant to the overall
station battery, but does not provide an indication of the condition of individual cells as required
within the new Table 1-4.
6. Battery terminal resistance shows the condition of the external connections, but reveals nothing
regarding the internal condition of the individual cells. Measuring the internal cell/unit resistance
provides an opportunity to trend the cell condition over time by verifying the electrical path through
the electrolyte within the battery. The ohmic testing is not intended to look for open cells/units, but
instead at the ability of the individual cell/unit to perform properly. The new Table 1-4 clarifies that,
if the electrolyte level is monitored, the internal ohmic testing need only be performed every six years.
Please see FAQ II.5.B, II.5,C and II.5.D for a discussion about continuity.
Segment:
Organization:
Member:
1
Ameren Services
Kirit S. Shah
We commend the SDT for developing a generally clear and well documented second draft. The SDT
considered and adopted many industry comments on the first draft. It generally provides a well reasoned and
balanced view of Protection System Maintenance, and good justification for its maximum intervals. Ameren
Comment: generally agrees that this second draft will be beneficial to BES reliability, but several inconsistencies,
unclear items, and a couple issues need to be addressed before we will be able to support it.
(a)The tables still contain several inconsistencies and items needing clarification
November 17, 2010
41
(b)Implementation of the PSMP must align with the start of a calendar year
(c) The expectation of perfection in maintaining the extremely high volume of Protection System parts is
inconsistent with accepted engineering practice (a fundamental tenet is that tolerances must be allowed for)
(d)The Project 2009-17 interpretation that clarifies the transmission Protection System border must be
incorporated.
(e)Generating Plant system-connected Station Service transformers should not be included as a Facility
because they are serving load.
Thank you for your comment.
a. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
b. The SDT Guidelines, which were endorsed by the NERC Standards Committee in April 2009,
establishes that proposed effective dates “must be the first day of the first calendar quarter after
entities are expected to be compliant.” The Implementation Plan is in accordance with these
guidelines.
c. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
Response:
without being in violation.
d. When the interpretation (Project 2009-17) is approved, the SDT for PRC-005-2 will consider if the
interpretation is appropriate for PRC-005-2 and make associated changes.
e. The “load” being served by the Station Service Transformer may be essential to operation of the
generating plant, and therefore is not the same as general distribution system load. Therefore, the
SDT believes that these system components must remain within the Applicability section of the
Standard.
Segment:
Organization:
Member:
Comment:
November 17, 2010
3
Florida Power Corporation
Lee Schuster
Progress Energy does not believe that the definition should be implemented separately from and prior to the
implementation of PRC-005-2. We believe there should be a direct linkage between the definition’s effective
date to the approval and implementation schedule of PRC-005-2. Since this new definition should be directly
42
linked to the proposed revised standard, it would be premature to make this new definition effective prior to
the effective date of the new standard. We believe that changes to the maintenance program should be driven
by the revision of the PRC standard, not by the revision of a definition.
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Thank you for your comment. When the Board of Trustees was asked to approve an interpretation of PRC005-1 that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the
drafting team caused by the definition of "Protection System" and directed that work to close this reliability
gap should be given priority. To close this reliability gap the revised definition must be applied to PRC-0051 as soon as practical - not years from now. The Implementation Plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
1, 3, 5, 6
Bonneville Power Administration
Donald S. Watkins, Rebecca Berdahl, Francis J. Halpin, Brenda S. Anderson
Please see BPA's comments submitted during the concurrent formal NERC comment period ending July 16,
2010.
Thank you for your comment. Please see our responses on the Consideration of Comments from the cited
comment period.
6
Northern Indiana Public Service Co.
Joseph O'Brien
1. It appears that some batteries are not able to accommodate all of the tests required in this standard.
Comment:
Response:
2. The standard also unreasonably requires 100% compliance for millions of protection system components.
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
November 17, 2010
43
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
6
Lakeland Electric
Paul Shipps
As written, is opens the standard to Technical Feasibility Exceptions due to some batteries not being able to
accommodate all of the tests proscribed in the draft standard
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-4. “Cell” has been replaced with “cell/unit” to address this concern. The Standard
only addresses distribution-located devices to the degree that they address BES issues. UFLS and UVLS per
the relevant NERC Standards are frequently implemented on the distribution system.
4
Fort Pierce Utilities Authority
Thomas W. Richards
1. The battery test procedure that calls for intra-cell resistance cannot be performed on batteries that have
internal cell-to-cell straps. A brief rewording of the requirement would take care of this. We recommend the
minimum requirement be changed to measure the internal resistance at the battery terminal. The reading of
individual cells is of little use anyway since a bad reading will result in having to replace the entire jar.
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit testing,
etc. on distribution elements with no significant improvement to BES reliability, which is beyond the
statutory scope of the standards.
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components. The audit becomes an investigation at this point and is not feasible even for
mid-sized entities that have hundreds of components subject to this standard.
Response:
November 17, 2010
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. “Cell” has been replaced with “cell/unit” to address this concern.
2. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
44
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
Segment:
Organization:
Member:
5
PowerSouth Energy Cooperative
Tim Hattaway
The maintenance and testing requirements are too prescriptive and leave little room for an entity to make
decisions regarding what type maintenance and testing they deem appropriate. Some of the maintenance and
testing methods and intervals as defined in the standard, e.g. the standard calls for a maximum 3 month
testing interval for sealed station batteries if performing impedance testing, do not seem to improve reliability
Comment:
at all.
The migration from compliance with the present standard to version 2 as prescribed would be a monumental
administrative task
Response:
Segment:
Organization:
Member:
Thank you for your comment. FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
5
Liberty Electric Power LLC
Daniel Duff
Comment:
Required tasks are overly prescriptive.
Response:
Thank you for your comment. FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
Segment:
Organization:
Member:
Comment:
November 17, 2010
5
ExxonMobil Research and Engineering
Martin Kaufman
In the past, NERC has taken care to avoid instructing an entity on how to create its compliance program. The
draft standard PRC-005-2 departs from this tradition and partially defines a maintenance and testing program
that all entities will be required to follow until such a time that the entity has collected enough data to
45
implement the performance based method defined in Attachment A.
Additionally, some of the maintenance and testing intervals defined in the tables (e.g. station battery testing)
mimic industry recommended test intervals instead of defining maximum acceptable testing intervals.
Response:
Segment:
Organization:
Member:
Thank you for your comment. FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
4
Y-W Electric Association, Inc.
James A Ziebarth
From Question 1 on the comment form:
Many of the changes to the proposed standard are reasonable and improve the clarity of the standard and its
requirements. However, Y-WEA concurs with others on their comments regarding the testing of battery cellto-cell connection resistance. Many types of stationary batteries are actually blocks of two or more cells that
are internally connected. This requirement would necessitate either some sort of feasibility exception process
(which, as shown by the TFE process with the CIP standards can be very difficult, cumbersome, and timeconsuming to develop and administer) or replacement of the batteries in question, which would pose
enormous burdens on small entities that must comply with this standard. The language in this requirement
should be changed from “cell-to-cell” to “unit-to-unit” in order to avoid these issues.
From Question 7 on the comment form:
Comment: 1. Y-WEA concurs with others regarding the timing of required battery tests. The IEEE standards referenced
indicate target maintenance intervals. In order to remain reasonable, then, this compliance standard needs to
allow some buffer between a targeted maintenance and inspection interval and a maximum enforceable
maintenance and inspection interval. The suggestion of a four-month maximum window is reasonable and
should be incorporated into the standard.
2. Y-WEA is also concerned with R1.1’s language indicating that all components must be identified with no
defined “floor” for the significance of a component to the Protection System. The SDT cannot possibly
expect that a parts list containing every terminal block, wire and jumper, screw, and lug is going to be
maintained with every single part having all the compliance data assigned to it, but without clearly stating
this, that is exactly the degree of record-keeping that some overzealous auditor could attempt to hold the
registered entity to. The FAQ is much clearer as to what is and is not a component and should be considered
November 17, 2010
46
for the standard.
3. Y-WEA also concurs with others' comments regarding the testing of batteries and DC control circuits
associated with UFLS relaying. Many UFLS relays are installed on distribution equipment. Furthermore,
many distribution equipment vendors are including UFLS functions in their distribution equipment. For
example, many recloser controls incorporate a UFLS function in them. These controls and the reclosers they
are attached to, however, are strictly distribution equipment. 16 USC 824o (a)(1) limits the definition of the
Bulk-Power System to “not include facilities used in the local distribution of electric energy.” A distribution
recloser and its control clearly fall into this exclusion. 16 USC 824o (i) (1) prohibits the ERO from
developing standards that cover more than the Bulk-Power System. As such, the DC control circuitry and
batteries associated with many UFLS relaying installations are precluded from regulation under NERC’s
reliability standards and may not be included in this standard because they are distribution equipment and
therefore not part of the Bulk-Power System. The proposed standard needs to be rewritten to allow for this
exclusion and to allow for the testing of only the UFLS function of any distribution class controls or relays.
Response:
Thank you for your comment.
From Question 1 - The Tables have been rearranged and considerably revised to improve clarity. Please
see new Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or
unit-to-unit connection resistance (where available to measure)” to address this comment.
From Question 7 –
1. The SDT disagrees. You should complete the activities within the intervals specified.
2. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
in consideration of your comment.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-4 and 1-5.
Segment:
Organization:
Member:
Comment:
November 17, 2010
4
Old Dominion Electric Coop.
Mark Ringhausen
While the SDT has made progress, there are still some areas that need additional work:
47
1. Battery testing of the cell to cell should be unit to unit or some other words for battery system locations
that do not allow cell to cell testing.
2. Battery checks on a three months period seems to aggressive and should be moved to six months.
3. Clarify your intent to test the CTs and PTs as some commenters have read it that one does not have to test
these pieces of equipment per this standard.
4. Require UFLS and UVLS testing to trip the breaker/recloser when this can be done without tripping of
load (by-pass is available).
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The SDT disagrees. You should complete the activities within the intervals specified.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-3.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
3
Springfield Utility Board
Jeff Nelson
Comment:
Please see SUB's comments on the comment form
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
Comment:
Response:
November 17, 2010
3
Salem Electric
Anthony Schacher
The standard is getting better but leaves to many holes for utilities that do not have specific equipment and
would need to file a TFE to exempt their facilities.
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Tables 1-1 through 1-5.
48
Segment:
Organization:
Member:
3
Public Utility District No. 2 of Grant County
Greg Lange
Although this version is a significant improvement in several areas from the past version there are still several
things that need clarification or overhaul.
Comment:
1. We find an inconsistency between the component based approach to version 2 and the way protective
systems are maintained. The description of components still needs work as well.
2. It appears that in the new version battery chargers and cables could be professionally judged to be a part of
the circuitry. We don't believe this is the intent, but again leaves too much to the imagination of an
overzealous auditor. Truly most of our issues are with the definition, but until that is corrected we cannot vote
for either.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. A definition of “Component” has been added to the Standard and the Tables have been rearranged and
considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
2. The dc supply component specifically includes battery chargers within the new Table 1-4.
3
Public Utility District No. 1 of Chelan County
Kenneth R. Johnson
Comments:
1. It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are
included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that
particular standard to protection systems that sense electrical quantities, it is remains unclear in other
Comment: standards that use the defined term whether mechanical input protections are included.
2. We suggest that “Protective Relay” also be defined, and that the definition clearly exclude devices that
respond to mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG
request.
Response:
November 17, 2010
Thank you for your comment.
1. The definition of Protection System has been modified to specifically limit it to protective relays that
49
respond to electrical quantities.
2. IEEE has provided a definition of protective relay, and the SDT sees no need to repeat or change that
definition within this Standard.
Segment:
Organization:
Member:
3, 3
Municipal Electric Authority of Georgia, MEAG Power
Steven M. Jackson, Steven Grego
1. Station DC supply testing was set at three months. A six month time based testing interval is reasonable.
2. Maximum maintenance interval for a lead-acid vented battery is listed at six calendar years. This type of
test reduces battery life. A 10 to 12 year interval is reasonable. As written this rule would require a TFE that
should be administratively unnecessary.
Comment:
3. Additional clarification is needed in: Control and trip circuits associated with UVLS and UFLS do not
require tripping of the breakers but all other protection systems require tripping. Please clarify.
4. Digital relays have electromagnetic output relays - are they categorized as electromechanical or solid state?
5. There needs to be reasonable flexibility based on industry experience in allowing less than 100%
perfection in the testing of relays, etc.
Response:
Segment:
Organization:
November 17, 2010
Thank you for your comment.
1. The SDT disagrees.
2. The SDT disagrees.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-1.
5. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
3, 4, 5
Cowlitz County PUD
50
Member:
Russell A Noble, Rick Syring, Bob Essex
Cowlitz agrees with most of the changes; however there are many issues from the last comment round that
needs to be addressed with a response from the SDT. In particular, Cowlitz is concerned with the following:
1. Verify Battery cell-to-cell connection resistance” has entered the table where it did not exist before. On
some types of stationary battery units, this internal connection is inaccessible. On other types the connections
are accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell connections
within units will be detected by the other required tests. This requirement will cause entities to scrap perfectly
good batteries just so this test can be performed, with no corresponding increase in bulk electric system
reliability while taking an unnecessary risk to personnel and the environment. And because buying battery
units composed of multiple cells allows space saving designs, entities may be forced to buy smaller capacity
batteries to fit existing spaces. This may end up having a negative effect on reliability. Suggest substituting
“unit-to-unit” wherever “cell-to-cell” is used in the table now.
Comment:
2. The level two table regarding Protection Station dc supply states that level one maintenance activities are
to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level one; which
activities shall Cowlitz use? Same situation for Station DC Supply (battery is not used) where the 18 month
interval is missing.
3. IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not
maximums. An entity wishing to avoid non-compliance for an interval that might extend past three calendar
months due to storms and outages must set a target interval of two months thereby increasing the number of
inspections each year by half again. This is unnecessarily frequent. Cowlitz suggests changing the maximum
interval for battery inspections to six calendar months. For consistency, Cowlitz also suggests that all
intervals expressed as three calendar months be changed to six calendar months.
4. Cowlitz is concerned over R1.1, where all components must be identified, without a definition for the word
component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. Cowlitz believes this will allow REs to claim
non-compliance for every three inch long terminal jumper wire not identified in a trip circuit path. Cowlitz
suggests that the FAQ definitions be included within the standard.
5. Many Distribution Providers do not own Protection Systems on the transmission side that are active
devices, but rather are passive in nature, i.e., fuses. This Standard verbiage will make it necessary for all DPs
November 17, 2010
51
to have a PSMP even if they do not own active Protective Systems that at least states that they have a null
listing of components. This is useless paperwork.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
3. The SDT disagrees. You should complete the activities within the intervals specified.
4. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component
types” in consideration of your comment.
5. Fuses are not a Protection System component. The SDT is not addressing what an entity that owns no
relevant components must do to demonstrate that for compliance.
Segment:
3
Organization:
Consumers Energy
Member:
David A. Lapinski
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided,
Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented.
Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead to
provide operating flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will be very
cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely lead
to entities NOT installing the redundant schemes, resulting in decreased reliability.
Comment:
2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include
sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply),
what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not
present.” Similarly, it isn’t clear from the general description within the Tables that components possessing
different monitoring attributes within a single scheme may be distinguished such that differing relevant tables
November 17, 2010
52
can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.
Battery assemblies supplied by some manufacturers have the connections made internally, making this option
unavailable. Experience with ASME standards show that NERC and SDT members may be jointly and
separately liable for litigation by specifying methods that either prefer or prohibit use of certain technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“ conclude
with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
such activities therefore require tripping of circuit breakers or other interrupting devices?
5. Performance of the minimum activities specified within Table 1a for legacy systems, particularly regarding
control circuits, will require considerable disconnection and reconnection of portions of the circuits. Such
activities will likely cause far more problems on restoration-to-service than they will locate and correct. We
suggest that the SDT reconsider these activities with regard for this concern.
6. We do not agree that Footnotes within the Standard are an appropriate method of providing information
that is important to the application of the Standard. Important information should be provided within the
standard text.
Response:
Thank you for your comment.
1. The SDT believes that it is important that all parallel paths be maintained within the indicated interval,
and the prescribed interval already considers the reliability benefits of parallel tripping paths.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
3. The use of the term “cell/unit” acknowledges that individual cells may not be accessible, but that
assemblies of several cells (into units) may be available instead, and may be used to address this
requirement. An acceptable baseline value and follow-on tests may be acceptable for the entire station
battery as a single unit.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
November 17, 2010
53
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15. To the degree that performance history for the components within these systems is available, a
performance-based program per R3 and Attachment A may be useful in these cases.
6. The SDT removed all footnotes from the Standard.
Segment:
Organization:
Member:
5
Consumers Energy
James B Lewis
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided,
Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented.
Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead to
provide operating flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will be very
cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely lead
to entities NOT installing the redundant schemes, resulting in decreased reliability.
2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include
sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply),
what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not
Comment:
present.” Similarly, it isn’t clear from the general description within the Tables that components possessing
different monitoring attributes within a single scheme may be distinguished such that differing relevant tables
can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.
Battery assemblies supplied by some manufacturers have the connections made internally, making this option
unavailable. Experience with ASME standards show that NERC and SDT members may be jointly and
separately liable for litigation by specifying methods that either prefer or prohibit use of certain technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“ conclude
with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
November 17, 2010
54
such activities therefore require tripping of circuit breakers or other interrupting devices?
5. Performance of the minimum activities specified within Table 1a for legacy systems, particularly regarding
control circuits, will require considerable disconnection and reconnection of portions of the circuits. Such
activities will likely cause far more problems on restoration-to-service than they will locate and correct. We
suggest that the SDT reconsider these activities with regard for this concern.
5. We do not agree that Footnotes within the Standard are an appropriate method of providing information
that is important to the application of the Standard. Important information should be provided within the
standard text.
6. As for the definition, it is unclear whether “voltage and current sensing inputs” include the instrument
transformer itself, or does it pertain to only the circuitry and input to the protective relays.
7. As for the definition, it is not clear what is included in the component, “station dc supply” without
referring to other documents (the posted Supplementary Reference and/or FAQ) for clarification. The
definition should be sufficiently detailed to be clear.
8. If Protection Systems trip via AC methods, are those systems and the associated control circuitry included
in the definition and within the requirements of the Standard as expressed within the Tables?
Response:
Thank you for your comment.
1. The SDT believes that it is important that all parallel paths be maintained within the indicated interval,
and the prescribed interval already considers the reliability benefits of parallel tripping paths.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
3. The use of the term “cell/unit” acknowledges that individual cells may not be accessible, but that
assemblies of several cells (into units) may be available instead, and may be used to address this
requirement. An acceptable base-line value and follow-on tests may be acceptable for the entire
station battery as a single unit.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
November 17, 2010
55
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15. To the degree that performance history for the components within these systems is available, a
performance-based program per R3 and Attachment A may be useful in these cases.
6. The SDT removed all footnotes from the Standard.
7. The SDT removed all footnotes from the Standard.
8. “Control circuitry” has been revised to remove “dc” to generalize it such that “ac” tripping would be
included.
Segment:
4
Organization:
Consumers Energy
Member:
David Frank Ronk
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided,
Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented.
Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead to
provide operating flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will be very
cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely lead
to entities NOT installing the redundant schemes, resulting in decreased reliability.
2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include
sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on
Comment:
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply),
what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not
present.” Similarly, it isn’t clear from the general description within the Tables that components possessing
different monitoring attributes within a single scheme may be distinguished such that differing relevant tables
can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.
Battery assemblies supplied by some manufacturers have the connections made internally, making this option
unavailable. Experience with ASME standards show that NERC and SDT members may be jointly and
November 17, 2010
56
separately liable for litigation by specifying methods that either prefer or prohibit use of certain technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“conclude
with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
such activities therefore require tripping of circuit breakers or other interrupting devices?
5. Performance of the minimum activities specified within Table 1a for legacy systems, particularly regarding
control circuits, will require considerable disconnection and reconnection of portions of the circuits. Such
activities will likely cause far more problems on restoration-to-service than they will locate and correct. We
suggest that the SDT reconsider these activities with regard for this concern.
6. In the Standard, Footnote 2 and Footnote 3 are identical. We presume that some information has been
omitted.
7. We do not agree that Footnotes are an appropriate method of providing information that is important to the
application of the Standard. Important information should be provided within the standard text.
Response:
Thank you for your comment.
1. The SDT believes that it is important that all parallel paths be maintained within the indicated interval,
and the prescribed interval already considers the reliability benefits of parallel tripping paths.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5.
3. The use of the term “cell/unit” acknowledges that individual cells may not be accessible, but that
assemblies of several cells (into units) may be available instead, and may be used to address this
requirement. An acceptable base-line value and follow-on tests may be acceptable for the entire
station battery as a single unit.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 15. To the degree that performance history for the components within these systems is available, a
performance-based program per R3 and Attachment A may be useful in these cases.
November 17, 2010
57
6. The SDT removed all footnotes from the Standard.
7. The SDT removed all footnotes from the Standard.
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
3
City of Bartow, Florida
Matt Culverhouse
The draft standard requires testing and maintenance on DC circuits of distribution systems that have no effect
on the reliability of the BES which we feel is outside of the bounds of the original intent of NERC.
Thank you for your comment. The Tables have been rearranged and considerably revised to improve clarity.
Please see new Table 1-5.
2
Midwest ISO, Inc.
Jason L Marshall
We are abstaining because a number of our stakeholders do not agree with the definition of Protection
Systems and inclusion of UFLS and UVLS in a standard dealing with maintenance of protection systems.
Thank you for your comment. FERC Order 693 suggests combining these Standards, as does the approved
SAR for this project. The Tables have been rearranged and considerably revised to improve clarity. Please
see new Tables 1-4 and 1-5 for the constrained activities regarding UFLS and UVLS.
8
Organization:
Roger C Zaklukiewicz
Member:
Roger C Zaklukiewicz
There in insufficient clarity on the Protection System components that are considered Transmission
Protection System equipment which require a Distribution Provider (DP) to perform the required
maintenance and testing to ensure compliance with the Standard. In certain distribution substations,
Comment: components of the high voltage source that supply the distribution substation may be considered components
of the Electric Bulk System and their associated protection and control systems must be specified, installed,
maintained and tested in accordance with the Standard. Clear delineation of Transmission Protection Systems
is therefore critical to ensure the reliability of the EPS.
November 17, 2010
58
Response:
Segment:
Organization:
Member:
Thank you for your comment. This is properly a concern regarding your regional BES definition, and the
SDT is unable to respond to these concerns.
10
Northeast Power Coordinating Council, Inc.
Guy V. Zito
1. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate equipment
identified in the existing or proposed definition. However, not all such equipment translates into a
transmission Protection System. The definition needs clarification on when such equipment is a part of the
transmission protection system.
2. Also, the time provided for the first phase "at least six months" is too open ended and does not provide
entities with a clear timeline. It is suggested that one year is appropriate for the first phase phasing out the
second year in stages.
3. Regarding battery visuals, the suggestion for consideration is it should be changed from 3 months to 6
months. Electrolyte levels of today's lead-calcium batteries are relatively stable for a 6 month period
compared to lead-antimony batteries used in the past.
Comment:
4. The Implementation plan is too short - In many instances it will be impossible to meet, especially if entities
have to create, purchase and adopt new databases to track maintenance activities. Often new procedures will
have to be written and additional resources justified and hired. It would be more acceptable if a staged
approached was taken similar to the DME Standard.
5. Accounting for every component of a protection system will be an enormous overhead and will take away
resources from actually doing maintenance. Emphasis should be on systems and not individual components.
6. The Standard does not provide a grace period if an entity is unable to meet the maintenance requirement
for extenuating circumstances. For example if an entity has to divert maintenance resources to storm
restoration following a major event, slack built into a maintenance program can be eaten up and put the
maintenance over the prescribed period. Provision should be made for a mitigation plan to get back on track.
We do not believe the reliability of the Bulk Electric System will be compromised if an entities' maintenance
November 17, 2010
59
program slips by a few months due to extreme contingencies, especially if it is brought back on track within a
short time frame.
Response:
Thank you for your comment.
1. This is an issue related to the regional BES definition, and the DP needs to consider their equipment
in the context of this definition.
2. This comment appears to be related to the Implementation Plan for the definition (which was
independent to the Standard), not to the Standard.
3. The SDT disagrees; these activities should be completed as prescribed in the Standard.
4. A staged Implementation Plan is provided for all activities that have prescribed maximum allowable
intervals over one year. However, the SDT believes that a staged Implementation Plan for developing
the PSMP is impractical, in that an entity cannot reasonably implement a plan until they have
developed it.
5. The SDT believes that the only alternative to these criteria is to provide a binary VSL, which would
mean that any non-compliance would be Severe. A definition of Component and Component Types
have been added to the Standard, and Requirement R1, part 1.1, has been revised to state, “Address
all Protection System component types” to assist in this task.
6. “Grace periods” within the Standard are not measurable, and would probably lead to persistently
increasing intervals. However, an entity may establish an internal program with grace-period
allowance, as long as the entire program (including grace periods) does not exceed the intervals
within the Standard.
Segment:
Organization:
Member:
1, 3
Hydro One Networks, Inc.
Ajay Garg, Michael D. Penstone
Hydro One is casting a negative vote for the following reasons:
1. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify
which protection system components it does own and needs to maintain. Many DPs own and/or
Comment:
operate equipment identified in the existing or proposed definition. However, not all such equipment
translates into a transmission Protection System.
2. The proposed definition of Protection System needs clarification on when such equipment is a part of
November 17, 2010
60
the transmission protection system. Emphasis should be on systems and not individual components.
3. The time provided for the first phase "at least six months" is too open ended and does not provide
entities with a clear timeline. It would be more acceptable if a staged approach was taken.
4. The Standard does not provide a grace period if an entity is unable to meet the maintenance
requirement for extenuating circumstances. For example if an entity has to divert maintenance
resources to storm restoration following a major event, slack built into a maintenance program can be
eaten up and put the maintenance over the prescribed period. Provision should be made for a
mitigation plan to get back on track. We do not believe the reliability of the Bulk Electric System will
be compromised if an entities' maintenance program slips by a few months due to extreme
contingencies, especially if it is brought back on track within a short time frame.
5. Table 1a: UFLS/UVLS DC control and trip circuits – Due to the distributed nature of this program,
random failures to trip are not impactive to the overall operation of the UFLS protection. There should
be no requirement to check the DC portion of these protections any more often than the DC circuit
checks associated with that LV breaker.
6. Table 1c: some of the proposed maintenance intervals for station DC supply are too stringent and they
would not produce significant increase in reliability to justify associated incremental expenditure.
Response:
Thank you for your comment.
1. This is an issue related to the regional BES definition, and the DP needs to consider their equipment
in the context of this definition.
2. This is an issue related to the regional BES definition, and the DP needs to consider their equipment
in the context of this definition. It seems that Protection Systems logically need to be maintained on a
Component level; definitions of Component and Component Type have been added to assist.
3. This comment appears to be related to the Implementation Plan for the definition (which was
independent to the Standard), not to the Standard.
4. “Grace periods” within the Standard are not measurable, and would probably lead to persistently
increasing intervals. However, an entity may establish an internal program with grace-period
allowance, as long as the entire program (including grace periods) does not exceed the intervals
within the Standard.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
November 17, 2010
61
1-5 for constrained activities related to UFLS/UVLS.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
Segment:
Organization:
Member:
1, 1, 3, 6
Consolidated Edison Co. of New York, Northeast Utilities, Consolidated Edison Co. of New York,
Consolidated Edison Co. of New York
Christopher L de Graffenried, David H. Boguslawski, Peter T Yost, Nickesha P Carrol
1. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate equipment
identified in the existing or proposed definition. However, not all such equipment translates into a
transmission Protection System. The definition needs clarification on when such equipment is a part of the
Comment: transmission protection system.
2. Also, the time provided for the first phase "at least six months" is too open ended and does not provide
entities with a clear timeline. It is suggested that one year is appropriate for the first phase phasing out the
second year in stages.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. This is an issue related to the regional BES definition, and the Distribution Provider needs to consider
their equipment in the context of this definition.
2. This comment appears to be related to the Implementation Plan for the definition (which was
independent to the Standard), not to the Standard.
3
Allegheny Power
Bob Reeping
Comment:
The draft standard expects 100% compliance for millions of protection system components at all times. The
standard should consider a statistically based performance metric instead of a performance target that expects
100% compliance.
Response:
Thank you for your comment. The NERC criteria for VSLs do not currently permit them to allow some level
November 17, 2010
62
of non-performance without being in violation.
Segment:
Organization:
Member:
1, 1, 3, 6
Keys Energy Services, Lakeland Electric, Lakeland Electric, Florida Municipal Power Pool
Stan T. Rzad, Larry E Watt, Mace Hunter, Thomas E Washburn
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard.
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit testing,
etc. on distribution elements with no significant improvement to BES reliability, which is beyond the
Comment:
statutory scope of the standards
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
1
Gainesville Regional Utilities
Luther E. Fair
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard as explained by Steve
Comment: Alexanderson in a prior e-mail to the ballot pool.
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit testing,
November 17, 2010
63
etc. on distribution elements with no significant improvement to BES reliability, which is beyond the
statutory scope of the standards.
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components. These comments are the same as provided by FMPA which we support.
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
1, 4, 5
Lake Worth Utilities, Florida Municipal Power Agency, Florida Municipal Power Agency
Walt Gill, Frank Gaffney, David Schumann
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some
batteries are not able to accommodate all of the tests proscribed in the draft standard
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit
testing, etc. on distribution elements with no significant improvement to BES reliability, which is
beyond the statutory scope of the standards
Comment:
November 17, 2010
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components.
4. Will the Standard Introduce Technical Feasibility Exceptions to PRC Standards? A large proportion
of the batteries (as high as 50% as reported by some SMEs) are not able to accommodate all of the
tests prescribed in the draft standard. Will this necessitate the introduction of TFEs into the process
unnecessarily?
5. The Standard Reaches beyond the Statutory Scope of the Reliability Standards As written, the
64
standard requires testing of batteries, DC control circuits, etc., of distribution level protection
components associated with UFLS and UVLS. UFLS and UVLS are different than protection systems
used to clear a fault from the BES. An uncleared fault on the BES can have an Adverse Reliability
Impact and hence; the focus on making sure the fault is cleared is important and appropriate.
However, a UFLs or UVLS event happens after the fault is cleared and is an inexact science of trying
to automatically restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable
levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays with the
same function, there is no significant impact to the function of UFLS or UVLS. Hence, there is no
corresponding need to focus on every little aspect of the UFLS or UVLS systems. Therefore, the only
component of UFLS or UVLS that ought to be focused on in the new PRF-005 standard is the UFLS
or UVLS relay itself and not distribution class equipment such as batteries, DC control circuitry, etc.,
and these latter ought to be removed from the standard.
6. In addition, most distribution circuit are radial without substation arrangements that would allow
functional testing without putting customers out of service while the testing was underway, or at least
without momentary outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES reliability.
7. Perfection is Not A Realistic Goal The standard allows no mistakes. Even the famous six sigma
quality management program allows for defects and failures (i.e., six sigma is six standard deviations,
which means that statistically, there are events that fall outside of six standard deviations). PRC-005
has been drafted such that any failure is a violation, e.g., 1 day late on a single relay test of tens of
thousands of relays is a violation. That is not in alignment with worldwide accepted quality
management practices (and also makes audits very painful because statistical, random sampling
should be the mode of audit, not 100% review as is currently being done in many instances). FMPA
suggests considering statistically based performance metrics as opposed to an unrealistic performance
target that does not allow for any failure ever. Due to the sheer volume of relays, with 100%
performance required, if the standards remain this way, PRC-005 will likely be in the top ten most
violated standards for the forever. There is a fundamental flaw in thinking about reliability of the
BES. We are really not trying to eliminate the risk of a widespread blackout; we are trying to reduce
the risk of a widespread blackout. We plan and operate the system to single and credible double
contingencies and to finite operating and planning reserves. To eliminate the risk, we would need to
plan and operate to an infinite number of contingencies, and have an infinite reserve margin, which is
infeasible. Therefore, by definition, there is a finite risk of a widespread blackout that we are trying to
reduce, not eliminate, and, by definition, by planning and operating to single and credible double
November 17, 2010
65
contingencies and finite operating and planning reserves, we are actually defining the level of risk
from a statistical basis we are willing to take. With that in mind, it does not make sense to require
100% compliance to avoid a smaller risk (relays) when we are planning to a specified level of risk
with more major risk factors (single and credible double contingencies and finite planning and
operating reserves).
Response:
Segment:
Organization:
Member:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
4. No. The Tables have been rearranged and considerably revised to improve clarity. Please see new
Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unitto-unit connection resistance (where available to measure)” to address this comment.
5. The Standard only addresses distribution-located devices to the degree that they address BES issues.
UFLS and UVLS per the relevant NERC Standards are frequently implemented on the distribution
system.
6. The Standard does not require functional testing, although it may be the most practical method of
completing some of the required activities. There are other methods, too, of completing these.
7. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
4
Illinois Municipal Electric Agency
Bob C. Thomas
IMEA is supportive of the intent of PRC-005-2; however, based on monitoring of comments submitted to
date, IMEA would like to see concerns addressed before voting to affirm this proposed standard revision.
Comment:
IMEA supports the comments expressed during ballot pool communications that provisions need to be
included to avoid the possible necessity of having to use the burdensome TFE process and to avoid the
November 17, 2010
66
unrealistic expectation of perfection in recordkeeping and exactness of maintenance schedule dates.
Response:
Segment:
Organization:
Member:
Thank you for your comment. Responses have been provided to the various ballot comments.
1
Georgia Transmission Corporation
Harold Taylor, II
The SDT has made significant changes to the minimum maintenance activities and maximum allowable
intervals within Tables 1a, 1b, and 1c, particularly related to station dc supply and dc control circuits. Do you
agree with these changes? If not, please provide specific suggestions for improvement. Comments:
1. Do not agree with the 3 calendar months interval and suggest using quarterly. Both terms require a
minimum of four inspections per year have proven to be successful, but the term “quarterly” provides
a bit more flexibility than the term “3 calendar months”. Given a 3 month maximum interval an entity
would need to schedule these tasks every 2 months.
Comment:
2. As the current requirements are written in R1 of PRC-005-2 Draft, we disagree with the terms identify
all Protection System components.
We recommend a less prescriptive requirement as listed below.
R1.1 Identify BES substations or facilities containing Protection Systems.
R1.2 Identify whether Protection Systems per substation or facilities are addressed through timebased, condition-based, performance based or a combination based etc.
R1.3 For each substation/facility with Protection Systems include all maintenance activities etc.
3. Listing each individual Protection System component as current draft is onerous and impedes any
interpretation of application with very little value.
4. The standard as written will require a great deal of effort by the utilities to maintain 100% compliance as
listed. The concern is the power system design allows for some contingencies but the standard allows for no
errors. Failing to complete 1% of the maintenance by 1 day infers an entity is out of compliance or in
violation. The violations should start for more than a level of 5% not identified, or not maintained.
5. We feel the minor changes of wording as described in R1.1 – R1.3 as listed above will go a long way in
November 17, 2010
67
removing the concerns of the standard. We feel the intent of the standard is sound and request minor changes
to facilitate an interpretable standard that sensibly mitigates problems with the BES. As the standard written,
the interpretation seems to create a stringent environment with undue compliance requirements.
6. Lastly, the SDT should attempt to embrace Gerry Cauley’s vision of “results-based standards” and clearly
identify the “risk mitigation objectives, reliability result or outcome” of the revised requirements and allow
each entity to meet the outcome and mitigate the risk without writing in such a prescriptive manner which is
not preferred. The prescriptive details currently proposed in the standard could then be captured in a reference
document.
Response:
Segment:
Organization:
Member:
November 17, 2010
Thank you for your comment.
1. The SDT disagrees. Once per calendar quarter would allow up to six months between inspections,
while three calendar months limits the effective interval to four months (minus 2 days).
2. Modifying Requirement R1 as you suggest would make it so general that it would be difficult to
measure for compliance. Additionally, because of the variety of types of component within a
substation, it may be difficult to define a substation-wide (or facility-wide) PSMP that addresses all
components and intervals. A definition of Component has been added to the Standard, and
Requirement R1, part 1.1, has been revised to state, “Address all Protection System component
types”.
3. A definition of Component has been added to the Standard to assist; also, Requirement R1, part 1.1,
has been revised to state, “Address all Protection System component types” in consideration of your
comment.
4. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
5. As noted above, the SDT believes that Requirement R1 would no longer be measurable.
6. The SDT agrees that the SDT may effectively embrace the “results-based” approach within this
Standard; however, doing so at this time would delay development of this high-priority Standard.
This is reflected on pages 13-14 of the current draft Standards Development Plan that is out for
comment at this time.
3, 4
Georgia System Operations Corporation
R Scott S. Barfield-McGinnis, Guy Andrews
68
1. Do not agree with the 3 calendar months interval and suggest using quarterly. Both terms require a
minimum of four inspections per year have proven to be successful, but the term “quarterly” provides a bit
more flexibility than the term “3 calendar months”. Given a 3 month maximum interval an entity would need
to schedule these tasks every 2 months.
2. As the current requirements are written in R1 of PRC-005-2 Draft, we disagree with the terms identify all
Protection System components. We recommend a less prescriptive requirement as listed below.
-R1.1 Identify BES substations or facilities containing Protection Systems.
-R1.2 Identify whether Protection Systems per substation or facilities are addressed through time-based,
condition-based, performance based or a combination based etc.
-R1.3 For each substation/facility with Protection Systems include all maintenance activities etc.
3. The VRF for R1 ranking should be lower or no greater than R2, R3, and R4. The task of identifying
Protection System components has very little to do with increasing reliability of the BES. The
implementation of the PSMP most likely will cover all the specific functions of Protection System
components although the entity failed to identify all PS components. We recommend the above language
Comment: changes and agree the requirement adds some value but not a high-risk value to the BES.
4. After correcting the language we feel that a requirement of 100% maintenance on 100% of all components
as listed on page 6 of the standard for the VSLs leaves no room for error for systems designed with
contingences. The violations should start for more than a level of 5% not identified, not maintained, etc.
5. Listing each individual Protection System component as current draft is onerous and impedes any
interpretation of application with very little value. The standard as written will require a great deal of effort
by the utilities to maintain 100% compliance as listed. The concern is the power system design allows for
some contingencies but the standard allows for no errors. Failing to complete 1% of the maintenance by 1 day
infers an entity is out of compliance or in violation. The violations should start for more than a level of 5%
not identified, or not maintained.
6. We feel the minor changes of wording as described in R1.1 – R1.3 as listed above will go a long way in
removing the concerns of the standard. We feel the intent of the standard is sound and request minor changes
to facilitate an interpretable standard that sensibly mitigates problems with the BES. As the standard written,
the interpretation seems to create a stringent environment with undue compliance requirements.
November 17, 2010
69
7. Lastly, the SDT should attempt to embrace Gerry Cauley’s vision of “results-based standards” and clearly
identify the “risk mitigation objectives, reliability result or outcome” of the revised requirements and allow
each entity to meet the outcome and mitigate the risk without writing in such a prescriptive manner which is
not preferred. The prescriptive details currently proposed in the standard could then be captured in a reference
document.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
Thank you for your comment.
1. The SDT disagrees. Once per calendar quarter would allow up to six months between inspections,
while three calendar months limits the effective interval to four months (minus 2 days).
2. Modifying Requirement R1 as you suggest would make it so general that it would be difficult to
measure for compliance. Additionally, because of the variety of types of component within a
substation, it may be difficult to define a substation-wide (or facility-wide) PSMP that addresses all
components and intervals. A definition of Component has been added to the Standard, and
Requirement R1, part 1.1, has been revised to state, “Address all Protection System component
types”.
3. The VRFs have been revised.
4. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation.
5. A definition of Component has been added to the Standard to assist; also, Requirement R1, part 1.1,
has been revised to state, “Address all Protection System component types” in consideration of your
comment.
6. As noted above, the SDT believes that Requirement R1 would no longer be measurable.
7. The SDT agrees that the SDT may effectively embrace the “results-based” approach within this
Standard; however, doing so at this time would delay development of this high-priority Standard.
This is reflected on pages 13-14 of the current draft Standards Development Plan that is out for
comment at this time.
1, 3, 6
FirstEnergy Energy Delivery, FirstEnergy Solutions, Kevin Querry
Robert Martinko, Kevin Querry, Mark S Travaglianti
Please see FE comments for suggested enhancements submitted via the parallel comment period for this
standard.
70
Response:
Segment:
Organization:
Member:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
1, 3, 5, 6
Entergy Corporation, Entergy, Entergy Corporation, Entergy Services, Inc.
George R. Bartlett, Joel T Plessinger, Stanley M Jaskot, Terri F Benoit
The following are the reasons associated with our Negative Ballot.
1. Table 1a contains “Type of Protection System Component” entry “Control and trip circuits with
electromechanical trip or auxiliary contacts (except for microprocessor relays, UFLS or UVLS)”.
However, there is no Component entry for the exception (except for microprocessor relays, UFLS or
UVLS). Please add a Component entry with associated intervals and activities for: “Control and trip
circuits with electromechanical trip or auxiliary contacts” with a microprocessor relay application.
2. The term “check” has replaced “verify” for some maintenance activities. Replace “verify” with
“check” in all locations in the Tables.
3. Redefine “verification” to “A means of determining or checking that the component is functioning
properly or maintenance correctable issues are identified”.
Comment:
4. We support this project and believe it is a positive step towards BES reliability. However, we believe
the draft document needs additional work as per our comments. Also, as indicated by the amount of
industry input on the last version draft comments, we believe revisions are still needed to properly
address this technically complex standard.
5. If this standard is to deviate from the original project schedule and follow a fast track timeline for
approval, then we disagree with the 3 month implementation for Requirement 1 and ask for at least 12
months. The original schedule provided sufficient advance notice to work on an implementation plan
and it included the typical time required for NERC Board of Trustees and regulatory approvals. If the
project schedule and typical NERC Board of Trustees and regulatory approval times are to be
accelerated, the implementation plan should be extended. We reserve the right to include selected
reasons submitted by other Negative balloters for their Negative Ballot.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
November 17, 2010
71
1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-5.
3. “Check” is not an element of the PSMP definition. This term, throughout the tables, has been
replaced with whatever term of the definition is relevant.
4. Thank you.
5. The Implementation Plan for Requirement R1 has been revised from three months to twelve months.
Segment:
Organization:
Member:
1
Empire District Electric Co.
Ralph Frederick Meyer
It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are
included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that
particular standard to protection systems that sense electrical quantities, it is remains unclear in other
Comment:
standards that use the defined term whether mechanical input protections are included. We suggest that
“Protective Relay” also be defined, and that the definition clearly exclude devices that respond to mechanical
inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG request.
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Protection System definition has been revised to explicitly include only
protective relays that respond to electrical quantities. This definition applies to all uses of this term within
NERC Standards. The SDT feels that the IEEE definition of protective relay is adequate and sees no need to
either repeat or change that definition.
1
Colorado Springs Utilities
Paul Morland
Comment:
CSU offers the following comments: With BES still not defined it is difficult to determine what the standard
applies to. Requirements are confusing at times, making the standard difficult to audit.
Response:
Thank you for your comment. This concern is a BES concern, and the SDT is unable to address or resolve it.
Segment:
November 17, 2010
1
72
Organization:
Avista Corp.
Member:
Scott Kinney
Avista has the following comments:
1. The modified definition of Protection System now refers to “functions” rather than “devices.” What are the
“functions?” This new term adds confusion without being defined in the standard.
2. Considering all the time spent by Regional Entities and utilities discussing what is meant by monthly,
quarterly, annual, etc., this standard should clearly define a Calendar Year and Calendar Month to eliminate
any confusion.
Comment:
3. In general, the requirements of the Standard are very prescriptive and granular which seem counter to the
newly adopted NERC philosophy of implementing “performance-based” or “results-based” standards.
Specifically, the relay testing requirements are very extensive and not entirely practical when it comes to
conducting actual breaker tripping for testing. Also, there are now different maintenance and testing
requirements for station batteries depending on the type of battery in service. What’s the real added reliability
to the BES to add this complexity to the maintenance program? Considering these observations, is there some
real historical research that has gone into determining these requirements? In general, how did the drafting
team arrive at the maximum allowable maintenance and testing intervals for inclusion in the Standard, i.e.,
what is the technical basis for their decisions regarding this?
Response:
Thank you for your comment.
1. “Functions” acknowledge that, while protective relays (or protective devices) is the most common
implementation, other devices are now used (particularly in SPSs) that provide these functions from
other than traditional relays.
2. A “calendar year” is a single number year on the Gregorian calendar; a calendar month is any one of
the twelve months within a single calendar year. Please see Section 8.3 of the Supplementary
Reference document.
3. Please see Section 8.3 of the Supplemental Reference document for a discussion of the determination
of relay and communications system intervals. For the other components, the SDT studied other
sources such as IEEE standard, EPRI documents, visited with various industry experts (such as within
IEEE), conducted informal surveys of existing practices, and adjusted to conform to concerns such as
generator outage intervals.
Segment:
November 17, 2010
3
73
Organization:
Member:
Comment:
Central Lincoln PUD
Steve Alexanderson
1. The SDT has made significant changes to the minimum maintenance activities and maximum allowable
intervals within Tables 1a, 1b, and 1c, particularly related to station dc supply and dc control circuits. Do you
agree with these changes? If not, please provide specific suggestions for improvement. 0 Yes X No
Comments:
We agree with most of the changes from the last draft. However, the phrase “Verify Battery cell-to-cell
connection resistance” has entered the table where it did not exist before. On some types of stationary battery
units, this internal connection is inaccessible. On other types the connections are accessible, but there is no
way to repair them based on a bad reading. And bad cell-to-cell connections within units will be detected by
the other required tests. This requirement will cause entities to scrap perfectly good batteries just so this test
can be performed, with no corresponding increase in bulk electric system reliability while taking an
unnecessary risk to personnel and the environment. And because buying battery units composed of multiple
cells allows space saving designs, entities may be forced to buy smaller capacity batteries to fit existing
spaces. This may end up having a negative effect on reliability. Suggest substituting “unit-to-unit” wherever
“cell-to-cell” is used in the table now.
2. The SDT has included VRFs and Time Horizons with this posting. Do you agree with the assignments that
have been made? If not, please provide specific suggestions for improvement. X Yes 0 No Comments:
3. The SDT has included Measures and Data Retention with this posting. Do you agree with the assignments
that have been made? If not, please provide specific suggestions for improvement. X Yes 0 No Comments:
4. The SDT has included VSLs with this posting. Do you agree with the assignments that have been made? If
not, please provide specific suggestions for change. 0 Yes X No Comments: It is possible that a component
that failed to be individually identified per R1.1 was included by entity A’s maintenance plan. This
documentation issue gets a higher VSL than entity B that identified a component without maintaining it. We
suggest the R1 VSL be change to Low, since we believe lack of maintenance to be more severe than
documentation issues.
5. The SDT has revised the “Supplementary Reference” document which is supplied to provide supporting
discussion for the Requirements within the standard. Do you agree with the changes? If not, please provide
November 17, 2010
74
specific suggestions for change. X Yes 0 No Comments:
6. The SDT has revised the “Frequently-Asked Questions” (FAQ) document which is supplied to address
anticipated questions relative to the standard. Do you agree with these changes? If not, please provide
specific suggestions for change. X Yes 0 No Comments:
7. If you have any other comments on this Standard that you have not already provided in response to the
prior questions, please provide them here. Comments:
The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be
used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which
activities shall we use?
8. Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing. IEEE
battery maintenance standards call for quarterly inspections. These are targets, though, not maximums. An
entity wishing to avoid non-compliance for an interval that might extend past three calendar months due to
storms and outages must set a target interval of two months thereby increasing the number of inspections
each year by half again. This is unnecessarily frequent. We suggest changing the maximum interval for
battery inspections to 4 calendar months. For consistency, we also suggest that all intervals expressed as 3
calendar months be changed to 4 calendar months.
9. We are concerned over R1.1, where all components must be identified, without a definition for the word
component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. We believe this will allow REs to claim noncompliance for every three inch long terminal jumper wire not identified in a trip circuit path. We suggest
that the FAQ definitions be included within the standard.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment.
2. Thank you.
3. Thank you.
4. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
and the VSL for Requirement R1 modified in consideration of your comment.
November 17, 2010
75
5. Thank you.
6. Thank you.
7. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4.
8. The SDT disagrees; the components should be maintained as specified within the new tables.
9. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types”
in consideration of your comment. Definitions were also added to the Standard for Component Type
and Component.
Segment:
Organization:
Member:
3, 5, 6
Lincoln Electric System
Bruce Merril, Dennis Florom, Eric Ruskamp
LES would like to thank the Drafting Team for its time and effort in developing the standard. However, the
standard as currently drafted raises concern as it relates to the identification of all Protection System
components. LES asks the Drafting Team to further examine the impact of implementing such a rigorous
maintenance program that could potentially impose unnecessary burden and reliability risk with an overly
prescriptive approach. Redundancy has been implemented in great detail throughout the history of protection
systems to ensure they function as intended. In addition to the comments submitted through the MRO NSRS
group comment form, LES would like to further emphasize the following points of contention:
Comment:
(1) Consider revising to consider maintenance activities on a communications channel basis in which
intermediate device functioning can be verified by sending a signal from one relay to another.
(2) R1, the statement “or are designed to provide protection for the BES” re-opens the argument about
transformer protection or breaker failure protection for transformer high-side breakers tripping BES breakers
being included in transmission protection systems.
(3) Table 1b “breaker trip coil, each auxiliary relay, and each lockout relay” should be changed from a 6 to 12
year interval similar to relay input and outputs. Experience has shown that these both have similar reliability.
(4) Include a detailed example of an Inventory List for voltage and current sensing input.
(5) Remove “proper functioning of” from the maintenance activities for voltage and current sensing inputs.
November 17, 2010
76
One is not verifying the functionality of the signals.
(6) Clarify why control circuitry is stated separately such as in “Control and trip circuits”. This implies that
close circuit DC paths are not subjects a PSMP when reclosing and closing of breakers have never before
been considered part of a Protection System.
Response:
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-2. Functional end-to-end testing would be one method of completing the necessary verification.
2. This is an issue regarding your regional BES definition, and this SDT is unable to resolve such issues.
3. The SDT believes that mechanical solenoid-operated devices share performance attributes (and failure
modes) with electromechanical relays and need to be tested at similar intervals. Performance-Based
maintenance is an option to increase the intervals if the performance of these devices supports those
intervals.
4. The SDT does not understand this comment. The Protection System definition has been changed;
perhaps this will help.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-3.
6. This component of the definition is stated to apply as “associated with protective functions” and thus
excludes close/reclosing circuits. Please see FAQ II.1.A.
Segment:
Organization:
Member:
Comment:
4
Madison Gas and Electric Co.
Joseph G. DePoorter
1. The six implementation plan is too quick for some entities. A 1 year implementation is recommended.
2. With the addition of all UFLS in this standard, it is implied battery testing, DC circuit testing, etc. on
distribution elements are part of the BES. This may lead to every wire and component to be classified as
being a part of the BES.
Response:
November 17, 2010
Thank you for your comment.
1. This comment appears to be focused on the Implementation Plan for the definition, not for the
Standard.
77
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-4 and 1-5 for simplified maintenance activities relevant to UFLS.
Segment:
Organization:
Member:
Comment:
8
SPS Consulting Group Inc.
Jim R Stanton
1. I share the concerns expressed by FMPA that the overly prescriptive battery testing requirements will
require a TFE process that would be tedious to manage. The standard goes far beyond the scope of Reliability
Standards to protect the BES. Reliability Standards should state "what" needs to be done, not "how" to do it.
Such overly prescriptive requirements blunt the development of superior and more efficient processes by the
industry.
2. Table 1a column "Maintenance Activity" should be renamed "Suggested Maintenance Activity".
3. Tables 1a, b, and c should be reference documents and not referred to in the Requirements. This is
especially true since we find terms like "where applicable" and "physical condition" in the tables that forces
the Registered Entity to make judgment calls that may not align with the judgment of the auditors. This will
mean more interpretation requests and will make the standard extremely difficult to audit as the Registered
Entities and auditors compare their "judgments."
Response:
Segment:
Organization:
November 17, 2010
Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table
1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit
connection resistance (where available to measure)” to address this comment. The SDT has
prescribed “what,” not “how,” except for those rare cases where it is necessary to specify both.
2. The “activities” in the Tables are required, not suggested.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables
1-1 through 1-5. These Tables are made requirements by incorporation within Requirement R4, part
4.1, and therefore are not reference documents. They are created in response to FERC Order 693 and
the approved SAR which assigned the SDT to develop a Standard with maximum allowable intervals
and minimum maintenance activities.
10
Midwest Reliability Organization
78
Member:
Dan R. Schoenecker
Comment:
“The MRO’s NERC Standards Review Subcommittee believes the proposed implementation plan for R1 is
unreasonably short. It proposes that: “Entities shall be 100% compliant on the first day of the first calendar
quarter three months following applicable regulatory approvals, or in those jurisdictions where no regulatory
approval is required, on the first day of the first calendar quarter six months following Board of Trustees
adoption.” We believe the implementation periods should be expanded to twice what was proposed in the
implementation plan due to the sheer volume of equipment that will need to meet compliance. Thus, we
propose an alternate implementation plan for requirement R1, “Entities shall be 100% compliant on the first
day of the first calendar quarter six months following applicable regulatory approvals, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter twelve
months following Board of Trustees adoption.”
Response:
Thank you for your comment. The Implementation Plan for Requirement R1 has been modified from three
months to twelve months in consideration of your comment.
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
The Implementation Plan is unreasonably short, for the number of assets. The time period should be doubled
to be more practicable.
Thank you for your comment. The Implementation Plan for Requirement R1 has been modified from three
months to twelve months in consideration of your comment.
1, 3, 5, 6
Manitoba Hydro
Michelle Rheault, Greg C Parent, Mark Aikens, Daniel Prowse
Comment:
The proposed timelines are not reasonable. See submitted comments.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
November 17, 2010
10
Western Electricity Coordinating Council
Louise McCarren
79
Comment:
Lack of clarity or apparent conflict between certain requirements would make compliance assessment
difficult.
Response:
Thank you for your comment.
Segment:
Organization:
Member:
1
Clark Public Utilities
Jack Stamper
Comment:
My negative vote reflects the ambiguity and over-stepping issues discussed in many of the comments.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
1, 3, 5, 6
Kansas City Power & Light Co.
Michael Gammon, Charles Locke, Scott Heidtbrink, Thomas Saitta
Comment:
The proposed changes in the Standard are far too prescriptive and do not take into account the multitude of
manufacturers equipment by establishing broad maintenance cycles and testing intervals.
Response:
Thank you for your comment.
Segment:
Organization:
Member:
1
Public Utility District No. 1 of Chelan County
Chad Bowman
Comment:
The requirements are confusing and at times seem to be in conflict with or duplicative of other requirements.
From a compliance perspective, this confusion would make the standard difficult to interpret for compliance
and audit purposes.
Response:
Thank you for your comment. The Requirements and Tables have been rearranged and considerably revised
to improve clarity. Please see new Tables 1-1 through 1-5.
Segment:
Organization:
Member:
Comment:
November 17, 2010
3
Wisconsin Public Service Corp.
Gregory J Le Grave
The standard and associated definitions as written are too vague, which leave room for varying interpretation.
80
Response:
Segment:
Organization:
Member:
Thank you for your comment. The Requirements, definitions, and Tables have been rearranged and
considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
1, 3
Tri-State G & T Association Inc.
Keith V. Carman, Janelle Marriott
Comment:
Clarification is needed to address the potentially onerous implementation, administration, audit of the
proposed revisions.
Response:
Thank you for your comment.
Segment:
Organization:
Member:
5
Tenaska, Inc.
Scott M. Helyer
Comment:
This standard has become too prescriptive and does too much to say "how" instead of "what" to do. Some of
the information in the various tables may or may not conflict with manufacturer recommended practices. It is
not clear at all whether such detail will lead to an increased level of reliability versus simply having
consistency for the sake of consistency.
Response:
Thank you for your comment. The SDT has prescribed “what,” not “how,” except for those rare cases where
it is necessary to specify both. Also, FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
Segment:
Organization:
Member:
6
Florida Power & Light Co.
Silvia P Mitchell
Comment:
This standard is too prescriptive and will result in many violations.
Response:
Thank you for your comment. FERC Order 693 and the approved SAR assigned the SDT to develop a
Standard with maximum allowable intervals and minimum maintenance activities.
Segment:
Organization:
Member:
November 17, 2010
9
Oregon Public Utility Commission
Jerome Murray
81
Comment:
The requirements in the latest draft are confusing and at times seem to be in conflict with other requirements.
From a compliance and enforcement perspective, this confusion would make the standard difficult to audit.
Response:
Thank you for your comment. The Requirements, definitions, and Tables have been rearranged and
considerably revised to improve clarity. Please see new Table 1-5.
Segment:
Organization:
Member:
1, 6
SCE&G
Henry Delk, Jr., Matt H Bullard
Comment:
While SCE&G believes the majority of the PRC-005-2 standard is ready to be affirmed there are still
inconsistencies with areas of the standard that need to be corrected prior to approval. These inconsistencies
are addressed in SCE&G’s comments which have been submitted for the current draft of this standard.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
1, 3, 5, 6
Xcel Energy, Inc.
Gregory L Pieper, Michael Ibold, Liam Noailles, David F. Lemmons
Comment:
Xcel Energy believes the standard still contains many aspects that are not clearly understood by entities,
including what is needed to demonstrate a compliant PSMP. Comments have been submitted concurrently to
NERC via the draft comment response form.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
8
Utility Services LLC
Brian Evans-Mongeon
Comment:
See filed comments
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
November 17, 2010
1
Baltimore Gas & Electric Company
82
Member:
John J. Moraski
Comment:
Please refer to BGE comments submitted for Project 2007-17 / PRC-005-2 Draft 2, submitted on 7/16/2010.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
1, 3, 5, 6
Public Service Electric and Gas Co., PSEG Energy Resources & Trade LLC
Kenneth D. Brown, Jeffrey Mueller, David Murray, James D. Hebson
Comment:
Please reference comments submitted by the PSEG companies on the official comment form for this
standard.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
1, 3, 3, 3, 3, 5
Southern Company Services, Inc., Alabama Power Company, Georgia Power Company, Gulf Power
Company, Mississippi Power, Southern Company Generation
Member:
Horace Stephen Williamson, Richard J. Mandes, Anthony L Wilson, Gwen S Frazier, Don Horsley, William
D Shultz
Comment:
Comments for this ballot are included in the Southern Company submitted comment form - Project 2007-17:
Protection System Maintenance and Testing.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
1
Duke Energy Carolina
Douglas E. Hils
Comment:
Please see our responses in the comment form - thank you.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
Comment:
November 17, 2010
1
GDS Associates, Inc.
Claudiu Cadar
All comments included in the NERC comment form
83
Response:
Segment:
Organization:
Member:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
3
Louisville Gas and Electric Co.
Charles A. Freibert
Comment:
Comments will be submitte4d under the comment form
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
4, 5
Ohio Edison Company, FirstEnergy Solutions
Douglas Hohlbaugh, Kenneth Dresner
Comment:
Please see FE comments for suggested enhancements submitted via the parallel comment period for this
standard
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
5
PPL Generation LLC
Mark A. Heimbach
Comment:
Please see comments submitted by "PPL Supply" on 7/16/10.
Response:
Thank you for your comment. Please see the SDT response in the Consideration of Comments.
Segment:
Organization:
Member:
Comment:
Response:
4
Detroit Edison Company
Daniel Herring
1. The definition should clarify whether current and voltage transformers themselves are included.
2. This implementation plan and the one for PRC-005-2 should be consistent.
Thank you for your comment.
1. These devices are included in the modified definition. This component of the Protection System
definition is to generally include this functionality as a part of the Protection System. The detailed
applicability of this component within PRC-005-2 is addressed within the Standard.
November 17, 2010
84
2. This comment appears to be addressing the Implementation Plan for the Definition, not for the
Standard.
Segment:
9
Organization:
California Energy Commission
Member:
William Mitchell Chamberlain
Comment:
The current proposal does not require coordination within the interconnection.
1. The standard should require the PCs within an interconnection to coordinate a UFLS Design with all other
PCs within the interconnection and that the PCs should be required to develop a coordinated interconnection
wide UFLS Design. As proposed the standard could conceivably result in as many different UFLS plans
within WECC as there are Planning Coordinators. Additionally, the proposed standard fails to address UFLS
relays which are currently part of the existing program which are owned by the customer. Recognition of
customer owned relays is critical to have a successful program. To assure areas are covered the LSE needs to
be included in the Applicability section. A third concern is the proposed standard attempts to establish
continent wide frequency-time curves and eliminate discrete set points. This approach fails to recognize the
unique characteristics of the four individual interconnections. Frequency-time curves do not allow for
specific and defined measurements and will leave individual entities defaulting to the lowest common
denominator. If frequency-time curves are intended to define the boundaries, the determination of discrete set
points would fall into the hands of the PCs leading to disagreements among entities. In addition, to determine
the frequency-time curves through stability and dynamic modeling, one must establish discrete set points.
Frequency-time curves are reverse engineering and require justification and correlation to the reliability of
the interconnections – no such justification has been provided.
Response:
Thank you for your comment. Your comments appear to be directed to the NERC Standard addressing
development of UFLS programs. The Protection System Maintenance and Testing SDT is unable to address
these comments.
November 17, 2010
85
Consideration of Comments on Initial Ballot of “Protection System” Definition
The PRC-005 Standard Drafting Team thanks all those who participated in the initial ballot for the proposed revision to the definition
of the term, “Protection System.”
All balloters are advised to review the comments and responses in this report as an aid in determining how to participate in the
recirculation ballot.
Based on stakeholder comments, the drafting team refined its proposed definition of Protection System as shown below:
Protective relays which respond to electrical quantities, communication systems necessary for correct operation of
protective functions, voltage and current sensing devices providing inputs to protective relays, station dc supply, and control
circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting devices.
Several comments questioned the reason for implementing the definition of Protection System in advance of implementing the
proposed modifications to PRC-005-1. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of
"protection system" and directed that work to close this reliability gap should be given “priority.” To close this reliability gap the
BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
Stakeholder comments indicated that applying the expanded scope of the definition of Protection System would to PRC-005-1 would
require more than six months and suggested expanding this to 12 months, and the drafting team made this change to the
implementation plan. The team adjusted the implementation plan so that entities will have at least twelve months, rather than the
six months originally proposed, to apply the new definition of Protection System to PRC-005-1 – Protection System Maintenance and
Testing to Requirement R1 of PRC-005-1. The other parts of the implementation plan remain unchanged.
Both clean and redline versions of the definition and the implementation that show the conforming revisions are posted at the
following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
July 22, 2010
1
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process! If you feel there has been an error or omission, you can contact the Vice President and Director of
Standards, Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
July 22, 2010
2
Segment: 1
Organization: International Transmission Company Holdings Corp
Member: Michael Moltane
It should clearly state in the definition or elsewhere in the standard that automatic ground switches intended to
Comment: protect the BES are to be considered interrupting devices. This is stated in the Supplemental Reference but the
Supplemental Reference is not part of the standard.
Response: The definition does not identify individual types of interrupting devices. It is left to Regional BES definitions
to determine if these devices, the system components “protected” by these devices, and their initiating
Protection Systems are BES elements.
Segment: 1, 6
Organization: Cleco Power LLC
Member: Danny McDaniel, Matthew D Cripps
The revised definition to Protection System should include the following exception. "Devices that sense non
Comment: electrical conditions, such as thermal or transformer sudden pressure relays are not included." For consistence
across the standards, see PRC-004, which references System Protection, the same definition should be used.
Response: The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
Segment: 1, 5, 6
Organization: American Electric Power, AEP Service Corp., AEP Marketing
Member: Paul B. Johnson, Brock Ondayko, Edward P. Cox
1. The term "station" should either be defined or removed from the definition, as it implies transmission and
distribution assets while the term "plant" is used to define generation assets. It would suffice to simply
refer to the "DC Supply".
Comment: 2. As written, the implementation plan only specifies a time frame for entities to update their documentation
for PRC-005-1 and PRC-005-2 compliance. The implementation plan also needs to give entities a time
frame to address any required changes to their documentation for other standards that use the term
"Protection System", including but not limited to NUC-001-2, PER-005-1, PRC-001-1, etc.
Response:
July 22, 2010
1. The term “station” is used in a generic sense to apply to either “substation” or “generation station”
3
facilities.
2. An assessment of the changes to the definition (posted with the first comment period), relative to the
entire body of other NERC Standards using this defined term, determined that the changes are
consistent with the other existing uses of the definition, and that no other implementation plan
considerations were necessary. No comments were received relative to this assessment.
Segment: 1
Organization: Avista Corp.
Member: Scott Kinney
Comment:
The modified definition of Protection System now refers to “functions” rather than “devices.” What are the
“functions?” This new term adds confusion without being defined in the standard.
Response: The “functions” are the accumulated performance of the various portions of the Protection System. This term
is used to distinguish “protective functions” from annunciation, signaling, or information.
Segment: 1, 3
Organization: MidAmerican Energy Co.
Member: Terry Harbour, Thomas C. Mielnik
The following changes should be incorporated in the definition to insure it is used consistently in PRC-005
and any other standards where it appears. The following is a suggested revised definition:
“Protection System” is defined as: A system that uses measurements of voltage, current, frequency and/or
phase angle to determine anomalies and to trip a portion of the BES to provide protection for the BES and
consists of
Comment:
1) Protective relays for BES elements and,
2) Communications systems necessary for correct BES protection system operations and,
3) Current and voltage sensing devices supplying BES protective relay input and,
4) Station DC supply to BES protection systems excluding battery chargers, and
5) DC control trip paths to the trip coil(s) of the circuit breakers or other interrupting devices for BES
July 22, 2010
4
elements.
Response: The definition of Protection System establishes “what a Protective System is”, not “what it does”. The
application-related suggestions in the comment are best left to individual standards. The SDT, however, did
modify the “protective relays” to include only those that respond to electrical quantities. Additionally,
constraining relays to “on BES elements” would necessarily exclude UFLS relays, and “trip a portion of the
BES” would exclude SPS and UVLS which are on the BES, but which trip non-BES elements. The SDT also
disagrees with excluding battery chargers.
Segment: 3, 5, 6
Organization: Lincoln Electric System
Member: Bruce Merrill, Dennis Florom, Eric Ruskamp
LES believes the proposed definition of Protection System as written remains open to interpretation. LES
offers the following Protection System definition for the SDT’s consideration:
“Protection System” is defined as: A system that uses measurements of voltage, current, frequency and/or
phase angle to determine anomalies and trips a portion of the BES and consists of
1) Protective relays, and associated auxiliary relays, that initiate trip signals to trip coils,
Comment: 2) associated communications channels,
3) current and voltage transformers supplying protective relay inputs,
4) dc station supply, excluding battery chargers, and
5) dc control trip path circuitry to the trip coils of BES connected breakers, or equivalent interrupting device,
and lockout relays.
Response: The definition of Protection System establishes “what a Protective System is”, not “what it does”. The
application-related suggestions in the comment are best left to individual standards. The SDT, however, did
modify the “protective relays” to include only those that respond to electrical quantities. Additionally,
constraining relays to “on BES elements” would necessarily exclude UFLS relays, and “trip a portion of the
BES” would exclude SPS and UVLS which are on the BES, but which trip non-BES elements. The SDT also
July 22, 2010
5
disagrees with excluding battery chargers.
Segment: 4
Organization: Madison Gas and Electric Co.
Member: Joseph G. DePoorter
Comment: Recommend the following definition “Protection System” is defined as: A system that uses measurements of
voltage, current, frequency and/or phase angle to determine anomalies and trips a portion of the BES and
consists of
1) Protective relays, and associated auxiliary relays, that initiate trip signals to trip coils,
2) associated communications channels,
3) current and voltage transformers supplying protective relay inputs,
4) dc station supply, excluding battery chargers, and
5) dc control trip path circuitry to the trip coils of BES connected breakers, or equivalent interrupting device,
and lockout relays.
Response: The definition of Protection System establishes “what a Protective System is”, not “what it does”. The
application-related suggestions in the comment are best left to individual standards. The SDT, however, did
modify the “protective relays” to include only those that respond to electrical quantities. Additionally,
constraining relays to “on BES elements” would necessarily exclude UFLS relays, and “trip a portion of the
BES” would exclude SPS and UVLS which are on the BES, but which trip non-BES elements. The SDT also
disagrees with excluding battery chargers.
Segment: 1
Organization: National Grid
Member: Saurabh Saksena
1. National Grid suggests adding “Protection System Components including” in the beginning. This is because
the word “components” has been used extensively throughout the standard and there is no mention of what
Comment:
constitutes a protection system component in the standard. The word “component” does find mention in
FAQs, however, it is recommended to mention it in the main standard.
July 22, 2010
6
2. Also, National Grid proposes a change in the proposed definition (changing "voltage and current sensing
inputs" to "voltage and current sensing devices providing inputs"). The revised definition should read as
follows: Protective System Components including Protective relays, communication systems necessary for
correct operation of protective functions, voltage and current sensing devices providing inputs to protective
relays and associated circuitry from the voltage and current sensing devices, station dc supply, and control
circuitry associated with protective functions from the station dc supply through the trip coil(s) of the circuit
breakers or other interrupting devices.
3. The time provided for the first phase “at least six months” is too open ended and does not give entities a
clear timeline. National Grid suggests 1 year for the first phase.
4. As a result, National Grid suggests phasing out the second phase in stages.
Response:
1. The SDT believes that the suggested text does not add to the definition, and may actually lead to
additional problems, such as an implication that the list within the definition is incomplete.
2. The definition has been modified to reflect the proposed change and the “associated circuitry …” has
been removed.
3. The implementation plan has been modified to replace “six months” with “twelve months”.
4. The SDT does not understand this comment.
Segment: 10
Organization: Midwest Reliability Organization
Member: Dan R. Schoenecker
Comment:
Response:
1. The MRO’s NERC Standards Review Subcommittee believes the proposed protection system
definition is unclear specifically as it relates to dc station supply. We would like more clarity as to
what is included in the dc station supply.
2. We believe battery chargers should not be included in the definition; if the Standard Drafting Team
revises the definition we would ask that Table 1 be adjusted, accordingly
1. The definition addressing “dc supply” was modified.
2. The SDT believes that battery chargers should be included in the definition. Without proper
functioning of battery chargers, the battery will be discharged by normal station dc load, and will be
unable to perform its function; also, there are some entities which use a charger to provide the dc
supply without use of a battery.
Segment: 4
July 22, 2010
7
Organization: Old Dominion Electric Coop.
Member: Mark Ringhausen
I am voting Yes on the ballot, but I do have a small issue with the wording of 'station DC supply'. In some of
our UFLS locations, we are not in a substation, but out on the feeder circuit and utilizing the DC supply on the
Comment:
feeder recloser. I think my reading of this definition would apply to this recloser DC supply as well as the
Station DC Supply.
Response: To the extent that UFLS is implemented within distribution system devices not within substations, the
activities and intervals established within the standard would apply.
Segment: 6
Organization: Northern Indiana Public Service Co.
Member: Joseph O'Brien
Comment: It is still not clear whether battery chargers fall under this definition.
Response: The change to “station dc supply” is intended to expand the definition to include all essential elements
including battery chargers.
Segment: 8
Organization: SPS Consulting Group Inc.
Member: Jim R Stanton
Comment: The words in the definition, “...includes one or more of the following activities” are ambiguous and subject to
inconsistent interpretation by auditors. Suggest changing the language to, "...at least one of the following
activities."
Response: This comment does not appear to apply to the “Protection System” definition.
Segment: 4
Organization: Detroit Edison Company
Member: Daniel Herring
Comment:
1. The definition should clarify whether current and voltage transformers themselves are included.
2. This implementation plan and the one for PRC-005-2 should be consistent.
Response:
1. This portion of the definition has been modified for clarity.
July 22, 2010
8
2. The Implementation Plan for the definition has been modified. The Implementation Plan for the
Standard is a separate issue.
Segment: 1
Organization: BC Transmission Corporation
Member: Gordon Rawlings
Comment: The definition excludes mechanical relays (Gas Relays) which may affect the BES
Response: The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
Segment: 1, 3, 4, 5, 6
Organization:
Empire District Electric Co., Cowlitz County PUD, Cowlitz County PUD, Cowlitz County PUD, Florida
Municipal Power Pool
Member: Ralph Frederick Meyer, Russell A Noble, Rick Syring, Bob Essex, Thomas E Washburn
Comment:
1. It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are
included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that
particular standard to protection systems that sense electrical quantities, it is remains unclear in other
standards that use the defined term whether mechanical input protections are included.
2. We suggest that “Protective Relay” also be defined, and that the definition clearly exclude devices that
respond to mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the
CMPWG request.
Response:
1.
The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
2. “Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC
standard, thus the SDT sees no need to either modify or duplicate that definition.
Segment: 3
Organization: Central Lincoln PUD
Member: Steve Alexanderson
Comment: 1. Do you believe the proposed definition of Protection System is ready for ballot? If not, please explain why.
July 22, 2010
9
0 Yes X No
Comments: It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure
relays, are included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope
of that particular standard to protection systems that sense electrical quantities, it is remains unclear in
other standards that use the defined term whether mechanical input protections are included. We suggest
that “Protective Relay” also be defined, and that the definition clearly exclude devices that respond to
mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG
request.
2. Do you agree with the implementation plan for the revised definition of Protection System? The
implementation plan has two phases – the first phase gives entities at least six months to update their
protection system maintenance and testing program; the second phase starts when the protection system
maintenance and testing program has been updated and requires implementation of any additional
maintenance and testing associated with the program changes by the end of the first complete maintenance
and testing cycle described in the entity’s revised program.
If you disagree with this implementation plan, please explain why. X Yes 0 No Comments:
Response:
1. The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
2. Thank you.
Segment: 3
Organization: Consumers Energy
Member: David A. Lapinski
Comment:
1. It is unclear whether “voltage and current sensing inputs” include the instrument transformer itself, or
does it pertain to only the circuitry and input to the protective relays.
2. It is not clear what is included in the component, “station dc supply” without referring to other
documents (the posted Supplementary Reference and/or FAQ) for clarification. The definition should
be sufficiently detailed to be clear.
3. If Protection Systems trip via AC methods, are those systems, and the associated control circuitry
included in the definition and within the requirements of the Standard as expressed within the Tables?
Response: 1. The definition has been changed for clarity; the SDT intends that the output of these devices, measured at
the relay should properly represent the primary quantities.
July 22, 2010
10
2. There are many possible variations to “station dc supply”. The definition must be sufficiently general such
that variations can be included.
3. The definition has been generalized such that ac tripping is included.
Segment: 1, 3, 5
Organization: Arizona Public Service Co., APS
Member: Robert D Smith, Thomas R. Glock, Mel Jensen
The change to the definition relative to the voltage and current sensing devices is too prescriptive. Methods of
Comment: determining the integrity of the voltage and current inputs into the relays to ensure reliability of the devices
should be up to the discretion of the utility.
Response: The definition has been changed for clarity; the SDT intends that the output of these devices, measured at the
relay should properly represent the primary quantities.
Segment: 4
Organization: Consumers Energy
Member: David Frank Ronk
1. It is unclear whether “voltage and current sensing inputs” include the instrument transformer itself, or does
it pertain to only the circuitry and input to the protective relays?
2. It is not clear what is included in the component, “station dc supply” without referring to other documents
(the posted Supplementary Reference and/or FAQ) for clarification. The definition should be sufficiently
detailed to be clear.
Comment: 3. If Protection Systems trip via AC methods, are those systems, and the associated control circuitry included?
4. For entities that may not have included all elements reflected in the modified definition within their PRC005-1 program, 6-months following regulatory approvals may not be sufficient to identify all relevant
additional components, develop maintenance procedures, develop maintenance and testing intervals,
develop a defendable technical basis for both the procedures and intervals, and train personnel on the
newly implemented items. We propose that a 12-month schedule following regulatory approvals may be
more practical.
Response: 1. The SDT made several changes to the definition to improve clarity. The SDT intends that the output of
July 22, 2010
11
these devices, measured at the relay should properly represent the primary quantities.
2. There are many possible variations to “station dc supply”. The definition must be sufficiently general such
that variations can be included.
3. The definition has been generalized such that ac tripping is included.
4. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to agree
with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day
of the first calendar quarter”.
Segment: 1, 3, 6
Organization: Consolidated Edison Co. of New York
Member: Christopher L de Graffenried, Peter T Yost, Nickesha P Carrol
1. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate
equipment identified in the existing or proposed definition. However, not all such equipment translates into
a transmission Protection System.
Comment:
2. The definition needs clarification on when such equipment is a part of the transmission protection system.
3. Also, the time provided for the first phase "at least six months" is too open ended and does not provide
entities with a clear timeline. It is suggested that one year is appropriate for the first phase phasing out the
second year in stages.
Response:
1. This issue is properly addressed within the Standard, not within the definition.
2. This issue is properly addressed within the Standard, not within the definition.
3. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to
agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
Segment: 1, 3
Organization: Hydro One Networks, Inc.
Member: Ajay Garg, Michael D. Penstone
Comment: The proposed definition of Protection System needs clarification on when such equipment is a part of the
July 22, 2010
12
transmission protection system. Emphasis should be on systems and not individual components.
Response: This issue is properly addressed within the Standard, not within the definition.
Segment: 4
Organization: Y-W Electric Association, Inc.
Member: James A Ziebarth
From Question 1 on the comment form: The application of this definition to Reliability Standards NUC-0012, PER-005-1, PRC-001-1, and PRC-004-1 results in confusion as to whether relays with mechanical inputs
are included or excluded from this definition. PRC-005-2_R1 contains language limiting its applicability to
Comment:
relays operating on electrical inputs only, but the remaining standards that rely on this definition are not so
specific. This being the case, it would make much more sense to clearly define what devices are actually
meant in the glossary definition rather than leaving it up to each individual standard to do so.
Response: The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
Segment: 1, 3
Organization: Platte River Power Authority
Member: John C. Collins, Terry L Baker
1. Although the applicable relays to which protective relays are outlined in the NERC PRC-005-2 Protection
system Maintenance Draft Supplementary Reference dated May 27, 2010, they are not defined in the
NERC Glossary of terms. Until it is clearly defined which relays are included inconsistencies will exists
from region to region in their audit approaches and which relays they will be looking at.
Comment:
2. Also, there is still debate why the protective relays would extend to mechanical devices such as the lock-out
relay and tripping for trip-free relays. In our system configuration we risk reliability to customer load by
testing the lock-out relays which we feel out weights the benefit of testing devices that we see little to no
evidence of failure in.
Response: 1. This is properly an issue for the various Regional BES definitions.
2. The definition does not explicitly include these devices, although they are implicitly part of “control
circuitry”.
Segment: 3
Organization: Public Utility District No. 2 of Grant County
July 22, 2010
13
Member: Greg Lange
These systems are not always maintained at the component level, i.e. meggering from the relay input test
switch through the cable and the CT. This has not closed all the issues around professional judgment
Comment:
(interpretations) that make us nervous when faced with the human element of an audit. We need more
specificity to close that gap.
Response: This issue is properly addressed within the Standard, not within the definition.
Segment: 1, 3, 5, 6
Organization:
Dominion Virginia Power, Dominion Resources Services, Dominion Resources, Inc., Dominion Resources,
Inc.
Member: John K Loftis, Michael F Gildea, Mike Garton, Louis S Slade
Comment: The proposed definition introduces ambiguity and we suggest retaining the current definition.
Response: The existing definition presents ambiguities and gaps which must be addressed in accordance with directives
from the NERC BOT. Additionally, the draft definition constrains certain components to remove ambiguities.
Segment: 5
Organization: Southern Company Generation
Member: William D Shultz
We agree that the definition provides clarity and will enhance the reliability of the Protection Systems to
which it is applicable. The negative vote is a result of a belief that the definition’s effective date must be
coincident with the approval and implementation schedule of PRC-005-2. Since this new definition is directly
Comment: linked to the proposed revised standard, it would be premature to make this definition effective prior to the
effective date of the new standard. If balloted and approved, there is no obligation to or guarantee of any
additional maintenance to be performed. PRC-005-2 includes this definition, the maintenance activities, and
the intervals that will ensure execution of the maintenance and testing.
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
July 22, 2010
14
definition to PRC-005-1.
Segment: 1, 3, 6
Organization: Great River Energy
Member: Gordon Pietsch, Sam Kokkinen, Donna Stephenson
Comment:
We agree with the revised Protection System definition. The revised definition should only be applied to PRC005-2. The revised definition should not be applied to PRC-005-1.
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
Segment: 5
Organization: Progress Energy Carolinas
Member: Wayne Lewis
Progress Energy does not believe that the definition should be implemented separately from and prior to the
implementation of PRC-005-2. We believe there should be a direct linkage between the definition’s effective
date to the approval and implementation schedule of PRC-005-2. Since this new definition should be directly
Comment:
linked to the proposed revised standard, it would be premature to make this new definition effective prior to
the effective date of the new standard. We believe that changes to the maintenance program should be driven
by the revision of the PRC standard, not by the revision of a definition.
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
July 22, 2010
15
Segment: 1
Organization: Ameren Services
Member: Kirit S. Shah
Comment: The implementation of the revised definition and PRC-005-2 PSMP must align on the same date.
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
Segment: 3
Organization: Niagara Mohawk (National Grid Company)
Member: Michael Schiavone
Comment:
Response:
1. National Grid does not agree with the proposed implementation plan. The time provided for the first
phase “at least six months” is too open ended and does not give entities a clear timeline. National Grid
suggests 1 year for the first phase.
2. National Grid also suggests phasing out the second phase in stages.
1. The Implementation Plan has been modified to replace “six months” with “twelve months”.
2. We do not understand your comment.
Segment: 1, 3, 3, 3, 3
Organization:
Southern Company Services, Inc., Alabama Power Company, Georgia Power Company, Gulf Power
Company, Mississippi Power
Member: Horace Stephen Williamson, Richard J. Mandes, Anthony L Wilson, Gwen S Frazier, Don Horsley
We agree that the definition provides clarity and will enhance the reliability of the Protection Systems to
which it is applicable. However, we feel that there needs to be a direct linkage of the definition’s effective
Comment: date to the approval and implementation schedule of PRC-005-2. Since this new definition is directly linked to
the proposed revised standard, it would be premature to make this definition effective prior to the effective
date of the new standard.
July 22, 2010
16
Response: Thank you. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused
by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1
as soon as practical - not years from now. The implementation plan now proposes at least 12 months for
entities to apply the new definition to PRC-005-1, and that should give entities time to apply the new
definition to PRC-005-1.
Segment: 1, 5
Organization: Entergy Corporation
Member: George R. Bartlett, Stanley M Jaskot
The following are the reasons associated with our Negative Ballot.
1. We agree with the definition, however we do not agree with the implementation plan. We believe
implementation of the definition needs to coincide with the implementation of Standard PRC-005-2. To do
otherwise, will cause entities to address equipment, documentation, work management process, and
Comment:
employee training changes needed for compliance twice within an unreasonably short timeframe.
2. A 12 month minimum timeframe is need to implement this definition
3. We also reserve the right to include selected reasons submitted by other Negative balloters for their
Negative Ballot.
Response:
1. Thank you.
2. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to
agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”. When the Board of Trustees was asked to approve an
interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the
reliability gap identified by the drafting team caused by the definition of "protection system" and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap
the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years
from now. The implementation plan now proposes at least 12 months for entities to apply the new
definition to PRC-005-1, and that should give entities time to apply the new definition to PRC-005-1.
3. Thank you.
Segment: 3, 6
July 22, 2010
17
Organization: Entergy
Member: Joel T Plessinger, Terri F Benoit
1. We agree with the definition, however we do not agree with the implementation plan. We believe
implementation of the definition needs to coincide with the implementation of Standard PRC-005-2. To do
Comment:
otherwise, will cause entities to address equipment, documentation, work management process, and
employee training changes needed for compliance twice within an unreasonably short timeframe.
2. A 12 month minimum timeframe is need to implement this definition
Response:
1. Thank you.
2. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to
agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”. When the Board of Trustees was asked to approve an
interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the
reliability gap identified by the drafting team caused by the definition of "protection system" and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap
the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years
from now. The implementation plan now proposes at least 12 months for entities to apply the new
definition to PRC-005-1, and that should give entities time to apply the new definition to PRC-005-1.
Segment: 5
Organization: U.S. Bureau of Reclamation
Member: Martin Bauer
1. It is unfortunate that the definition did not retain consistency in the terms. As an example, the definition
indicates it includes protective relays and communication systems for the correct operation of protective
functions. It would have been better to use the term relays instead of the term functions. Now it is unclear
what the communication systems are for.
Comment:
July 22, 2010
2. The Time Horizons are too narrow for the implementation of the standard as written. The SDT appears to
have not accounted for the data analysis associated with performance based systems. The data collection,
analysis, and subsequent decisions associated development of a maintenance program and its justification do
not occur overnight especially with larger utilities. In addition, this new standard will require complete rewrite
of an entities internal maintenance programs. The internal processes associated with these vary based on the
18
size of the entity and its organizational structure. Since this standard is so invasive into the internal decisions
concerning maintenance, the standard should allow at least 18 months for entities to rewrite their internal
maintenance programs to meet the program development requirements and 18 months to train the staff in the
new program, incorporate the program into the entities compliance processes, and to implement the new
program.
Response:
1. “Functions” was used, as some applications (SPS, for example) may have communications systems
that operate other than via protective relays.
2. This comment appears to be focused on the revised Standard, not on the definition.
Segment: 2
Organization: Midwest ISO, Inc.
Member: Jason L Marshall
Comment:
We are abstaining because a number of our stakeholders have concerns regarding the definition of Protection
System and the inclusion of UVLS and UFLS in a standard dealing with maintenance of protection systems.
Response: The inclusion of UVLS/UFLS is related to a directive from FERC in Order 693, and to the SAR for this
project.
Segment: 1
Organization: Lakeland Electric
Member: Larry E Watt
Comment: An implementation plan should be associated with this definition change.
Response: An Implementation Plan specifically for the definition is posted.
Segment: 1
Organization: Clark Public Utilities
Member: Jack Stamper
Comment: The proposed definition does not provide the level of clarity that is needed.
Response: The SDT made several changes to the definition to improve clarity.
Segment: 1
Organization: Beaches Energy Services
July 22, 2010
19
Member: Joseph S. Stonecipher
Comment: While better than the last draft, too many problems still exist.
The following series of comments all indicate that the entity has submitted comments via the official comment form.
Segment: 1, 5, 6
Organization: Public Service Electric and Gas Co., PSEG Energy Resources & Trade LLC
Member: Kenneth D. Brown, David Murray, James D. Hebson
Comment: Please reference comments submitted by the PSEG companies on the official comment form for this standard.
Segment: 1
Organization: Potomac Electric Power Co.
Member: Richard J. Kafka
Comment: PHI submitted comments
Segment: 3
Organization: Louisville Gas and Electric Co.
Member: Charles A. Freibert
Comment: Comments will be submitte4d under the comment form
Segment: 3
Organization: Bonneville Power Administration
Member: Rebecca Berdahl
Comment: Please see BPA's comments submitted during the concurrent formal comment period ending July 16, 2010.
Segment: 1
Organization: GDS Associates, Inc.
Member: Claudiu Cadar
Comment: All comments included in the NERC comment form
Segment: 1, 3, 4, 5, 6
Organization: FirstEnergy Energy Delivery, FirstEnergy Solutions, FirstEnergy Solutions, Ohio Edison Company,
July 22, 2010
20
FirstEnergy Solutions
Member: Robert Martinko, Kevin Querry, Kenneth Dresner, Douglas Hohlbaugh, Mark S Travaglianti
Comment:
Please see FE comments for suggested enhancements submitted via the parallel comment period for this
definition.
Segment: 1
Organization: Duke Energy Carolina
Member: Douglas E. Hils
Comment: Please see our responses in the comment form - thank you.
Segment: 8
Organization: Utility Services LLC
Member: Brian Evans-Mongeon
Comment: see filed comments
Segment: 5
Organization: PPL Generation LLC
Member: Mark A. Heimbach
Comment: Please see comments submitted by "PPL Supply" on 7/16/10.
From this point on, all comments provided relate to the proposed standard, not to the proposed definition and its implementation plan.
Responses to comments submitted with ballots for the standard are included in the comment report for the standard – they are not
duplicated here.
Segment: 1
Organization: Lake Worth Utilities
Member: Walt Gill
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard 2. The draft standard would cause
Comment: NERC to regulate through the standards battery testing, DC circuit testing, etc. on distribution elements with
no significant improvement to BES reliability, which is beyond the statutory scope of the standards 3. The
standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of protection
July 22, 2010
21
system components. Will the Standard Introduce Technical Feasibility Exceptions to PRC Standards? a large
proportion of the batteries (as high as 50% as reported by some SMEs) are not able to accommodate all of the
tests prescribed in the draft standard. Will this necessitate the introduction of TFEs into the process
unnecessarily? The Standard Reaches Beyond the Statutory Scope of the Reliability Standards As written, the
standard requires testing of batteries, DC control circuits, etc., of distribution level protection components
associated with UFLS and UVLS. UFLS and UVLS are different than protection systems used to clear a fault
from the BES. An uncleared fault on the BES can have an Adverse Reliability Impact and hence; the focus on
making sure the fault is cleared is important and appropriate. However, a UFLs or UVLS event happens after
the fault is cleared and is an inexact science of trying to automatically restore supply and demand balance
(UFLS) or restore voltages (UVLS) to acceptable levels. If a few UFLS or UVLS relays fail to operate out of
potentially thousands of relays with the same function, there is no significant impact to the function of UFLS
or UVLS. Hence, there is no corresponding need to focus on every little aspect of the UFLS or UVLS
systems. Therefore, the only component of UFLS or UVLS that ought to be focused on in the new PRF-005
standard is the UFLS or UVLS relay itself and not distribution class equipment such as batteries, DC control
circuitry, etc., and these latter ought to be removed from the standard. In addition, most distribution circuit are
radial without substation arrangements that would allow functional testing without putting customers out of
service while the testing was underway, or at least without momentary outages while customers were switched
from one circuit to another. Therefore, as written, we would be sacrificing customer service for a negligible
impact on BES reliability. Perfection is Not A Realistic Goal The standard allows no mistakes. Even the
famous six sigma quality management program allows for defects and failures (i.e., six sigma is six standard
deviations, which means that statistically, there are events that fall outside of six standard deviations). PRC005 has been drafted such that any failure is a violation, e.g., 1 day late on a single relay test of tens of
thousands of relays is a violation. That is not in alignment with worldwide accepted quality management
practices (and also makes audits very painful because statistical, random sampling should be the mode of
audit, not 100% review as is currently being done in many instances). FMPA suggests considering statistically
based performance metrics as opposed to an unrealistic performance target that does not allow for any failure
ever. Due to the shear volume of relays, with 100% performance required, if the standards remain this way,
PRC-005 will likely be in the top ten most violated standards for the forever. There is a fundamental flaw in
thinking about reliability of the BES. We are really not trying to eliminate the risk of a widespread blackout,
we are trying to reduce the risk of a widespread blackout. We plan and operate the system to single and
credible double contingencies and to finite operating and planning reserves. To eliminate the risk, we would
need to plan and operate to an infinite number of contingencies, and have an infinite reserve margin, which is
infeasible. Therefore, by definition, there is a finite risk of a widespread blackout that we are trying to reduce,
July 22, 2010
22
not eliminate, and, by definition, by planning and operating to single and credible double contingencies and
finite operating and planning reserves, we are actually defining the level of risk from a statistical basis we are
willing to take. With that in mind, it does not make sense to require 100% compliance to avoid a smaller risk
(relays) when we are planning to a specified level of risk with more major risk factors (single and credible
double contingencies and finite planning and operating reserves).
Segment: 3, 4, 5
Organization: Wisconsin Electric Power Marketing, Wisconsin Energy Corp., Wisconsin Electric Power Co.
Member: James R. Keller, Anthony Jankowski, Linda Horn
We Energies does not agree to the implementation plan proposed. While it makes common sense to proceed
with R1 prior to proceeding with implementing R2, R3, and R4, the timeline to be compliant for R1 is too
short. It will take a considerable amount of resources to migrate the maintenance plan from today’s standard
to the new standard in phase one. ATC recommends that time to develop and update the revised program be
increased to at least one year followed by a transition time for the entity to collect all the necessary field data
for the protection system within its first full cycle of testing. (In ATC’s case would be 6 years) To address
phase two, We Energies believes human and technological resources will be overburdened to implement this
revised standard as written. The transition to implementing the new program will take another full testing
cycle once the program has been updated. Increased documentation and obtaining additional resources to
accomplish this will be challenging. Implementation of PRC-005-2 will impact We Energies in the following
manner: a. Increase costs: double existing maintenance costs. b. Since there will be a doubling of human
Comment:
interaction (or more), it is expected that failures due to human error will increase, possibly proportionately. c.
Breaker maintenance may need to be aligned with protection scheme testing, which will always contain
elements that are include in the non-monitored table for 6 yr testing. d. We Energies is developing standards
for redundant bus and transformer protection schemes. This would allow We Energies to test the protection
packages without taking the equipment out of service. Further if one system fails, there is full redundancy
available. With the current version of PRC-005-2, We Energies would need to take an outage to test the
protection schemes for a transformer or a bus, there is not an incentive to install redundant schemes. We
Energies is working with a condition based breaker maintenance program. This program’s value would be
greatly diminished under PRC-005-2 as currently written. Consideration also needs to be given for other
NERC standards expected to be passed and in the implementation stage at the same time, such as the CIP
standards.
Segment: 4, 5
July 22, 2010
23
Organization: Florida Municipal Power Agency
Member: Frank Gaffney, David Schumann
FMPA recommends a negative vote on PRC-005-2, Project 2007-17, for three significant reasons 1. As
written, it opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries are not
able to accommodate all of the tests proscribed in the draft standard as explained by Steve Alexanderson in a
prior e-mail to the ballot pool. 2. The draft standard would cause NERC to regulate through the standards
battery testing, DC circuit testing, etc. on distribution elements with no significant improvement to BES
reliability, which is beyond the statutory scope of the standards 3. The standard unreasonably retains the
"100% compliance" paradigm for thousands, if not millions of protection system components. Will the
Standard Introduce Technical Feasibility Exceptions to PRC Standards? As described by Steve Alexanderson
in a prior e-mail to the ballot pool, a large proportion of the batteries (as high as 50% as reported by some
SMEs) are not able to accommodate all of the tests prescribed in the draft standard. Will this necessitate the
introduction of TFEs into the process unnecessarily? The Standard Reaches Beyond the Statutory Scope of the
Reliability Standards As written, the standard requires testing of batteries, DC control circuits, etc., of
distribution level protection components associated with UFLS and UVLS. UFLS and UVLS are different
than protection systems used to clear a fault from the BES. An uncleared fault on the BES can have an
Adverse Reliability Impact and hence; the focus on making sure the fault is cleared is important and
Comment:
appropriate. However, a UFLs or UVLS event happens after the fault is cleared and is an inexact science of
trying to automatically restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable
levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays with the same
function, there is no significant impact to the function of UFLS or UVLS. Hence, there is no corresponding
need to focus on every little aspect of the UFLS or UVLS systems. Therefore, the only component of UFLS or
UVLS that ought to be focused on in the new PRF-005 standard is the UFLS or UVLS relay itself and not
distribution class equipment such as batteries, DC control circuitry, etc., and these latter ought to be removed
from the standard. In addition, most distribution circuit are radial without substation arrangements that would
allow functional testing without putting customers out of service while the testing was underway, or at least
without momentary outages while customers were switched from one circuit to another. Therefore, as written,
we would be sacrificing customer service for a negligible impact on BES reliability. Perfection is Not A
Realistic Goal The standard allows no mistakes. Even the famous six sigma quality management program
allows for defects and failures (i.e., six sigma is six standard deviations, which means that statistically, there
are events that fall outside of six standard deviations). PRC-005 has been drafted such that any failure is a
violation, e.g., 1 day late on a single relay test of tens of thousands of relays is a violation. That is not in
July 22, 2010
24
alignment with worldwide accepted quality management practices (and also makes audits very painful
because statistical, random sampling should be the mode of audit, not 100% review as is currently being done
in many instances). FMPA suggests considering statistically based performance metrics as opposed to an
unrealistic performance target that does not allow for any failure ever. Due to the shear volume of relays, with
100% performance required, if the standards remain this way, PRC-005 will likely be in the top ten most
violated standards for the forever. There is a fundamental flaw in thinking about reliability of the BES. We are
really not trying to eliminate the risk of a widespread blackout, we are trying to reduce the risk of a
widespread blackout. We plan and operate the system to single and credible double contingencies and to finite
operating and planning reserves. To eliminate the risk, we would need to plan and operate to an infinite
number of contingencies, and have an infinite reserve margin, which is infeasible. Therefore, by definition,
there is a finite risk of a widespread blackout that we are trying to reduce, not eliminate, and, by definition, by
planning and operating to single and credible double contingencies and finite operating and planning reserves,
we are actually defining the level of risk from a statistical basis we are willing to take. With that in mind, it
does not make sense to require 100% compliance to avoid a smaller risk (relays) when we are planning to a
specified level of risk with more major risk factors (single and credible double contingencies and finite
planning and operating reserves).
Segment: 1
Organization: Keys Energy Services
Member: Stan T. Rzad
As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries are
not able to accommodate all of the tests proscribed in the draft standard. The draft standard would cause
NERC to regulate through the standards battery testing, DC circuit testing, etc. on distribution elements with
Comment:
no significant improvement to BES reliability, which is beyond the statutory scope of the standards The
standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of protection
system components.
Segment: 3
Organization: Municipal Electric Authority of Georgia
Member: Steven M. Jackson
Comment:
July 22, 2010
Station DC supply testing was set at three months. A six month time based testing interval is reasonable.
Maximum maintenance interval for a lead-acid vented battery is liste at six calendar years. This type of test
25
reduces battery life. A 10 to 12 year interval is reasonable. As written this rule would require a TFE that
should be administratively unnecessary. Additional clarification is needed in: Control and trip circuits
associated with UVLS and UFLS do not require tripping of the breakers but all other protection systems
require tripping. Please clarify. Digital relays have electromagnetic output relays - are they categorized as
electromechanical or solid state? There needs to be reasonable flexibility based on industry experience in
allowing less than 100% perfection in the testing of relays, etc.
Segment: 1
Organization: American Transmission Company, LLC
Member: Jason Shaver
ATC does not agree to the implementation plan proposed. While it makes common sense to proceed with R1
prior to proceeding with implementing R2, R3, and R4, the timeline to be compliant for R1 is too short. It will
take a considerable amount of resources to migrate the maintenance plan from today’s standard to the new
standard in phase one. ATC recommends that time to develop and update the revised program be increased to
at least one year followed by a transition time for the entity to collect all the necessary field data for the
protection system within its first full cycle of testing. (In ATC’s case would be 6 years) To address phase two,
ATC believes human and technological resources will be overburdened to implement this revised standard as
written. The transition to implementing the new program will take another full testing cycle once the program
has been updated. Increased documentation and obtaining additional resources to accomplish this will be
challenging. Implementation of PRC-005-2 will impact ATC in the following manner: a. Increase costs:
Comment: double existing maintenance costs. b. Since there will be a doubling of human interaction (or more), it is
expected that failures due to human error will increase, possibly proportionately. c. Breaker maintenance may
need to be aligned with protection scheme testing, which will always contain elements that are include in the
non-monitored table for 6 yr testing. d. ATC is developing standards for redundant bus and transformer
protection schemes. This would allow ATC to test the protection packages without taking the equipment out
of service. Further if one system fails, there is full redundancy available. With the current version of PRC005-2, ATC would need to take an outage to test the protection schemes for a transformer or a bus, there is not
an incentive to install redundant schemes. ATC is working with a condition based breaker maintenance
program. This program’s value would be greatly diminished under PRC-005-2 as currently written.
Consideration also needs to be given for other NERC standards expected to be passed and in the
implementation stage at the same time, such as the CIP standards.
Segment: 1
July 22, 2010
26
Organization: Tucson Electric Power Co.
Member: John Tolo
Comment: The mention of communication systems maintenance (M1.) needs more clarity as to the depth of the
maintenance required. Also, Table 1a, a 3-month interval to verify that the Protection System communications
system is functional is too frequent to be practical.
Segment: 4
Organization: Fort Pierce Utilities Authority
Member: Thomas W. Richards
Comment: The requirement for taking intracell readings is not possible for all batteries. Some minor rewording would
resolve this issue and make it applicable to those batteries that have internal cell-to-cell straps. I would
recommend changing the minimum requirement to take intracell resistance readings from the battery
terminals, since identifying the particular cell that is going bad is of little use. I imagine all utilities replace an
entire jar, not individual cells. The draft standard would cause NERC to regulate, through the standards
battery testing, DC circuit testing, etc. on distribution elements with no significant improvement to BES
reliability, which is beyond the statutary scope of the standards The standard unreasonably retains the "100%
compliance" paradigm for thousands, if not millions of protection system components. This becomes an
investigation, not an audit. There is no way an audit team will have the time to arrive at 100% compliance
with a large entity.
Segment: 1, 3, 6
Organization: Xcel Energy, Inc.
Member: Gregory L Pieper, Michael Ibold, David F. Lemmons
Xcel Energy believes the standard still contains many aspects that are not clearly understood by entities,
Comment: including what is needed to demonstrate a compliant PSMP. Comments have been submitted concurrently to
NERC via the draft comment response form.
Segment: 1, 3, 5, 6
Organization: Kansas City Power & Light Co.
Member: Michael Gammon, Charles Locke, Scott Heidtbrink, Thomas Saitta
Comment: The proposed changes in the Standard are far too prescriptive and does not take into account the multitude of
July 22, 2010
27
manufacturers equipment by establishing broad maintenance cycles and testing intervals.
Segment: 1
Organization: SCE&G
Member: Henry Delk, Jr.
While SCE&G believes the majority of the PRC-005-2 standard is ready to be affirmed there are still
Comment: inconsistencies with areas of the standard that need to be corrected prior to approval. These inconsistencies are
addressed in SCE&G’s comments which have been submitted for the current draft of this standard.
Segment: 1, 3, 4, 6
Organization: Seattle City Light
Member: Pawel Krupa, Dana Wheelock, Hao Li, Dennis Sismaet
Comment: Functional testing is impractical.
Segment: 6
Organization: Florida Power & Light Co.
Member: Silvia P Mitchell
Comment: This standard is too prescriptive and will result in many violations.
Segment: 5
Organization: Salt River Project
Member: Glen Reeves
SRP believes the requirements of the Standard are confusing and may be problematic in determining
compliance. We also believe the required functional testing of the breaker trip coil may potentially increase
maintenance outages of circuit breakers. In most cases, circuit breaker maintenance outages can be
Comment: coordinated such that Protection System maintenance and testing can be done simultaneously. However, in
some cases this may not be possible. Outages of any BES facility whether planned or unplanned can impact
system reliability. SRP suggests that trip coil monitoring devices be included as an acceptable means of
ensuring the trip coil is functioning properly. This will help to avoid unnecessary outages.
Segment: 3
Organization: Lakeland Electric
July 22, 2010
28
Member: Mace Hunter
Comment:
The proposed draft may introduce TFEs into the PRC standards, not a good thing. The proposed draft
reacheds beyound the statutory scope of the reliability standards. Perfection is not a realistic goal.
Segment: 1
Organization: PPL Electric Utilities Corp.
Member: Brenda L Truhe
PPL EU is voting negative because Rqmt 1.1 "Identify all Protection System components" is too broad and
Comment: must be clarified and the definition of Protective Relays is not limited to only those devices that use electrical
quantities as inputs (exclude pressure, temperature, gas, etc).
Segment: 1
Organization: Pacific Gas and Electric Company
Member: Chifong L. Thomas
We are concerned over R1.1, where all components must be identified, without a definition for the word
component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in
determining the granularity, the FAQ is not part of the standard. We are concerned whether identification is
Comment: required for every individual component, such as each auxiliary relay, or is it sufficient that the auxiliary
relays are included within the scheme that is being tested and documented. Do the auxiliary relays need to be
documented within the maintenance database and/or on the actual test reports of schemes being tested? We
suggest that the FAQ definitions be included within the standard.
July 22, 2010
29
Consideration of Comments on Non-binding Poll of VRFs and VSLs associated with PRC-005-2 – Protection
System Maintenance
The PRC-005 Standard Drafting Team thanks all those who participated in non-binding poll for the VRFs and VSLs associated with
PRC-005-2. The initial non-binding poll was conducted from July 8 through July 17, 2010 and achieved a quorum with 85.96 % of the
ballot pool members returning an opinion, and with 32.29 % of those indicating support for the proposed VRFs and VSLs.
Many commenters proposed that the VSLs allow for some amount of non-compliance with the Standard before incurring a violation.
NERC’s guidelines for VSLs do not allow some level of non-performance without being in violation. The SDT did, however, modify
the VSLs for Requirements R1 and R4 to provide gradated VSLs.
Some commenters suggested the SDT re-evaluate the VRF assignments. The SDT reconsidered the VRFs in accordance with the
guidance provided by NERC and FERC, and modified the Standard to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium,
and R4 – High. Some commenters made comments that appeared to be related to the technical content of the Standard, not to the
VRFs or VSLs and these comments were addressed in the report containing responses to comments on the standard. All comments
submitted have been publicly posted on the following web page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process! If you feel there has been an error or omission, you can contact the Vice President and Director of
Standards, Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
November 17, 2010
1
Segment:
Organization:
Member:
3, 4, 5
Cowlitz County PUD
Russell A Noble, Rick Syring, Bob Essex
Comment:
Cowlitz does not understand a High VRF designation for requirement R1; this should be a Low or Medium
designation. R1 is merely covering a maintenance program, not the actual maintenance. Actual missed
maintenance of components (requirement R4) should have the Medium or High VRF. This Standard is very
descriptive of minimum maintenance intervals on each “component;” thus, it is possible to have maintenance
documentation that is in full compliance once the Program is built around it. It should never be a case where
an entity can receive a higher VRF over missing documentation of a process, and then a lower VRF over
missing documentation of the implementation of the process.
Response:
The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and the
Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 –
High.
Segment:
Organization:
Member:
Comment:
1
United Illuminating Co.
Jonathan Appelbaum
The VRF for R1 should be Low. It is administrative to create an inventory list. If R1 failed to be executed but
the other requirements wee executed fully then the BES would be properly secured. Compare this against the
scenario of performing R1 but failing to perform the other tasks; in which case the BES is at risk. UI
recognizes that the SDT considers the inventory as the foundation of the PSMP but it is not the element of the
PSMP that provides for the level of reliability sought.
R1 should be VRF Low and R2 thru R4 VRF is Medium.
UI agrees with the Time Horizon.
Response:
November 17, 2010
The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and the
Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 –
High.
2
Segment:
Organization:
Member:
1, 3, 4, 5, 6
FirstEnergy Energy Delivery, FirstEnergy Solutions, Ohio Edison Company, FirstEnergy Solutions,
FirstEnergy Solutions
Robert Martinko, Kevin Querry, Douglas Hohlbaugh, Kenneth Dresner, Mark S Travaglianti
Comment:
FirstEnergy appreciates the hard work of the drafting team, but unfortunately we must cast a Negative vote for
the VRF for Requirement R1. Although we agree that Requirement 1 is important because it establishes a
sound PSMP, a HIGH VRF assignment is not appropriate and it should be changed to LOWER. By definition,
a requirement with a LOWER VRF is administrative in nature, and documentation of a program is
administrative. Assigning a LOWER VRF to R1 is more logical since R4, which is the requirement to
implement the PSMP, is assigned a MEDIUM VRF because, if violated, it could directly affect the electrical
state or the capability of the bulk electric system.
Response:
The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and the
Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 –
High.
Segment:
Organization:
Member:
1
Ameren Services
Kirit S. Shah
Comment:
The Lower VSL for all Requirements should begin above 1% of the components.
Response:
The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
Segment:
Organization:
Member:
Comment:
November 17, 2010
5
Constellation Power Source Generation, Inc.
Amir Y Hammad
In general, the VSLs are completely biased against small generating facilities that may have only 20 or 30
components to their protective system. If a facility with only 30 components were to fail to identify 2
components, then that would automatically fall under a moderate VSL. This is true for R1 and R4. A
suggestion would be to eliminate the percentage of components and instead focus on what the violation is. For
example, for R1, a lower VSL could state “the entity’s PSMP includes all of the ‘types’ of components
included in the definition of ‘Protection System’, but failed to specify whether a component is being addressed
3
by time-based, condition-based, or performance-based maintenance.
Response:
Segment:
Organization:
Member:
The SDT believes the stepped VSLs are not biased against small entities.
5
Liberty Electric Power LLC
Daniel Duff
Comment:
Voting no due to a no vote on the standard, as well as a disagreement with the percentage concept. Smaller
entities will have a higher violation level for the same offense due to fewer chances for a violation.
Response:
The SDT believes the stepped VSLs are not biased against small entities.
Segment:
Organization:
Member:
Comment:
5, 6
Tennessee Valley Authority
George T. Ballew, Marjorie S. Parsons
The reason for the no vote on the Non-Binding Poll for VRFs and VSLs is the Violation Severity Level Table
listing for Requirement R4 lists the following under “Severe VSL”. “Entity has failed to initiate resolution of
maintenance-correctable issues”
The threshold for a Severe Violation in this case is too broad and too subjective. The threshold needs to be
clearly defined with low, medium, and high criteria. This feedback has been added to the NERC Standards
Under Development Comment webpage.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
The VSL for Requirement R4 has been modified to provide a stepped VSL for initiation of resolution of
maintenance correctable issues.
1
Duke Energy Carolina
Douglas E. Hils
We appreciate the work of the team however we do not agree with some of the text proposed. The VSLs for
PRC-005-2 requirements R1, R2 and R4 have significantly tighter percentages than the corresponding
requirements in PRC-005-1.
We believe that the Lower VSL should be up to 10%, the Moderate VSL should be 10%-15%, the High VSL
should be 15% to 20%, and the Severe VSL should be greater than 20%, which is still a lower percentage than
4
the 25% Lower VSL currently in PRC-005-1.
Response:
Segment:
Organization:
Member:
Comment:
The percentages for the stepped VSLs were established in accordance with the NERC VSL Guidelines which
were in turn established pursuant to the FERC VSL Order. The current approved PRC-005-1 preceded these
guidelines, and therefore is not in accordance with them.
5
U.S. Bureau of Reclamation
Martin Bauer
The intervals in the standard are based on the weighted average practice of entities surveyed. The weighted
average practice was the result of a requirement to have a documented program. The intervals did not have
demonstrated relationship to reliability of the BES. This nullifies the requirements and subsequent VSL's.
1. The VSL's use terms that are not tied back to a requirement and appear to be based on the concept that
every component will cause an impact on the BES. The VSL's use the term "countable event" to score the
VSL; however, there is no requirement associated with the number of "countable events".
2. The VSL's should allow for minor gaps in maintenance documentation where there is no impact to the BES
if the component failed.
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
1. The SDT disagrees that the VSLs are not tied back to a requirement. R3 refers to Attachment A for the
criteria for a performance based program, which establishes criteria for the percentage of countable events
allowed for the components in any specific designated segment.
2. “Minor gaps in maintenance documentation” would seem to be within the description of a Lower VSL; the
NERC criteria for VSLs do not currently permit them to allow some “gaps” without being in violation. The
VSL for Requirement R4 has been modified to provide a stepped VSL for initiation of resolution of
maintenance correctable issues.
1
Georgia Transmission Corporation
Harold Taylor, II
1. As the current requirements are written in R1 of PRC-005-2 Draft, we disagree with the terms identify all
Protection System components. We recommend a less prescriptive requirement as listed below.
R1.1 Identify BES substations or facilities containing Protection Systems.
5
R1.2 Identify whether Protection Systems per substation or facilities are addressed through time-based,
condition-based, performance based or a combination based etc.
R1.3 For each substation/facility with Protection Systems, include all maintenance activities etc.
2. The VRF for R1 ranking should be lower or no greater than R2, R3, and R4. The task of identifying
Protection System components has very little to do with increasing reliability of the BES. The implementation
of the PSMP most likely will cover all the specific functions of Protection System components although the
entity failed to identify all PS components.
3. We recommend the above language changes and agree the requirement adds some value but not a high-risk
value to the BES. After correcting the language we feel that a requirement of 100% maintenance on 100% of
all components as listed on page 6 of the standard for the VSLs leaves no room for error for systems designed
with contingences. The violations should start for more than a level of 5% not identified, not maintained, etc.
Response:
Segment:
Organization:
Member:
1. This appears to be a comment related to the standard content, not the VRFs and VSLs.
2. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and
the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 –
High.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
1, 3
National Grid, Niagara Mohawk (National Grid Company)
Saurabh Saksena, Michael Schiavone
Comment:
National Grid does not support the VSL criteria based on "total number of components". Calculating total
number of components will be hugely costly and does not enhance any reliability. It will also take away the
much needed resources required for maintenance.
Response:
The SDT believes establishing multiple levels within the VSL is preferable to assigning only a Severe VSL;
consequently, a method of measuring relative performance must exist, and determining the quantity of
components is a necessity.
Segment:
Organization:
November 17, 2010
1, 3, 3, 3, 3, 5
Southern Company Services, Inc., Georgia Power Company, Gulf Power Company, Mississippi Power,
6
Alabama Power Company, Southern Company Generation
Member:
Horace Stephen Williamson, Anthony L Wilson, Gwen S Frazier, Don Horsley, Richard J. Mandes, William
D Shultz
Comment:
If an entity is not able to reasonably quantify which components are in scope, demonstrating compliance on a
percent-basis may prove difficult or impossible. Further review may indicate the need to reformat the VSL.
Response:
The SDT believes establishing multiple levels within the VSL is preferable to assigning only a Severe VSL;
consequently, a method of measuring relative performance must exist, and determining the quantity of
components is a necessity.
Segment:
Organization:
Member:
3
Allegheny Power
Bob Reeping
Comment:
The draft standard expects 100% compliance for millions of protection system components at all times. The
standard should consider a statistically based performance metric instead of a performance target that expects
100% compliance.
Response:
The SDT shares your concerns regarding the Lower VSL portion of the stepped VSLs not providing any
tolerance for non-conformance without being non-compliant. However, the VSL Guidelines, which conform
to the FERC VSL order, specify that Lower shall be “5% or less.”
Segment:
Organization:
Member:
5
AEP Service Corp.
Brock Ondayko
Comment:
AEP has stated in other projects, setting a VSL at “Severe” for a binary outcome could be challenged as being
arbitrary and another level should be used as the starting point.
Response:
The NERC VSL Guidelines, which were established pursuant to the FERC VSL Order, specify that Severe
VSLs be assigned for binary outcomes.
Segment:
Organization:
Member:
November 17, 2010
3, 4
Georgia System Operations Corporation
R Scott S. Barfield-McGinnis, Guy Andrews
7
Comment:
1. Do not agree with the 3 calendar months interval and suggest using quarterly. Both terms require a
minimum of four inspections per year have proven to be successful, but the term “quarterly” provides a bit
more flexibility than the term “3 calendar months”. Given a 3 month maximum interval an entity would
need to schedule these tasks every 2 months. As the current requirements are written in R1 of PRC-005-2
Draft, we disagree with the terms identify all Protection System components. We recommend a less
prescriptive requirement as listed below. -R1.1 Identify BES substations or facilities containing Protection
Systems. -R1.2 Identify whether Protection Systems per substation or facilities are addressed through timebased, condition-based, performance based or a combination based etc. -R1.3 For each substation/facility
with Protection Systems include all maintenance activities etc.
2. The VRF for R1 ranking should be lower or no greater than R2, R3, and R4. The task of identifying
Protection System components has very little to do with increasing reliability of the BES. The
implementation of the PSMP most likely will cover all the specific functions of Protection System
components although the entity failed to identify all PS components. We recommend the above language
changes and agree the requirement adds some value but not a high-risk value to the BES.
2. After correcting the language we feel that a requirement of 100% maintenance on 100% of all components
as listed on page 6 of the standard for the VSLs leaves no room for error for systems designed with
contingences.
3. The violations should start for more than a level of 5% not identified, not maintained, etc. Listing each
individual Protection System component as current draft is onerous and impedes any interpretation of
application with very little value.
4. The standard as written will require a great deal of effort by the utilities to maintain 100% compliance as
listed. The concern is the power system design allows for some contingencies but the standard allows for no
errors. Failing to complete 1% of the maintenance by 1 day infers an entity is out of compliance or in
violation.
5. The violations should start for more than a level of 5% not identified, or not maintained. We feel the minor
changes of wording as described in R1.1 – R1.3 as listed above will go a long way in removing the concerns
of the standard. We feel the intent of the standard is sound and request minor changes to facilitate an
interpretable standard that sensibly mitigates problems with the BES. As the standard written, the
November 17, 2010
8
interpretation seems to create a stringent environment with undue compliance requirements.
6. Lastly, the SDT should attempt to embrace Gerry Cauley’s vision of “results-based standards” and clearly
identify the “risk mitigation objectives, reliability result or outcome” of the revised requirements and allow
each entity to meet the outcome and mitigate the risk without writing in such a prescriptive manner which is
not preferred. The prescriptive details currently proposed in the standard could then be captured in a
reference document.
Response:
Segment:
Organization:
Member:
1. This comment appears be related to the technical content of the standard and not on the VRFs or VSLs.
2. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and FERC, and
the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4
– High.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
4. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
5. The SDT believes establishing multiple levels within the VSL is preferable to assigning only a Severe VSL;
consequently, a method of measuring relative performance must exist, and determining the quantity of
components is a necessity.
6. This comment appears to be related to the standard itself, not to the VRFs or VSLs.
1
Tennessee Valley Authority
Larry Akens
Comment:
The VSL Table listing for Requirement R4 list the following under Severe VSL: "Entity has failed to initiate
resolution of maintenance-correctable issues" The threshold for a Severe Violation in this case is too broad
and too subjective. The threshold needs to be clearly defined with low, medium, and high criteria.
Response:
The VSL for Requirement R4 has been modified to provide a stepped VSL for initiation of resolution of
maintenance correctable issues.
Segment:
Organization:
Member:
November 17, 2010
3, 5, 6
Entergy, Entergy Corporation, Entergy Services, Inc.
Joel T Plessinger, Stanley M Jaskot, Terri F Benoit
9
Comment:
Entergy provides the following reasons for our Negative Ballot. Entergy reserves the right, after review of all
the submitted ballots, to join with other balloters, whether positive or negative ballots, where any reasons
included in their ballot that may be applicable to or otherwise impact Entergy as related to this ballot.
1. The VSLs for R1 is “Failure to specify whether a component is being addressed by time-based, conditionbased, or performance-based maintenance” by itself is a documentation issue and not an equipment
maintenance issue. We recommend this warrants only a Lower VSL, especially when one of the required
components can only be time based.
2. We also recommend the VSLs for R4 be revised to be stepped from Lower to Severe for “Entity has failed
to initiate resolution of maintenance-correctable issues”. While we understand the importance of
addressing a correctable issue, it seems like there should be some allowance for an isolated unintentional
failure to address a correctable issue. If possible, consider the potential impact to the system. For example,
a failure to address a pilot scheme correctable issue for an entity that only employs pilot schemes for
system stability applications should not necessarily have the same VSL consequence as an entity which
employs pilot schemes everywhere on their system as a standard practice.
Response:
Segment:
Organization:
Member:
1. This portion of the VSL for Requirement R1 has been modified to provide a stepped VSL relating to the
number of Component Types that are not addressed by time-based, condition-based, or performance-based
maintenance.
2. The VSL for Requirement R4 has been modified to provide a stepped VSL for initiation of resolution of
maintenance correctable issues.
1
Pacific Gas and Electric Company
Chifong L. Thomas
Comment:
We cannot vote affirmative on the VRFs and VSLs until concerns on the proposed standard have been
addressed.
Response:
Thank you.
Segment:
Organization:
Member:
November 17, 2010
1, 3
Platte River Power Authority
John C. Collins, Terry L Baker
10
Comment:
Because of the recommended NO vote on the standard, it would not make sense to approve the proposed
VRFs and VSLs until such time the requirements of the standard are clarified.
Response:
Thank you.
Segment:
Organization:
Member:
1
Public Service Company of New Mexico
Laurie Williams
Comment:
Because of the NO vote on the standard, it would not make sense to approve the proposed VRFs and VSLs
until such time that the requirements of the standard are clarified.
Response:
Thank you.
Segment:
1
Organization:
Xcel Energy, Inc.
Member:
Gregory L Pieper
Comment:
Xcel Energy believes the standard still contains many aspects that are not clearly understood by entities,
including what is needed to demonstrate a compliant PSMP. Comments have been submitted concurrently to
NERC via the draft comment response form.
Response:
Thank you.
Segment:
Organization:
Member:
2
Midwest ISO, Inc.
Jason L Marshall
Comment:
We are abstaining because a number of our stakeholders have concerns regarding the definition of Protection
System and inclusion of UVLS and UFLS in a standard dealing with maintenance of protection systems.
Response:
Thank you.
Segment:
Organization:
Member:
Comment:
November 17, 2010
5
Pacific Gas and Electric Company
Richard J. Padilla
We cast a negative ballot due to a negative vote on the standard and recommend that the VRFs and VSLs be
11
addressed after the standard comments are resolved
Response:
Segment:
Organization:
Member:
Thank you.
10
Western Electricity Coordinating Council
Louise McCarren
Comment:
Do not agree with all of the requirements of the current proposed standard, so will not vote to approve
associated VRFs and VSLs
Response:
Thank you.
Segment:
Organization:
Member:
3
Central Lincoln PUD
Steve Alexanderson
Comment:
Too early to approve the VRFs and VSLs since the requirements need to be fixed first.
Response:
Thank you.
Segment:
Organization:
Member:
1
American Electric Power
Paul B. Johnson
Comment:
AEP has comments regarding the current requirements and measures that need to be addressed, so comments
on VSLs are irrelevant at this time.
Response:
Thank you.
Segment:
6
Organization:
AEP Marketing
Member:
Edward P. Cox
Comment:
AEP has comments regarding the current requirements and measures that need to be addressed.
Response:
Thank you.
Segment:
November 17, 2010
1
12
Organization:
Member:
BC Transmission Corporation
Gordon Rawlings
Comment:
Not prepared to vote affirmative until such time as BC Hydro can support Project 2007-17 PRC-005-2
Response:
Thank you.
Segment:
Organization:
Member:
3
City of Bartow, Florida
Matt Culverhouse
Comment:
The proposed draft opens the standard up to regulate DC circuit testing on distribution elements with no
significant improvement to BES reliability.
Response:
This appears to be a comment on the technical content of the standard, not on the VRFs or VSLs.
Segment:
Organization:
Member:
3
Tri-State G & T Association Inc.
Janelle Marriott
Comment:
Clarification is needed to address the potentially onerous implementation, administration, audit of the
proposed revisions.
Response:
Without details of your concern, the SDT is unable to respond.
Segment:
Organization:
Member:
3
Consolidated Edison Co. of New York
Peter T Yost
Comment:
There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate equipment
identified in the existing or proposed definition. However, not all such equipment translates into a
transmission Protection System. The definition needs clarification on when such equipment is a part of the
transmission protection system. Also, the time provided for the first phase "at least six months" is too open
ended and does not provide entities with a clear timeline. It is suggested that one year is appropriate for the
first phase phasing out the second year in stages.
Response:
This appears to be a comment on the technical content of the standard, definition, and Implementation Plan,
November 17, 2010
13
not on the VRFs or VSLs.
Segment:
Organization:
Member:
2
New York Independent System Operator
Gregory Campoli
Comment:
There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which
protection system components it does own and needs to maintain. Many DPs own and/or operate
equipment identified in the existing or proposed definition. However, not all such equipment translates into
a transmission Protection System. The definition needs clarification on when such equipment is a part of
the transmission protection system. Also, the time provided for the first phase "at least six months" is too
open ended and does not provide entities with a clear timeline. It is suggested that one year is appropriate
for the first phase phasing out the second year in stages. Regarding battery visuals, the suggestion for
consideration is it should be changed from 3 months to 6 months. Electrolyte levels of today's lead-calcium
batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past.
The Implementation plan is too short - In many instances it will be impossible to meet, especially if entities
have to create, purchase and adopt new databases to track maintenance activities. Often new procedures
will have to be written and additional resources justified and hired. It would be more acceptable if a staged
approached was taken similar to the DME Standard. Accounting for every component of a protection
system will be an enormous overhead and will take away resources from actually doing maintenance.
Emphasis should be on systems and not individual components.The Standard does not provide a grace
period if an entity is unable to meet the maintenance requirement for extenuating circumstances. For
example if an entity has to divert maintenance resources to storm restoration following a major event, slack
built into a maintenance program can be eaten up and put the maintenance over the prescribed period.
Provision should be made for a mitigation plan to get back on track. We do not believe the reliability of the
Bulk Electric System will be compromised if an entities' maintenance program slips by a few months due
to extreme contingencies, especially if it is brought back on track within a short time frame.
Response:
These comments appear to be related to the technical content of the standard, definition, and Implementation
Plan, not on the VRFs or VSLs.
Segment:
4, 5
Organization:
Florida Municipal Power Agency
Member:
Frank Gaffney, David Schumann
November 17, 2010
14
Comment:
November 17, 2010
FMPA recommends a negative vote on PRC-005-2, Project 2007-17, for three significant reasons
1. As written, it opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard as explained by Steve
Alexanderson in a prior e-mail to the ballot pool. The draft standard would cause NERC to regulate through
the standards battery testing, DC circuit testing, etc. on distribution elements with no significant
improvement to BES reliability, which is beyond the statutory scope of the standards
2. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components. Will the Standard Introduce Technical Feasibility Exceptions to PRC
Standards? As described by Steve Alexanderson in a prior e-mail to the ballot pool, a large proportion of the
batteries (as high as 50% as reported by some SMEs) are not able to accommodate all of the tests prescribed
in the draft standard. Will this necessitate the introduction of TFEs into the process unnecessarily? The
Standard Reaches Beyond the Statutory Scope of the Reliability Standards As written, the standard requires
testing of batteries, DC control circuits, etc., of distribution level protection components associated with
UFLS and UVLS. UFLS and UVLS are different than protection systems used to clear a fault from the BES.
An uncleared fault on the BES can have an Adverse Reliability Impact and hence; the focus on making sure
the fault is cleared is important and appropriate. However, a UFLs or UVLS event happens after the fault is
cleared and is an inexact science of trying to automatically restore supply and demand balance (UFLS) or
restore voltages (UVLS) to acceptable levels. If a few UFLS or UVLS relays fail to operate out of
potentially thousands of relays with the same function, there is no significant impact to the function of
UFLS or UVLS. Hence, there is no corresponding need to focus on every little aspect of the UFLS or UVLS
systems. Therefore, the only component of UFLS or UVLS that ought to be focused on in the new PRF-005
standard is the UFLS or UVLS relay itself and not distribution class equipment such as batteries, DC control
circuitry, etc., and these latter ought to be removed from the standard. In addition, most distribution circuit
are radial without substation arrangements that would allow functional testing without putting customers out
of service while the testing was underway, or at least without momentary outages while customers were
switched from one circuit to another. Therefore, as written, we would be sacrificing customer service for a
negligible impact on BES reliability. Perfection is Not A Realistic Goal The standard allows no mistakes.
Even the famous six sigma quality management program allows for defects and failures (i.e., six sigma is
six standard deviations, which means that statistically, there are events that fall outside of six standard
deviations). PRC-005 has been drafted such that any failure is a violation, e.g., 1 day late on a single relay
test of tens of thousands of relays is a violation. That is not in alignment with worldwide accepted quality
management practices (and also makes audits very painful because statistical, random sampling should be
the mode of audit, not 100% review as is currently being done in many instances). FMPA suggests
15
considering statistically based performance metrics as opposed to an unrealistic performance target that does
not allow for any failure ever. Due to the shear volume of relays, with 100% performance required, if the
standards remain this way, PRC-005 will likely be in the top ten most violated standards for the forever.
There is a fundamental flaw in thinking about reliability of the BES. We are really not trying to eliminate
the risk of a widespread blackout, we are trying to reduce the risk of a widespread blackout. We plan and
operate the system to single and credible double contingencies and to finite operating and planning reserves.
To eliminate the risk, we would need to plan and operate to an infinite number of contingencies, and have
an infinite reserve margin, which is infeasible. Therefore, by definition, there is a finite risk of a widespread
blackout that we are trying to reduce, not eliminate, and, by definition, by planning and operating to single
and credible double contingencies and finite operating and planning reserves, we are actually defining the
level of risk from a statistical basis we are willing to take. With that in mind, it does not make sense to
require 100% compliance to avoid a smaller risk (relays) when we are planning to a specified level of risk
with more major risk factors (single and credible double contingencies and finite planning and operating
reserves).
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
1. This comment appears to be related to the technical content of the Standard, not on the VRFs or VSLs.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance
without being in violation. Much of this comment appears to be related to the technical content of the
standard, not on the VRFs or VSLs.
1
Lake Worth Utilities
Walt Gill
1. As written, is opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard
2. The draft standard would cause NERC to regulate through the standards battery testing, DC circuit testing,
etc. on distribution elements with no significant improvement to BES reliability, which is beyond the
statutory scope of the standards
3. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components. Will the Standard Introduce Technical Feasibility Exceptions to PRC
Standards? a large proportion of the batteries (as high as 50% as reported by some SMEs) are not able to
accommodate all of the tests prescribed in the draft standard. Will this necessitate the introduction of TFEs
into the process unnecessarily? The Standard Reaches Beyond the Statutory Scope of the Reliability
16
Standards As written, the standard requires testing of batteries, DC control circuits, etc., of distribution level
protection components associated with UFLS and UVLS. UFLS and UVLS are different than protection
systems used to clear a fault from the BES. An uncleared fault on the BES can have an Adverse Reliability
Impact and hence; the focus on making sure the fault is cleared is important and appropriate. However, a
UFLs or UVLS event happens after the fault is cleared and is an inexact science of trying to automatically
restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable levels. If a few UFLS
or UVLS relays fail to operate out of potentially thousands of relays with the same function, there is no
significant impact to the function of UFLS or UVLS. Hence, there is no corresponding need to focus on
every little aspect of the UFLS or UVLS systems. Therefore, the only component of UFLS or UVLS that
ought to be focused on in the new PRF-005 standard is the UFLS or UVLS relay itself and not distribution
class equipment such as batteries, DC control circuitry, etc., and these latter ought to be removed from the
standard. In addition, most distribution circuit are radial without substation arrangements that would allow
functional testing without putting customers out of service while the testing was underway, or at least
without momentary outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES reliability. Perfection is
Not A Realistic Goal The standard allows no mistakes. Even the famous six sigma quality management
program allows for defects and failures (i.e., six sigma is six standard deviations, which means that
statistically, there are events that fall outside of six standard deviations). PRC-005 has been drafted such
that any failure is a violation, e.g., 1 day late on a single relay test of tens of thousands of relays is a
violation. That is not in alignment with worldwide accepted quality management practices (and also makes
audits very painful because statistical, random sampling should be the mode of audit, not 100% review as is
currently being done in many instances). FMPA suggests considering statistically based performance
metrics as opposed to an unrealistic performance target that does not allow for any failure ever. Due to the
shear volume of relays, with 100% performance required, if the standards remain this way, PRC-005 will
likely be in the top ten most violated standards for the forever. There is a fundamental flaw in thinking
about reliability of the BES. We are really not trying to eliminate the risk of a widespread blackout, we are
trying to reduce the risk of a widespread blackout. We plan and operate the system to single and credible
double contingencies and to finite operating and planning reserves. To eliminate the risk, we would need to
plan and operate to an infinite number of contingencies, and have an infinite reserve margin, which is
infeasible. Therefore, by definition, there is a finite risk of a widespread blackout that we are trying to
reduce, not eliminate, and, by definition, by planning and operating to single and credible double
contingencies and finite operating and planning reserves, we are actually defining the level of risk from a
statistical basis we are willing to take. With that in mind, it does not make sense to require 100%
November 17, 2010
17
compliance to avoid a smaller risk (relays) when we are planning to a specified level of risk with more
major risk factors (single and credible double contingencies and finite planning and operating reserves).
Response:
Segment:
Organization:
Member:
Comment:
Response:
Segment:
Organization:
Member:
Comment:
November 17, 2010
1. This comment appears to be related to the technical content of the standard, not on the VRFs or VSLs.
2. This comment appears to be related to the technical content of the standard, not on the VRFs or VSLs.
3. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation. Much of this comment appears to be related to the technical content of the Standard, not
on the VRFs or VSLs.
4
Wisconsin Energy Corp.
Anthony Jankowski
see comments on standard
Please refer to the SDT responses to your comments on the comment form.
5
Consumers Energy
James B Lewis
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided,
Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented.
Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead
to provide operating flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will be very
cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely
lead to entities NOT installing the redundant schemes, resulting in decreased reliability.
2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include
sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on
supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply),
what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not
present.” Similarly, it isn’t clear from the general description within the Tables that components possessing
different monitoring attributes within a single scheme, may be distinguished such that differing relevant
tables can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can
18
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.
Battery assemblies supplied by some manufacturers have the connections made internally, making this
option unavailable. Experience with ASME standards show that NERC and SDT members may be jointly
and separately liable for litigation by specifying methods that either prefer or prohibit use of certain
technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“ conclude
with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two
such activities therefore require tripping of circuit breakers or other interrupting devices? 5. Performance of
the minimum activities specified within Table 1a for legacy systems, particularly regarding control circuits,
will require considerable disconnection and reconnection of portions of the circuits. Such activities will
likely cause far more problems on restoration-to-service than they will locate and correct. We suggest that
the SDT reconsider these activities with regard for this concern.
5. We do not agree that Footnotes within the Standard are an appropriate method of providing information that
is important to the application of the Standard. Important information should be provided within the
standard text.
6. As for the definition, it is unclear whether “voltage and current sensing inputs” include the instrument
transformer itself, or does it pertain to only the circuitry and input to the protective relays.
7. As for the definition, it is not clear what is included in the component, “station dc supply” without referring
to other documents (the posted Supplementary Reference and/or FAQ) for clarification. The definition
should be sufficiently detailed to be clear.
8. If Protection Systems trip via AC methods, are those systems, and the associated control circuitry included
in the definition and within the requirements of the Standard as expressed within the Tables?
Response:
Segment:
Organization:
Member:
These comments all appear to be related to the technical content of the Standard and to the definition, not to
the VRFs or VSLs.
1, 3, 5, 6
Kansas City Power & Light Co.
Mike Gammon, Charles Locke, Scott Heidtbrink, Thomas Saitta
Comment:
The proposed changes in the Standard are far too prescriptive and do not take into account the multitude of
manufacturers' equipment by establishing broad maintenance cycles and testing intervals.
Response:
This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
Segment:
November 17, 2010
5
19
Organization:
Member:
Salt River Project
Glen Reeves
Comment:
SRP believes the requirements of the Standard are confusing and may be problematic in determining
compliance. We also believe the required functional testing of the breaker trip coil may potentially increase
maintenance outages of circuit breakers. In most cases, circuit breaker maintenance outages can be
coordinated such that Protection System maintenance and testing can be done simultaneously. However, in
some cases this may not be possible. Outages of any BES facility whether planned or unplanned can impact
system reliability. SRP suggests that trip coil monitoring devices be included as an acceptable means of
ensuring the trip coil is functioning properly. This will help to avoid unnecessary outages.
Response:
This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
Segment:
Organization:
Member:
6
Seattle City Light
Dennis Sismaet
Comment:
Functional testing is impractical.
Response:
This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
Segment:
Organization:
Member:
1
Keys Energy Services
Stan T. Rzad
Comment:
1. As written, it opens up the PRC-005 standard to Technical Feasibility Exceptions because some batteries
are not able to accommodate all of the tests proscribed in the draft standard. The draft standard would cause
NERC to regulate through the standards battery testing, DC circuit testing, etc. on distribution elements with
no significant improvement to BES reliability, which is beyond the statutory scope of the standards
2. The standard unreasonably retains the "100% compliance" paradigm for thousands, if not millions of
protection system components.
Response:
1. This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation. Much of this comment appears to be related to the technical content of the Standard, not
on the VRFs or VSLs.
November 17, 2010
20
Segment:
Organization:
Member:
1
PPL Electric Utilities Corp.
Brenda L Truhe
Comment:
PPL EU is voting negative because Requirement 1.1 "Identify all Protection System components" is too broad
and must be clarified and the definition of Protective Relays is not limited to only those devices that use
electrical quantities as inputs (exclude pressure, temperature, gas, etc).
Response:
This comment appears to be related to the technical content of the Standard, not to the VRFs or VSLs.
Segment:
Organization:
Member:
3
Springfield Utility Board
Jeff Nelson
Comment:
Please refer to SUB's comments on VRFs and VFLs in the Comment Form
Response:
Please refer to the SDT responses to your comments on the comment form.
Segment:
Organization:
Member:
3
Louisville Gas and Electric Co.
Charles A. Freibert
Comment:
Comments will be submitted under a comment form
Response:
Please refer to the SDT responses to your comments on the comment form.
November 17, 2010
21
Consideration of Comments on Proposed Definition of Protection System
for Project 2007-17
The Protection System Maintenance and Testing Standard Drafting Team thanks all
commenters who submitted comments on the draft definition of “Protection System.” This
document was posted for a special 35-day public comment period from June 11, 2010
through July 16, 2010. Stakeholders were asked to provide feedback on the proposed
definition through a special Electronic Comment Form. There were 50 sets of comments,
including comments from more than 110 different people from over 55 companies
representing 8 of the 10 Industry Segments as shown in the table on the following pages.
Based on stakeholder comments, the drafting team refined its proposed definition of
Protection System as shown below:
Protective relays , which respond to electrical quantities, communication systems
necessary for correct operation of protective functions, voltage and current sensing
devices providing inputs to protective relays, station dc supply, and control circuitry
associated with protective functions through the trip coil(s) of the circuit breakers or
other interrupting devices.
Several comments questioned the reason for implementing the definition of Protection
System in advance of implementing the proposed modifications to PRC-005-1. When the
Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by
the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team
caused by the definition of "protection system" and directed that work to close this reliability
gap should be given “priority.” To close this reliability gap the BOT has directed that revised
definition be applied to PRC-005-1 as soon as practical - not years from now.
Stakeholder comments indicated that applying the expanded scope of the definition of
Protection System would to PRC-005-1 would require more than six months and suggested
expanding this to 12 months, and the drafting team made this change to the
implementation plan. The team adjusted the implementation plan so that entities will have
at least twelve months, rather than the six months originally proposed, to apply the new
definition of Protection System to PRC-005-1 – Protection System Maintenance and Testing
to Requirement R1 of PRC-005-1. The other parts of the implementation plan remain
unchanged.
All work of the drafting team has been posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_200717.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition,
there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on the Definition of Protection System — Project 2007-17
Index to Questions, Comments, and Responses
1.
Do you believe the proposed definition of Protection System is ready for ballot? If not,
please explain why. ........................................................................................... 10
2.
Do you agree with the implementation plan for the revised definition of Protection
System? The implementation plan has two phases – the first phase gives entities at
least six months to update their protection system maintenance and testing program;
the second phase starts when the protection system maintenance and testing program
has been updated and requires implementation of any additional maintenance and
testing associated with the program changes by the end of the first complete
maintenance and testing cycle described in the entity’s revised program. If you
disagree with this implementation plan, please explain why. ................................... 30
July 22, 2010
2
Consideration of Comments on the Definition of Protection System — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Guy Zito
Additional Member
Organization
1
2
3
4
5
6
7
8
9
Northeast Power Coordinating Council
Additional Organization
New York State Reliability Council, LLC
NPCC 10
2. Gregory Campoli
New York Independent System Operator
NPCC 2
3. Kurtis Chong
Independent Electricity System Operator
NPCC 2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7. Ben Eng
New York Power Authority
NPCC 4
8. Brian Evans-Mongeon Utility Services
NPCC 8
9. Dean Ellis
Dynegy Generation
NPCC 5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
11. Kathleen Goodman
ISO - New England
NPCC 2
12. David Kiguel
Hydro One Networks Inc.
NPCC 1
13. Michael R. Lombardi
Northeast Utilities
NPCC 1
14. Randy MacDonald
New Brunswick System Operator
NPCC 2
15. Bruce Metruck
New York Power Authority
NPCC 6
10
X
Region Segment Selection
1. Alan Adamson
July 22, 2010
Industry Segment
3
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
Organization
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
21. Chantel Haswell
FPL Group
NPCC 5
22. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
2.
Group
Pacific Northwest Small Public Power Utility
Comment Group
Steve Alexanderson
Industry Segment
1
2
3
4
X
X
5
6
7
8
9
Additional Member Additional Organization Region Segment Selection
1. Russ Noble
Cowlitz PUD
WECC 3, 4, 5
2. Dave Proebstel
Clallam County PUD
WECC 3
3. John Swanson
Benton PUD
WECC 3
4. Steve Grega
Lewis County PUD
WECC 3, 5
3.
Group
Margaret Ryan
Additional Member
PNGC Power
Additional Organization
X
Region Segment Selection
1.
Blachly-Lane Electric Cooperative
WECC 3
2.
Central Electric Cooperative
WECC 3
3.
Clearwater Electric Cooperative
WECC 3
4.
Consumer's Power Company
WECC 3
5.
Coos-Curry Electric Cooperative
WECC 3
6.
Douglas Electric Cooperative
WECC 3
7.
Fall River Electric Cooperative
WECC 3
8.
Lane Electric Cooperative
WECC 3
9.
Lincoln Electric Cooperative
WECC 3
10.
Lost River Electric Cooperative
WECC 3
11.
Northern Lights Electric Cooperative WECC 3
12.
Okanogan Electric Cooperative
WECC 3
13.
Raft River Electric Cooperative
WECC 3
July 22, 2010
X
4
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
Organization
14.
Salmon River Electric Cooperative
WECC 3
15.
Umatilla Electric Cooperative
WECC 3
16.
West Oregon Electric Cooperative
WECC 3
17.
PNGC
WECC 8
4.
Group
Denise Koehn
Additional Member
1. Dean Bender
5.
Group
Bonneville Power Administration
Additional Organization
Industry Segment
1
2
3
X
X
X
X
X
X
X
X
4
5
6
X
X
X
X
7
8
9
Region Segment Selection
BPA, Transmission SPC Technical Svcs WECC 1
Sam Ciccone
FirstEnergy
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
2. Jim Kinney
FE
RFC
1
3. Ken Dresner
FE
RFC
5
4. Brian Orians
FE
RFC
5
5. Bill Duge
FE
RFC
5
6. J. Chmura
FE
RFC
1
7. Dave Folk
FE
RFC
1, 3, 4, 5, 6
6.
Group
Terry L. Blackwell
Santee Cooper
X
Additional Member Additional Organization Region Segment Selection
1. S. Tom Abrams
Santee Cooper
SERC
1
2. Rene' Free
Santee Cooper
SERC
1
3. Bridget Coffman
Santee Cooper
SERC
1
7.
Group
Kenneth D. Brown
Public Service Enterprise Group ("PSEG
Companies")
X
X
Additional Member Additional Organization Region Segment Selection
1. Jim Hubertus
PSE&G
2. Scott Slickers
PSEG Power Connecticut NPCC
3. Jim Hebson
PSEG ER&T
ERCOT 5, 6
4. Dave Murray
PSEG Fossil
RFC
July 22, 2010
RFC
1, 3
5
5
5
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
8.
Group
Daniel Herring
Organization
Industry Segment
1
The Detroit Edison Company
2
3
4
5
X
X
X
6
7
8
9
Additional Member Additional Organization Region Segment Selection
1. David A Szulczewski Relay Engineering
RFC
9.
Hydro One
Group
Sasa Maljukan
3, 4, 5
X
Additional Member Additional Organization Region Segment Selection
1. David Kiguel
Hydro One Networks, Inc. NPCC 1
10.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
11.
Individual
Brent Inebrigtson
E.ON U.S.
X
X
X
X
12.
Individual
Brandy A. Dunn
Western Area Power Administration
X
13.
Individual
Jana Van Ness
Arizona Public Service Company
X
14.
Individual
Jack Stamper
Clark Public Utilities
X
15.
Individual
Dan Roethemeyer
Dynegy Inc.
16.
Individual
Robert Ganley
Long Island Power Authority
X
17.
Individual
Lauri Dayton
Grant County PUD
X
18.
Individual
Fred Shelby
MEAG Power
X
19.
Individual
James A. Ziebarth
Y-W Electric Association, Inc
20.
Individual
Armin Klusman
CenterPoint Energy
X
21.
Individual
Andrew Z.Pusztai
American Transmission Company
X
22.
Individual
Eric Ruskamp
Lincoln Electric System
X
X
X
X
23.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
24.
Individual
Edward Davis
Entergy Services
X
X
X
X
25.
Individual
James Sharpe
South Carolina Electric and Gas
X
X
X
X
26.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
27.
Individual
Scott Kinney
Avista Corp
X
July 22, 2010
X
X
X
X
X
X
X
X
X
6
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
4
5
6
28.
Individual
Amir Hammad
Constellation Power Generation
29.
Individual
Jeff Nelson
Springfield Utility Board
30.
Individual
Michael R. Lombardi
Northeast Utilities
X
X
X
31.
Individual
John Bee
Exelon
X
X
X
32.
Individual
Barb Kedrowski
We Energies
X
X
X
33.
Individual
Jianmei Chai
Consumers Energy Company
X
X
X
34.
Individual
Art Buanno
ReliabilityFirst Corp.
35.
Individual
Greg Rowland
Duke Energy
X
X
X
X
36.
Individual
Thad Ness
American Electric Power
X
X
X
X
37.
Individual
Rex Roehl
Indeck Energy Services
38.
Individual
Claudiu Cadar
GDS Associates
X
39.
Individual
Terry Bowman
Progress Energy Carolinas
X
X
X
X
40.
Individual
Kirit Shah
Ameren
X
X
X
X
Group
Joe Spencer - SERC
staff and Phil Winston PCS co-chair
SERC Protection and Control Sub-committee
(PCS)
41.
Additional Member
8
9
10
X
X
X
X
X
Additional Organization
Region Segment Selection
1. Paul Nauert
Ameren Services Co.
SERC
2. Bob Warren
Big Rivers Electric Corp.
SERC
3. Trevor Foster
Calpine Corp.
SERC
4. John (David) Fountain Duke Energy Carolinas
SERC
5. Paul Rupard
East Kentucky Power Coop.
SERC
6. Charles Fink
Entergy
SERC
7. Marc Tunstall
Fayetteville Public Works Commission SERC
8. John Clark
Georgia Power Co
SERC
9. Nathan Lovett
Georgia Transmission Corp
SERC
July 22, 2010
7
7
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
Organization
10. Danny Myers
Louisiana Generation, LLC
SERC
11. Ernesto Paon
Municipal Electric Authority of GA
SERC
12. Jay Farrington
PowerSouth Energy Coop.
SERC
13. Jerry Blackley
Progress Energy Carolinas
SERC
14. Joe Spencer
SERC Reliability Corp
SERC
15. Russ Evans
South Carolina Electric and Gas
SERC
16. Bridget Coffman
South Carolina Public Service Authority SERC
17. Phillip Winston
Southern Co. Services Inc.
SERC
18. George Pitts
Tennessee Valley Authority
SERC
19. Rick Purdy
Virginia Electric and Power Co.
SERC
42.
Group
Frank Gaffney
Additional Member
Florida Municipal Power Agency
Additional Organization
Utilities Commission of New Smyrna Beach FRCC 4
2. Greg Woessner
Kissimmee Utility Authority
FRCC 1
3. Jim Howard
Lakeland Electric
FRCC 1
4. Lynne Mila
City of Clewiston
FRCC 3
5. Joe Stonecipher
Beaches Energy Services
FRCC 1
6. Cairo Vanegas
Fort Pierce Utilities Authority
FRCC 4
Group
Richard Kafka
Additional Member
Pepco Holdings, Inc. - Affiliates
Additional Organization
2
3
4
5
6
X
X
X
X
X
X
X
X
X
7
8
9
Region Segment Selection
1. Alvin Depew
Potomac Electric Power Company RFC
1
2. Carl Kinsley
Delmarva Power & Light
RFC
1
3. Rob Wharton
Delmarva Power & Light
RFC
1
4. Evan Sage
Potomac Electric Power Company RFC
1
5. Carlton Bradsaw
Delmarva Power & Light
RFC
1
6. Jason Parsick
Potomac Electric Power Company RFC
1
7. Walt Blackwell
Potomac Electric Power Company RFC
1
8. John Conlow
Atlantic City Electric
RFC
1
9. Randy Coleman
Delmarva Power & Light
RFC
1
July 22, 2010
1
Region Segment Selection
1. Timothy Beyrle
43.
Industry Segment
8
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
Commenter
44.
Group
Mallory Huggins
Additional Member Additional Organization
Organization
1
2
3
4
5
6
7
8
9
10
NERC Staff
Region
Segment Selection
1. Joel DeJesus
NERC
NA - Not Applicable NA
2. Mike DeLaura
NERC
NA - Not Applicable NA
3. Al McMeekin
NERC
NA - Not Applicable NA
4. Earl Shockley
NERC
NA - Not Applicable NA
5. Bob Cummings
NERC
NA - Not Applicable NA
6. David Taylor
NERC
NA - Not Applicable NA
45.
Individual
JT Wood
Southern Company Transmission
46.
Individual
Tom Schneider
WECC
47.
Individual
Hugh Conley
Allegheny Power
48.
Individual
Scott Berry
Indiana Municipal Power Agency
49.
Individual
Terry Habour
MidAmerican Energy Company
50.
Individual
Martin Bauer
US Bureau of Reclamation
July 22, 2010
Industry Segment
X
X
X
X
X
X
X
9
Consideration of Comments on the Definition of Protection System — Project 2007-17
1. Do you believe the proposed definition of Protection System is ready for ballot? If not,
please explain why.
Summary Consideration: Almost half of the commenters felt that the definition itself was not ready for ballot.
Many commenters wanted more clarity regarding the portion of the definition addressing “voltage and current sensing inputs to
protective relays ... “. The SDT inserted the words “devices providing” into the phrase to clarify that instrument transformers are
included in the definition. This portion of the definition now reads:
•
Voltage and current sensing devices providing inputs to protective relays,
Many commenters also suggested that the definition should limit the protective relays “to those using electrical quantities”, rather
than addressing this subject as a footnote in the standard. The SDT incorporated this suggestion; this portion of the definition now
reads:
•
“Protective relays which respond to electrical quantities”.
The SDT also removed the phrase “from the station dc supply” from the “control circuitry” portion of the definition.
Some commenters suggested that “protective relays” be defined; the SDT chose not to do this as IEEE already defines this term.
Many commenters also offered comments on the standard itself. These comments are being addressed in the comment forms for
the standard.
The revised definition is:
Protection System:
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply, and
• Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting
devices.
Several commenters indicated that the definition should not apply to PRC-005-1. When the Board of Trustees was asked to approve
an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the
July 22, 2010
10
Consideration of Comments on the Definition of Protection System — Project 2007-17
drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not
years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1,
and that should give entities time to apply the new definition to PRC-005-1.
Organization
GDS Associates
Yes or
No
Question 1 Comment
No
1. The inserted wording “and associated circuitry from the voltage and current sensing
devices” implies that the maintenance program will include the verification, monitoring,
etc. of the wiring from the voltage/current sensing devices which requirement will be a
bit excessive under current presentation of the standard. See comment on the standard
as well.
2. SDT’s additional wording such as “from the station DC supply through the trip coil(s) of
the circuit breakers or other interrupting devices” can be a bit of an issue as the coils
could be good at time of verification and testing, but can fail right after or due to the
testing. We recommend to change the Protection System definition to read “up to the
trip coils(s)” instead the word “through”
Response: Thank you for your comments.
1. The definition has been modified to say, “voltage and current sensing devices providing inputs to protective relays”.
2. The SDT disagrees, and asserts that the trip coil(s) must be included within the Protection System. The observation that
the element may be good at the time of verification and testing, but fail immediately thereafter, is true of any device that is
not monitored continuously for proper operating function.
Grant County PUD
No
1) We note that the definition of a “Protection System” has been expanded to include the
trip coils and what used to be confined to batteries has now been expanded to “station
DC supply.” “Trip coils” is an improvement. Inasmuch as the mark-up changing “DC” to
“dc” is intended to communicate a more general term as opposed to a strict definition, it
leaves room for differing opinions among auditors as to what all should be included. We
July 22, 2010
11
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
support the change to exclude battery chargers since the rationale for their inclusion was
never clear. The battery itself will be, without exception, the “first responder” to provide
DC power to a Protection System. However, battery chargers have not been excluded
under the FAQs.
2) The SPCTF’s effort to define applicability in terms of “Facilities” is confusing.
Additionally, it is unclear how the terms “component,” “element” and “Facility” are
intended to relate to one another. An assumption may be that one or more components
(which are physical assets) can comprise an “element,” one or more of which can be
associated with an identifiable function, aligning with the five Protection System
Equipment Categories, found in SPCTF’s “PROTECTION SYSTEM MAINTENANCE-A
Technical Reference, dated Sept. 13, 2007, and that “Facility” is as used in 4.2.1 of the
Standard Development Roadmap, dated May 27, 2010. Please provide guidance on the
terms relate to one another.
3) The structure of the proposed standard is less clear than the existing standard PRC-0051 because of the potential for ambiguity between the definition of Protection System and
how the term “Facilities” is applied. A suggested resolution would be to revise the
definition of Protection System to resolve this ambiguity or to delete reference to 86
lockouts and auxiliary relays in the description of “Facilities.” If the 86 lockout relays are
to be included, they should be added as part of the DC Control Circuitry “element” (as
found in the NERC Glossary) of the circuit that energizes the 86 relay, thus placing it
within the definition of a “Protection System.”-once-and therefore in a manner that would
require only one scheduled maintenance to be performed if the testing schemes are
properly set up. We do agree, however, that sudden pressure relays, reclosing relays,
and other non fault detecting relays such as loss of cooling relays should not be
referenced as part of the “dc control circuitry” Element.
Response: Thank you for your comments.
1. A recent Interpretation request, referring to the currently approved definition specifying “station batteries”, excluded
July 22, 2010
12
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
battery chargers. The change to “station dc supply” is intended to expand the definition to include all essential elements
including battery chargers; without proper functioning of battery chargers, the battery will be discharged by normal
station dc load, and will be unable to perform its function; also, there are some entities which use a charger to provide the
dc supply without use of a battery. Use of “dc” rather than “DC” reflects the IEEE style guide for this term. The FAQ
intentionally does not exclude battery chargers as the SDT intend to include them within PRC-005-2.
2. This comment does not appear to apply to the definition, but instead to the draft Standard itself.
3. The SDT contends that “dc control circuitry” includes elements such as lockout relays and auxiliary relays.
Consumers Energy
No
1. It is unclear whether “voltage and current sensing inputs” include the instrument
transformer itself, or does it pertain to only the circuitry and input to the protective relays?
2. It is not clear what is included in the component, “station dc supply” without referring to
other documents (the posted Supplementary Reference and/or FAQ) for clarification. The
definition should be sufficiently detailed to be clear.
3. If Protection Systems trip via AC methods, are those systems, and the associated
control circuitry included?
Response: Thank you for your comments.
1.
The SDT has modified the definition for clarity; the SDT intends that the output of these devices, measured at the relay,
properly represents the primary quantities.
2.
There are many possible variations to “station dc supply”; it seems impossible to reflect all variations in the definition.
The definition must be sufficiently general such that variations can be included.
3.
The definition has been generalized such that ac tripping is included.
Public Service Enterprise
Group ("PSEG
Companies")
July 22, 2010
No
Based on review of ballot pool comments there are still too many questions that should be
resolved prior to submittal for ballot. It is suggested that a specific reference to the
supplementary reference document figures 1 & 2 and the legend be added. That would
13
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
further define the protection system components and scope boundary.
Response: Thank you for your comments. The SDT has revised the definition to make it more clear as a stand-alone product.
CenterPoint Energy
No
CenterPoint Energy believes the proposed definition of “Protection System” is technically
incorrect. The present definition does not include trip coils of interrupting devices, such as
circuit breakers; and correctly so, as trip coils are components of the interrupting device. A
Protection System has correctly performed its function if it provides tripping voltage up to
the circuit breaker trip coil. From that point, the circuit breaker can fail to timely interrupt
fault current due to several factors, such as a binding mechanism that affects breaker
clearing time, a broken pull rod, a bad insulating medium, or bad trip coils. Local breaker
failure protection, or remote backup protection, is installed to address the various possible
causes of circuit breaker failure.
For correctness, the definition of “Protection System” should be “Protective relays,
communication systems necessary for correct operation of protective functions, voltage and
current sensing inputs to protective relays and associated circuitry from the voltage and
current sensing devices, station dc supply, and control circuitry associated with protective
functions from the station dc supply UP TO THE TERMINALS OF the trip coil(s) of the
circuit breakers or other interrupting devices.”
Response: Thank you for your comments. The SDT disagrees, and asserts that the trip coil(s) must be included within the
Protection System.
Constellation Power
Generation
July 22, 2010
No
Constellation believes that this definition is to verbose, which can lead to unintended
interpretations. Constellation is concerned with the term sensing inputs, which may infer
that testing on instrument transformers must be completed while they are energized. This
proves difficult at a generating facility where most testing is completed during planned
outages when this equipment is not energized.
14
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
4.
Yes or
No
Question 1 Comment
Response: Thank you for your comments. The SDT has modified the definition for clarity; the SDT intends that the
output of these devices, measured at the relay, properly represents the primary quantities. Testing methods are not a
part of the definition.
Hydro One
No
1. Hydro One suggests adding “Components including” in the beginning. This is because
the word “components” has been used extensively throughout the standard and there is
no mention of what constitutes a protection system component in the standard. The
word “component” does find mention in FAQs, however, it is recommended to mention it
in the main standard.
The revised definition should read as follows: Protective System Components including
Protective relays, communication systems necessary for correct operation of protective
functions, voltage and current sensing devices providing inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station dc supply, and
control circuitry associated with protective functions from the station dc supply through
the trip coil(s) of the circuit breakers or other interrupting devices.
2. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly
identify which all protection system components does it own and need to maintain. This
is critical since NPCC had proposed a SAR to this effect which was not accepted by
NERC citing that this concern will be incorporated in the revised standard.
3. Also, reference should be made to Project 2009-17 in which Y-W Electric Association,
Inc. (Y-WEA) and Tri-State Generation and Transmission Association, Inc. (Tri-State)
requested an interpretation of the term "transmission Protection System" and
specifically whether protection for a radially-connected transformer protection system
energized from the BES is considered a transmission Protection System and is subject
to these standards.
Response: Thank you for your comments.
1. The SDT believes that the suggested text does not add to the definition, and may actually lead to additional problems,
July 22, 2010
15
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
such as an implication that the list within the definition is incomplete.
2. This issue is properly addressed within the Standard, not within the definition.
3. This issue relates to the application of the standard, and is not part of the definition.
Pacific Northwest Small
Public Power Utility
Comment Group
No
1. It is still unclear whether relays that respond to mechanical inputs, such as sudden
pressure relays, are included in the proposed definition as protective relays.
While PRC-005-2 R1 limits the scope of that particular standard to protection systems
that sense electrical quantities, it is remains unclear in other standards that use the
defined term whether mechanical input protections are included.
2. We suggest that “Protective Relay” also be defined, and that the definition clearly
exclude devices that respond to mechanical inputs in line with the NERC interpretation of
PRC-005-1 in response to the CMPWG request.
Response: Thank you for your comments.
1. The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
2. “Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC standard, thus the SDT
sees no need to either modify or duplicate that definition.
Pepco Holdings, Inc. Affiliates
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden
pressure relays, are included in the proposed definition as protective relays.
While PRC-005-2 R1 limits the scope of that particular standard to protection systems that
sense electrical quantities, it remains unclear in other standards that use the term
“Protection System” (such as PRC-004) whether devices responding to mechanical inputs
July 22, 2010
16
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
are included.
As such, we suggest that the term “Protective Relay” also be defined, and that the definition
clearly exclude devices that respond to mechanical inputs in line with the NERC
interpretation of PRC-005-1 in response to the CMPWG request.
Response: Thank you for your comments.
The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
“Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC standard, thus the SDT sees
no need to either modify or duplicate that definition.
PNGC Power
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden
pressure relays, are included in the proposed definition as protective relays.
While PRC-005-2 R1 limits the scope of that particular standard to protection systems that
sense electrical quantities, it is remains unclear in other standards that use the defined
term whether mechanical input protections are included.
We suggest that “Protective Relay” also be defined, and that the definition clearly exclude
devices that respond to mechanical inputs in line with the NERC interpretation of PRC-0051 in response to the CMPWG request.
Response: Thank you for your comments.
The definition has been modified to specify, “Protective relays which respond to electrical quantities”.
“Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC standard, thus the SDT sees
July 22, 2010
17
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
no need to either modify or duplicate that definition.
Duke Energy
No
It is unclear whether the revised definition includes PTs and CTs, but it does include the
wiring. We don’t see a way to list the wiring in R1.1 and provide supporting compliance
evidence. We believe the phrase “and associated circuitry from the voltage and current
sensing devices” should be struck from the definition.
Response: Thank you for your comments. The definition has been modified as suggested.
Indeck Energy Services
No
It presumes that all relays in a plant are Protective Systems that affect BES reliability.
As discussed at the FERC Technical Conference on Standards Development, the goal of
the standards program is to avoid or prevent cascading outages--specifically not loss of
load. The purpose of PRC-005-2 uses the term in its global sense but there is no subset of
the Protection Systems that affect reliability. PRC-005 R1 requires identification of all
components.
With the broad definition proposed and no separate term for only relays and other
components that have been identified as affecting reliability, confusion results. If this term
has its global meaning, then another term, such as Reliability Protection Systems, should
be instituted to avoid confusion.
Response: Thank you for your comments. The SDT believes that this issue is one for application of the definition within
various standards, not one of the definition itself.
Lincoln Electric System
July 22, 2010
No
LES believes the proposed definition of Protection System as written remains open to
interpretation. LES offers the following Protection System definition for the SDT’s
consideration: “Protection System” is defined as: A system that uses measurements of
18
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
voltage, current, frequency and/or phase angle to determine anomalies and trips a portion
of the BES and consists of 1) Protective relays, and associated auxiliary relays, that initiate
trip signals to trip coils, 2) associated communications channels, 3) current and voltage
transformers supplying protective relay inputs, 4) dc station supply, excluding battery
chargers, and 5) dc control trip path circuitry to the trip coils of BES connected breakers, or
equivalent interrupting device, and lockout relays.
Response: Thank your for your comments. The SDT has modified the definition to address some of the suggestions. Other
elements of the suggestion do not add to the existing definition, and the SDT disagrees with the suggestions regarding “trip a
portion of the BES” since Special Protection Systems and UVLS may actually trip non-BES facilities, and with excluding
battery chargers.
Long Island Power
Authority
No
1. LIPA suggests adding “Protection System Components including” in the beginning. This
is because the word “components” has been used extensively throughout the standard
and there is no mention of what constitutes a protection system component in the
standard. The word “component” does find mention in FAQs, however, it is
recommended to mention it in the main standard.
2. Also, LIPA proposes a change in the proposed definition (changing "voltage and current
sensing inputs" to "voltage and current sensing devices providing inputs").The revised
definition should read as follows: Protective System Components including Protective
relays, communication systems necessary for correct operation of protective functions,
voltage and current sensing devices providing inputs to protective relays and associated
circuitry from the voltage and current sensing devices, station dc supply, and control
circuitry associated with protective functions from the station dc supply through the trip
coil(s) of the circuit breakers or other interrupting devices.
3. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly
identify all protection system components it owns and needs to maintain. This is critical
since NPCC had proposed a SAR to this effect which was not accepted by NERC citing
that this concern will be incorporated in the revised standard.
July 22, 2010
19
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank you for your comments.
1. The SDT believes that the suggested text does not add to the definition, and may actually lead to additional problems,
such as an implication that the list within the definition is incomplete.
2. The SDT has modified the definition as suggested regarding voltage and current sensing inputs.
3. This issue is properly addressed within the Standard.
Progress Energy Carolinas
No
See comment associated with question 2.
Response: Thank you for your comments. Please see our response to your comment associated with question 2.
Northeast Power
Coordinating Council
No
1. Suggest adding “Protection System Components including” in the beginning. This is
because the word “components” has been used extensively throughout the standard
and there is no mention of what constitutes a protection system component in the
standard. The word “component” does find mention in FAQs, however, it is
recommended to mention it in the body of the standard.
The revised definition should read as follows: Protection System Components including
Protective relays, communication systems necessary for correct operation of protective
functions, voltage and current sensing devices providing inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station dc supply, and
control circuitry associated with protective functions from the station dc supply through
the trip coil(s) of the circuit breakers or other interrupting devices.
2. An alternative definition for Protection System to eliminate the need to capitalize
“component”:The collective components comprised of protective relays, communication
systems necessary for correct operation of protective functions, voltage and current
sensing devices providing inputs to protective relays and associated circuitry from the
voltage and current sensing devices, station dc supply, and control circuitry associated
with protective functions from the station dc supply through the trip coil(s) of the circuit
July 22, 2010
20
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
breakers or other interrupting devices.
3. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly
identify which protection system components it does own and needs to maintain. Many
DPs own and/or operate equipment identified in the existing or proposed definition.
However, not all such equipment translates into a transmission Protection System. The
definition needs clarification on when such equipment is a part of the transmission
protection system. This is critical since NPCC had proposed a SAR to this effect which
was not accepted by NERC citing that this concern will be incorporated in the revised
standard. Also, reference should be made to Project 2009-17 in which Y-W Electric
Association, Inc. (Y-WEA) and Tri-State Generation and Transmission Association, Inc.
(Tri-State) requested an interpretation of the term "transmission Protection System" and
specifically whether protection for a radially-connected transformer protection system
energized from the BES is considered a transmission Protection System and is subject
to these standards.
Response: Thank you for your comments.
1. The SDT believes that the suggested text does not add to the definition, and may actually lead to additional problems,
such as an implication that the list within the definition is incomplete.
2. The SDT believes that the suggested text does not add to the definition, and may actually lead to additional problems,
such as an implication that the list within the definition is incomplete.
3. This issue relates to the application of the standard, and is not part of the definition.
Y-W Electric Association,
Inc
July 22, 2010
No
The application of this definition to Reliability Standards NUC-001-2, PER-005-1, PRC-0011, and PRC-004-1 results in confusion as to whether relays with mechanical inputs are
included or excluded from this definition. PRC-005-2_R1 contains language limiting its
applicability to relays operating on electrical inputs only, but the remaining standards that
rely on this definition are not so specific. This being the case, it would make much more
sense to clearly define what devices are actually meant in the glossary definition rather
21
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
than leaving it up to each individual standard to do so.
Response: Thank you for your comments. The definition has been modified to specify, “Protective relays which respond to
electrical quantities”.
Arizona Public Service
Company
No
1. The change to the definition relative to the voltage and current sensing devices is too
prescriptive.
2. Methods of determining the integrity of the voltage and current inputs into the relays to
ensure reliability of the devices should be up to the discretion of the utility.
Response: Thank you for your comments.
1. The SDR modified the definition, relating to voltage and current sensing inputs, for clarity.
2. The issue regarding methods, etc, is an issue for the standard itself, not the definition.
MidAmerican Energy
Company
No
The definition is expanded and clarified in the language of PRC-005-2. These changes
should be incorporated in the definition to insure it is used consistently in PRC-005 and any
other standards where it appears.
The following is a suggested revised definition:”Protection System” is defined as: A system
that uses measurements of voltage, current, frequency and/or phase angle to determine
anomalies and to trip a portion of the BES to provide protection for the BES and consists of
1) Protective relays for BES elements and, 2) Communications systems necessary for
correct BES protection system operations and, 3) Current and voltage sensing devices
supplying BES protective relay input and, 4) Station DC supply to BES protection systems
excluding battery chargers, and 5) DC control trip paths to the trip coil(s) of the circuit
breakers or other interrupting devices for BES elements.
July 22, 2010
22
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank your for your comments.
The SDT modified the definition to address some of the suggestions. Other elements of the suggestion do not add to the
existing definition, and the SDT disagrees with the suggestions regarding “trips a portion of the BES” since Special
Protection Systems and UVLS may actually trip non-BES facilities, and with excluding battery chargers.
The Detroit Edison
Company
No
The definition should clarify whether current and voltage transformers themselves are
included.
Response: Thank you for your comments. The SDT modified the definition to state, “voltage and current sensing devices
providing inputs to protective relays”.
Avista Corp
No
The modified definition of Protection System now refers to “functions” rather than “devices.”
What are the “functions?” This new term adds confusion without being defined in the
standard.
Response: Thank you for your comments. The “functions” are the accumulated performance of the various portions of the
Protection System. This term is used to distinguish “protective functions” from annunciation, signaling, or information.
American Electric Power
No
The term "station" should either be defined or removed from the definition, as it implies
transmission and distribution assets while the term "plant" is used to define generation
assets. It would suffice to simply refer to the "DC Supply".
Response: Thank you for your comments. The term “station” is used in a generic sense to apply to either “substation” or
“generation station” facilities.
Xcel Energy
No
We recommend modifying the language to remove circuit breakers altogether: “...through
the trip coil(s) of the circuit breakers or other interrupting devices.”
Response: Thank you for your comments. The SDT believes that circuit breakers are by far the most prevalent interrupting
July 22, 2010
23
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
devices, and to generalize as suggested will lead to industry confusion.
Allegheny Power
Yes
American Transmission
Company
Yes
Bonneville Power
Administration
Yes
Clark Public Utilities
Yes
Dynegy Inc.
Yes
E.ON U.S.
Yes
Entergy Services
Yes
Exelon
Yes
Indiana Municipal Power
Agency
Yes
Manitoba Hydro
Yes
MEAG Power
Yes
Northeast Utilities
Yes
PacifiCorp
Yes
July 22, 2010
24
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Springfield Utility Board
Yes
US Bureau of Reclamation
Yes
We Energies
Yes
WECC
Yes
Western Area Power
Administration
Yes
Florida Municipal Power
Agency
Yes
Question 1 Comment
Because the definition changes the scope of what a protection system covers, increasing
that scope, the definition should not be balloted separately from PRC-005-2 so that the
industry knows what is being committed to. For instance, the circuitry connecting the
voltage and current sensing devices to the relays is a scope expansion. Station DC supply
increases the scope to include the charger, etc. This scope increase needs to have an
appropriate implementation period.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
NERC Staff
July 22, 2010
Yes
Still, to make sure the reference to dc supply is more generic than just “station dc supply,”
NERC staff suggests the following modified definition of Protection System:"Protective
relays, communication systems necessary for correct operation of protective functions,
voltage and current sensing inputs to protective relays and associated circuitry from the
voltage and current sensing devices, and any dc supply or control circuitry associated with
25
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
the preceding devices."
Response: Thank you for your comments. The SDT believes that modifying the definition as suggested does not add to the
definition.
FirstEnergy
Yes
1. The definition is ready for ballot with the addition of auxiliary relays to the definition of
protective relays. There is a potential for an entity to determine that auxiliary relays do
not perform a protection function since they typically do not sense fault current.
Furthermore, one could determine that the term "circuitry" only refers to the wiring to
connect the various DC devices together. We suggest adding "auxiliary relays
necessary for correct operation of protective devices" to improve clarity of the definition.
2. With regard to the change from the current definition phrase "station batteries" to the
new definitions phrase "station DC supply", it may not be clear to the reader that this
includes battery chargers. To alleviate future interpretation issues, we suggest adding a
clarifying statement at the end of the definition, such as "The station DC supply includes
the battery, battery charger, and other DC components".
3. The acronym "dc" should be capitalized.
Response: Thank you for your comments.
1. The SDT believes that auxiliary relays are implicitly part of the control circuitry. The Supplementary Reference as posted
in June 2010 (Section 15.3, page 22) specifically states that “the dc control circuitry also includes each auxiliary tripping
relay …”.
2. Clarifications such as this properly belong in supplementary materials. This is described in the FAQ posted in June 2010
(FAQ II.5.A).
3. The term, “dc”, rather than “DC”, reflects the NERC style guide.
ReliabilityFirst Corp.
July 22, 2010
Yes
The definition should probably include interrupting devices as the Protection System is of
26
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
little value if the fault cannot be interrupted.
Response: Thank you for your comments. Interrupting devices are not within the scope of this project.
South Carolina Electric and
Gas
Yes
The new definition effective date should be directly linked to the approval and
implementation schedule of PRC-005-2 to avoid any possible compliance issues under the
current PRC-005 standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Ameren
Yes
1. We agree that the definition provides clarity and will enhance the reliability of the
Protection Systems to which it is applicable; however, we suggest that a Glossary term
for Protective Relay be added in order to clarify in all standards inclusion of relays that
measure voltage, current, frequency and/or phase angle to determine anomalies, as
stated in PRC-005-2 R1.
2. We believe there should be a direct linkage of the definition’s effective date to the
approval and implementation schedule of PRC-005-2. Since this new definition is
directly linked to the proposed revised standard, it would be premature to make this
definition effective prior to the effective date of the new standard.
3. We agree that the voltage and current inputs at the protective relays correctly identifies
that component, that this excludes the instrument transformer itself.
4. We suggest replacing "to" with "at", and omitting "and associated circuitry from the
voltage and current sensing devices."
July 22, 2010
27
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank you for your comments.
1. Thank you. “Protective relay” is defined by IEEE and does not have a unique meaning when used in a NERC standard,
thus the SDT sees no need to either modify or duplicate that definition.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the
board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed
that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The implementation plan now
proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to
apply the new definition to PRC-005-1.
3. Based on other industry comments, the SDT has modified the definition to include these devices.
4. The SDT modified this portion of the definition to state, “voltage and current sensing devices providing inputs to
protective relays”.
SERC Protection and
Control Sub-committee
(PCS)
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection
Systems to which it is applicable; however, we believe there should be a direct linkage of
the definition’s effective date to the approval and implementation schedule of PRC-005-2.
Since this new definition is directly linked to the proposed revised standard, it would be
premature to make this definition effective prior to the effective date of the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Southern Company
July 22, 2010
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection
Systems to which it is applicable. However, we feel that there needs to be a direct linkage
28
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Transmission
Question 1 Comment
of the definition’s effective date to the approval and implementation schedule of PRC-0052. Since this new definition is directly linked to the proposed revised standard, it would be
premature to make this definition effective prior to the effective date of the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Santee Cooper
Yes
We agree with the proposed definition. However, the effective date of this definition should
be linked to the implementation schedule of PRC-005-2. This definition should not be
made effective prior to the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
July 22, 2010
29
Consideration of Comments on the Definition of Protection System — Project 2007-17
2. Do you agree with the implementation plan for the revised definition of Protection System? The
implementation plan has two phases – the first phase gives entities at least six months to update their
protection system maintenance and testing program; the second phase starts when the protection
system maintenance and testing program has been updated and requires implementation of any
additional maintenance and testing associated with the program changes by the end of the first
complete maintenance and testing cycle described in the entity’s revised program. If you disagree with
this implementation plan, please explain why.
Summary Consideration: Most commenters felt that the definition and its implementation should be linked to the approval and
implementation of the revised standard. The retirement date for the existing definition, in the Implementation Plan, was developed
upon advice of NERC Compliance staff and is intended to address a reliability gap caused by the existing definition. When the Board
of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the
reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this
reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC005-1 as soon as practical - not years from now.
Additional commenters indicated that a 6-month implementation schedule for modifying their Protection System maintenance and
testing program is insufficient. The SDT revised the first phase of the implementation plan to 12-months. The implementation plan
now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply
the new definition to PRC-005-1.
Organization
WECC
Yes or
No
Question 2 Comment
Compliance agrees only if the original “Protection System” definition is in place for the
interim implementation period, so that only the changes and or additions to the “Protection
System” definition are covered under the proposed implementation plan.
Response: Thank you for your comments. The retirement date for the existing definition, in the Implementation Plan, was
developed upon advice of NERC Compliance staff and is intended to address a reliability gap caused by the existing
July 22, 2010
30
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
No
1. The draft implementation plan general considerations have a requirement to identify all
the protection system components addressed under PRC-005-1 and PRC-005-2 for
potential audits while modifying the existing programs. The standard revision will require
extensive reviews and possibly add significant amounts of components to the program.
This is listed as a requirement without a specific deadline other than supplying the
information as part of an audit. If an audit is scheduled or announced early in the
implementation period the evidence is required. The requirement for identifying all the
components in the implementation process should have a time specified with bases for
the starting point.
definition.
Public Service Enterprise
Group ("PSEG
Companies")
2. Where additional definition of a protection system scope boundary is determined as a
result of the standard revisions, the implementation plan completion requirement should
be at the end of next maintenance interval of that added protection system component.
There may be situations where additional scope as determined by the additions or
revisions to the standard and/or supporting reference material (e.g., an auxiliary contact
input in a tripping scheme) would require going back and taking equipment out of
service to perform that one check. To keep the maintenance and outage schedules
coordinated the new requirements should be at the end of current cycles, not beginning.
Response: Thank you for your comments.
1. The posted implementation plan for the definition specifies that the program be updated by the end of the first calendar
quarter six months following regulatory approvals. This establishes the requested schedule for the definition alone.
Implementation of PRC-005-2 is discussed in the implementation plan for the standard.
2. The posted implementation plan for the definition provides for the requested implementation by specifying, “and
implement any additional maintenance and testing (required in Requirement R2 of PRC-005-1 – Transmission and
Generation Protection System Maintenance and Testing) by the end of the first complete maintenance and testing cycle
described in the entity’s program description and basis document(s) following establishment of the program changes
July 22, 2010
31
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
resulting from the revised definition”.
Ameren
No
As noted above, the implementation plan should be linked to the approval of PRC-005-2.
Since this new definition is directly linked to the proposed revised standard, it would be
premature to make this definition effective prior to the effective date of the new standard.
Otherwise, entities must address equipment, documentation, work management process,
and employee training changes needed for compliance twice within an unreasonably short
timeframe. If PRC-005-2 receives regulatory approval in 1st quarter 2011, PSMP
implementation along with this revised definition should be effective at the beginning of
2012 to coincide with the calendar year. These nine months will be needed to fully assess
and address the necessary maintenance program documentation changes, maintenance
system tool revisions, and personnel training needed to incorporate this new definition into
our program.
Response: Thank you for your comments. The retirement date for the existing definition, in the Implementation Plan, was
developed upon advice of NERC Compliance staff and is intended to address a reliability gap caused by the existing
definition. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection
system" and directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT
has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The implementation
plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time
to apply the new definition to PRC-005-1.
SERC Protection and
Control Sub-committee
(PCS)
No
As noted above, the implementation plan should be linked to the approval of PRC-005-2.
Since this new definition is directly linked to the proposed revised standard, it would be
premature to make this definition effective prior to the effective date of the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
July 22, 2010
32
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Florida Municipal Power
Agency
No
As stated in response to Question 1, it is inappropriate to change the definition of
Protection System for PRC-005-1 and the new definition should wait for the new standard.
In all honesty, the new PRC-005-2 lays out the program anyway, so, any change to the
definition needs to be accompanied by the commitment associated with that change.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
American Electric Power
No
As written, the implementation plan only specifies a time frame for entities to update their
documentation for PRC-005-1 and PRC-005-2 compliance. The implementation plan also
needs to give entities a time frame to address any required changes to their documentation
for other standards that use the term "Protection System", including but not limited to NUC001-2, PER-005-1, PRC-001-1, etc.
Response: Thank you for your comments. An assessment of the changes to the definition (posted with the first comment
period), relative to the entire body of other NERC Standards using this defined term, determined that the changes are
consistent with the other existing uses of the definition, and that no other implementation plan considerations were
necessary. No comments were received relative to this assessment.
American Transmission
Company
July 22, 2010
No
1. ATC does not agree to the implementation plan proposed. While it makes common
sense to proceed with R1 prior to proceeding with implementing R2, R3, and R4, the
timeline to be compliant for R1 is too short. It will take a considerable amount of
33
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
resources to migrate the maintenance plan from today’s standard to the new standard in
phase one. ATC recommends that time to develop and update the revised program be
increased to at least one year followed by a transition time for the entity to collect all the
necessary field data for the protection system within its first full cycle of testing. (In
ATC’s case would be 6 years) To address phase two, ATC believes human and
technological resources will be overburdened to implement this revised standard as
written. The transition to implementing the new program will take another full testing
cycle once the program has been updated. Increased documentation and obtaining
additional resources to accomplish this will be challenging.
2. Implementation of PRC-005-2 will impact ATC in the following manner: a. Increase
costs: double existing maintenance costs. b. Since there will be a doubling of human
interaction (or more), it is expected that failures due to human error will increase,
possibly proportionately. c. Breaker maintenance may need to be aligned with
protection scheme testing, which will always contain elements that are include in the
non-monitored table for 6 yr testing. d. ATC is developing standards for redundant bus
and transformer protection schemes. This would allow ATC to test the protection
packages without taking the equipment out of service. Further if one system fails, there
is full redundancy available. With the current version of PRC-005-2, ATC would need to
take an outage to test the protection schemes for a transformer or a bus, there is not an
incentive to install redundant schemes. ATC is working with a condition based breaker
maintenance program. This program’s value would be greatly diminished under PRC005-2 as currently written.
3. Consideration also needs to be given for other NERC standards expected to be passed
and in the implementation stage at the same time, such as the CIP standards.
Response: Thank you for your comments.
1. This comment appears to address implementation of the draft Standard, not the definition.
2. This comment appears to address implementation of the draft Standard, not the definition.
July 22, 2010
34
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
3. Thank you.
Duke Energy
No
Definition should be implemented concurrently with PRC-005-2.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Consumers Energy
Company
No
For entities that may not have included all elements reflected in the modified definition
within their PRC-005-1 program, 6-months following regulatory approvals may not be
sufficient to identify all relevant additional components, develop maintenance procedures,
develop maintenance and testing intervals, develop a defendable technical basis for both
the procedures and intervals, and train personnel on the newly implemented items. We
propose that a 12-month schedule following regulatory approvals may be more practical.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule as
suggested. However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
Exelon
No
PECO would like to have the implementation plan provide at least 1 year for full
implementation of the new standard. This will provide adequate time for development of
documentation, training for all personnel, and testing then implementation of the new
process(es).
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule as
suggested. However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
July 22, 2010
35
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Progress Energy Carolinas
Yes or
No
Question 2 Comment
No
Progress Energy does not believe that the definition should be implemented separately
from and prior to the implementation of PRC-005-2. We believe there should be a direct
linkage between the definition’s effective date to the approval and implementation schedule
of PRC-005-2. Since this new definition should be directly linked to the proposed revised
standard, it would be premature to make this new definition effective prior to the effective
date of the new standard. We believe that changes to the maintenance program should be
driven by the revision of the PRC standard, not by the revision of a definition.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Pepco Holdings, Inc. Affiliates
No
The 6 month time frame to update the revised maintenance and testing program is too
short. Specifically identifying and documenting each component not presently individually
identified in our maintenance databases, auxiliary relays, lock-out relays, etc. will require a
major effort. We recommend at least one year.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule as
suggested. However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
Indeck Energy Services
No
The definition should not be implemented separate from PRC-002-2. The PRC-002-2
implementation plan would be adequate.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
July 22, 2010
36
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
E.ON U.S.
No
The first phase is only 3 months (per Implementation Plan) to update the program, not the 6
months as listed in this question. E.ON U.S. recommends that it should be a minimum of 6
months, regardless.
Response: Thank you for your comments. The Implementation Plan for the definition specifically indicated a 6-month
(increased to 12-months in response to comments) implementation schedule to update the program. However, to agree with
the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the first calendar
quarter”.
Santee Cooper
No
The implementation plan should be linked to the approval of PRC-005-2. The definition
should not be made effective prior to the new standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Xcel Energy
No
1. The implementation plans for both the definition and standard are confusing. Does this
imply a "clean slate" approach can be used? i.e. do entities have up to the first interval
window to complete the maintenance or must they have it complete on day 1 of the
standard and again by the first interval?
2. It also appears that the implementation plans are conflicting whereby one requires full
compliance and the other allows 6 months...the definition implementation plan also refer
July 22, 2010
37
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
to a basis document though the standard does not require one.
Response: Thank you for your comments.
1. The implementation plan for the definition specifically states that the entity has until the end of the first full interval
established per their program and basis documents to implement the updated program (i.e. complete the maintenance).
2. The Implementation Plan for the definition specifically indicated a 6-month (increased to 12-months in response to
comments) implementation schedule to update the program. However, to agree with the SDT Guidelines established by
NERC, “end of the first calendar quarter” was modified to “first day of the first calendar quarter”. PRC-005-1 requires
basis documents, where PRC-005-2 (draft) does not, as maximum intervals and minimum activities are prescribed within
the standard.
Manitoba Hydro
No
The proposed implementation stage of 6 months is much too stringent and an 18 month
window is suggested.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule.
However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day
of the first calendar quarter”.
MidAmerican Energy
Company
No
The protection system definition implementation plan should be consistent with the
implementation plan of PRC-005-2 R1. Actual maintenance requirements implementation
should be as required by the PRC-005-2 implementation plan and should not be included in
the implementation plan for the protection system definition.
Response: Thank you for your comments.
Southern Company
Transmission
July 22, 2010
No
The revised definition should not be made effective until the revised PRC-005-2 is in effect.
There is no definite reliability benefit to balloting this definition prior to the revised standard.
If balloted and approved, entities would definitely have to modify their Protection System
Maintenance and Testing Program methodology, but there is no obligation to or guarantee
38
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
of any additional maintenance being performed. PRC-005-2 includes this definition, the
maintenance activities, and the intervals that will ensure execution of the maintenance and
testing.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1
that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the
definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
Indiana Municipal Power
Agency
No
The second part of the implementation effective date does not make sense and might be
wrong. The second part talks about implementing any additional maintenance and testing
(required in R2 of PRC-005-1- Transmission and Generation Protection system
Maintenance and Testing); this is referring to version 1 of the standard and there should be
no additional maintenance and testing added from version 1 of the standard, just version 2
which is the new version. Overall, the wording on this implementation plan needs to be
made more clear about how the implementation plan will work.
Response: Thank you for your comments. The second part of the implementation plan for the definition allows the entity to
implement any program changes that result from the modified definition systematically via the intervals establised to address
those changes. The SDT believes that this portion of the implementation plan is clear.
US Bureau of Reclamation
July 22, 2010
No
The Time Horizons are too narrow for the implementation of the standard as written. The
SDT appears to have not accounted for the data analysis associated with performance
based systems. The data collection, analysis, and subsequent decisions associated
development of a maintenance program and its justification do not occur overnight
especially with larger utilities. In addition, this new standard will require complete rewrite of
an entities internal maintenance programs. The internal processes associated with these
vary based on the size of the entity and its organizational structure. Since this standard is
39
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
so invasive into the internal decisions concerning maintenance, the standard should allow
at least 18 months for entities to rewrite their internal maintenance programs to meet the
program development requirements and 18 months to train the staff in the new program,
incorporate the program into the entities compliance processes, and to implement the new
program.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule to
update the entities’ program in accoradnce with the modified definition.
Hydro One
No
1. The time provided for the first phase “at least six months” is too open ended and does
not give entities a clear timeline. HYDRO ONE suggests 1 year for the first phase.
2. Also, HYDRO ONE suggests phasing out the second phase in stages.
Response: Thank you for your comments.
1. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to agree with the SDT
Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the first calendar
quarter”.
2. The SDT does not understand this comment.
Long Island Power
Authority
No
1. The time provided for the first phase “at least six months” is too open ended and does
not give entities a clear timeline. LIPA suggests 1 year for the first phase.
2. It is also suggested phasing out the second phase in stages.
Response: Thank you for your comments.
1. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to agree with the SDT
Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the first calendar
quarter”.
July 22, 2010
40
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
2. The SDT does not understand this comment.
Northeast Power
Coordinating Council
No
1. The time provided for the first phase “at least six months” is too open ended and does
not give entities a clear timeline. Suggest 1 year for the first phase.
2. Suggest phasing out the second phase in stages.
Response: Thank you for your comments.
1. The Implementation Plan has been modified to allow a 12-month schedule as suggested. However, to agree with the SDT
Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the first calendar
quarter”.
2. The SDT does not understand this comment.
Northeast Utilities
No
The time provided for the first phase “at least six months” is too open ended and does not
give entities a clear timeline. Northeast Utilities suggests 1 year for the first phase.
Response: Thank you for your comments. The Implementation Plan has been modified to allow a 12-month schedule as
suggested. However, to agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified
to “first day of the first calendar quarter”.
Grant County PUD
No
There needs to be more clarity concerning the role of the 3 year audit during the
implementation phase. Do the audit tests consist of varying proportions of -1 criteria and -2
criteria?
Response: Thank you for your comments. This comment appears to address implementation of the revised standard, not the
revised definition.
Constellation Power
Generation
July 22, 2010
No
This does not match the implementation proposed for PRC-005-2. The implementation plan
for revising the program is 6 months based on the “definition implementation” but R1 in
41
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
PRC-005-2 has a 3 month implementation plan.
Response: Thank you for your comments. The intent is to implement the definition and apply it to PRC-005-1 before PRC005-2 becomes effective. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written
by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of
"protection system" and directed that work to close this reliability gap should be given “priority.” To close this reliability gap
the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should
give entities time to apply the new definition to PRC-005-1.
The Detroit Edison
Company
No
This implementation plan and the one for PRC-005-2 should be consistent.
Response: Thank you for your comments. The intent is to implement the definition and apply it to PRC-005-1 before PRC005-2 becomes effective. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written
by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of
"protection system" and directed that work to close this reliability gap should be given “priority.” To close this reliability gap
the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should
give entities time to apply the new definition to PRC-005-1.
Entergy Services
No
1. We agree with the definition, however we do not agree with the implementation plan.
We believe implementation of the definition needs to coincide with the implementation
of Standard PRC-005-2. To do otherwise, will cause entities to address equipment,
documentation, work management process, and employee training changes needed for
compliance twice within an unreasonably short timeframe.
2. Additional time, 12 months minimum, will be needed to fully assess and address the
necessary maintenance program documentation changes, maintenance system tool
revisions, and personnel training needed to incorporate this new definition into our
July 22, 2010
42
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
program.
Response: Thank you for your comments.
1. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the
board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed
that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The implementation plan now
proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to
apply the new definition to PRC-005-1.
2. The Implementation Plan for the definition has been modified to allow a 12-month schedule as suggested. However, to
agree with the SDT Guidelines established by NERC, “end of the first calendar quarter” was modified to “first day of the
first calendar quarter”.
Clark Public Utilities
No
1. While the drafting team has done a great job of simplifying the implementation plan from
the original draft 1 language, the current language has some ambiguities. I do not
understand what the term “the end of the first calendar quarter six months following
regulatory approvals” means. What is wrong with just saying “within nine months (or six
months or twelve months) following regulatory approvals? Using the current language I
would be inclined to assume it is six months so I can avoid a dispute (and quite possibly
a notice of alleged violation) over a date.
2. Also, I am not sure what the term “the end of the first complete maintenance and testing
cycle described in the entity’s program description” means. It is quite likely that a
registered entity will make the required definition change to its maintenance program (at
approximately six months) and wind up with devices that need to be tested. Is the
implementation plan attempting to provide some allowed time delay so the registered
entity will not be out of compliance even though it has devices that are now beyond the
maximum testing interval due to the definition change? The existing language implies
that within approximately six months of regulatory approval, the maintenance program
needs to be changed to incorporate the revised definition for Protection System.
July 22, 2010
43
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
However, the effective date for the revised maintenance program is going to be some
date that corresponds with the end of the first complete maintenance and testing cycle
in that program. I really don’t understand what that time period is and I believe the
drafting team needs to put in something that clears up this confusion. By testing cycle
do you mean “maximum interval” as shown in the PRC-005 table? Do you mean the
“maximum interval” that a registered entity includes in their maintenance program? If
so, do you intend the implementation to be a different date for protection devices
depending on the maximum testing interval? Or do you envision some date beyond the
six months where the entire maintenance program (with the definition change) becomes
effective and any registered entities with out-of-compliance issues would need to file
mitigation plans?
Response: Thank you for your comments.
1. Within the US, NERC Standards are not mandatory and enforceable until approval by FERC. As established within the
NERC Drafting Team Guidelines, the effective dates must be “the first day of the first calendar quarter after entities are
expected to be compliant”. The effective dates are always on the first day of a calendar quarter to make it easier for
entities to track the effective dates of requirements. To agree with the SDT Guidelines established by NERC, “end of the
first calendar quarter” was modified to “first day of the first calendar quarter”.
2. Continuing on the example above, if an entity then establishes a 3-calendar-year schedule for additional components as
addressed by the definition, the entity must be fully compliant by the end of 2014.
We Energies
No
Wisconsin Electric does not agree with the six-month implementation requirement in the
first phase. It is our position that a longer adjustment time is needed for entities to update
their maintenance programs to implement the new definition. The new definition results in
a significant increase in the scope of affected equipment and the documentation required to
implement the program, and requires additional resources beyond present levels, including
hiring and training. We estimate that this effort will require three years to fully implement.
Response: Thank you for your comments. The Implementation Plan for the definition has been modified to allow a 12-month
July 22, 2010
44
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
Question 2 Comment
schedule to update the program. The entity then has the full interval as established within their program to implement the
program for added components.
Allegheny Power
Yes
Arizona Public Service
Company
Yes
Avista Corp
Yes
Bonneville Power
Administration
Yes
Dynegy Inc.
Yes
FirstEnergy
Yes
Lincoln Electric System
Yes
MEAG Power
Yes
NERC Staff
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PacifiCorp
Yes
PNGC Power
Yes
July 22, 2010
45
Consideration of Comments on the Definition of Protection System — Project 2007-17
Organization
Yes or
No
ReliabilityFirst Corp.
Yes
South Carolina Electric and
Gas
Yes
Springfield Utility Board
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Inc
Yes
July 22, 2010
Question 2 Comment
46
Consideration of Comments on 2nd Draft of the Standard for Protection
System Maintenance and Testing Project 2007-17
The Protection System Maintenance and Testing Standard Drafting Team thanks all
commenters who submitted comments on the 2nd draft of the PRC-005-2 standard for
Protection System Maintenance and Testing. This standard was posted for a 45-day public
comment period from June 11, 2010 through July 16, 2010. The stakeholders were asked
to provide feedback on the standards through a special Electronic Comment Form. There
were 58 sets of comments, including comments from more than 130 different people from
over 70 companies representing 8 of the 10 Industry Segments as shown in the table on the
following pages.
Many commenters objected to the establishment of maximum allowable intervals and
offered comments on most of the individual activities and intervals within the Tables.
•
The SDT responded that “FERC Order 693 and the approved SAR assigned the SDT
to develop a Standard with maximum allowable intervals and minimum maintenance
activities.”
To provide more clarity, the SDT completely rearranged and revised the Tables.
•
The Tables now consist of one table for each of the five Protection System
component types, as well as a sixth table to address monitoring and alarming
requirements to support extended intervals for monitored Protection System
components.
Many commenters disagreed with some of the VRF and VSL assignments.
•
The SDT made several modifications to the VRFs and VSLs that are in-keeping with
the guidance provided by NERC and FERC.
Other comments were offered regarding Time Horizons, resulting in modification of the Time
Horizons for both R3 and R4 from Long-Term Planning to Operations Planning.
In response to suggestions relative to the Measures, the SDT made changes to all four
Measures.
Commenters were appreciative for the information contained in the two reference
documents, but indicated a preference for some of the information to be included within the
body of the Standard.
•
In response, the SDT included the definitions of those terms exclusive to this
standard, specifically “component type”, “component”, “segment”, “maintenance
correctable issue”, and “countable event”, within the Standard.
In this report, comments have been organized by question number. Comments can be viewed
in their original format on the following web page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herbert Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there
is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on PSMTSDT — Project 2007-17
Index to Questions, Comments, and Responses
1.
The SDT has made significant changes to the minimum maintenance activities and
maximum allowable intervals within Tables 1a, 1b, and 1c, particularly related to
station dc supply and dc control circuits. Do you agree with these changes? If not,
please provide specific suggestions for improvement. ............................................ 13
2.
The SDT has included VRFs and Time Horizons with this posting. Do you agree with the
assignments that have been made? If not, please provide specific suggestions for
improvement. ................................................................................................... 75
3.
The SDT has included Measures and Data Retention with this posting. Do you agree
with the assignments that have been made? If not, please provide specific suggestions
for improvement. .............................................................................................. 84
4.
The SDT has included VSLs with this posting. Do you agree with the assignments that
have been made? If not, please provide specific suggestions for change. ............... 100
5.
The SDT has revised the “Supplementary Reference” document which is supplied to
provide supporting discussion for the Requirements within the standard. Do you agree
with the changes? If not, please provide specific suggestions for change. .............. 116
6.
The SDT has revised the “Frequently-Asked Questions” (FAQ) document which is
supplied to address anticipated questions relative to the standard. Do you agree with
these changes? If not, please provide specific suggestions for change. .................. 129
7.
If you have any other comments on this Standard that you have not already provided
in response to the prior questions, please provide them here. ............................... 143
November 17, 2010
2
Consideration of Comments on PSMTSDT — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Joseph DePoorter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
MRO’s NERC Standards Review Subcommittee
(NSRS)
X
Additional Member Additional Organization Region Segment Selection
1. Mahmood Safi
OPPD
MRO
1, 3, 5, 6
2. Chuck Lawrence
ATC
MRO
1
3. Tom Webb
WPSC
MRO
3, 4, 5, 6
4. Jason Marshall
MISO
MRO
2
5. Jodi Jenson
WAPA
MRO
1, 6
6. Ken Goldsmith
ALTW
MRO
4
7. Dave Rudolph
BEPC
MRO
1, 3, 5, 6
8. Eric Ruskamp
LES
MRO
1, 3, 5, 6
9. Joseph Knight
GRE
MRO
1, 3, 5, 6
10. Joe DePoorter
MGE
MRO
3, 4, 5, 6
11. Scott Nickels
RPU
MRO
4
12. Terry Harbour
MEC
MRO
6, 1, 3, 5
November 17, 2010
10
3
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
13. Carol Gerou
2.
Group
MRO
Organization
MRO
Guy Zito
Additional Member
1
2
3
4
5
6
7
8
9
10
10
Northeast Power Coordinating Council
Additional Organization
X
Region Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2. Gregory Campoli
New York Independent System Operator
NPCC 2
3. Kurtis Chong
Independent Electricity System Operator
NPCC 2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7. Ben Eng
New York Power Authority
NPCC 4
8. Brian Evans-Mongeon Utility Services
NPCC 8
9. Dean Ellis
Dynegy Generation
NPCC 5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
11. Kathleen Goodman
ISO - New England
NPCC 2
12. David Kiguel
Hydro One Networks Inc.
NPCC 1
13. Michael R. Lombardi
Northeast Utilities
NPCC 1
14. Randy MacDonald
New Brunswick System Operator
NPCC 2
15. Bruce Metruck
New York Power Authority
NPCC 6
16. Chantel Haswell
FPL Group
NPCC 5
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
18. Robert Pellegrini
The United Illuminating Company
NPCC 1
19. Saurabh Saksena
National Grid
NPCC 1
20. Michael Schiavone
National Grid
NPCC 1
November 17, 2010
Industry Segment
4
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
21. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
22. Si Truc Phan
Hydro-Quebec TransEnergie
3.
Group
1
2
3
4
X
X
5
6
7
8
9
NPCC 1
Pacific Northwest Small Public Power Utility
Comment Group
Steve Alexanderson
Industry Segment
Additional Member Additional Organization Region Segment Selection
1. Russ Noble
Cowlitz PUD
WECC 3, 4, 5
2. Dave Proebstel
Clallam County PUD
WECC 3
3. John Swanson
Benton PUD
WECC 3
4. Steve Grega
Lewis County PUD
WECC 3, 4
4.
Group
Margaret Ryan
Additional Member
PNGC Power
Additional Organization
X
Region Segment Selection
1.
Blachly-Lane Electric Cooperative
WECC 3
2.
Central Electric Cooperative
WECC 3
3.
Clearwater Electric Cooperative
WECC 3
4.
Consumer's Power Company
WECC 3
5.
Coos-Curry Electric Cooperative
WECC 3
6.
Douglas Electric Cooperative
WECC 3
7.
Fall River Electric Cooperative
WECC 3
8.
Lane Electric Cooperative
WECC 3
9.
Lincoln Electric Cooperative
WECC 3
10.
Lost River Electric Cooperative
WECC 3
11.
Northern Lights Electric Cooperative WECC 3
12.
Okanogan Electric Cooperative
WECC 3
13.
Raft River Electric Cooperative
WECC 3
November 17, 2010
X
5
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
14.
Salmon River Electric Cooperative
WECC 3
15.
Umatilla Electric Cooperative
WECC 3
16.
West Oregon Electric Cooperative
WECC 3
17.
PNGC
WECC 8
5.
Group
Dave Davidson
Tennessee Valley Authority
Industry Segment
1
2
3
X
4
5
6
7
8
9
X
Additional Member Additional Organization Region Segment Selection
1. Russell Hardison
TOM Support Manager
SERC
2. Pat Caldwell
TOM Support
SERC
3. David Thompson
GO
SERC
4. Jim Miller
GO
SERC
6.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
BPA, Tx SPC Technical Svcs
WECC 1
2. John Kerr
BPA, Tx Technical Operations
WECC 1
3. Mason Bibles
BPA, Tx Sub Maint and HV Engineering WECC 1
4. Laura Demory
BPA, Tx PSC Technical Svcs
Group
Kenneth D. Brown
X
X
X
X
X
X
X
X
X
X
X
Region Segment Selection
1. Dean Bender
7.
X
WECC 1
Public Service Enterprise Group ("PSEG
Companies")
Additional Member Additional Organization Region Segment Selection
1. Jim Hubertus
PSE&G
2. Scott Slickers
PSEG Power Connecticut NPCC
3. Jim Hebson
PSEG ER&T
ERCOT 5, 6
4. Dave Murray
PSEG Fossil
RFC
8.
Group
Sam Ciccone
November 17, 2010
RFC
1, 3
5
5
FirstEnergy
6
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
4
5
X
X
X
6
7
8
9
Additional Member Additional Organization Region Segment Selection
1. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
2. Jim Kinney
FE
RFC
1
3. K. Dresner
FE
RFC
5
4. B. Duge
FE
RFC
5
5. J. Chmura
FE
RFC
1
6. B. Orians
FE
RFC
5
9.
Group
Terry L. Blackwell
Santee Cooper
X
Additional Member Additional Organization Region Segment Selection
1. S. Tom Abrams
Santee Cooper
SERC
1
2. Rene' Free
Santee Cooper
SERC
1
3. Bridget Coffman
Santee Cooper
SERC
1
10.
Group
Daniel Herring
The Detroit Edison Company
Additional Member Additional Organization Region Segment Selection
1. Dave Szulczewski
11.
Group
Relay Engineering
Sasa Maljukan
RFC
3, 4, 5
Hydro One Networks
X
Additional Member Additional Organization Region Segment Selection
1. Peter FALTAOUS
Hydro One Networks, Inc. NPCC 1
2. David Kiguel
Hydro One Networks, Inc. NPCC 1
3. Paul DIFILIPPO
Hydro One Networks, Inc. NPCC 1
12.
Group
Annette M. Bannon
Additional Member
PPL Supply
Additional Organization
X
Region Segment Selection
1. Mark A. Heimbach
PPL Martins Creek, LLC
RFC
5
2. Joseph V. Kisela
PPL Lower Mount Bethel Energy, LLC RFC
5
November 17, 2010
7
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
3.
PPL Brunner Island, LLC
RFC
5
4.
PPL Montour, LLC
RFC
5
5.
PPL Holtwood, LLC
RFC
5
6.
PPL Wallingford, LLC
NPCC 5
7.
PPL University Park, LLC
RFC
5
8. David L. Gladey
PPL Susquehanna, LLC
RFC
5
9. Thomas E. Lehman PPL Montana, LLC
WECC 5
10. Lloyd R. Brown
PPL Montana, LLC
WECC 5
11. Augustus J. Wilkins PPL Montana, LLC
WECC 5
13.
Group
Richard Kafka
Additional Member
Pepco Holdings, Inc. - Affiliates
Additional Organization
Industry Segment
1
Potomac Electric Power Company RFC
1
2. Carl Kinsley
Delmarva Power & Light
RFC
1
3. Rob Wharton
Delmarva Power & Light
RFC
1
4. Evan Sage
Potomac Electric Power Company RFC
1
5. Carlton Bradsaw
Delmarva Power & Light
RFC
1
6. Jason Parsick
Potomac Electric Power Company RFC
1
7. Walt Blackwell
Potomac Electric Power Company RFC
1
8. John Conlow
Atlantic City Electric
RFC
1
9. Randy Coleman
Delmarva Power & Light
RFC
1
X
X
X
14.
Individual
JT Wood
Southern Company Transmission
X
15.
Individual
Silvia Parada Mitchell
Corporate Compliance
X
Individual
Jana Van Ness, Director
Regulatory Compliance
Arizona Public Service Company
November 17, 2010
3
4
5
6
X
X
X
X
X
X
7
8
9
Region Segment Selection
1. Alvin Depew
16.
2
X
X
8
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
4
5
6
17.
Individual
Tom Schneider
WECC
18.
Individual
Brandy A. Dunn
Western Area Power Administration
X
19.
Individual
Sandra Shaffer
PacifiCorp
X
20.
Individual
John Canavan
NorthWestern Corporation
X
21.
Individual
Dan Roethemeyer
Dynegy Inc.
22.
Individual
Robert Ganley
Long Island Power Authority
X
23.
Individual
Jonathan Appelbaum
The United Illuminating Company
X
24.
Individual
Lauri Dayton
Grant County PUD
X
25.
Individual
Mark Fletcher
Nebraska Public Power District
X
26.
Individual
Brian Evans-Mongeon
Utility Services
27.
Individual
Charles J.Jensen
JEA
X
X
X
28.
Individual
Fred Shelby
MEAG Power
X
X
X
29.
Individual
James A. Ziebarth
Y-W Electric Association, Inc.
30.
Individual
Armin Klusman
CenterPoint Energy
X
31.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
32.
Individual
Edward Davis
Entergy Services
X
X
X
X
33.
Individual
James Sharpe
South Carolina Electric and Gas
X
X
X
X
34.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
35.
Individual
Jeff Nelson
Springfield Utility Board
36.
Individual
Amir Hammad
Constellation Power Generation
37.
Individual
Gerry Schmitt
BGE
X
38.
Individual
Michael R. Lombardi
Northeast Utilities
X
X
X
39.
Individual
Jeff Kukla
Black Hills Power
X
X
X
November 17, 2010
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
9
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
Industry Segment
1
2
3
4
5
40.
Individual
John Bee
Exelon
X
41.
Individual
Andrew Z.Pusztai
American Transmission Company
X
42.
Individual
Thad Ness
American Electric Power
X
43.
Individual
Barb Kedrowski
We Energies
X
X
X
44.
Individual
Jianmei Chai
Consumers Energy Company
X
X
X
45.
Individual
Art Buanno
ReliabilityFirst Corp.
46.
Individual
Tyge Legier
San Diego Gas & Electric
X
X
X
47.
Individual
Greg Rowland
Duke Energy
X
X
X
X
48.
Individual
Claudiu Cadar
GDS Associates
X
49.
Individual
Kirit Shah
Ameren
X
X
X
X
50.
Individual
Joe Knight
Great River Energy
X
X
X
X
51.
Individual
Terry Bowman
Progress Energy Carolinas
X
X
X
X
Group
Joe Spencer - SERC staff
and Phil Winston - PCS
co-chair
SERC Protection and Control Sub-committee
(PCS)
52.
Additional Member
X
X
X
7
8
9
10
X
X
X
Additional Organization
Region Segment Selection
1. Paul Nauert
Ameren Services Co.
SERC
2. Bob Warren
Big Rivers Electric Corp.
SERC
3. Trevor Foster
Calpine Corp.
SERC
4. John (David) Fountain Duke Energy Carolinas
SERC
5. Paul Rupard
East Kentucky Power Coop.
SERC
6. Charles Fink
Entergy
SERC
7. Marc Tunstall
Fayetteville Public Works Commission SERC
8. John Clark
Georgia Power Co
November 17, 2010
X
6
SERC
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
9. Nathan Lovett
Georgia Transmission Corp
SERC
10. Danny Myers
Louisiana Generation, LLC
SERC
11. Ernesto Paon
Municipal Electric Authority of GA
SERC
12. Jay Farrington
PowerSouth Energy Coop.
SERC
13. Jerry Blackley
Progress Energy Carolinas
SERC
14. Joe Spencer
SERC Reliability Corp
SERC
15. Russ Evans
South Carolina Electric and Gas
SERC
16. Bridget Coffman
South Carolina Public Service Authority SERC
17. Phillip Winston
Southern Co. Services Inc.
SERC
18. George Pitts
Tennessee Valley Authority
SERC
19. Rick Purdy
Virginia Electric and Power Co.
SERC
53.
Group
Frank Gaffney
Additional Member
Florida Municipal Power Agency
Additional Organization
Utilities Commission of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority
FRCC
1
3. Jim Howard
Lakeland Electric
FRCC
1
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services
FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority
FRCC
4
Group
Mallory Huggins
Additional Member Additional Organization
X
2
3
4
5
X
X
X
6
7
8
NERC Staff
Region
Segment Selection
1. Joel deJesus
NERC
NA - Not Applicable NA
2. Mike DeLaura
NERC
NA - Not Applicable NA
3. Bob Cummings
NERC
NA - Not Applicable NA
November 17, 2010
1
Region Segment Selection
1. Timothy Beyrle
54.
Industry Segment
11
9
10
Consideration of Comments on PSMTSDT — Project 2007-17
Commenter
Organization
4. David Taylor
NERC
NA - Not Applicable NA
5. Al McMeekin
NERC
NA - Not Applicable NA
6. Earl Shockley
NERC
NA - Not Applicable NA
Industry Segment
1
2
3
4
5
55.
Individual
Terry Harbour
MidAmerican Energy Company
56.
Individual
Scott Berry
Indiana Municipal Power Agency
57.
Individual
Rex Roehl
Indeck Energy Services
X
58.
Individual
Martin Bauer
US Bureau of Reclamation
X
November 17, 2010
6
7
8
X
X
12
9
10
Consideration of Comments on PSMTSDT — Project 2007-17
1. The SDT has made significant changes to the minimum maintenance activities and
maximum allowable intervals within Tables 1a, 1b, and 1c, particularly related to station dc
supply and dc control circuits. Do you agree with these changes? If not, please provide
specific suggestions for improvement.
Summary Consideration: Commenters expressed concerns with virtually all elements of posted Tables
1a, 1b, and 1c. In response to these comments, the Tables have been completely rearranged and
extensively revised. The Tables now consist of one table for each of the five Protection System
component types, as well as a sixth table to address monitoring and alarming requirements to support
extended intervals for monitored Protection System components.
Several entities proposed extending the 3 month interval for unmonitored communication systems, and
the drafting team did not adopt this suggestion because the SDT believes that three-months is necessary
for these inspection-related activities related to communications systems
Organization
Yes or
No
Question 1 Comment
Santee Cooper
No comment.
Xcel Energy
1. The current language is not aligned with the FAQ concerning the level of maintenance
required for Dc Systems, in particular the FAQ states that with only 1 element of the
Table 1b attributes in place the DC Supply can be maintained using the Table 1b
activities, the table itself is clear that ALL of the elements must be present to classify the
DC Supply as applicable to Table 1b. The FAQ needs to be aligned with the tables.
2. The FAQ also contains a duplicate decision tree chart for DC Supply. The FAQ contains
a note on the Decision tree that reads, "Note: Physical inspection of the battery is
required regardless of level of monitoring used", this statement should be placed on the
table itself, and should include the word quarterly to define the inspection period.
November 17, 2010
13
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. The FAQ has been modified.
2. The FAQ has been modified.
Pepco Holdings, Inc. Affiliates
November 17, 2010
1. There were numerous comments submitted for Draft 1 indicating that the 3 month
interval for verifying unmonitored communication systems was much too short. The
SDT declined to change the interval and in their response stated: The 3 month intervals
are for unmonitored equipment and are based on experience of the relaying industry
represented by the SDT, the SPCTF and review of IEEE PSRC work. Relay
communications using power line carrier or leased audio tone circuits are prone to
channel failures and are proven to be less reliable than protective relays. Statistics on
the causes of BES protective system misoperations, however, do not support this
assertion. The PJM Relay Subcommittee has been tracking 230kV and above
protective system misoperations on the PJM system for many years. For the six year
period from 2002 to 2007, the number of protective system misoperations due to
communication system problems were lower (and in many cases significantly lower)
than those caused by defective relays, in every year but one. Similarly, RFC has
conducted an analysis of BES protection system misoperations for 2008 and 2009, and
found the number of misoperations caused by communication system problems to be in
line with the number attributed to relay related problems. If unmonitored protective
relays have a 6 year maximum maintenance/inspection interval, it does not seem
reasonable to require the associated communication system to be inspected 24 times
more frequently, particularly when relay failures are statistically more likely to cause
protective system misoperations. As such, a 12 or 18 calendar month interval for
inspection of unmonitored communication systems would seem to be more appropriate.
FAQ II 6 B states that the concept should be that the entity verify that the
communication equipment...is operable through a cursory inspection and site visit.
However, unlike FSK schemes where channel integrity can easily be verified by the
14
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
presence of a guard signal, ON-OFF carrier schemes would require a check-back or
loop-back test be initiated to verify channel integrity. If the carrier set was not equipped
with this feature, verification would require personnel to be dispatched to each terminal
to perform these manual checks.
2. The phrase “Verify Battery cell-to-cell connection resistance” has entered the table
where it did not exist before. On some types of stationary battery units, this internal
connection is inaccessible. On other types the connections are accessible, but there is
no way to repair them based on a bad reading. And bad cell-to-cell connections within
units will be detected by the other required tests. This requirement will cause entities to
scrap perfectly good batteries just so this test can be performed, with no corresponding
increase in bulk electric system reliability while taking an unnecessary risk to personnel
and the environment.
Response: Thank you for your comments.
1. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
2. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where
available to measure)” to address this comment.
Indeck Energy Services
No
GDS Associates
No
Table 1a. Protective relays
1. For microprocessor relays need guidance in how all the inputs/outputs will be checked
and how is determined which one are “essential to proper functioning of the Protection
System”
2. For microprocessor relays need guidance in how the acceptable measurement is
physically determined.
November 17, 2010
15
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Response: Thank you for comments.
1. The Standard is proscribed from describing “how.” Section 15.3 of the Supplementary Reference provides some guidance, but it is
left to the entity to determine what methods best address their program.
2. The Standard is proscribed from describing “how.” Section 15.3 of the Supplementary Reference provides some guidance, but it is
left to the entity to determine what methods best address their program.
Western Area Power
Administration
No
1) Standard, Table 1a, “Control and trip circuits with electromechanical trip or aux contacts
(except for microprocessor relays, UFLS or UVLS)”: Where would un-monitored control
and trip circuits connected to a microprocessor relay fall, and what is the associated
interval and maintenance activity?
2) Standard, Table 1a, “Control and trip circuits with electromechanical trip or aux contacts
(except for microprocessor relays, UFLS or UVLS)”: Please confirm that the defined
Maintenance Activity requires actual tripping of circuit breakers or interrupting devices.
3) Standard, Table 1a, “Control and trip circuits with unmonitored solid state trip or auxiliary
contacts (except UFLS or UVLS)”: Please confirm that the defined Maintenance Activity
requires actual tripping of circuit breakers or interrupting devices.
4) Standard, Table 1b. On page 13, for Protective Relays, please clarify the intent of
“Conversion of samples to numeric values for measurement calculations by
microprocessor electronics that are also performing self diagnosis and alarming.”
5) Standard, Table 1b. On page 13, for Protective Relays, please clarify the intent of
“Verify correct operation of output actions that used for tripping.” Does this require
functional testing of a microprocessor relay, i.e., using a relay test set to simulate a fault
condition?
6) Standard, Tables 1a and 1b: Would it be possible to provide an interval credit for full
parallel redundancy from relay to trip coil?
7) Table 1a (page 9) Voltage and Current Sensing Inputs to Protective Relays and
November 17, 2010
16
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
associated circuitry – This maintenance activity statement implies that signal tests to
prove the voltage and current are present is all that is required. Can this be accomplished
by adding a step to the Relay Maintenance Job Plan to take a snapshot of the currents
and potentials (In-Service Read) with piece of test equipment?
8) Table 1b (Page 14) Control and Trip Circuitry - Level 2 Monitoring Attributes for
Component is too wordy and hard to understand the meaning. Does this whole paragraph
mean that the dc circuits need to be monitored and alarmed? At what level does the dc
control circuits need the alarming? Can this be at the control panel dc breaker output?
9) Table 1b (Page 15) Station Dc Supply - Should this be in Table 1c because the attributes
indicate that the station dc supply cells and electrolyte levels are monitored remotely. To
do a fully monitored battery system would be cost prohibitive and require a tremendous
amount of engineering.
10) Voltage and Current Sensing Inputs to Protective Relays and associated circuitry - This
maintenance activity statement implies that signal tests to prove the voltage and current
are present is all that is required. Can this be accomplished by adding a step to the Relay
Maintenance Job Plan to take a snapshot of the currents and potentials (In-Service Read)
with piece of test equipment?
11) Table 1a and 1b (Page 11 and 16) Associated communications system - Western has
monitoring capability on all Microwave Radio and Fiber Optics communications systems
with the Communications Alarm System that monitors and annunciates trouble with all
communications equipment in the communications network. The protective relays that
use a communications channel on these systems have alarm capability to the remote
terminal units in the substation. Since these are digital channels how does an entity prove
channel performance on a digital system?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see the new Table 1-5.
November 17, 2010
17
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
2. The Standard requires that breakers (except for those for UFLS/UVLS) be tripped at least once during each 6 calendar year
interval. See new Table 1-5.
3. The Standard requires that breakers (except for those for UFLS/UVLS) be tripped at least once during each 6 calendar year
interval. See new Table 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
6. No. The SDT believes that it is important that all parallel paths be maintained within the indicated interval, and the prescribed
interval already considers the reliability benefits of parallel tripping paths.
7. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. It may be possible to do
as suggested in some cases; a snapshot may be able to determine that voltage and current is present at the relay. However, the
snapshot may not be sufficient to determine that the values are acceptable.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
10. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. It may be possible to do
as suggested in some cases; a snapshot may be able to determine that voltage and current is present at the relay. However, the
snapshot may not be sufficient to determine that the values are acceptable.
11. Many digital communications systems or digital relays themselves use bit-error-rate or other methods to monitor and alarm on
channel performance – check the design of the equipment used.
Southern Company
Transmission
November 17, 2010
No
1) Comment on Control Circuitry - Below in Figure 1 is a previous version of Table 1. It
clearly shows 3 levels of monitoring for Control Circuitry. For Unmonitored schemes such
as EM, SS, unmonitored MP relays, you must do a complete functional trip test every 6
years. For partially monitored schemes such as MP relays with continuous trip coil/circuit
monitoring, you must do a complete functional trip test every 12 years. For fully
monitored schemes where all trip paths are monitored, you do not have to trip test the
scheme but you still have to operate the breaker trip coils, EM aux/lockout relays every 6
18
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
years. This is very clear and reasonable. The latest version of Table 1 is not very clear
or reasonable. The previous Partially Monitored control circuit monitoring requirements
were deleted and the Fully Monitored control circuit monitoring requirements were moved
to Partially Monitored requirements. We are not sure why this major change in
philosophy was made?? This makes all of our MP relay control schemes that
continuously monitor trip coils/circuits fall into the unmonitored category and therefore
requires a 6 year full functional trip test. For a scheme that monitors 99+% of the control
scheme (and probably 100% of the control scheme that actually has problems) to be
considered Unmonitored does not seem logical or reasonable to us. This puts these
“highly monitored” schemes in the same category and requires the same maintenance
requirements / intervals as EM relays with no alarms whatsoever. This also seems to
contradict the intent of the following statement from the Supplementary Reference doc on
page 9: Level 2 Monitoring (Partially Monitored) Table 1b This table applies to
microprocessor relays and other associated Protection System components whose selfmonitoring alarms are transmitted to a location (at least daily) where action can be taken
for alarmed failures. The attributes of the monitoring system must meet the requirements
specified in the header of the Table 1b. Given these advanced monitoring capabilities, it
is known that there are specific and routine testing functions occurring within the device.
Because of this ongoing monitoring hands-on action is required less often because
routine testing is automated. However, there is now an additional task that must be
accomplished during the hands-on process - the monitoring and alarming functions must
be shown to work. Recommendation - Please consider going back to the previous table
as shown below in Figure 1. It seems much clearer and reasonable. Feel free to convert
the old wording to the latest wording. Figure 1 - Previous Table - Control Circuitry See
Figure 1 in email documentation sent to Al McMeekin. Current Table - Control Circuitry
(see pdf file) See pdf file PRC-005-2_clean_20 10June88131418.pdf in email
documentation sent to Al McMeekin.
2) Comments: The comments below are grouped by component type. The following (5)
comments pertain to the maintenance intervals for protective relays:
November 17, 2010
19
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
a. Is the “verify acceptable measurement of power system input values” activity listed in
the protective relay 6 year interval in Table 1a the same activity as the 12-year activity
for Voltage and Current Sensing Inputs in the same table?
b. Please clarify the meaning of “check the relay inputs and outputs” that are specified to
be checked for microprocessor relays at the following table locations: the protective
relay 6 year interval in Table 1a, the protective relay 12-year interval in Table 1b. Is this
referring to a check of the relay internal input recognition and output control ending at
the relay case terminals, or is this referring to a check extending to the source (and
target) of all inputs and outputs to the relay? The latter interpretation results in a repeat
of the maintenance required for dc control circuitry.
c. Are the second, third, and fourth maintenance activities in the Table 1a Protective
Relay, 6-year row those activities that apply to microprocessor relays? If so, we
suggest rewording these items as follows: For microprocessor relays, verify that the
settings are as specified, check the relay digital inputs and outputs that are essential to
proper functioning of the Protection System, and verify acceptable measurement of
power system analog input values.”
d. Please clarify the meaning of “Verify proper functioning of the relay trip contacts” found
in protective relays with trip contacts 12 year interval in Table 1c. Is this verification a
check of the relay internal contact to the relay case terminals or is this meant to be a trip
check functional test? This category of component does not appear in table 1a or 1b.
Should it? Is this activity the same as the protective relay Table 1b maintenance activity
“output actions used for tripping”? If so, please make the wording match exactly to
clarify.
e. Table 1c introduces the use of “Continuous” Maximum Maintenance Intervals. This is
inconsistent with the Table 1a and Table 1b usage of the interval. In Tables 1a and 1b
this interval is used to describe the maximum time frame within which the activities
shown in “Maintenance Activities” must be completed. The table column “Maintenance
Activities” has been used to identify those activities which must be performed in addition
November 17, 2010
20
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
to those accomplished by the monitoring attributes. To maintain consistency in use of
the interval and activity columns of Tables 1a, 1b, and 1c, each entry that uses the
“Continuous” interval should be changed to N/A and the Maintenance Activities should
be changed to either “No additional activities required” or “None, due to continuous
automatic verification of the status of the relays and alarming on change of settings”
[example given for Table 1c, Protective Relays]
3) The following (8) comments apply to Maintenance Tables 1a, 1b, and 1c for Station DC
supplies.
a. In Table 1a, Station dc supply, 18 calendar month, the verify item “Float voltage of
battery charger” is not listed in Table 1b. Is this requirement independent of the level of
monitoring and always required? If so, should it be added in to Table 1b and 1c, Station
dc supply, 18 calendar months above the “Inspect:” section?
b. The 6 year interval maintenance activity for NiCad batteries in Table 1a and Table 1b
should read “station battery” rather than “substation battery”.
c. It is recommended to simplify the Station dc supply sections in each of the three
maintenance tables by relocating the common items that do not change dependent
upon the level of monitoring. Specifically, the following rows of each of the three tables
have identical maintenance requirements that are independent of the level of
monitoring. The tables would be significantly simplified if these “monitor level
independent” requirements are moved outside of the table:
I. Station dc supply; 18 calendar months; Inspect: “
II. Station dc supply (that has a s a component Valve Regulated Lead Acid batteries)
III. Station dc supply (that has as a component Vented Lead Acid batteries)
IV. Station dc supply (that has as a component Nickel Cadmium batteries)
V. Station dc supply (battery is not used)
November 17, 2010
21
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
d. Table 1a has 18 calendar month requirements for “Station dc supply (battery is not
used)”. This category is missing from Table 1b - was this intentional?
e. Table 1a has 6 calendar year and 18 calendar month requirements for “Station dc
supply (battery is not used)”. This category is missing from Table 1c - was this
intentional?
f. Please clarify the meaning of “Battery terminal connection resistance”. Does this apply
only to multi-terminal batteries? Is this referring to the cables external to the battery (to
the charger and load panel)?
g. Table 1c contains a Type of Protection System Component not found in any of the
other tables: “Station dc supply (any battery technology). Is this the same as “Station
dc supply” found in Tables 1a and 1b?
h. The Level 3 Monitoring Attributes for “Station dc supply (any battery technology)” are
identical to the Level 2 Monitoring Attributes for “Station dc supply”. This appears to be
duplicative in description with two different “maximum maintenance intervals” and
“maintenance activities” listed.
4) The following (3) comments pertain to the Voltage and Current Sensing Input component
type:
a. Why is “signals” bolded in the Table 1a row for this component type?
b. Are the Table 1a, 12 year maintenance activities for this component type a
duplication of the Table 1a, Protective relay, 6 year maintenance activity for
microprocessor relays (verify acceptable measurement of power system input
values)?
c. Why is this component type highlighted in bold in Table 1c?
5) The following (8) comments pertain to the Control and Trip Circuit component type:
a. Why are microprocessor relay initiated tripping schemes excluded from the 6 year
November 17, 2010
22
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
complete functional testing? The auxiliary relay operations resulting from these
initiating devices are just as likely to stick (mis-operate) as those initiated from
electromechanical devices.
b. We propose simplifying Table 1a for this component type by grouping the two 6 year
and the two 12 year interval maintenance lines into two rather than four table rows.
The 6 year interval maintenance activities for the UFLS/UVLS systems could be
addressed in the table row above using a parenthetical adder to the existing text = (for
UFLS/UVLS systems, the verification does not require actual tripping of circuit breakers
or interrupting devices). All of the other text in the UFLS/UVLS table row matches that
found two rows above. The same parenthetical adder in the first 12 year interval row
for this component type would eliminate the need for the (UFLS/UVLS Systems Only)
row for 12 year intervals.
c. If the two rows are combined as suggested previously - this comment is irrelevant:
The Table 1a 6 year interval activity for UFLS/UVLS Systems Only is missing the word
“contacts” after auxiliary.
d. There appears to be no difference in the 6 year interval maintenance activities for this
component type in Table 1a and Table 1b. Table 1b monitoring attributes include
“Monitoring and alarming of continuity of trip circuits”, but the interval between
electrically operating each breaker trip coil, auxiliary relay, and lockout relay remains at
6 years. What maintenance activity advantage do the Level 1b monitoring attributes
provide?
e. The difference between the two DC Control Circuits in Table 1b (on page 14) is
unclear. What is the difference between the “Control Circuitry (Trip Circuits)” and the
“Control and trip circuitry”? We propose combing the multiple table rows for this
component type into a single line item for this component type, as it takes a
combination of the protective relay action, any auxiliary relay, and the circuit breaker to
comprise a complete tripping system.
f. We have three questions on the monitoring attributes given for this component type on
November 17, 2010
23
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
page 14:
I. Does the attribute beginning “Monitoring of Protection ...” indicate a requirement to
monitor every input, every output, and every connection of every Protection System
Component involved in each tripping scheme?
II. Does the attribute beginning “Connection paths...” related to monitoring of
communication paths?
III. Does the attribute beginning “Monitoring of the continuity...” require the presence of
coil monitoring of any auxiliary relay whose contact is encountered when tracing a
tripping path from a protective relay to a breaker?
g. Are the Table 1c attributes for this component type different from the monitoring
described in Table 1b beginning “Connection paths...”?
h. Are there no requirements to operate any relays functionally for “Protection System
control and trip circuitry” in Table 1c? The devices need to be exercised some or they
will not be reliable.
6) The following (1) comment pertains to the Associated communications system
component type:
The Table 1b monitoring attribute for this component type (communications channel
monitor and alarm) clearly should (and does) eliminate the Table 1a, 3 month interval
activity (verifying the communication system is functional). The common maintenance
activities found in Table 1a (6 year) and Table 1b (12 year) should be same interval - either
6 or 12.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1 for all five of these
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Yes or
No
Question 1 Comment
comments.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4 for all eight of these
comments.
3f. Please see IEEE 450-2002 Appendix F, IEEE 1188-2005 Appendix D, and Section 6.3.2 of IEEE 1106-2005 for clarification of the
meaning of “battery terminal connection resistance”.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3 for all three of these
comments.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5 for all eight of these
comments.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-2 for this comment.
Consumers Energy
Company
No
1. If multiple redundant Protection System components, with associated parallel tripping
paths, are provided, Table 1a, 1b, and 1c require that each parallel path be maintained,
and that the maintenance be documented. Often, these multiple schemes are provided
not to meet specific reliability-related requirements, but instead to provide operating
flexibility. Testing these likely will require outages, and those outages may result in
decreased reliability. Further, the documentation related to maintenance of all paths will
be very cumbersome, and will lead to increased compliance exposure simply by its
volume. This may perversely lead to entities NOT installing the redundant schemes,
resulting in decreased reliability.
2. Many of the activities described in the Tables are not, by themselves, clear. The
standard should include sufficient detail such that entities are clear as to what must be
done for compliance, rather that relying on supplementary documents for this information.
For example, it’s not clear, in Table 1a (Station DC Supply), what is meant by, “Verify that
the dc supply can perform as designed when the ac power from the grid is not present.”
Similarly, it isn’t clear from the general description within the Tables that components
possessing different monitoring attributes within a single scheme, may be distinguished
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Question 1 Comment
such that differing relevant tables can be used for the separate components.
3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station
battery can perform as designed by evaluating the measured cell/unit internal ohmic
values to station battery baseline. Battery assemblies supplied by some manufacturers
have the connections made internally, making this option unavailable. Experience with
ASME standards show that NERC and SDT members may be jointly and separately
liable for litigation by specifying methods that either prefer or prohibit use of certain
technologies.
4. Two of the four Maintenance Activities that begin with “Perform a complete functional
trip ...” conclude with “... does not require actual tripping of circuit breakers or other
interrupting devices. Do the other two such activities therefore require tripping of circuit
breakers or other interrupting devices?
5. Performance of the minimum activities specified within Table 1a for legacy systems,
particularly regarding control circuits, will require considerable disconnection and
reconnection of portions of the circuits. Such activities will likely cause far more problems
on restoration-to-service than they will locate and correct. We suggest that the SDT
reconsider these activities with regard for this concern.
Response: Thank you for your comments.
1. The SDT believes that it is important that all parallel paths be maintained within the indicated interval, and the prescribed interval
already considers the reliability benefits of parallel tripping paths.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. The use of the term “cell/unit” acknowledges that individual cells may not be accessible, but that assemblies of several cells (into
units) may be available instead, and may be used to address this Requirement. An acceptable base-line value and follow-on tests
may be acceptable for the entire station battery as a single unit.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
November 17, 2010
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Yes or
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Question 1 Comment
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. To the degree that
performance history for the components within these systems is available, a performance-based program per Requirement R3 and
Attachment A may be useful in these cases.
JEA
No
1. R1.1 What is a Protection System component? Could the SDT provide a better
understanding of what is meant by component?
2. R4: A “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
3. R4: Suggest a stepped VSL for “Entity has failed to initiate resolution of maintenancecorrectable issues”. While we understand the importance of addressing a correctable
issue, it seems like there should be some allowance for an isolated unintentional failure to
address a correctable issue.
Response: Thank you for your comments.
1. A definition of “Component” has been added to the draft Standard. The SDT’s intent is that this definition will be used only in PRC005-2, and thus will remain with the Standard when approved, rather than being relocated to the Glossary of Terms.
2. This comment appears to be related to the VSL for Requirement R1, not Requirement R4 as indicated. The SDT disagrees that this
is a “documentation” issue, and believes that that the related Requirement is fundamental to establishing an effective PSMP per this
Standard. Also, this VSL is graded such that missing up to 5% of the required activity is indeed a Lower VSL.
3. The VSL for Requirement R4 has been modified as suggested.
Entergy Services
November 17, 2010
No
1. Table 1a has a “Control and trip circuits with electromechanical trip or auxiliary contacts
(except for microprocessor relays, UFLS or UVLS)” component type listed, and there is a
“Control and trip circuits with electromechanical trip or auxiliary [editorial comment: add
‘contacts’] (UFLS/UVLS systems only)” component type listed. Suggest a “Control and
trip circuits with electromechanical trip or auxiliary contacts” for a microprocessor relay
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No
Question 1 Comment
application should be addressed since it seems to be missing.
2. The term “check” has replaced “verify” for some of the maintenance activities in this draft
version. What is the difference between these two terms, and shouldn’t “check” be
defined if it is to be included as a PSMP activity term?
3. Assuming the term “check” replaced “verify proper functioning” in order to allow for the
completion of a maintenance activity within the required interval and yet account for a
maintenance correctable issue being present, suggest the other remaining activities in
the tables where the term “verify proper functioning” is used, also be replaced with
“check”.
4. Consider modifying the definition of “verification” to “A means of determining or checking
that the component is functioning properly or maintenance correctable issues are
identified”, eliminate use of the term “verify proper functioning” (which seems to be
redundant by PRC-005-2 standard definition), and simply use the term “verify”.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. “Check” is not an element of the PSMP definition. This term has been replaced throughout the tables with whatever term of the
definition is relevant.
3. “Check” is not an element of the PSMP definition. This term has been replaced throughout the tables with whatever term of the
definition is relevant.
4. The terms within the PSMP definition have been revised to reflect the action (“verify” rather than “verification,” for example). The
SDT believes that the use of the term “verify” within the modified tables and the definition of this component in the PSMP definition
is appropriate and correct.
MEAG Power
November 17, 2010
No
1. The descriptions for the "type of protection system components" do not appear to be
consistent between Tables, 1a, 1b and 1c.
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2. The maximum maintenance interval for a lead-acid vented battery is listed at 6 calendar
years for performing a capacity test. This type of test has been proven to reduce battery
life and an interval of 10 to 12 years would be better.
3. The maximum maintenance interval for "Station DC supply" was set at 3 months. This is
too short of a period and 6 months would be better.
4. The control and trip circuits associated with UVLS and UFLS do not require tripping of
the breakers but all other protection systems require tripping of the breakers, this appears
to be inconsistent?
5. Digital relays have electromagnetic output relays. Do they fall into the electromechanical
trip or solid state trip?
6. Need for clarification: The standard indicates that only voltage and current signals need
to be verified. Does this mean that voltage and current transformers do not need to be
tested by applying a primary signal and verifying the secondary output?
Response: Thank you for your comment.
1. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
2. The SDT disagrees, and believes that a capacity test at 6-year levels is appropiate. A properly maintained battery, according to
various credible references (from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle multiple deep discharges over its
expected life.
3. The activity related to this interval is to verify various basic operating parameters. The SDT believes that extension of verification of
these parameters beyond the interval within the Standard is inappropriate.
4. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the Standard,
because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system elements.
5. These devices fall under “electromechanical output contacts.” The Tables have been rearranged and considerably revised to
improve clarity. Please see new Table 1-1.
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Question 1 Comment
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
Ameren
No
Ameren does agree that draft 2 is a considerable improvement from draft 1 of PRC-005-2;
however the following still need to be addressed.
1) Use “Control circuitry” to be consistent with the proposed definition. If ‘and trip’ was
included so that users would know this is a trip circuit, then the definition should use ‘Trip
circuitry’ instead of ‘Control circuitry’. It is important to use consistent terminology
throughout the definition and the standard.
2) Please add row numbers in each of Tables 1a, 1b, and 1c, and arrange so that row 1 in
each table corresponds, etc. (or state which rows correspond to each other.) This would
help clarify movement from table to table. The number of sub clauses, nuances, and
varied Type of Component descriptors among rows in the same table as well as from
table-to-table can be overwhelming. This would help keep Regional Entities and System
Owners from making errors.
3) Please clarify that the instrument transformer itself is excluded. The standard indicates
that only voltage and current signals need to be verified. The FAQ seems to cover this,
but see our comments on your question 6.
4) Clarifications need to be made on testing requirements on trip contacts relative to
microprocessor vs. EM relays. Digital relays have electromagnetic output relays. Do they
fall into the electromechanical trip or solid state trip?
5) There appears to be an inconsistency in the use of “check” vs. “verify” in the tables.
Consider modifying the definition of “verification” to “A means of determining or checking
that the component is functioning properly or that the maintenance correctable issues are
identified”, eliminate use of the term “verify proper functioning” (which seems to be
redundant by PRC-005-2 standard definition), and simply use the term “verify”.
6) Alternately if the term “check” replaced “verify proper functioning” in order to allow for the
completion of a maintenance activity within the required interval and yet account for an
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Question 1 Comment
outstanding maintenance correctable issue being present, suggest the other remaining
activities in the tables where the term “verify proper functioning” is used, also be replaced
with “check”.
7) If there is an intentional difference between “verify” and “check”, shouldn’t “check” be
defined if it is to be included as a PSMP activity term?
8) Functional trip testing will require extensive analysis and could involve an extensive
testing evolution to ensure the correct circuit is tested without unexpected trip of other
components, particularly for generator protection systems and some transmission
configurations. The complexity of the system and the test would be conducive to an error
that resulted in excessive tripping, thus affecting the reliability of the BES. It would seem
that the potential for an adverse affect from this test would be greater than the benefit
gained of testing the circuit. In addition, scheduling outages to perform the functional trip
testing in conjunction with other outages required to perform maintenance and other
construction activities will be difficult due to the large number of outage requirements for
the functional testing. This will challenge the BES more often and thus reduce reliability.
For these reasons functional trip testing is too frequent, and should be extended to twelve
years.
9) In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now. Many
batteries are packaged such that the individual cells are not accessible.
10) IEEE battery maintenance standards call for quarterly inspections. These are targets,
though, not maximums. An entity wishing to avoid non-compliance for an interval that
might extend past three calendar months due to storms and outages must set a target
interval of two months thereby increasing the number of inspections each year by half
again. This is unnecessarily frequent. We suggest changing the maximum interval for
battery inspections to 4 calendar months. For consistency, we also suggest that all
intervals expressed as 3 calendar months be changed to 4 calendar months.
11) Replace “State of charge of the individual battery cells/units” with “Voltage of the
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Question 1 Comment
individual battery cells or units”.
12) The maximum maintenance interval for a lead-acid vented battery is listed at 6 calendar
years for performing a capacity test. This type of test has been proven to reduce battery
life and an interval of 10 to 12 years would be better.
13) The level 2 table regarding Protection Station dc supply states that level 1 maintenance
activities are to be used, but then goes on to give a list of Maintenance Activities that
don’t match those in level 1. Which activities shall we use? Same situation for Station DC
Supply (battery is not used) where the 18 month interval is missing.
14) Also, Table 1B, in the second to last row, should be referring to UFLS rather than SPS.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
3. The definition has been modified to clarify that instrument transformers ARE part of the Protection System, and the maintenance
activities in the new Table 1-3 specify WHAT must be done regarding this component type. The FAQ (II.3.A) is correct on this
subject.
4. The Tables have been rearranged and considerably revised to improve clarity. These devices fall under “electromechanical output
contacts.” The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
5. “Check” is not an element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the
definition is relevant. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
6. “Check” is not an element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the
definition is relevant. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
7. “Check” is not an element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the
definition is relevant.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
November 17, 2010
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9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This element of the table
has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to
address this comment.
10. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. The Requirement
remains as “3 Calendar Months” and the SDT is not prescribing or suggesting what measures an entity may take within their
program to assure compliance.
11. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. Verification of voltage
of individual cells, etc., is one method; there are other ways.
12. The SDT disagrees, and believes that a capacity test at 6-year intervals is appropiate for Vented Lead Acid and Ni-Cad batteries.
A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI, various manufacturers, etc.), can
easily handle multiple deep discharges over its expected life.
13. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
14. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-5.
American Transmission
Company
November 17, 2010
No
ATC feels additional changes are needed.
1. The functional testing requirement should be altered or removed as it increases the
amount of hands-on involvement and the opportunity for human error related outages to
occur, thereby introducing more opportunities to decrease system reliability. As noted
on p. 8 in the supplementary reference document, “Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.”
By removing circuits from service on the proposed timelines for functional testing, the
chance for human error is greater than a mis-operation from faulty wiring. Alternatively,
entities may choose to schedule more planned outages to conduct their functional
testing in order to limit the risk of unplanned outages resulting from human error. Under
this scenario, more elements will be scheduled out of service on a regular basis, thereby
reducing transmission system availability and weakening the system making it more
challenging to withstand each subsequent contingency (N-1). Thus testing an in-tact
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Question 1 Comment
system is more desirable than taking it out of service for testing.
2. While the SDT has included language in the draft standard to use fault analysis to
complete maintenance obligations, in practicality, this option does not offer any relief to
taking outages to perform functional tests. Nearly all BES circuit breakers are equipped
with dual trip coils. Identifying which trip coil operated for a fault only covers the one trip
coil. Functional tests would still be needed on the other. The likelihood of having
multiple trips on a given line in the course of several years is very low. Given it can take
a year to schedule some outages, planning maintenance with random faults is
unpractical and will create unacceptable risk to compliance violations. A better
approach is to use the basis in schedule A, but extend this to cover the entire protection
schemes. The document should establish target goals for mis-operation rates
(dependability and security). This would allow the utilities to develop cost effective
programs to increase reliability. The utilities would have incentives to replace poorly
performing communications systems; they would be able to quantify the value of
upgrading relay systems.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. Operational results, if desired by an entity, MAY be used to meet maintenance requirements to the degree that they verify, etc., the
relevant performance. Whether their use is effective for a specific entity is left to the entity to determine. “Maintenance correctable
issues,” which may result in part from misoperations, are a part of using Attachment A to develop a Performance Based PSMP.
Corporate Compliance
No
Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s
lead-calcium batteries are relatively stable for a 6 month period compared to lead-antimony
batteries used in the past.
Response: Thank you for your comments. The activity related to this interval is to verify various basic operating parameters. The SDT
believes that extension of verification of these parameters beyond the interval within the Standard is inappropriate.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Northeast Power
Coordinating Council
Yes or
No
No
Question 1 Comment
1. Clarification is needed for “to a location where action can be taken”. Some examples in
the FAQ will help in this clarification.
2. What type of documentation is required to show compliance that maintenance
correctable issue has been reported?
3. Clarify the removal of requirement (see redline version, third row of Table 1a) for testing
of unmonitored breaker trip coils. Is it the intention of the SDT to remove a requirement
that would drive the industry to install TC monitors on breakers to improve reliability?
4. UFLS/UVLS DC control and trip circuits (Rows 5 and 6 of Table 1a) - Due to the
distributed nature of this program, random failures to trip are not impactive to the overall
operation of the UFLS protection. There should be no requirement to check the DC
portion of these protections any more often than the DC circuit checks associated with
that LV breaker. Since it is clear the requirement does not include the need to trip the
breakers why the need to check the trip paths? Deletion of this requirement leaves the
requirement to check only the relays and relay trip outputs from the protections every 6
years (or as often as the protective relay component type). Should the maintenance
activities for “UVLS and UFLS relays that comprise a protection scheme distributed over
the power system” not be the same as “Protective Relays”? V and I sensing to relays
have a 12 year Maximum Maintenance Interval listed. It is good work practice to have
this activity done the same time as maintenance activities associated with relay
maintenance.
5. What is the basis for the various Maximum Maintenance Intervals listed in Table 1a?
6. From page 12 of the redline version, for "Station dc Supply (used only for UFLS and
UVLS)", is the requirement applicable to distribution substations only?
7. For “Control and trip circuits with unmonitored solid-state trip or auxiliary contacts
(UFLS/UVLS Systems only)” under Maintenance Activities - the word “complete: may be
removed as it requires to actually trip the breakers. The sentence that tripping of the
circuit breakers is not required contradicts with the word “complete”. More specifics are
November 17, 2010
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Question 1 Comment
required to spell out the adequate testing e.g. up to the lockout with the trip paths
isolated etc. See Page 12 of the redline version.
8. For “Station dc Supply” having 18 calendar months as the Maximum Maintenance
Interval, a battery has a 20 year life. IEEE standard PM is on a quarterly basis. What is
the basis of the 18 calendar month interval? See page 12 of the redline version.
9. For “Associated communications systems” with a Maximum Maintenance Interval of 6
Calendar years, why is this required? The text "Verify proper functioning of
communications equipment inputs and outputs that are essential to proper functioning
of the Protection System. Verify the signals to/from the associated protective relay(s)"
seems sufficient to ensure reliability. See page 15 of the redline version.
10. For “Relay sensing for Centralized UFLS or UVLS systems UVLS and UFLS relays that
comprise a protection scheme distributed over the power system” under maintenance
activities, clarify “overlapping segments”. What is the specified interval? Is actual
breaker tripping required? See page 15 of the redline version.
11. On the row for Associated communications systems in Table 1c, in the Level 3
Monitoring Attributes for Component column, suggest a change in wording to:
Evaluating the performance and quality of the channel as well as the performance of
any interface to connected protective relays and alarming if the channel/protective relay
connections do not meet performance criteria.
12. In Table 1c it is required to report the detected maintenance correctable issues within 1
hour or less to a location where action can be taken to initiate resolution of that issue.
Even for a fully monitored protection system component it can be difficult to report the
action in 1 hour. A 24 hour period for both Level 2 and Level 3 reporting of maintenance
correctable issues is recommended.
Response: Thank you for your comments.
1. This is addressed in the Supplementary Reference document as posted with this draft (Section 8.1 and Section 13), and within the
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Question 1 Comment
FAQ as posted with this draft Standard (V.3.D).
2. Specific effective forms of documentation are left to the entity to determine, but the SDT believes that this could include, among
other things, work orders addressing the maintenance correctable issue.
3. The Tables have been rearranged and considerably revised to simplify and improve clarity. Please see new Table 1-5. Specifically
to your comment, the SDT initially specified inspection of trip-coil monitoring functions at intervals of 3 months, with tripping
otherwise requried annually. This has been revised to simply require tripping at 6-calendar-month intervals.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
5. Please see Supplementary Reference, Section 8.3.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. Specifically for this item,
this applies to whatever interrupting device is being tripped by the UFLS/UVLS. To the degree that the same interrupting devices
are tripped by other Protection System components, the relevant Requirements apply.
7. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
8. This interval is based on EPRI and other industry documents referencing these specific activities.
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
10. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
11. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
12. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 2. This requirement is now
uniformly 24 hours as suggested within the comment.
SERC Protection and
Control Sub-committee
(PCS)
No
1. Clarifications need to be made on testing requirements on trip contacts relative to
microprocessor vs. EM relays. There appears to be an inconsistency in the use of
“check” vs. “verify” in the tables.
2. Also, Table 1B, in the second to last row, should be referring to UFLS rather than SPS.
3. Also, note that M2 incorrectly excludes distribution provider.
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Question 1 Comment
4. In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. Measure M2 has been corrected as suggested.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
BGE
No
Comment 1.1: In its decision to use “calendar years” with the maintenance intervals
prescribed for most components the SDT has provided a framework that is consistent
with a well-run PSMP but with enough flexibility to be practical. However BGE believes
the application of this approach to short maintenance intervals, like three months for
some battery maintenance will risk numerous violations due to practical scheduling
constraints that are not a realistic threat to reliability. As the requirements are presently
defined the inherent flexibility for battery maintenance that is nominally done on three
month intervals may be as long as 1/3 of the interval or as short as one day (Our
interpretation: Maintenance last done on January 1 is next due on April 1 and can be
done no later than April 30. Maintenance done on Jan 31 is next due on April 30 and is
overdue if done on May 1). The only practical solution is to increase the frequency so that
the average intervals are significantly shorter than the nominal requirement.BGE
recommends an alternate formulation for intervals if the nominal interval is less than one
year. Some possible alternatives (assuming a three month nominal interval): Once per
calendar quarter no later than the end of the quarter no earlier than one month before it.
Four times per year, no more than 120 days apart no less than 60.
Comment 1.2: On page 11, Row-3/Column-1 of Table-1a includes the following entry for
functional trip testing:"Control and trip circuits with electromechanical trip or auxiliary
contacts (except for microprocessor relays, UFLS or UVLS)". It is not clear why
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Question 1 Comment
electromechanical trip contacts in microprocessor relays are excluded.
Comment 1.3: On page 12, Row-3/Column-3 of Table-1a includes the following Verification
Task for Station DC Supplies: "Verify Battery cell-to-cell connection resistance". Multiple
cell units do not provide the ability to measure cell-cell resistance.
Response: Thank you for your comments.
1. The intervals remain as prescribed within the Standard and are designed to be effective, clear, and consistently monitored for
compliance; the SDT is not prescribing or suggesting what measures an entity may take within their program to assure compliance.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where
available to measure)” to address this comment.
Constellation Power
Generation
No
1. Constellation Power Generation (CPG) does not agree with the maximum maintenance
interval for associated communication systems and station dc supply that has as a
component any type of battery, which is 3 months. If the intent of the drafting team was to
make this test quarterly (as recommended in IEEE-450), than the maximum interval
should be 4 months. As written, for a registered entity to ensure they complete this test in
an interval less than 3 months, they will most likely complete this test every 2 months.
This causes two additional and unwarranted tests every year. CPG recommends an
alternate formulation for intervals if the nominal interval is less than one year. Some
possible alternatives (assuming a three month nominal interval):
Once per calendar quarter no later than the end of the quarter no earlier than one month
before it.
Four times per year, no more than 120 days apart no less than 60.
2. CPG does not agree with differentiating between the different battery types. A
suggestion would be to take the maximum maintenance interval for all the battery types,
which is 6 years, and apply them across all types of batteries, eliminating the need to
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Question 1 Comment
differentiate between them. Furthermore, multiple cell units do not provide the ability to
measure cell-cell resistance, and so that requirement should be removed.
3. CPG is not clear why electromechanical trip contacts in microprocessor relays are
excluded in Table 1a.
Response: Thank you for your comments.
1. The intervals remain as prescribed within the Standard and are designed to be effective, clear, and consistently monitored for
compliance; the SDT is not prescribing or suggesting what measures an entity may take within their program to assure compliance.
2. The appropriate maintenance activities and intervals differ considerably for various battery types. This element of the table has
been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to address
this comment.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
Exelon
No
Exelon does not completely agree with the minimum maintenance activities and maximum
allowable intervals as suggested by SDT. Comments on minimum maintenance activities:
1. Reference Table 1a (Page 11) of Standard PRC-005-2: With regard to the maintenance
activity: "Verify that the station battery can perform as designed by conducting a
performance ......". The standard should clearly define what is meant by "perform as
designed" to eliminate ambiguity in future interpretations.
2. Also, Table 1a Station dc supply (that has as a component Vented Regulated Lead-Acid
batteries) discusses “modified performance capacity test of the entire battery bank”.
This needs additional clarification or should be reworded because modified test includes
both the performance test (which is the capacity test) and the service test. Should be
reworded to be “modified performance test”.
3. Comments on maximum allowable intervals:
Nuclear generating stations have refueling outage schedule windows of approximately
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18 months or 24 months (based on reactor type). If for some reason the schedule
window shifts by even a few days, an issue of potential non-compliance could occur for
scheduled outage-required tasks. The possibility exists that a nuclear generator may
be faced with a potential forced maintenance outage in order to maintain compliance
with the proposed standard. For the requirements with a maximum allowable interval
that vary from months to years (including 18 Months surveillance activities), the SDT
should consider an allowance for NRC-licensed generating units to default to existing
Operating License Technical Specification Surveillance Requirements if there is a
maintenance interval that would force shutting down a unit prematurely or face noncompliance with a PRC-005 required interval. Therefore, Tables 1a, 1b & 1c should
include an allowance for any equipment specifically controlled within each licensee’s
plant specific Technical Specifications to implement existing Operating License
requirements if such a conflict were to occur. Please see additional comments under
Q7.
Response: Thank you for your comments.
1. This concern is addressed within IEEE standards (specifically IEEE 450, IEEE 1188, and IEEE 1106) by their description and
definition of a “performance test” as further established within this requirement. The SDT believes that entities involved in battery
maintenance will be familiar with these IEEE standards.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. It is left to the the entity to determine how to align these requirements with requirements of other
regulations and with operational concerns. Entities should be able to complete the activities with 18-month or shorter intervals
without outages. See the SDT responses to your comments in Question 7.
Black Hills Power
November 17, 2010
No
1. For Protective Relays, Table 1a Maintenance Activities has no requirement for verifying
output contacts on non-microprocessor based relays. The actual contacts used for
tripping should be verified by this activity.
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2. For Protective Relays, Table 1b Maintenance Activities states “Verify correct operation
of output actions that are used for tripping”. This requirement is vague and needs to
define whether all protection logic or conditions that would initiate a relay trip output are
required to be simulated and tested to the relay tripping output contact.
3. For Voltage and Current Sensing Inputs to Protective Relays and associated circuitry,
Table 1a references “current and voltage signals” and Table 1b references “current and
voltage circuit signals”. Need consistency or definitions to meet this requirement.
4. For Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS
Systems Only), Table 1a states “except that verification does not require actual tripping
of circuit breakers or interrupting devices.” This exception to the requirement seems to
defeat the whole purpose of the standard and leaves a huge gap open to interpretation
and conflict. -For Control and trip circuits with unmonitored solid-state trip or auxiliary
contacts (UFLS/UVLS Systems Only), Table 1a states “except that verification does not
require actual tripping of circuit breakers or interrupting devices.” This exception to the
requirement seems to defeat the whole purpose of the standard and leaves a huge gap
open to interpretation and conflict.
5. For Station dc supply, Table 1a requirement includes “Inspect: The condition of nonbattery-based dc supply.” This is redundant with the requirements of the section Station
dc supply (battery is not used) and should be removed from this section.
6. For Voltage and Current Sensing Inputs to Protective Relays and associated circuitry, a
maximum interval of verification of 12 years seems to contradict the intent of the rest of
the Maintenance standard which dictates 6 years on all of the other components. The
requirement for these components should fall in line with the rest of the standard.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1. “Verify” is defined within
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Question 1 Comment
the PSMP defintion.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. This is an intentional
difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the Standard, because of the
distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system elements.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. These devices are not
typically subject to in-service degradation to the degree that those with 6-year intervals are. Entities have the latitude to perform
maintenance more frequently than specified if they feel that such maintenance is needed.
Duke Energy
No
General comment - the draft changes the word “verify” to “check” in several places; should
use consistent phrasing throughout the standard.
With regards to Table 1a, we have the following comments:
1. Control and trip circuits with electromechanical trip or auxiliary contacts (except for
microprocessor relays. UVLS or UFLS) - We believe that while there may be value in a 6
calendar year cycle, this will be difficult to accomplish, since you either have to get
outages scheduled or block protection, which risks reliability. Since this is essentially a
re-commissioning check, the cycle should be 12 calendar years. Also 6 years appears to
be in conflict with the system protection standard.
2. Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (except for
UVLS or UFLS) - agree with 12 calendar years as consistent with electromechanical
above.
3. Control and trip circuits with electromechanical trip or auxiliary (UVLS or UFLS Systems
Only) - 6 year cycle should be changed to 12 calendar years (see comment above on
non-UVLS/UFLS).
4. Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (UVLS or
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UFLS Systems Only) - agree with change to 12 calendar years.
5. Station dc Supply (used only for UVLS or UFLS) - Strike the word “Station”. We don’t
differentiate between dc supply used for UFLS and other protection.
6. Station dc supply - Change 18 calendar months to 24 months, since this testing requires
generator outages. Nuclear plant fuel cycles can be longer than 18 months.
7. Associated communications systems - More clarity is needed regarding what is to be
included in the definition of “Associated”.
Response: Thank you for your comments. “Check” is not an element of the PSMP definition. The term has been replaced throughout
the tables with whatever term of the definition is relevant.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. The circuit itself is 12
years, but interval for the electromechanical devices such as aux or lockout relays remains at 6 years, as these devices contain
“moving parts” which must be periodically exercised to remain reliable.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
6. The SDT believes the specified intervals and activities are technically effective, and in a fashion that may be consistently
monitored for compliance. The entity must determine how to best align these requirements with requirements of other regulations
and with operational concerns. Entities should be able to complete the activities with 18-month or shorter intervals without
outages.
7. This portion of the definition of Protection System has been modified for clarity. Also, the Tables have been rearranged and
considerably revised to improve clarity. Please see new Table 1-3.
American Electric Power
November 17, 2010
No
1. In Table 1a for the component “Station dc Supply (used only for UVLS and UFLS)”, the
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interval prescribed is "(when the associated UVLS or UFLS system is maintained)" and
the activity is to "verify the proper voltage of the dc supply". The description of the
interval "(when the associated UVLS or UFLS system is maintained)" needs to be
changed. Relay personnel do not generally take battery readings. The interval should
read “according to the maximum maintenance interval in table 1a for the various types
of UFLS or UVLS relays". The testing does not need to be in conjunction with the relay
testing, it is only the test interval that is important, although relay operation during relay
testing is a good indicator of sufficient voltage of the battery.
2. The monitoring and/or maintenance activities listed for batteries are not appropriate in
Tables 1b and 1c. There are no commercial battery monitors that monitor and alarm for
electrolyte level of all cells. Why not move the electrolyte level to the 18 month
inspection and actually open the possibility of condition monitoring to commercially
available devices? Or give an option to do the electrolyte check at other time intervals
(perhaps 12 months) by visual electrolyte inspection and still allow the monitoring of
other functions on the listed 6 year schedule using condition monitoring. It makes no
sense to prescribe an unattainable condition monitoring solution. The way that the
tables are written, there is no advantage to use the charger alarms since battery
maintenance requirements are not reduced in any way.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
Great River Energy
November 17, 2010
No
1. In Table 1a section-Station DC Supply - 18 calendar months, under Maintenance
Activities column, suggest changing under Verify: Battery terminal connection resistance
To: Entire battery bank terminal connection resistance (This could have been interpreted as
individual batteries) And change: Battery cell-to-cell connection resistance To: Battery cellto-cell connection resistance, where an external mechanical connection is available.
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2. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid
batteries) suggest changing Max Maintenance Interval=3 Calendar Years or 3 Calendar
Months to 4 Calendar Years or 12 Calendar Months. Our concern is that the insurance
companies may push NERC maintenance intervals on all battery banks not associated with
the BES.
3. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max
Maintenance Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason:
performance tests may degrade the battery.
4. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max
Maintenance Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason:
performance tests may degrade the battery.
5. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and
trip circuitry) we suggest the following change: If a trip circuit comprises multiple paths, at
least one of those paths is monitored. Alarming for loss of continuity or dc supply for trip
circuits is reported to a location where action can be taken.
6. While all tripping circuits are not completely monitored, the trip coils and the outdoor
cable runs are completely monitored. The only portion that would not be monitored is a
portion of inter and intra-panel wiring having no moving parts located in a control house.
Our company has extremely low failure rate of panel wiring and terminal lugging. I don’t
think that there is provision for moving control and trip circuitry to performance based
maintenance? This control circuitry should be maintained less frequent than un-monitored
trip circuits (6 years).
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This element of the
Table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to
address this comment.
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2. NERC Standards are limited to facilities and equipment related to the BES. How the Standard may be otherwise used is outside the
scope of NERC Standards.
3. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Ni-Cad batteries. A properly
maintained battery, according to various credible references (from IEEE, EEI, EPRI, various manufacturers, etc.), can easily handle
multiple deep discharges over its expected life.
4. The SDT disagrees, and believes that a performance test at 6-year intervals is appropiate for Vented Lead Acid and Ni-Cad
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI, various manufacturers,
etc.), can easily handle multiple deep discharges over its expected life.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. Nothing in the draft
Standard (including Attachment A) precludes an entity from using performance-based maintenance for dc control circuits.
Long Island Power
Authority
No
1. In Table 1c it is required to report the detected maintenance correctable issues within 1
hour or less to a location where action can be taken to initiate resolution of that issue.
Even for a fully monitored protection system component it can be difficult to report the
action in 1 hour. LIPA recommends a 24 hour period for both Level 2 and Level 3
reporting of maintenance correctable issues. The time identified is report time and not
response time to correct issue.
2. LIPA seeks clarification on “to a location where action can be taken”. Some examples in
the FAQ will help in this clarification.
3. What type of documentation is required to show compliance that maintenance
correctable issues have been reported?
4. What is the basis of the various Maximum Maintenance Intervals tabulated in Table 1aTime based maintenance?
Response: Thank you for your comments.
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1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5 and Table
2. These Tables reflect your proposed change.
2. This is addressed in the Supplementary Reference document as posted with this draft (Section 8.1 and Section 13), and within
the FAQ as posted with this draft Standard (V.3.D).
3. Specific effective forms of documentation are left to the entity to determine, but the SDT believes that this could include, among
other things, work orders addressing the maintenance correctable issue.
4. Please see Section 8.3 of the Supplementary Reference document.
Northeast Utilities
No
1. In Table 1c it is required to report the detected maintenance correctable issues within 1
hour or less to a location where action can be taken to initiate resolution of that issue.
Even for a fully monitored protection system component it can be difficult to report the
action in 1 hour. Recommend a 24 hour period for both Level 2 and Level 3 reporting of
maintenance correctable issues.
2. Additionally, please clarify meaning of “to a location where action can be taken”.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5 and Table
2. These tables reflect your proposed change.
2. This is addressed in the Supplementary Reference document as posted with this draft (Section 13), and within the FAQ as posted
with this draft Standard (V.3.D).
MidAmerican Energy
Company
November 17, 2010
No
1. In the tables trip circuit has been replaced by “control and trip circuit”. From the context
of the standard and the reference and frequently asked question documents it is clear
that the requirement is to test the trip circuit only. Adding the word “control’ introduces
ambiguity and the potential to imply the closing circuit of the interrupting device also
requires testing under the standard. The word “control” should be removed. On this
same subject the nomenclature in Table 1b for type of protection system component is
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not consistent with Table 1a.In Table 1b in the Level 2 Monitoring Attributes for
Component column for Relay sensing for centralized UFLS or UVLS systems there is a
reference to SPS. This reference should likely be to UFLS/UVLS.
2. In Table 1a functional testing of associated communications systems is included with a
maximum maintenance interval of 3 calendar months. Testing of this equipment at that
frequency is not believed to be necessary. It is suggested that the interval be changed
to 12 calendar months.
3. For control and trip circuit maintenance the requirement includes “a complete functional
trip test”. In order to accomplish this type of testing given current design of lock-out relay
and interrupting device trip circuitry multiple breakers and line terminal outages would
be required simultaneously. In addition complete functional testing has the potential to
result in unintentional tripping of equipment that could cause equipment damage and
customer outages. Segmentation of trip circuits by lifting wires has the potential for
incorrect restoration following testing. This type of testing has the potential to degrade
system reliability as multiple entities schedule this work. An alternate to complete
functional testing that does not potentially degrade system reliability should be
substituted.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. The interval for
maintenance of electromechanical devices such as aux or lockout relays remains at 6 years, as these devices contain “moving
parts” which must be periodically exercised to remain reliable.
Nebraska Public Power
District
November 17, 2010
No
1. It would be very helpful in Table 1a, 1b, and 1c to reference the FAQ or
Supplemental Reference by page number and section number for the corresponding
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Maintenance Activity statements.
2. Table 1a, Control and Trip Circuits with electromechanical trip or auxiliary contact how is the control and trip circuit functional trip test performed without affecting the
BES or without tripping more than just the breaker (trip coil)? What is the basis for an
actual trip of the breaker that will affect the BES? Functional trip testing will require
extensive analysis and could involve an extensive testing evolution to ensure the
correct circuit is tested without unexpected trip of other components, particularly for
generator protection systems. The complexity of the system and the test would be
conducive to an error that resulted in excessive tripping, thus affecting the reliability
of the BES. It would seem that the potential for an adverse affect from this test would
be greater than the benefit gained of testing the circuit. In addition, scheduling
outages to perform the functional trip testing in conjunction with other outages
required to perform maintenance and other construction activities will be difficult due
to the large number of outage requirements for the functional testing. This will
challenge the BES more often and thus reduce reliability.
3. 2. Table 1a, Control and Trip circuits with electromechanical trip or auxiliary contacts
- What is the differentiation between control and trip circuits? The FAQ appears to
use the term interchangeably.
4. Table 1a, associated communication systems - What is the basis for checking that
the associated communication equipment is functioning every 3 calendar months for
unmonitored components? NPPDs experience indicates that a check every 6
months is sufficient.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5. Doing as
you suggest would make the supporting information with the FAQ and Suppementary Reference part of the Standard, and this would
add extensive and unnecessary prescription to the Standard.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. These devices contain
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“moving parts” which must be periodically exercised to remain reliable.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. The FAQ has been
modified.
4. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
Y-W Electric Association,
Inc.
No
Many of the changes to the proposed standard are reasonable and improve the clarity of
the standard and its requirements.
However, Y-WEA concurs with Central Lincoln and FMPA on their comments regarding the
testing of battery cell-to-cell connection resistance. Many types of stationary batteries are
actually blocks of two or more cells that are internally connected. This requirement would
necessitate either some sort of feasibility exception process (which, as shown by the TFE
process with the CIP standards can be very difficult, cumbersome, and time-consuming to
develop and administer) or replacement of the batteries in question, which would pose
enormous burdens on small entities that must comply with this standard. The language in
this requirement should be changed from “cell-to-cell” to “unit-to-unit” in order to avoid
these issues.
Response: Thank you for your comments.
The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This element of the table
has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to address
this comment.
Progress Energy Carolinas
No
1. The modified definition of “Protection System” (page 2 of the clean version of PRC-0052) uses the terminology “control circuitry associated with protective functions” whereas
Table 1a rows 3-6, Table 1b Rows 3 and 5, and Table 1c Row 4 uses the terminology
“control and trip circuits.” This is a conflict. “Control” implies that the standard applies to
closing/reclosing circuits as well. We do not believe that is the intent.
2. Row 7 of Table 1a (page 10 of the clean version of PRC-005-2) indicates that proper
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voltage of the station dc supply must be verified when the associated UVLS or UFLS
maintenance is performed. It is not clear whether this requirement is over and above the
quarterly and 18-month battery maintenance listed elsewhere in the table or is it the only
battery maintenance required for UVLS and UFLS systems? If the intent is to check the
station dc supply only when UVLS and UFLS maintenance is performed, the other rows
addressing station dc should be revised to exclude UVLS and UFLS.
3. Row 4 of Table 1b (page 14 of the clean version of PRC-005-2) indicates that remote
alarms must be verified every twelve calendar years for control circuitry (trip circuits)
(except UFLS/UVLS) provided “Monitoring of Protection System component inputs,
outputs, and connections” exists. Clarification should be made to indicate how to monitor
inputs. For example, a breaker auxiliary switch is relied upon to communicate breaker
status to a protective relay. If the switch is out of adjustment so that incorrect breaker
status is reported to the relay, the relay may not operate when needed. Could proper
operation of the auxiliary contacts be credited through in-service operation or the six-year
breaker operation maintenance?
4. The term “calendar years” is used to define the maximum intervals. Does this mean that
a six-year PM could go one-day shy of seven years? For example, if a six-year
maintenance PM was last performed on 1/1/2010, it would be due on 1/1/2016. Could
this allow until 12/31/2016 to complete the maintenance?
5. Table 1b, Row 14 (Row 2 on page 17): Under the “Level 2 Monitoring Attributes for
Component,” UFLS/UVLS should be referenced instead of SPS.
6. Clarifications need to be made on testing requirements on trip contacts relative to
microprocessor vs. EM relays.
7. There appears to be an inconsistency in the use of “check” vs. “verify” in the tables.
8. In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
Response: Thank you for your comments.
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1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. To the degree that inservice test-operating of the breaker also performs the specified maintenance on other portions of the Protection System, the entity
should be able to document and “take credit” for it.
4. Your explanation of “6 Calendar Years” is correct.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1 and 1-5.
7. “Check” is not an element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the
definition is relevant.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
PPL Supply
No
PPL Generation, on behalf of the entities listed above, has the following comments on the
dc entries in these tables:
1. Table 1a, Table 1b, Table 1c- Station DC supply - Maintenance Activities - references
substation batteries. For generators, shouldn't that reference be station battery?
Substation implies an association strictly with transmission, not generation.
2. Station DC supply - verify Battery continuity. What is the technical basis for this
requirement? Neither battery installation and operation instructions nor technical reviews
explain the basis for how this verification is supposed to work. NERC's Protection
System Maintenance: A Technical Reference does not address this requirement. The
Frequently-Asked Questions provides some ways that this verification can be completed.
However, one example is tied to the microprocessor battery chargers. If there is a
technical basis for this requirement, it should be provided.
3. Condition based monitoring on station dc supply - it appears the Table 1b excludes any
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Question 1 Comment
condition based monitoring of the batteries because of the requirement for monitoring
electrolyte level, individual cell state of charge, cell to cell and battery terminal resistance.
Most monitoring equipment does not monitor those functions.
4. In general, the Tables are especially confusing in the dc system area. The “lines”
overlap and need to be labeled, so they can be referenced in a maintenance document to
show how the appropriate program can be followed. Each line should be separate in the
function stated, so one can identify what has to be done to comply.
5. Provide examples of “non-battery-based dc equipment” that is covered under this
standard.
6. For dc supply, the changes from the Sept. 2007 NERC “Protection System
Maintenance”, A Technical Reference seem too restrictive. The Sept. 2007 document
contained a solid maintenance program. What is the basis for the change?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This has been
corrected in the revision.
2. Please see the FAQ (I.5.B, I.5.C and I.5.D)
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
5. The SDT has been advised that entities are considering or using technologies such as flywheels and fuel cells. Also, we have
been told that some entities are using modern battery chargers without the battery.
6. When developing the original technical reference, the SPCTF was not challenged to develop a complete, measurable Standard.
The SDT used the original document as a starting point to develop actual requirements, etc.
San Diego Gas & Electric
November 17, 2010
No
1. Proofing of CT circuits is not always trivial. Given this function is not presently being
performed and documented by the company, a reasonable grace period would be
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required to achieve compliance. The company believes present practice, such as
verification that relay current inputs are not zero and that phases are balanced, is a
reasonable indication individual CTs are functioning properly.
2. An entities protection system maintenance program is a Time Based Maintenance
program. The protection system maintenance program describes the maintenance
intervals and states that the protection system maintenance is triggered every 4 years.
The maintenance program describes that the due date for compliance is 6 months past
the trigger date to allow for planning and scheduling of the maintenance activity.
Therefore the actual due date for the 4 year maintenance interval is 4 years and six
months from the last maintenance completion date. The four year six month time based
interval is within the six year maximum time based interval as required by PRC-005-2.
Given the above, is the four year six month interval as described in the entities
maintenance program compliant with PRC-005-2?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. The intervals remain
as prescribed within the Standard and are designed to be effective, clear, and consistently monitored for compliance; the SDT is
not prescribing or suggesting what measures an entity may take within their program to assure compliance. “Grace periods”
within the Standard are not measurable, and would probably lead to persistently increasing intervals. However, an entity may
establish an internal program with grace-period allowance, as long as the entire program (including grace periods) does not
exceed the intervals within the Standard. Simply observing non-zero instrument transformer outputs may not be sufficient to
determine that the values are acceptable.
2. “Grace periods” within the Standard are not measurable, and would probably lead to persistently increasing intervals. However,
an entity may establish an internal program with grace-period allowance, as long as the entire program (including grace periods)
does not exceed the intervals within the Standard.
Springfield Utility Board
November 17, 2010
No
SUB appreciates the effort to try to strike a balance between specificity around a specific
standard and flexibility to meet the requirement under the standard. The maximum
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
allowable intervals don't seem unreasonable combined with the implementation schedule.
However, it seems that the proposed changes stray toward a proscriptive set of
maintenance that 1) does not allow for an alternate method of testing and 2) sets unrealistic
testing requirements.
For example, battery terminal to terminal testing is not feasible with all battery systems.
This is a consistent message SUB has heard from others as well.
First and foremost - a test or maintenance must be done for each device within the defined
interval. With that in mind...SUB's preference would be that the maintenance activities
focus on what specifically must be done for a device (may be type specific) vs. what could
be done for a device for compliance (as an example of what an auditor could look for when
conducting an audit) vs. alternative best-practices for testing and maintenance that the
entity demonstrates constitutes as maintenance or test.
With regard to the first (maintenance activities focus on what specifically must be done for a
device) - it seems that this would apply to a limited number of devices
With regard to the second (maintenance activities focus on what specifically can be done
for a device) - it seems that this would apply broad number of devices and the list of what
can be done should be broad to cover a range of different devices that provide the same
function.
With regard to the last (alternative best-practices for testing and maintenance that the entity
demonstrates constitutes as maintenance or test), it would be helpful to have a mechanism
outside the standard itself to either have a NERC technical group craft a series of criteria
that must be met for an acceptable alternative maintenance or the entity document the
criteria used to determine an adequate test and provide for a test that meets that set of
criteria). It would be anticipated that these would fall under a minority of devices.
Response: Thank you for your comments.
November 17, 2010
56
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
In the draft Standard, the SDT is defining the basic parameters for an effective PSMP; the entity is required to develop its program with
specific activities that would satisfy those basic parameters.
The Detroit Edison
Company
No
Suggest that the interval for cell ohmic testing on VRLA batteries be changed to 12 months.
Also, include ohmic testing of NiCad batteries at 18 mos. as an option.
Response: Thank you for your comments. The activity related to this interval is to verify various basic operating parameters. The
SDT believes that extension of verification of these parameters beyond the interval within the Standard is inappropriate.
NorthWestern Corporation
No
Table 1a - Rows 3 & 4 (control and trip circuits) - add language in the Maintenance
Activities - "except that verification does not require actual tripping of circuit breakers or
interrupting devices"
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-5.
We Energies
No
1. Table 1a, Protective Relays: Change 1st line to: “Test and calibrate if necessary the
relays...”Table 1a, Protective Relays: 3rd line: Change “check the relay inputs...” to
“verify the relay inputs...”. The term “check” is not defined, whereas “verify” is. Tables
1a & 1b We agree that six / twelve years is an acceptable interval for relay
maintenance.
2. Table 1a & 1b, Control & Trip Circuits: The proposed addition to require tripping circuit
breakers during Protection System maintenance is detrimental to BES reliability and
should be removed. Ï
3. Generating unit protection system maintenance is done during scheduled outages.
The high voltage breaker on a generating unit often remains energized to backfeed and
supply station auxiliaries when the generator is offline. The proposed requirement will
increase the amount of equipment requiring an outage for maintenance, and possibly
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
the length of the outage, resulting in significantly more equipment out of service as well
as increased costs. This requirement also results in greater maintenance efforts and
costs when there are redundant protection system equipment (breaker trip coils, lockout
relays, etc), which is contrary to good practice and reliability.
4. Many of the breakers that We Energies, as the Distribution Provider, trips from its BES
protection systems are not owned by We Energies and are owned by a separate
transmission company. The trip testing and maintenance of the transmission company
may not coincide with our relay maintenance testing program. The standard shall have
allowances for the entity to ONLY test or maintain equipment that it OWNS!
5. Table 1a, Station dc supply:
a. The activity to verify the state of charge of battery cells is too vague, and requires
more specific action. We assume that the drafting committee is recommending
specific gravity measurements. Specific gravity measurements have not been
shown to an accurate indicator on state of charge. In addition, as shown in the
nuclear power industry, there is no established corrective action that is taken based
on specific gravity results (eg. Don’t require a test where there is no acceptable
corrective action).
b. The activities to “verify battery continuity” and “check station dc supply voltage” are
also vague and need to be more clearly specified what is intended.
c. The 3 month time interval for battery impedance testing is too frequent. 18 month or
annual testing is more appropriate.
d. The 3 calendar year performance or service test is too frequent and will actually
remove life from a battery and reduce reliability. Recommend capacity testing no
more that every 5 years and more frequent test if the capacity is within 10% of
the end of life or design. This is consistent with the nuclear power industry.
6. Table 1b, Station dc supply: Recommend a change or addition to Table 1b Recommend a level 2 monitoring (not just a default to the level 1 maintenance activities)
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
which allows for the removal of quarterly “check” of electrolyte levels, DC supply
voltage, and DC grounds - if station DC supply (charger) voltage is continuously
monitored (eg. one should not have detrimental gassing of a battery if the float voltage
of the battery is properly set and monitored).
7. Table 1a, Associated communications systems: The requirement to verify functionality
every three months is excessive; verifying this every twelve months is adequate.
8. Tables 1a & 1b - Although the latest standard provided some additional clarification,
more clarification is required on what maintenance / testing is ONLY required for
UFLS/UVLS protection systems vs. BES protection systems (eg. UFLS / UVLS systems
- Is a verification of proper voltage of the DC supply the only battery or DC supply
required (eg. no state of charge, float voltage, terminal resistance, electrolyte level,
grounds, impedance or performance test, etc.)?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1. “Check” is not an
element of the PSMP definition. This term has been replaced throughout the Tables with whatever term of the definition is
relevant.
2. These devices contain “moving parts” which must be periodically exercised to remain reliable.
3. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. It is left to the the entity to determine how to align these requirements with operational concerns.
4. The SDT contends that “its Protection Systems” is synonymous with “Protection Systems that it owns.”
5. a.The SDT is not specifically requiring specific gravity tests, although they may be one effective method of meeting the
requirement. Another method is to measure the individual cell voltage. R4 establishes that the entity must initiate resolution of
maintenance-correctable issues, so it IS necessary to correct problems that are found.
b.The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. The SDT does not
prescribe specific activities to satisfy the requirements, although some guidance may be found in the FAQ (II.5.B, II.5.C and
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
II.5.D) and Supplementary Reference Section 15.4.
c. The activity related to this interval is to verify basic operating parameters. The SDT believes that extension of verification of
these parameters beyond the interval within the Standard is inappropriate.
d. The SDT disagrees, and believes that a performance test at 3-year intervals is appropriate for Valve-Regulated Lead Acid
batteries. A properly maintained battery, according to various credible references (from IEEE, EEI, EPRI, various manufacturers,
etc.) can easily handle multiple deep discharges over its expected life.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
7. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
Hydro One Networks
No
1. Table 1a:
a. V and I sensing to relays - 12 years? Why not perform this activity with maintenance
activities associated with relay maintenance so that they line up? It would only be an
incremental amount of work to perform this with associated relay maintenance work
b. Removal of requirement for testing of unmonitored breaker trip coils? Is it really the
intention of the SDT to remove a requirement that would drive the industry to install TC
monitors on breakers to improve reliability?
c. UFLS/UVLS DC control and trip circuits - Due to the distributed nature of this program,
random failures to trip are not impactive to the overall operation of the UFLS protection.
There should be no requirement to check the DC portion of these protections any more
often than the DC circuit checks associated with that LV breaker. Since it is clear the
requirement does not include the need to trip the breakers why the need to check the
trip paths? Deletion of this requirement leaves the requirement to check only the relays
and relay trip outputs from the protections every 6 years (or as often as the protective
relay component type).
d. Along the same lines as the above comment should the maintenance activities for
November 17, 2010
60
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
“UVLS and UFLS relays that comprise a protection scheme distributed over the power
system” not be the same as “Protective Relays”
2. Table 1c:
a. Level 3 attributes for “Associated communications systems” might better read
“Evaluating the performance and quality of the channel as well as the performance of
any interface to connected protective relays and alarming if the channel/protective relay
connections do not meet performance criteria”
b. We believe that some of the proposed maintenance intervals for station DC supply are
too stringent and that they would not produce significant increase in reliability to justify
associated incremental expenditure. For example we suggest that the following
changes are considered:- The interval for electrolyte level check for all batteries except
VRLAs and internal measured cell/unit Ohmic value for VRLAs be extended to 6
months instead of current time period of 3 months.- The performance or service
capacity test of the VRLA battery banks to be extended from 3 years to 5 years.
Response: Thank you for your comments.
1. a. This activity CAN be performed with the relays (for example, every other relay interval) if the entity so desires.
b. The Tables have been rearranged and considerably revised to simplify and improve clarity. Please see new Table 1-5. Specific
to your comment, the SDT initially specified inspection of trip-coil monitoring functions at intervals of 3 calendar months, with
tripping otherwise requried annually. This has been revised to simply require tripping at 6-calendar-month intervals.
c. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
d. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the
Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system
elements.
2. a. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
b. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
Arizona Public Service
Company
No
The associated maintenance activities are too prescriptive. The activities needed to ensure
the reliable service of the relay or device should be left up to the discretion of the utility.
Response: Thank you for your comments. The SDT disagrees. In the draft Standard, the SDT is defining the basic parameters for an
effective PSMP; the entity is required to develop its program with specific activities that would satisfy those basic parameters.
Manitoba Hydro
No
1. The monitoring attributes required to achieve level 2 monitoring of Station DC supply
seem excessive. We are not aware of any other utilities doing automatic monitoring all
6 attributes required. In particular automatic monitoring of electrolyte level & battery
terminal resistance does not seem practical.
2. There is inconsistency between Table 1 and the FAQ. In the Group by Monitoring Level
section of the FAQ it indicates that a battery with low voltage alarm would be considered
to have level 2 monitoring.
3. In Table 1C under the heading "Maximum Maintenance Interval" some of the entries are
stated as being "Continuous". In the case of other maintenance activities the descriptor
for Maintenance Interval indentifies the maximum period of time that may elapse before
action must be taken. "Continuous" implies continuous action; however, in reality
continuous monitoring enables no maintenance action to be taken until such time as
trends indicate the need to do so. Therefore we recommend that where the
maintenance interval be changed to read "Not Applicable".
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-4.
2. The FAQ has been modified. (See the examples in Section V.)
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
November 17, 2010
62
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
MRO’s NERC Standards
Review Subcommittee
(NSRS)
Yes or
No
No
Question 1 Comment
The NSRS feels additional changes are needed.
1. The functional testing requirement should be altered or removed as it increases the
amount of hands-on involvement and the opportunity for human error related outages to
occur, thereby introducing a greater risk to decrease system reliability. As noted on p. 8
in the supplementary reference document, “Experience has shown that keeping human
hands away from equipment known to be working correctly enhances reliability.” By
removing circuits from service on the proposed timelines for functional testing, the
chance for human error is greater than a misoperation from faulty wiring. Alternatively,
entities may choose to schedule more planned outages to conduct their functional
testing in order to limit the risk of unplanned outages resulting from human error. Under
this scenario, more elements will be scheduled out of service on a regular basis, thereby
reducing transmission system availability and weakening the system making it more
challenging to withstand each subsequent contingency (N-1). Thus testing an intact
system is more desirable than taking it out of service for testing.
2. While the SDT has included language in the draft standard to use fault analysis to
complete maintenance obligations, in practicality, this option does not offer any relief to
taking outages to perform functional tests. Nearly all BES circuit breakers are equipped
with dual trip coils. Identifying which trip coil operated for a fault only covers the one trip
coil. Functional tests would still be needed on the other. The likelihood of having
multiple trips on a given line in the course of several years is very low. Given it can take
a year to schedule some outages; planning maintenance with random faults is
unpractical and will create unacceptable risk to compliance violations. A better
approach is to use the basis in schedule A, but extend this to cover the entire protection
schemes. The document should establish target goals for mis-operation rates
(dependability and security). This would allow the utilities to develop cost effective
programs to increase reliability. The utilities would have incentives to replace poorly
performing communications systems; they would be able to quantify the value of
upgrading relay systems.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
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Yes or
No
Question 1 Comment
Response: Thank you for your comments.
1. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be
consistently monitored for compliance. The entity must determine how to align these requirements with operational
concerns.
2. Operational results, if desired by an entity, MAY be used to meet maintenance requirements to the degree that it verifies,
etc., the relevant performance. Whether their use is effective for a specific entity is left to the entity to determine.
“Maintenance correctable issues”, which may result in part from misoperations, are a part of using Attachment A to develop
a performance-based PSMP.
Tennessee Valley Authority
No
The requirement to measure internal ohmic values of the station dc supply batteries every
18 months is excessive. The interval should be 36 months. Our experience from
performing our routine maintenance program including cell impedance testing at 3-year
intervals has been that the program is fully adequate in monitoring bank condition.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4. The activity related to this interval is to verify various basic operating parameters. The SDT believes that extension of
verification of these parameters beyond the interval within the Standard is inappropriate.
Bonneville Power
Administration
No
The requirements pertaining to dc control circuitry are confusing.
1. To start with, a definition or further explanation is required for the term “auxiliary
contact”. Is this strictly a breaker “a” or “b” switch, or does this include lockout relay
contacts, etc.?
2. Another confusing point is that the term trip circuit is used in several places throughout
the tables, but it is not included in the definition of Protection System, where the term dc
control circuitry is used. It is important to use consistent terminology throughout the
definition and the standard.
3. The requirements for (dc) control circuits in Table 1a are fairly straightforward, but in
November 17, 2010
64
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
Table 1b control circuits are broken down into three parts: trip coils and auxiliary relays;
trip circuits; and control and trip circuitry. It is very unclear exactly what each of these
three parts includes. In Table 1c, control circuitry is covered as a single element.
Please provide clarity to what is included in each part of a control circuit in Table 1b and
the monitoring attributes of each. Also, please be consistent in the treatment of control
circuits throughout the three tables.
4. Table 1a, SPS, BPA does not understand the following segment of this paragraph “The
output action may be breaker tripping, or other control action that must be verified, but
may be verified in overlapping segments. A grouped output control action need be
verified only once within the specified time interval." In one sentence, it says you can
test a SPS in segments - and in the next sentence it says you have to verify the
grouped output control action at least once within the specified time interval. It seems
that the sentences contradict themselves.
5. Table 1b, Control and trip circuitry - "Monitoring of the continuity of breaker trip circuits
along with the presence of tripping voltage supply all the way from relay terminals (or
from inside the relay) through to the trip coil(s)..." To monitor the trip path as proposed
in this Standard would cost some serious time and $$.
6. BPA does not believe there is a way to meet level two monitoring for batteries. In
addition, some of the maintenance tasks need to be defined:- monitoring the electrolyte
level is not commercially available.- the state of charge of each individual cell may need
to be better defined. There are means to verify the state of charge of the entire bank,
but not each individual cell.
7. Since a device to provide level 2 monitoring is not commercially available, we would be
forced to follow level 1 maintenance guides, which would require maintenance of
communication batteries every three months. Many of these batteries are not
accessible during 9 months of the year except via snow-cat or helicopter. We currently
monitor for some of the level 2 requirements, but not all. Our current practices of
monitoring and yearly maintenance supplemented by opportunity inspections have
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
successfully identified problems before we lost DC power to any of our communication
facilities. VRLA type batteries: - battery continuity needs to be defined.
8. In regards to the maximum allowable intervals; the frequency with which BPA performs
the 18 month maintenance tasks as prescribed in the standard are on a 24 month
interval along with visual inspections and voltage measurements weekly to bi-weekly.
BPA has seen success with this maintenance program with the ability to identify suspect
cells or entire banks with adequate time to perform corrective actions such as repairs or
replacements. BPA also does not perform routine capacity testing, this is an as
required maintenance task to confirm/validate our other test results if needed. Our
suggestion would be to extend the maintenance intervals beyond 18 months, and to
provide some clarity on the above items.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. Please see Section 15.3
of the Supplementary Reference Document and the FAQ (II4.E.).
2. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
3. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
5. The Tables have been rearranged and considerably revised to improve clarity and consistency. Please see new Table 1-5.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. Also, the SDT believes
that there are devices available to monitor electrolyte levels.
7. The FAQ (II.5.K) advises that “communications system batteries” are not “station batteries” and are maintained with the
communications systems.
8. The activity related to this interval is to verify various basic operating parameters. The SDT believes that extension of verification of
these parameters beyond the interval within the Standard is inappropriate.
November 17, 2010
66
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Public Service Enterprise
Group ("PSEG
Companies")
Yes or
No
No
Question 1 Comment
The SDT is to be commended for the work and details included in the most recent draft
revision. The standard - with associated references is easier to interpret.
1. The sections on DC supply are too restrictive. Quartile checks of VLA electrolyte levels
for unmonitored systems is reasonable, however the option of checking the electrolyte
levels and voltages with less frequency is not an option with systems that have voltage
alarm notification and ground detection monitoring alarm notification unless all level 2
attributes are followed. The level 2 monitoring attributes are too comprehensive to allow
for a suggested alternative less restrictive interval of 6 months to a year. Suggest there
be an additional option for level 2 monitoring that includes voltage level and ground
alarms with a 6 month maintenance activity interval.
2. The perception of table 1a page 12 for station DC supply - “used for UVLS and UFLS” is
a maintenance activity to verify proper DC supply voltage when the UVLS and UFLS
system is maintained. This is the only DC supply maintenance activity for those
applications and the other more rigorous maintenance activities do not apply? If this is a
correct interpretation specifically list that as such in the maintenance activity description
(State the other DC supply maintenance activities are not applicable for UVLS and
UFLS). The maintenance intervals for station DC supply for level 1 and 2 monitoring
does not appear to be consistent and is somewhat confusing. A battery system with
level 2 monitoring attributes for components has intervals of 6 years, and then in next
section states that no level 2 attributes are defined - use level 1 maintenance activities.
Suggest that all DC supply / batteries be broken out all be included in one separate stand alone table with varied maintenance requirements based on monitoring attributes.
3. The maintenance activities shown on table 1b on page 19 for Station DC supply is
intended for VLA batteries? If so add that in component definition.
4. For DC systems that use a storage battery, suggest that chargers be eliminated as
other required maintenance activities will expose any problems with the charger.
5. The requirements of performing a capacity test every 6 years during the initial service
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
life of a VLA battery in addition to the other maintenance activities are too restrictive and
will cause extensive outages of the affected equipment. Suggest that this frequency be
extended to 10 years for VLA batteries for the first iteration if all the other maintenance
activities are followed. Failure rate of VLA in first 10 years is extremely low. Other
maintenance activities will expose significant issues.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
4. If the charger fails, the battery will quickly discharge via normal dc loads, and be unable to adequately serve the Protection System.
5. The SDT disagrees, and believes that a capacity test at 6-year intervals is appropiate for Vented Lead Acid batteries.
US Bureau of Reclamation
No
1. There is no reliability based justification to alter the standards to include allowable
intervals.
2. The intervals prescription for performance based PSMP virtually eliminates the
capability of smaller utilities who do not have a large equipment database to justify a
performance based system that may be sound based on their experience. This overly
prescriptive approach should be eliminated and return to allowing utilities to justify their
programs. The standard should return to addressing real reliability impacts as required
by law. This would be to develop a maintenance required which identifies that if it is
shown that an event in which reliability is impacted by the utilities PSMP, as evidenced
by disturbance reports, the utility would be required to submit to the RRO a corrective
action plan which addresses how the PSMP will be revised and when compliance with
that PSMP is to be achieved.
3. Finally, the standard presumes that components within a BES Element will cause a
reliability impact to the BES. In numerous meeting with NERC and WECC it was
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
emphasized that a reliability impact has been described as causing cascading outages
or causing loss of service to load above a certain magnitude. The BES has an ability to
absorb element outages resulting from a variety of causes without impact load or
resulting in cascading outages.
Response: Thank you for your comments.
1. FERC Order 693 directs NERC to establish maximum allowable intervals.
2. Small entities are permitted to aggregate their components with similar components of other entities to meet the component
populations, as long as the programs are (and remain) similar – see Section 9 of the Supplementary Reference, the FAQ (IV.3.A)
and the associated footnote to Attachment A. Decreasing the component population below the requirements of Attachment A will
result in an unsound program due to component populations that are not statistically significant.
3. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the
currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and understands this to be consistent with the position
of FERC staff.
Dynegy Inc.
No
We agree with all proposed intervals in Tables 1a, 1b, and 1c except the 3 calendar month
interval for Associated Communication Systems in Table 1a. We suggest using a 1 year
interval because all other elements of the Protection System are being verified a minimum
of every 3 years. Therefore, we believe annual verification of Associated Communication
Systems is sufficient.
Response: Thank you for your comments. The SDT believes that the 3-month interval is proper for unmonitored communications
systems.
Pacific Northwest Small
Public Power Utility
Comment Group
November 17, 2010
No
We agree with most of the changes from the last draft. However, the phrase “Verify Battery
cell-to-cell connection resistance” has entered the table where it did not exist before. On
some types of stationary battery units, this internal connection is inaccessible. On other
types the connections are accessible, but there is no way to repair them based on a bad
reading. And bad cell-to-cell connections within units will be detected by the other required
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
tests. This requirement will cause entities to scrap perfectly good batteries just so this test
can be performed, with no corresponding increase in bulk electric system reliability while
taking an unnecessary risk to personnel and the environment. And because buying battery
units composed of multiple cells allows space saving designs, entities may be forced to buy
smaller capacity batteries to fit existing spaces. This may end up having a negative effect
on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table
now.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)” to address this comment.
PNGC Power
No
We agree with most of the changes from the last draft. However, the phrase “Verify Battery
cell-to-cell connection resistance” has entered the table where it did not exist before. On
some types of stationary battery units, this internal connection is inaccessible. On other
types the connections are accessible, but there is no way to repair them based on a bad
reading. And bad cell-to-cell connections within units will be detected by the other required
tests. This requirement will cause entities to scrap perfectly good batteries just so this test
can be performed, with no corresponding increase in bulk electric system reliability while
taking an unnecessary risk to personnel and the environment. And because buying battery
units composed of multiple cells allows space saving designs, entities may be forced to buy
smaller capacity batteries to fit existing spaces. This may end up having a negative effect
on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table
now.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)” to address this comment.
FirstEnergy
November 17, 2010
No
We support most of the maintenance activities detailed in the Tables, but question the
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
verification of battery cell-to-cell resistance. On some types of battery units, this internal
connection is inaccessible. We suggest substituting "unit-to-unit" in place of "cell-to-cell".
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4. This element of the table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)” to address this comment.
Florida Municipal Power
Agency
No
1. Will the Standard Introduce Technical Feasibility Exceptions to PRC Standards? A large
proportion of the batteries (as high as 50% as reported by some SMEs) are not able to
accommodate all of the tests prescribed in the draft standard. The phrase “Verify
Battery cell-to-cell connection resistance” has entered the table where it did not exist
before. On some types of stationary battery units, this internal connection is
inaccessible. On other types the connections are accessible, but there is no way to
repair them based on a bad reading. And bad cell-to-cell connections within units will be
detected by the other required tests. This requirement will cause entities to scrap
perfectly good batteries just so this test can be performed, with no corresponding
increase in bulk electric system reliability while taking an unnecessary risk to personnel
and the environment. And because buying battery units composed of multiple cells
allows space saving designs, entities may be forced to buy smaller capacity batteries to
fit existing spaces. This may end up having a negative effect on reliability. Suggest
substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now.
2. The Standard Reaches Beyond the Statutory Scope of the Reliability Standards As
written, the standard requires testing of batteries, DC control circuits, etc., of distribution
level protection components associated with UFLS and UVLS. UFLS and UVLS are
different than protection systems used to clear a fault from the BES. An uncleared fault
on the BES can have an Adverse Reliability Impact and hence; the focus on making
sure the fault is cleared is important and appropriate. However, a UFLs or UVLS event
happens after the fault is cleared and is an inexact science of trying to automatically
restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable
November 17, 2010
71
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays
with the same function, there is no significant impact to the function of UFLS or UVLS.
Hence, there is no corresponding need to focus on every little aspect of the UFLS or
UVLS systems. Therefore, the only component of UFLS or UVLS that ought to be
focused on in the new PRF-005 standard is the UFLS or UVLS relay itself and not
distribution class equipment such as batteries, DC control circuitry, etc., and these latter
ought to be removed from the standard. In addition, most distribution circuit are radial
without substation arrangements that would allow functional testing without putting
customers out of service while the testing was underway, or at least without momentary
outages while customers were switched from one circuit to another. Therefore, as
written, we would be sacrificing customer service for a negligible impact on BES
reliability.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. This element of the
table has been modified to state, “Battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)” to
address this comment.
2. The Standard addresses UFLS and UVLS to the degree that they are installed per NERC Standards, even though entities may
choose to install them on distribution systems.
NERC Staff
Yes
PacifiCorp
Yes
WECC
Yes
Compliance agrees with the changes as they add clarity though the Tables do not define
what is actually required to demonstrate compliance without reading the Supplementary
Reference and the FAQs.
Response: Thank you for your comments. The Measures do provide discussion of what is required to demonstrate compliance.
November 17, 2010
72
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
The United Illuminating
Company
Yes or
No
Yes
Question 1 Comment
In general yes. There are concerns with verifying cell-to-cell resistance in Batteries. On
some battery sets this is not possible to do.
Response: Thank you for your comments. This element of the table has been modified to state, “Battery internal cell-to-cell or unitto-unit connection resistance (where available to measure)” to address this comment.
South Carolina Electric and
Gas
Yes
Please provide clarity on why Table 1b for “Station dc supply” has a double entry that
appears to be contradictory. The table provides monitoring attributes for a maximum
maintenance interval of 6 calendar years and the next row says to refer to level 1
maintenance activities.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Table 1-4.
ReliabilityFirst Corp.
Yes
1. The SDT has made significant and worthwhile changes to these tables. However, these
tables still seem overly complex and should be simplified. One possibility would be to
eliminate Table 1c and use Table 1b for those components that meet certain monitoring
attributes.
2. There are some errors in Table 1a in rows 5 and 6. In row 5 in the component column
the word “contact” is missing. In the same row in the third column, there is an extra
period. In row 6 in the third column, “circuit” should be “circuits” as in the other rows.
3. The maintenance intervals seem to give preference to solid-state outputs but there is no
evidence given that these are truly more reliable than an electromechanical trip at least
not sufficient to double the maintenance interval.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
November 17, 2010
73
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 1 Comment
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1.
November 17, 2010
74
Consideration of Comments on PSMTSDT — Project 2007-17
2. The SDT has included VRFs and Time Horizons with this posting. Do you agree with the
assignments that have been made? If not, please provide specific suggestions for
improvement.
Summary Consideration: Many commenters disagreed with various VRFs as specified in the draft
Standard. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC and
FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 –
Medium, and R4 – High. Some comments were offered regarding Time Horizons, resulting in modification
of the Time Horizons for both R3 and R4 from Long-Term Planning to Operations Planning.
Organization
Yes or
No
Question 2 Comment
PPL Supply
No comment.
Xcel Energy
No comments
SERC Protection and
Control Sub-committee
(PCS)
The SERC PCS expresses no opinion on this question.
San Diego Gas & Electric
No
The Detroit Edison
Company
No
Black Hills Power
No
The United Illuminating
Company
No
November 17, 2010
The VRF for R1 should be Low. It is administrative to create an inventory list. If R1 failed
to be executed but the other requirements wee executed fully then the BES would be
75
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
properly secured. Compare this against the scenario of performing R1 but failing to
perform the other tasks; in which case the BES is at risk. UI recognizes that the SDT
considers the inventory as the foundation of the PSMP but it is not the element of the
PSMP that provides for the level of reliability sought. R1 should be VRF Low and R2 thru
R4 VRF is Medium. UI agrees with the Time Horizon.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
JEA
No
1. What role with the Supplementary Reference and FAQ play with reference to the
proposed standard? We have a concern that the standard will stand-alone and not
include the interpretations, examples and explanations that are needed to properly
apply these values in a compliance environment. There needs to be a method to
include the FAQ and Supplementary Reference.
2. The method will also need to allow for future modifications as the standard is revised,
etc.
Response: Thank you for your comments.
1. The Supplementary Reference and FAQ documents provide supporting discussion, but are not part of the Standard. The SDT
intends that these be posted as reference documents, accompanying the Standard.
2. The SDT intends that these documents be updated as the Standard is revised, such that they continue to be relevant to the
application of the Standard.
FirstEnergy
November 17, 2010
No
Although we agree that Requirement 1 is important because it establishes a sound PSMP,
a HIGH VRF assignment is not appropriate and it should be changed to LOWER. By
definition, a requirement with a LOWER VRF is administrative in nature, and documentation
of a program is administrative. Assigning a LOWER VRF to R1 is more logical since R4,
which is the requirement to implement the PSMP, is assigned a MEDIUM VRF because, if
violated, it could directly affect the electrical state or the capability of the bulk electric
76
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
system. Additionally, revising the VRF to LOWER would provide a consistent assignment to
a VRF on a similar requirement in the proposed FAC-003-2 standard.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
For a VRF to be classified as “Lower” it must be administrative, and none of the requirements in this standard are ‘administrative’.
Pepco Holdings, Inc. Affiliates
No
An explanation is needed to justify why the VRF for R1 of the PSMP is High whereas the
implementing and following of the PSMP is Medium, R2, R3 & R4.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
American Transmission
Company
No
ATC disagrees with the VRFs as specified in the standard. R1 VRF would more likely be
classified as “medium” and R2 through R4 should be classified as a “High” VRF. ATC is
O.K. with the Time Horizons specified.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
Constellation Power
Generation
No
Constellation Power Generation questions why the VRF for R1 is High while all other
requirements are Medium. This VRF should be changed to Medium to follow suit with the
other requirements.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
Florida Municipal Power
Agency
November 17, 2010
No
R1, R2 and R3 are administrative in nature and ought to be a Low VRF, not a High or
Medium VRF. R4 is doing the actual maintenance and testing and ought to be the highest
VRF in the standard. Medium VRF is appropriate for R4.
77
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
ReliabilityFirst Corp.
No
R4 is the implementation of a maintenance program which is extremely important. Effective
operation of the BES is so dependent on adequate maintenance that requirement R4
warrants a High VRF. It seems that requirement R3 may actually be better categorized as
having an Operations Assessment Time Horizon as the entity needs to review events to
analyze the adequacy of maintenance periods.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
The SDT agrees with the suggestion to change the R3 Time Horizon and has assigned an Operations Planning Time Horizon.
BGE
No
See comments under 7 regarding the ambiguity of R1.1. A high VRF for some
interpretations of R1.1 may not be reasonable. A program may be structured so that
sufficient maintenance to ensure reliability is taking place even though a specific
component is not identified. Contrasting the high VRF for R1 with the medium VRF for R4
seems backwards.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
MRO’s NERC Standards
Review Subcommittee
(NSRS)
No
The NSRS disagrees with the VRFs as specified in the standard. R1 VRF would more
likely be classified as “medium” and R2 through R4 should be classified as a “High” VRF.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
November 17, 2010
78
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
US Bureau of Reclamation
Yes or
No
Question 2 Comment
No
The Time Horizons are too narrow for the implementation of the standard as written. The
SDT appears to have not accounted for the data analysis associated with performance
based systems. The data collection, analysis, and subsequent decisions associated
development of a maintenance program and its justification do not occur overnight
especially with larger utilities. In addition, this new standard will require complete rewrite of
maintenance programs. The internal processes associated with these vary based on the
size of the utility. Since this standard is so invasive into the internal decisions concerning
maintenance, the standard should allow at least 18 months for entities to rewrite their
internal maintenance programs to meet the requirements and 18 months to train the staff
and implement the new program.
Response: Thank you for your comments. The SDT has reviewed the time horizons, and feels that R1 and R2 are properly assigned a
Long-Term Planning Time Horizon, as the activities to develop a program and to determine the monitoring attributes of components are
performed within the related time period. The SDT has assigned an Operations Planning Time Horizon to R3 and R4, as some of the
related activities must take place within 1-year intervals.
Ameren
No
The VRF for R1 should be Medium because the failure to do so is commensurate with the
risks of the other requirements. For example, failing to establish a PSMP for some portion
of the entity’s components could lead to their maintenance not meeting this standard; this is
the same is establishing the PSMP and then not performing the maintenance per the
standard.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
Indeck Energy Services
November 17, 2010
No
The VRF's are highly arbitrary because they treat all registered entities and all protective
systems alike. They're not. For example, under-frequency relays for generators protect the
equipment needed to restore the system after a blackout. The under-frequency load relays
prevent a cascading outage. As discussed at the FERC Technical Conference on
Standards Development, the goal of the standards program is to avoid or prevent
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
cascading outages--specifically not loss of load. That would make under-frequency load
relays more important to prevent cascading outages.
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
The risk to the system is independent of entity size. VSLs have been modified where necessary to make them independent of size of
entity.
Springfield Utility Board
No
1. Time horizons for implementation seem adequate and SUB appreciates the attention to
putting together a reasonable but assertive implementation plan.
2. The Violation Risk Factors are problematic. With all due respect, it seems that NERC
still operates in a "BIG UTILITY" mind set. There are "PROTECTION SYSTEMS" and
there are "Protection Systems" - some Protection Systems may significantly impact
system reliability and others may not. This not promote reliability in that if an entity was
thinking about installing a minor system or installing an improvement that enhances
reliability (but is not required) that it might back away because of the risk associated
with somehow being out of compliance. Reliability runs the risk of being diminished
through the standards approach. SUB suggests stepping back and putting more
granularity on VRFs and there needs to be more perspective on the purpose of the
device when arriving at a risk factor. Perhaps a voltage threshold could be attached to
the VRFs. For example language could be added to say "For Elements at 200kV and
above, or for Critical Assets, the risk factor is higher" and "For Elements operating at
100kV and above, the risk factor is medium" and "For Elements below 100kV, the risk
factor is lower" In SUB's view, a discussion on VRF's needs to coupled with Violation
Severity Levels. SUB discusses VRF's later in this comment form. SUB would be
supportive of a Medium VRF designation if there were a more balanced VLF structure
(please refer to the comments of VLFs)
Response: Thank you for your comments. The SDT has reconsidered the VRFs in accordance with the guidance provided by NERC
and FERC, and the Standard has been modified to assign the VRFs as R1 – Medium, R2 – Medium, R3 – Medium, and R4 – High.
November 17, 2010
80
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 2 Comment
According to the current Reliability Standards Development Procedure, each Requirement is assigned one (and only one) VRF.
Manitoba Hydro
No
Time horizons to change from present 6 months to 3 months maintenance time intervals
within proposed implementation time period is not realistic.
Response: Thank you for your comments. The options for Time Horizon are Long-Term Planning, Operations Planning, Same-Day
Operations, Real-Time Operations, and Operations Assessment. The SDT has reviewed the Time Horizons, and feels that R1 and R2
are properly assigned a Long-Term Planning time horizon, as the activities to develop a program and to determine the monitoring
attributes of components is performed within the related time period. The SDT has assigned an Operations Planning Time Horizon to
R3 and R4, as some of the related activities must take place within 1-year intervals.
American Electric Power
Yes
Arizona Public Service
Company
Yes
Bonneville Power
Administration
Yes
Consumers Energy
Company
Yes
Duke Energy
Yes
Dynegy Inc.
Yes
Entergy Services
Yes
Exelon
Yes
November 17, 2010
81
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Great River Energy
Yes
Hydro One Networks
Yes
Long Island Power
Authority
Yes
MEAG Power
Yes
MidAmerican Energy
Company
Yes
Northeast Power
Coordinating Council
Yes
Northeast Utilities
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PNGC Power
Yes
Progress Energy Carolinas
Yes
Public Service Enterprise
Group ("PSEG
Companies")
Yes
November 17, 2010
Question 2 Comment
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Santee Cooper
Yes
South Carolina Electric and
Gas
Yes
Southern Company
Transmission
Yes
Tennessee Valley Authority
Yes
We Energies
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Inc.
Yes
PacifiCorp
Yes
Question 2 Comment
Agree with the exception that the time horizon for implementation needs to recognize that
documentation for maintenance tasks performed prior to this standard may not match
current requirements and there should be no penalty for this.
Response: Thank you for your comments. The Implementation Plan needs to address the concerns expressed.
Nebraska Public Power
District
Yes
Please provide an example of how the compliance percentage will be calculated for the
implementation plan.
Response: Thank you for your comments. The SDT does not understand how this comment relates to the VRFs or to the Time
Horizons.
November 17, 2010
83
Consideration of Comments on PSMTSDT — Project 2007-17
3. The SDT has included Measures and Data Retention with this posting. Do you agree with
the assignments that have been made? If not, please provide specific suggestions for
improvement.
Summary Consideration: Many commenters expressed concern about the data retention requirements
for two full maintenance intervals, and the SDT responded that this is consistent with today’s expectations
of many Compliance Monitors. Other commenters were concerned about data retention over the
transition from PRC-005-1 to two full maintenance intervals for PRC-005-2, and the SDT offered advice
that, until two maintenance cycles have been experienced under PRC-005-2, the program and associated
documentation for PRC-005-1 will still be relevant.
Comments were offered that “on-site” audits as expressed in the Data Retention Section (item 1.3 under
Compliance) are not relevant for small entities which are not audited on-site; the SDT agrees and changed
the term to “scheduled” audits.
Several commenters offered suggestions relative to the Measures, resulting in changes to all four
Measures. The SDT removed the detailed Protection System definition from Measure M1, inserted
“Distribution Provider” in Measure M2, and made changes to consistently use “shall” rather than “will” or
“should” throughout all the Measures.
Organization
WECC
Yes or
No
Question 3 Comment
1. Compliance agrees with the measures.
2. Compliance recommends making the Supplementary Reference part of the standard
and that it be referenced appropriately in Table 1a, 1b, 1c and Attachment A.
3. Compliance does not agree with the Data Retention as provided in the draft. In order
for an entity to demonstrate that they have maintained system protection elements
within their defined intervals retention of documentation will be required for many years.
November 17, 2010
84
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
This is in order to establish bookends for the maintenance interval. Maintenance
intervals commonly span 5 years or more. Entities should be required to retain data for
the entire period of the maintenance interval.
Data Retention should be changed to: The Transmission Owner and any Distribution
Provider that owns a transmission Protection System and each Generation Owner that
owns a generation Protection System, shall retain evidence of the implementation of its
Protection System maintenance and testing program for a minimum of the duration of
one maintenance interval as defined in the maintenance and testing program.
Response: Thank you for your comments.
1. Thank you.
2. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a Reference
Document, accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of
requirements, etc, and is not to include explanatory information like that included in the Supplementary Reference Document.
3. The SDT believes that the modification suggested in the comment is not sufficient to demonstrate compliance. In order that a
Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding one. The SDT has specified the data retention in the
posted Standard to establish this level of documentation.
Xcel Energy
No comments
San Diego Gas & Electric
No
The Detroit Edison
Company
No
Ameren
No
1) M2 incorrectly excludes Distribution Provider.
2) For those components with numerous cycles between on-site audits, retaining and
November 17, 2010
85
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
providing evidence of the two most recent distinct maintenance performances and the
date of the others should be sufficient. If an entity misses a required maintenance, that
results in a self report. We are subject to spot audits and inquiries at any time between
on-site audits as well.
3) For those components with cycles exceeding on-site audit interval, retaining and
providing evidence of the most recent distinct maintenance performance and the date of
the preceding one should be sufficient. Auditors will have reviewed the preceding
maintenance record. Retaining these additional records consumes resources with no
reliability gain.
4) FAQ II 2B final sentence states that documentation for replaced equipment must be
retained to prove the interval of its maintenance. We oppose this because: the replaced
equipment is gone and has no impact on BES reliability; and such retention clutters the
data base and could cause confusion. For example, it could result in saving lead acid
battery load test data beyond the life of its replacement.
Response: Thank you for your comments.
1. Distribution Provider has been added to Measure M2.
2. The SDT understands that Compliance Monitors will usually wish to review data to review program performance back to the
preceding on-site audit.
3. The SDT believes that the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the
data of the preceding one. The SDT has specified the data retention in the posted Standard to establish this level of
documentation. The SDT understands that Compliance Monitors are currenlty requesting data on retired components to validate
that entities have been in compliance since the last audit (or currently, since the beginning of mandatory compliance), and believes
that this suggestion in the FAQ is appropriate.
Northeast Power
Coordinating Council
November 17, 2010
No
1. Clarification is needed for “on-site audit” - does it include audits by any of the following NPCC/NERC/FERC. Several small entities do not have on-site audits and participate in
86
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
off-site audits. Hence, suggest deleting “on-site” from the requirement.
2. Further clarification is required to the Data Retention section to coordinate with the
statement in FAQ (Section IV.d p. 22 redline). Suggest the following revised Data
Retention requirement consistent with the statement and example given in FAQ:”The
Transmission Owner, Generator Owner, and Distribution Provider shall each retain at
least two maintenance test records or statistical data to demonstrate compliance with
test interval required for each distinct maintenance activity for the Protection System
components. The Compliance Enforcement Authority shall keep the last periodic audit
report and all requested and submitted subsequent compliance records.”
Response: Thank you for your comments.
1. We have modified “on-site” to “scheduled” to address this comment.
2. The SDT was unable to locate the discussion from the comment within the FAQ.
Constellation Power
Generation
No
Constellation Power Generation does not agree with the proposed data retention section.
Retaining and providing evidence of the two most recent performances of each distinct
maintenance activity should be sufficient. For entities that have not been audited since
June of 2007, having to retain evidence from that date to the date of an audit could contain
numerous cycles, which is cumbersome and does not improve the reliability of the BES.
Response: Thank you for your comments. For shorter-interval activities (such as those with quarterly intervals), the SDT understands
that Compliance Monitors are currently requesting data to validate that entities have been in compliance since the last audit (or
currently, since the beginning of mandatory compliance) or for the duration specified in a standard.
JEA
No
November 17, 2010
Data retention becomes a complex issue for maintenance intervals of 12 years where the
last two test intervals are required to be kept, i.e. 24 years. It would seem much more
reasonable to set a limit of two test intervals or the last regional audit, not having to keep
some 24 years of documentation with maintenance systems changing and archival records
87
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
somewhat problematic to keep.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one. The SDT has specified the data retention in the posted standard to establish this level of documentation.
Public Service Enterprise
Group ("PSEG
Companies")
No
Data retention for battery capacity test should be most recent performance, not last 2. The
other maintenance activities documentation with one iteration of capacity test is sufficient
documentation
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one, as well as data to validate that entities have been in compliance since the last audit (or currently, since the beginning of mandatory
compliance). The SDT has specified the data retention in the posted Standard to establish this level of documentation.
PacifiCorp
No
Data retention requirements need to be modified. The need to maintain records of two
previous tasks is excessive, one should be adequate. Per the two previous task
requirements an entity may need to maintain records for 35 years.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one, as well as data to validate that entities have been in compliance since the last audit (or currently, since the beginning of mandatory
compliance). The SDT has specified the data retention in the posted Standard to establish this level of documentation.
Progress Energy Carolinas
No
M2 incorrectly excludes Distribution Provider.
Response: Thank you for your comments. Measure M2 has been modified to add “Distribution Provider.”
Duke Energy
November 17, 2010
No
M4 states that entities shall have evidence such as maintenance records or maintenance
summaries (including dates that the components were maintained). We would like to see
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
M4 revised/expanded to explicitly include the FAQ Section IV 1.B information which states
that forms of evidence that are acceptable include, but are not limited to:
o Process documents or plans
o Data (such as relay settings sheets, photos, SCADA, and test records)
o Database screen shots that demonstrate compliance information
o Diagrams, engineering prints, schematics, maintenance and testing records, etc.
o Logs (operator, substation, and other types of log)
o Inspection forms
o U.S. or Canadian mail, memos, or email proving the required information was exchanged,
coordinated, submitted or received
o Database lists and records
o Check-off forms (paper or electronic)
o Any record that demonstrates that the maintenance activity was known and accounted
for.
Response: Thank you for your comments. The Standard Development Procedure requires that Measures provide some examples of
evidence, but does not require an exhaustive list. The SDT did add “check-off lists” and “inspection records.”
Indeck Energy Services
No
Measure 1 is complete overkill for a small generating facility. The maintenance program is
to inspect and test the equipment within the intervals. A qualified contractor applies
industry standard methods to maintain the equipment. Trying to have each entity define
the maintenance program down to the component level does not improve reliability.
Response: Thank you for your comments. A definition of “Component” has been added to the draft PRC-005-2 Standard to help
explain how “component” can be characterized.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
PPL Supply
Yes or
No
Question 3 Comment
No
1. Measurers M1 - requires having a maintenance program that addresses control circuitry
associated with protective functions from the station dc supply through the trip coil(s) of
the circuit breakers. Some generators do not own this equipment to the circuit breaker
or other interrupting devices. The requirement should be to maintain and test the
equipment owned by the generator.
2. Data Retention 1.3 references on-site audits. Entities registered as GO and GOP are
not audited on-site.
Response: Thank you for your comments.
1. The SDT believes that “its Protection Systems” in Requirement R1 is synonymous with “Protection Systems that it owns” and
declines to modify the Standard to address this comment.
2. We have modified “on-site” to “scheduled” to address this comment.
Arizona Public Service
Company
No
The change to the Protection System definition and establishing a PSMP with prescriptive
maintenance activities relative to the voltage and current sensing devices has created a
situation where data from original or prior verification not being available or not at the
interval to meet the data retention requirement. Although, methods of determining the
integrity of the voltage and current inputs into the relays were used to ensure reliability of
the devices meets the utilities requirements, they may not meet the interval requirement
and would then be considered a violation due to changes in the standard. Recommend a
single exemption of the two recent most recent performances of maintenance activities to
the most recent performance of maintenance activity in the first maintenance interval for
this component due to the long maintenance interval, the changes in the standard
definitions and the prescriptive maintenance activities.
Response: Thank you for your comments. The SDT believes that Compliance Monitors will assess compliance for activities performed
before the effective date of this Standard using the program that you had in place previously.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
American Electric Power
Yes or
No
Question 3 Comment
No
1. The measure includes the entire definition of "Protection System". Remove the definition
from the measure and let the definition stand alone in the NERC glossary.
2. 1.3 Data Retention This calls for past 2 distinct maintenance records to be kept. Since
UFLS interval can be 12 years, this would mean that we would need to keep records for
24 years. This is not realistic and consideration should be given to choosing a
reasonable retention threshold.
Response: Thank you for your comments.
1. Measure M2 has been modified as suggested.
2. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data
of the most recent performance of the maintenance, as well as the data of the preceding one, as well as data to validate that entities
have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified
the data retention in the posted Standard to establish this level of documentation.
Springfield Utility Board
November 17, 2010
No
The measures do not seem unreasonable. However the data retention states that
documentation must exist for the two most recent performances of each maintenance
activity. Stepping back, there is an implementation schedule that is designed to bring all
devices into compliance with ONE maintenance or test within (SUB's understanding is) 6
years. There may not be documentation for more than one activity. Further, new or
replacement components won't have more than one activity for a number of years. The
data retention schedule, left unchanged, will promote non-compliance because it is
impossible to have two records when only one may possibly exist. Rather than promote a
culture of compliance, the standard promotes a culture of non-compliance by creating an
standard that cannot be met. The FAQ addresses this issue, but the Data Retention
language seems to be less clear. SUB suggests that the Data Retention language be clear
that new components that do not replace existing components may have only one record
for maintenance if only one maintenance of the component could possibly exist. SUB
suggests that the Data Retention language also be clear that for new components that
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
replace existing components, that the Data Retention requirement reflect that the entity
needs to retain the last test for the pre-existing component and the test for the new
component (for a total of two tests).
Response: Thank you for your comments. First of all, the Data Retention presumes a stable Standard that has been in effect.
Further, the SDT believes that Compliance Monitors will assess compliance for activities performed before the effective date of this
Standard using the program that you had in place previously. Therefore, the documentation for your program under PRC-005-1
(whatever it may have been) will serve as your “second interval” documentation until supplanted by new PRC-005-2 records.
US Bureau of Reclamation
No
The measures M2, M3, and M4 are redundant to measure M1. Either eliminate M1 or M2
through M4. The entity must provide documentation of its maintenance program in M1
irrespective of the type used. As previously mentioned there is not reliability based
justification for the documentation required. The Entity should be afforded the freedom to
make intelligent maintenance choices based on innumerable factors. These choices will be
reviewed if a reliability impact is determined to be related to the choices.
Response: Thank you for your comments. The NERC Reliability Standard Development Procedure establishes that each individual
requirement will have its own Measure. Additionally, the four Measures are NOT redundant – Measure M1 addresses “having a
program,” Measure M2 addresses “monitoring attributes to use extended intervals in the Tables,” Measure M3 addresses “criteria for a
performance-based program,” and Measure M4 addresses “implementation of the program.”
American Transmission
Company
No
The NERC standard assigns a retention period for the two most recent performances of
maintenance activity which implies two intervals of documentation be maintained. ATC
does not agree that requiring all data for two full cycles is warranted. The volume and
length of data retention is unreasonable. ATC recommends that the entity retain the last
test date with the associated data, plus the prior cycle test date only without retaining the
test data. ATC agrees with assignment of the measures.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
one. The SDT has specified the data retention in the posted Standard to establish this level of documentation.
MRO’s NERC Standards
Review Subcommittee
(NSRS)
No
The NERC standard assigns a retention period for the two most recent performances of
maintenance activity which implies two intervals of documentation being maintained. The
NSRS does not agree that requiring all data for two full cycles is warranted. The volume
and length of data retention is unreasonable. The NSRS recommends that the entity retain
the last test date with the associated data, plus the prior cycle test date only without
retaining the test data.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one. The SDT has specified the data retention in the posted Standard to establish this level of documentation.
Pepco Holdings, Inc. Affiliates
November 17, 2010
No
The present wording regarding data retention states - The Transmission Owner, Generator
Owner, and Distribution Provider shall each retain documentation of the two most recent
performances of each distinct maintenance activity for the Protection System components,
or to the previous on-site audit date, whichever is longer. This wording was changed by the
SDT following comments received from Draft 1. However, the present wording is
somewhat confusing. It is assumed that the intent of the SDT was to require
documentation be retained for the two most recent performances of each distinct
maintenance activity, regardless of when they occurred (i.e., whether prior to, or since the
last audit), since the phrase whichever is longer was used. In addition, for those activities
requiring short maintenance intervals (such as battery inspections), records must be kept
for all performances (not just the last two) that have taken place since the last on-site audit.
For example: Assume a PSMP with a 6 year interval for relay maintenance and 3 month
interval for battery inspections. At a particular station assume the batteries have been
inspected every 3 months; the relays were last inspected 5 years ago, and before that 11
years ago. The last audit was 2 years ago. Records from each 3 month battery inspection
going back to the last audit needs to be retained. Also, both relay maintenance records
from 5 and 11 years ago needs to be retained, despite the fact that this interval should
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
have been reviewed during the last audit. Documentation from the 11 year ago activity can
be discarded when the relays are next maintained.
Is this what the SDT intended? If
so, the requirement should be re-worded to better explain the intent. Also, examples
should be included in either the FAQ or Supplemental Reference to demonstrate what is
expected.
Response: Thank you for your comments. You understand the data retention correctly as intended by the SDT and specified in the
draft standard. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will
need the data of the most recent performance of the maintenance, as well as the data of the preceding one, as well as data to validate
that entities have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has
specified the data retention in the posted Standard to establish this level of documentation. .
We Energies
No
The requirement to retain data for the two most recent maintenance cycles is excessive.
The required data should be limited to the complete data for the most recent cycle, and
only the test date for the previous cycle.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one. The SDT has specified the data retention in the posted Standard to establish this level of documentation.
Long Island Power
Authority
No
1. Two most recent performances of each distinct maintenance activity for the Protection
System components will require data retention for an extended period of time. For
example, in certain cases, battery maintenance is on a 12 year cycle which suggests
that records need to be retained for 24 years. LIPA suggests retaining data for the most
recent maintenance activity.
2. LIPA seeks clarification on “on-site audit” - does it include audits by any of the following
- NPCC/NERC/FERC. Also, several small entities do not have on-site audits and
participate in off-site audits. Hence, LIPA suggests deleting “on-site” from the
requirement. In addition further clarification is required to the Data Retention section to
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
coordinate with the statement in FAQ (Section IV.d p. 22 redline).
Response: Thank you for your comments.
1. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data
of the most recent performance of the maintenance, as well as the data of the preceding one; thus, records for maintenance which
is performed every 12 years will need to be retained for 24 years.. The SDT has specified the data retention in the posted Standard
to establish this level of documentation. Audits may be by any of the entities listed. The term “on-site” has been replaced by
“scheduled” to address your concern.
Northeast Utilities
No
Two most recent performances of each distinct maintenance activity for the Protection
System components will require data retention for an extended period of time. From the
FAQ, it is understood that “the intent is not to have three test result providing two time
intervals, but rather have two test results proving the last interval”. However two intervals
still results in an extended period of time. For example, for a twelve year interval, data
would need to be retained for ~24 years. During that period of time a number of on-site
audits would have been completed - it is not clear why the requirement is the longer of the
two most recent performances or to the previous on site audit date.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one. The SDT has specified the data retention in the posted Standard to establish this level of documentation.
MidAmerican Energy
Company
No
Verification of compliance with the maximum time intervals for testing only needs to include
retention of the documentation of the two most recent maintenance activities. The phrase
“or to the previous on-site audit (whichever is longer)” should be deleted.
Response: Thank you for your comments. In order that a Compliance Monitor can be assured of compliance, the SDT believes that
the Compliance Monitor will need the data of the most recent performance of the maintenance, as well as the data of the preceding
one, as well as data to validate that entities have been in compliance since the last audit (or currently, since the beginning of mandatory
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
compliance). The SDT has specified the data retention in the posted Standard to establish this level of documentation.
BGE
Yes
Black Hills Power
Yes
Bonneville Power
Administration
Yes
Consumers Energy
Company
Yes
Dynegy Inc.
Yes
Entergy Services
Yes
Exelon
Yes
Great River Energy
Yes
Hydro One Networks
Yes
MEAG Power
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PNGC Power
Yes
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
ReliabilityFirst Corp.
Yes
Southern Company
Transmission
Yes
The United Illuminating
Company
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Inc.
Yes
South Carolina Electric and
Gas
Yes
Question 3 Comment
(Note that Section C.M2 leaves off "Distribution Provider" but references Requirement R2
at the end of the Section. "R2 applies to the Distribution Provider.")
Response: Thank you for your comments. Measure M2 has been modified to add “Distribution Provider.”.
Nebraska Public Power
District
Yes
Additional guidance on what is acceptable evidence is always good.
Response: Thank you for your comments. In addition to the lists within the Measures, the FAQ (IV.1.B) and Section 15.7 of the
Supplementary Reference Document provide additional guidance about acceptable evidence.
Florida Municipal Power
Agency
Yes
M1 could be shortened to just a program in accordance with R1, rather than repeat the
entire requirement
Response: Thanks you for your comments. The restatement of the definition has been removed from Measure M1, but the Reliability
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
Standards Development Procedure specifies that Measures contain levels of detail similar to Measure M1 as posted.
NERC Staff
Yes
Make sure that the use of verbs like “shall,” “should,” and “will” is consistent across
Requirements and Measures. In these four measures, all three verbs are used, and they
should be made uniform to avoid misinterpretation.
Response: Thank you for your comments. The Measures have been modified to consistently use “shall.”
Manitoba Hydro
Yes
No issues or concerns at present
Yes
The SERC PCS expresses no comments on this question.
Yes
We agree with the Measures but suggest some improvements:
Response: Thank you.
SERC Protection and
Control Sub-committee
(PCS)
Response: Thank you.
FirstEnergy
1. In Measures M2 and M3, the term "should" must be changed to "shall"
2. In Measure M2, the Distribution Provider entity is missing
Response: Thank you for your comments.
1. Measure M2 and Measure M3 have been modified as suggested.
2. Distribution Provider has been added to Measure M2.
Santee Cooper
November 17, 2010
Yes
We are concerned with the long-term implementation of the data retention requirements for
activities with long maximum intervals. For example, if you are performing an activity that is
required every 12 years, the implementation plan says that you should be 100% compliant
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 3 Comment
in 12 years following regulatory approval. However, assuming that 100% compliant meant
that you got through all of your components once, you still would not be able to show the
last two test dates. 12 years from now, would you still have to discuss the program you
were using prior to 12 years ago for those components to have a complete audit, because
of having to address the last 2 test dates?
Response: Thank you for your comments. First of all, the Data Retention presumes a stable Standard that has been in effect.
Further, the SDT believes that Compliance Monitors will assess compliance for activities performed before the effective date of this
Standard using the program that you had in place previously. Therefore, the documentation for your program under PRC-005-1
(whatever it may have been) will serve as your “second interval” documentation until supplanted by new PRC-005-2 records.
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Consideration of Comments on PSMTSDT — Project 2007-17
4. The SDT has included VSLs with this posting. Do you agree with the assignments that have
been made? If not, please provide specific suggestions for change.
Summary Consideration: Many commenters were concerned about the basis for the percentage
increments for different severities of VSLs; these commenters were referred to the VSL Guidelines which
propose a Lower VSL as noncompliant with “5% or less,” the Medium VSL as “more than 5% but less than
(or equal to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the Severe VSL as
“more than 15% noncompliant.”.
Similarly, many commenters suggested that binary VSLs be assigned a Lower or High rather than a
Severe, and were also referred to the VSL Guidelines which indicate that total noncompliance with a
requirement is a Severe VSL. VSLs are not indicators of “importance” or “reliability-related risk” – VSLs
are an indication of the degree of noncompliant performance.
The VSL for Requirement R4 was modified to add stepped VSLs relating to resolution of maintenancecorrectable issues in response to several comments.
Several commenters suggested that the Lower VSL for R4 start at 1% rather than 5%, which is not in
accordance with the VSL Guidelines.
Organization
Yes or
No
Question 4 Comment
PPL Supply
No Comment.
Xcel Energy
No comments
San Diego Gas & Electric
No
The Detroit Edison
No
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
Company
GDS Associates
No
1. We do agree with the majority of the assignments that have been made, however the
standard needs specific guidance so to be clearly evidentiated the components as
included in the definition of Protection System. The applicability of the standard does
not address the current issues regarding radial + load serving only situation when
Protection System not designed to provide protection for the BES.
2. Not sure if the percentages corresponding to the events and activities are appropriately
assigned. What were the criteria on which all these percentages are based upon?
3. Requirement R3 Severe VSL note 3 allows smaller segment population than the Lower
VSL. How these segment limits were developed?
Response: Thank you for your comments.
1. This is an issue related to your Regional BES definition, not to the VSLs.
2. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the Lower VSL for stepped VSLs as “5% or
less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including)
15%,” and the Severe VSL as “more than 15%.”
3. The segment limits for Requirement R3 and Attachment A were developed according to statistical references to assure that
performance-based programs are based on a statistically-significant population. See Section 9 of the Supplementary Reference
Document. The Lower VSL addresses “a slightly smaller segment population” than specified; the Severe VSL addresses “a
significantly smaller segment population” than specified.
Ameren
November 17, 2010
No
1) The Lower VSL for all Requirements should begin above 1% of the components. For
example for R4: “Entity has failed to complete scheduled program on 1% to 5% of total
Protection System components.” PRC-005-2 unrealistically mandates perfection without
providing technical justification. A basic premise of engineering is to allow for reasonable
tolerances, even Six Sigma allows for defects. Requiring perfection may well harm
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
reliability in that valuable resources will be distracted from other duties.
2) In R1, a “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based. It is possible
that a component that failed to be individually identified per R1.1 was included by entity
A’s maintenance plan. This documentation issue gets a higher VSL than entity B that
identified a component without maintaining it. We suggest the R1 VSL be change to Low,
since we believe lack of maintenance to be more severe than documentation issues.
Response: Thank you for your comments.
1. The SDT shares your concerns regarding the Lower VSL portion of the stepped VSLs not providing any tolerance for nonconformance without being non-compliant. However, the VSL Guidelines, which conform to the FERC VSL Order, specify that
Lower shall be “5% or less.”
2. The VSL for Requirement R1 addresses various levels of severity for degrees of non-compliance. The VSL Guidelines, developed
in accordance with the FERC VSL Order, establish that if only a single VSL is provided, it must be Severe. The reliability-related
risk related to noncompliance with this requirement is addressed by the VRF being assigned as Lower.
Entergy Services
No
1. R4: A “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
2. R4: Suggest a stepped VSL for “Entity has failed to initiate resolution of maintenancecorrectable issues”. While we understand the importance of addressing a correctable
issue, it seems like there should be some allowance for an isolated unintentional failure to
address a correctable issue. If possible, consider the potential impact to the system. For
example, a failure to address a pilot scheme correctable issue for an entity that only
employs pilot schemes for system stability applications should not necessarily have the
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
same VSL consequence as an entity which employs pilot schemes everywhere on their
system as a standard practice.
Response: Thank you for your comments.
1. This actually addresses the VSL for Requirement R1, which addresses various levels of severity for degrees of non-compliance.
The risk related to this is addressed by the VRF being assigned as Lower.
2. The VSL for Requirement R4 has been modified to provide stepped VSLs for initiation of resolution of maintenance-correctable
issues.
WECC
No
Compliance does not agree. The R1 VSL allows too much to interpret. What does no
more than 5% of the component actually use to define the percentage; it should be specific
if it is referring to the weight of each component and how many components are there. For
example, Protective Relay is one component of five. In addition the VSL for Lower,
Moderate and High states in the first paragraph that the entity included all of the “Types” of
components according to the definition, though failed to “Identify the Component”. It needs
clarity on how it can be included though not specifically identified like the next two bullets.
The same concern applies to R2 and R4. Be specific about what is included (or not) to
calculate those percentages.
Response: Thank you for your comments. The percentages will depend to a large degree how the entity describes their components.
A definition of “Component” has been added to the Standard to provide guidance and help provide consistency.
Constellation Power
Generation
No
Constellation Power Generation does not agree with the proposed data retention section.
Retaining and providing evidence of the two most recent performances of each distinct
maintenance activity should be sufficient. For entities that have not been audited since
June of 2007, having to retain evidence from that date to the date of an audit could contain
numerous cycles, which is cumbersome and does not improve the reliability of the BES.
Response: Thank you for your comments. This comment is not relevant to VSLs. In order for a Compliance Monitor to be assured of
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Organization
Yes or
No
Question 4 Comment
compliance, the SDT believes that the Compliance Monitor will need the data of the most recent performance of the maintenance, as
well as the data of the preceding one, as well as data to validate that entities have been in compliance since the last audit (or currently,
since the beginning of mandatory compliance). The SDT has specified the data retention in the posted Standard to establish this level
of documentation.
Northeast Utilities
No
For R1 under Severe VSL - suggest moving the first criteria “The entity’s PSMP failed to
address one or more of the type of components included in the definition of “Protection
System” under High VSL since this criteria cannot have the same VSL level as “Entity has
not established a PSMP”.
Response: Thank you for your comments. The SDT believes that, if an entity has missed one (of the five) entire component types in
their program, they do not have a complete program.
Florida Municipal Power
Agency
No
1. For the VSLs of R1 and R2, we do not understand where the 5%, 10% come from.
There are only a few types of components, relays, batteries, current transformers and
voltage transformers, DC control circuitry, communication, that’s 6 component types by
our count, so, missing 1 component type in discussing the type of maintenance program
is already a 17% error and Low, Medium and High VSLs are meaningless as currently
drafted and every violation would be Severe, was the intention to apply this is a different
fashion?
2. Perfection is Not A Realistic Goal R4 allows no mistakes. Even the famous six sigma
quality management program allows for defects and failures (i.e., six sigma is six
standard deviations, which means that statistically, there are events that fall outside of
six standard deviations). PRC-005 has been drafted such that any failure is a violation,
e.g., 1 day late on a single relay test of tens of thousands of relays is a violation. That is
not in alignment with worldwide accepted quality management practices (and also
makes audits very painful because statistical, random sampling should be the mode of
audit, not 100% review as is currently being done in many instances). FMPA suggests
considering statistically based performance metrics as opposed to an unrealistic
performance target that does not allow for any failure ever. Due to the shear volume of
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
relays, with 100% performance required, if the standards remain this way, PRC-005 will
likely be in the top ten most violated standards for the forever. In other words, 1-2% of
components outside of the program should be allowed without a violation and Low VSL
should start at a non-zero number, such as “Entity failed to complete scheduled
program for 3-6% of components based on a statistically significant random sampling”
or something to that affect.
3. There is a fundamental flaw in thinking about reliability of the BES. We are really not
trying to eliminate the risk of a widespread blackout; we are trying to reduce the risk of a
widespread blackout. We plan and operate the system to single and credible double
contingencies and to finite operating and planning reserves. To eliminate the risk, we
would need to plan and operate to an infinite number of contingencies, and have an
infinite reserve margin, which is infeasible. Therefore, by definition, there is a finite risk
of a widespread blackout that we are trying to reduce, not eliminate, and, by definition,
by planning and operating to single and credible double contingencies and finite
operating and planning reserves, we are actually defining the level of risk from a
statistical basis we are willing to take. With that in mind, it does not make sense to
require 100% compliance to avoid a smaller risk (relays) when we are planning to a
specified level of risk with more major risk factors (single and credible double
contingencies and finite planning and operating reserves).
Response: Thank you for your comments.
1. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the Lower VSL for stepped VSLs as “5% or
less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including)
15%,” and the Severe VSL as “more than 15%.” Much of this comment seems to relate to the VSL for Requirement R1; this VSL
has been extensively revised, and additional terms have been added to the Definitions section to clarify.
2. The SDT shares your concerns regarding the Lower VSL portion of the stepped VSLs not providing any tolerance for nonconformance without being non-compliant. However, the VSL Guidelines, which conform to the FERC VSL Order, specify that
Lower shall be “5% or less.” The VRF and VSLs are only a starting point in determining the size of a penalty or sanction – the
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
Compliance Enforcement Authority has latitude to consider aggravating factors and mitigating factors in determining whether there
should be any penalty, and the size of any penalty. These mitigating and aggravating factors are oultined in the Compliance
Monitoring and Enforcement Program. http://www.nerc.com/files/Appendix4C_Uniform_CMEP_10022009.pdf
3. The SDT believes that Protection Systems that trip (or can trip) the BES should be included. This position is consistent with the
currently-approved PRC-005-1, consistent with the SAR for Project 2007-17, and understands this to be consistent with the position
of FERC staff. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in
violation.
Santee Cooper
No
In R1, a “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance.
SERC Protection and
Control Sub-committee
(PCS)
No
In R1, a “Failure to specify whether a component is being addressed by time-based,
condition-based, or performance-based maintenance” by itself is a documentation issue
and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance.
Progress Energy Carolinas
No
In the VSL for R1, a failure to “specify whether a component is being addressed by timebased, condition-based, or performance-based maintenance” by itself is a documentation
issue and not an equipment maintenance issue. Suggest this warrants only a lower VSL,
especially when one of the required components can only be time based.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of nonNovember 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
compliance.
Pacific Northwest Small
Public Power Utility
Comment Group
No
is possible that a component that failed to be individually identified per R1.1 was included
by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B
that identified a component without maintaining it. We suggest the R1 VSL be change to
Low, since we believe lack of maintenance to be more severe than documentation issues.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance. The risk related to non-compliance with the various requirements is addressed by assignment of the associated VRFs.
Additionally, Requirement R1 and the associated VSLs have been substantially modified, and may address your concern.
Pepco Holdings, Inc. Affiliates
No
It is possible that a component that failed to be individually identified per R1.1 was included
by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B
that identified a component without maintaining it. We suggest the R1 VSL be change to
Low, since we believe lack of maintenance to be more severe than documentation issues.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance.
PNGC Power
No
It is possible that a component that failed to be individually identified per R1.1 was included
by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B
that identified a component without maintaining it. We suggest the R1 VSL be change to
Low, since we believe lack of maintenance to be more severe than documentation issues.
Response: Thank you for your comments. The VSL for Requirement R1 addresses various levels of severity for degrees of noncompliance.
Long Island Power
Authority
November 17, 2010
No
1. R4 under Severe VSL mentions - Entity has failed to initiate resolution of maintenancecorrectable issues. What proofs will satisfy the requirement that the entity has initiated the
resolution.
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
2. R1 under Severe VSL - LIPA suggests moving the first criteria “The entity’s PSMP failed
to address one or more of the type of components included in the definition of “Protection
System” under High VSL since this criteria cannot have the same VSL level as “Entity has
not established a PSMP”.
Response: Thank you for your comments.
1. The SDT is unable to categorically state what will satisfy a Compliance Monitor, but it seems that a work order addressing the
maintenance-correctable issue would be one example. FAQ IV.1.B and Section 15.7 of the Supplementary Reference Document
may also be helpful.
2. The SDT believes that if an entity has missed one (of the five) entire component types in their program, they do not have a complete
program.
Northeast Power
Coordinating Council
No
1. R4 under Severe VSL mentions - Entity has failed to initiate resolution of maintenancecorrectable issues. What proof will satisfy the requirement that the entity has initiated
the resolution?
2. R1 under Severe VSL - Move the first criteria “The entity’s PSMP failed to address one
or more of the type of components included in the definition of ‘Protection System’”
under High VSL since this criteria cannot have the same VSL level as “Entity has not
established a PSMP”.
Response: Thank you for your comments.
1. The SDT is unable to categorically state what will satisfy a Compliance Monitor, but it seems that a work order addressing the
maintenance-correctable issue would be one example. FAQ IV.1.B and Section 15.7 of the Supplementary Reference Document
may also be helpful.
2. The SDT believes that if an entity has missed one (of the five) entire component types in their program, they do not have a complete
program.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
MidAmerican Energy
Company
Yes or
No
No
Question 4 Comment
The lower VSL specification for R4 should allow for a small level of incomplete testing.
Suggest changing “5% or less” to “from 1% to 5%”.
Response: Thank you for your comments. The SDT shares your concerns regarding the Lower VSL portion of the stepped VSLs not
providing any tolerance for non-conformance without being non-compliant. However, the VSL Guidelines, which conform to the
FERC VSL Order, specify that Lower shall be “5% or less.”The VRF and VSLs are only a starting point in determining the size of a
penalty or sanction – the Compliance Enforcement Authority has latitude to consider aggravating factors and mitigating factors in
determining whether there should be any penalty, and the size of any penalty. These mitigating and aggravating factors are oultined
in the Compliance Monitoring and Enforcement Program. http://www.nerc.com/files/Appendix4C_Uniform_CMEP_10022009.pdf
Springfield Utility Board
No
The Violation Risk Factors are problematic.
1. With all due respect, it seems that NERC still operates in a "BIG UTILITY" mind set. Big
utilities have potentially hundreds or thousands of components under different device
types. Looking at the VRFs, the percentages 5% or 15% as an example, are looked at
based on a deep pool of multiple devices so a "BIG UTILITY" that misses a component
or small number of components may not trigger a high severity level. However a small
utility may have only a handful of components under each type. Therefore if the small
utility were to miss one component all of a sudden the utility automatically triggers the
5% or 15% threshold. This type of dynamic unreasonable and not equitable. Therefore
(in an attempt to work within the framework proposed), SUB proposes that there be a
minimum number of components that might not be in compliance which result in a much
lower Violation Severity Level. SUB suggests that NERC try to create a level playing
field. If 15% of a Big Utility's total number of components averages at around 15 out of
100 total then perhaps a reasonable outcome would be that up to 5 components
(regardless of the total number of components an entity has under each type) could be
in violation without tripping into a high VSL.(the 5 components threshold may not apply
to all types, this is just for illustrative purposes).
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
2. Also, are the missed components compounding? For example, if an entity missed 5
components on year three and another 5 components in year 10 is the VSL based on
10 components or 5 components. There should be a time horizon attached to the VSL
such that the VSL does not count prior components that were brought into compliance
through a past action. That intent may be to not have the VSLs be based on
compounding numbers of components; however that should be made clear.
Response: Thank you for your comments. You discussed VRFs, but it appears that you are actually discussing VSLs.
1. The SDT shares your concern about the stepped VSLs. However, the VSL Guidelines, developed in accordance with the FERC
VSL Order, establish the Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as “more than 5% but less than (or equal
to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the Severe VSL as “more than 15%.” The SDT did,
however, modify the VSLs for R1 so that they do not use percentages.
2. The VSLs are assigned on the basis of percentages of components for which you are non-compliant. The SDT suggests that you
review the Compliance Monitoring Enforcement Program for clarification on self-reports, and so forth.
Tennessee Valley Authority
No
The Violation Severity Level Table listing for Requirement R4 lists the following under
“Severe VSL”.”Entity has failed to initiate resolution of maintenance-correctable issues” The
threshold for a Severe Violation in this case is too broad and too subjective. The threshold
needs to be clearly defined with low, medium, and high criteria.
Response: Thank you for your comments. The VSLs for Requirement R4 have been modified to provide stepped VSLs for initiation of
resolution of maintenance-correctable issues.
BGE
No
The VSL’s as proposed may be reasonable but it is difficult to endorse them until the
ambiguity in R1.1 is reduced.
No
The VSLs for PRC-005-2 requirements R1, R2 and R4 have significantly tighter
Response: Thank you.
Duke Energy
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
percentages than the corresponding requirements in PRC-005-1. We believe that the
Lower VSL should be up to 10%, the Moderate VSL should be 10%-15%, the High VSL
should be 15% to 20%, and the Severe VSL should be greater than 20%, which is still a
lower percentage than the 25% Lower VSL currently in PRC-005-1.
Response: Thank you for your comments. The SDT shares your concern abuout the stepped VSLs. However, the VSL Guidelines,
developed in accordance with the FERC VSL Order, establish the Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as
“more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the Severe VSL as
“more than 15%.”
Indeck Energy Services
No
1. The VSL's treat all entities, components and problems alike. By combining 4 protection
maintenance standards, it elevates the VSL on otherwise minor problems to the highest
levels of any of the predecessor standards. The threshold percentages are very
arbitrary. Severe VSL doesn't in any way relate to reliability. For a small generator to
miss or mis-categorize 1 out of 7 relays is unlikely to have any impact on reliability,
much less deserving a severe VSL. The R2 & R4 VSL's don't care about results of the
program, only whether all components are covered. Half of the components could fail
annually and it’s not a Severe VSL.
2. The R3 VSL allows 4% countable events, which can be hundreds for a large entity and
only allows a few for a small entity.
Response: Thank you for your comments.
1. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the Lower VSL for stepped VSLs as “5% or
less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including)
15%,” and the Severe VSL as “more than 15%.” VSLs are not intended to assess the risk to reliability of noncompliance, VSLs are
intended to identify different degrees of noncompliance with the associated requirement. The VRFs assess the risk to reliability of
noncompliance with the requirement.
2. Relating to the R3 VSL, the “4% countable events” corresponds to the requirement relevant to performance-based programs in
Attachment A. This value was determined to be a statistically significant value relating to performance-based programs, which
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Organization
Yes or
No
Question 4 Comment
may not be practical for a small entity to implement without aggregation with other entities having similar programs. See Section 9
of the Supplementary Reference Document.
US Bureau of Reclamation
No
1. The VSL's use terms that are not tied back to a requirement and appear to be based on
the concept that every component will cause an impact on the BES. The VSL's use the
term "countable event" to score the VSL; however, there is no requirement associated
with the number of "countable events".
2. The VSL's should allow for minor gaps in maintenance documentation where there is no
impact to the BES if the component failed.
Response: Thank you.
1. The VSL for Requirement R3, which you are questioning, addresses limits on “countable events” as they relate to the requirements
for a Perfomance Based program within Attachment A.
2. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation. The VRF
and VSLs are only a starting point in determining the size of a penalty or sanction – the Compliance Enforcement Authority has
latitude to consider aggravating factors and mitigating factors in determining whether there should be any penalty, and the size of
any penalty. These mitigating and aggravating factors are oultined in the Compliance Monitoring and Enforcement Program.
http://www.nerc.com/files/Appendix4C_Uniform_CMEP_10022009.pdf
Black Hills Power
No
-VSL's are based on percentages of components, where the definition of a 'component' is in
many cases up to the entity to interpret (see PRC-005-2 FAQ sheet, Page 2). Basing VSL's
on an entities interpretation (or count) of 'components' is not an equitable measure of
severity level.
Response: Thank you for your comment. A definition of “Component” has been added to the Standard to provide guidance and help
provide consistency.
JEA
No
November 17, 2010
We could find no rational provided for the % associated with each VSL, or component
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
rationale used to determine the proposed values listed. Is this included in some
documentation that is available but not included as part of this review?
Response: Thank you for your comments. The percentages, are established in accordance with the VSL Guidelines, developed in
accordance with the FERC VSL Order, which establish the Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as “more
than 5% but less than (or equal to) 10%,” the High VSL as “more than 10% up to (and including) 15%,” and the Severe VSL as “more
than 15%.” The VSL Guidelines are posted on the Standard Resources web page:
http://www.nerc.com/files/VSL_Guidelines_20090817.pdf
American Electric Power
Yes
American Transmission
Company
Yes
Arizona Public Service
Company
Yes
Bonneville Power
Administration
Yes
Consumers Energy
Company
Yes
Dynegy Inc.
Yes
Exelon
Yes
FirstEnergy
Yes
Great River Energy
Yes
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Hydro One Networks
Yes
MRO’s NERC Standards
Review Subcommittee
(NSRS)
Yes
Nebraska Public Power
District
Yes
PacifiCorp
Yes
Public Service Enterprise
Group ("PSEG
Companies")
Yes
ReliabilityFirst Corp.
Yes
South Carolina Electric and
Gas
Yes
The United Illuminating
Company
Yes
We Energies
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Yes
November 17, 2010
Question 4 Comment
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 4 Comment
Inc.
MEAG Power
Yes
It would be good to have the basis of the 5%, 10% and 15% defined. With time and
experience these percentages may need to be changed.
Response: Thank you for your comment. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the
Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as
“more than 10% up to (and including) 15%,” and the Severe VSL as “more than 15%.”
Manitoba Hydro
Yes
There is no rational provided for the % associated with each VSL, or component rationale
used to determine the proposed values listed.
Response: Thank you for your comment. The VSL Guidelines, developed in accordance with the FERC VSL Order, establish the
Lower VSL for stepped VSLs as “5% or less,” the Medium VSL as “more than 5% but less than (or equal to) 10%,” the High VSL as
“more than 10% up to (and including) 15%,” and the Severe VSL as “more than 15%.”
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Consideration of Comments on PSMTSDT — Project 2007-17
5. The SDT has revised the “Supplementary Reference” document which is supplied to provide
supporting discussion for the Requirements within the standard. Do you agree with the
changes? If not, please provide specific suggestions for change.
Summary Consideration: Most commenters seemed to appreciate the information provided within the
Supplementary Reference document. Many commenters asked whether the Supplementary Reference
was part of the Standard, to which the SDT replied, “No.”
Several commenters also were concerned that the Supplementary Reference document may not be kept
current with the Standard itself. There were assorted individual technical comments about the
Supplementary Reference document, to which the SDT responded. Several comments irrelevant to the
Supplementary Reference document were also offered; the SDT offered responses relevant to the
comments.
Organization
Yes or
No
Question 5 Comment
PPL Supply
No Comment.
Santee Cooper
No Comment.
SERC Protection and
Control Sub-committee
(PCS)
The SERC PCS expresses no opinion on this question.
San Diego Gas & Electric
No
Ameren
No
November 17, 2010
1) Is this document considered part of the standard? We expect to use it as a reference in
developing our PSMP, during audits, and for self-certification as an authentic source of
information. It is also unclear how this document will be controlled (i.e. Revised and
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
Approved, if at all).
2) On page 22 please clarify that only applies to high speed ground switches associated
with BES elements.
3) We appreciate the SDT providing this valuable reference.
Response:Thank you for your comments.
1. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference
document, accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of
Requirements, etc., and is not to include explanatory information like that included in the Supplementary Reference document. The
SDT intends that this document help explain, clarify, and in some cases suggest methods to comply with the Standard. The
Standards Committee has a formal process for determining whether to authorize posting a reference document with an approved
standard. That process is posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. The Standard applies to High-Speed Ground Switches that are used to trip BES elements or that are used to protect BES elements.
In response to your comment, the SDT has modifed the Supplementary Reference Section 15.3 as follows: “The SDT believes that
this is essentially a transferred-tripping device without the use of communications equipment. If this high-speed ground switch is
“…applied on, or designed to provide protection for the BES…” then this device needs to be treated as any other Protection System
component. The control circuitry would have to be tested within 12 years and any electromechanically operated device will have to
be tested every 6 years. If the spring-operated ground switch can be disconnected from the solenoid triggering unit then the solenoid
triggering unit can easily be tested without the actual closing of the ground blade.
3.
Thank you.
Xcel Energy
No
1. As we commented on in the previous draft of the standard that proposed the
Supplementary Reference and FAQ, we are concerned as to what role these
documents will play in compliance/auditing. It is also unclear how these documents will
be controlled (i.e. Revised and Approved, if at all).
2. Inconsistencies have been identified between proposed standard and the documents
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
(e.g. page 29 of FAQ example 1).
Response: Thank you for your comments.
1. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a Reference
Document, accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of Requirements,
etc., and is not to include explanatory information like that included in the Supplementary Reference document. The Supplementary
Reference and FAQ have been revised to make them consistent with the new version of PRC-005-2. The Standards Committee has
a formal process for determining whether to authorize posting a reference document with an approved standard. That process is
posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. Thank you. The FAQ has been revised to make it consistent with the new version of PRC-005-2 and the Supplementary Reference
document.
Pepco Holdings, Inc. Affiliates
No
Figure 1 & 2 Legend (page 29), Row 5, Associated Communications Systems, includes
Tele-protection equipment used to convey remote tripping action to a local trip coil or
blocking signal to the trip logic (if applicable). This description does not include all the
various types of signals communicated for proper operation of various protective schemes
(i.e., DUTT, POTT, DCB, Current Differential, Phase Comparison, synchro-phasors, etc.)
A more inclusive and generic description might be - Tele-protection equipment used to
convey specific information, in the form of analog or digital signals, necessary for the
correct operation of protective functions. This is also consistent with the revised definition
of Protection System. Conversely, excluded equipment would be - Any communications
equipment that is not used to convey information necessary for the correct operation of
protective functions.
Response: Thank you for your comment.
The Supplementary Reference and FAQ have been revised to make them consistent with the new version of PRC-005-2 and each
other, and to incorporate language similar to your suggestion.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
MEAG Power
No
Further clarification is needed. The information provided on verifying outputs of voltage
and current sensing devices is confusing. In one part, it indicates that the intent is to verify
that intended voltages and currents are getting to the relay apparently without regards to
accuracy. A practical method of verifying the output of VTs and CTs is not identified and
need to be identified.
Response: Thank you for your comments.
The intent of the maintenance activity is to verify that the necessary values reach the protective relays. The SDT believes that a
maintenance plan that requires infra-red scanning of VTs and CTs is not sufficient. The SDT further believes that routine
commissioning tests, while certainly allowed, need not be required in the Standard because mere ratio tests would not prove that the
values reach the relay.
A practical method is to read the values at the relays and, as you state, verify that the quantities meet your needs.
The SDT believes that the discussion in Section 15.2 of the Supplementary Reference is sufficient, and is supplemented in several
subsections of FAQ II.3.
Indeck Energy Services
No
In 2.3, the applicability is stated to have been modified. As discussed at the FERC
Technical Conference on Standards Development, the goal of the standards program is to
avoid or prevent cascading outages--specifically not loss of load. The modified applicability
moves away from the purpose of the standards program to an undefined fuzzy concept.
Applicable Relays ignore the fact that some relays, or even some entities, have little to no
affect on reliability. The global definition of Protective System encompasses all equipment,
and doesn't differentiate the components that meet the purpose of the standards program.
The Supplementary Reference doesn't overcome the inherent shortcomings of the
standard.
Response: Thank you for your comments.
The Supplementary Reference is intended to help clarify the Standard.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
The United Illuminating
Company
Yes or
No
Question 5 Comment
No
Include a detailed example of an Inventory list. Allow for different means of maintaining the
lists electronically, that is, as spreadsheets, or databases.
Response: Thank you for your comments.
The Supplementary Reference is intended to help clarify the Standard, not add to the Requirements of the Standard. Maintaining your
lists is a business practice that you make, spreadsheets and/or databases have not been precluded in the Standard or in any reference
document.
US Bureau of Reclamation
No
It is not reasonable to assert that a statistical analysis of survey data is reliability based
justification for requiring specific maintenance intervals. The reference document admits
that intervals varied widely. To assert a postage stamp interval does not account for other
variables which optimize a specific maintenance program. That is not saying that the
reference documents are worthless. Indeed it has many good suggestions. However, to
impugn the maintenance programs in practice because they do not follow the "weighted
average" is hardly scientific or credible. The reference document should analyze the
maintenance programs from the stand point of the outages associated with those facilities.
If a specific maintenance practice was shown to have compromised the performance of the
facility and the reliability of the BES, then it would added to the statistical database of
practices which would not be acceptable. Now the statistical analysis of the database
would show that certain practices have consequences which impact reliability and a
requirement can be constructed to disallow them.
Response: Thank you for your comments.
FERC directed the SDT to set maximum time intervals between maintenance activities. The SDT recognized that different types of
equipment, different generations of equipment, different failure modes of equipment and different versions of time-based maintenance
had to be considered. The SDT agrees with the commenter that the Standard allows statistical analysis and performance-based
maintenance allows an entity to create time intervals that could exceed any “weighted-averages” time-based intervals. The
Supplementary Reference adds a section (9) to show how an entity can create a performance-based maintenance interval.
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Public Service Enterprise
Group ("PSEG
Companies")
Yes or
No
No
Question 5 Comment
1. Suggest that figure 2 has a line of demarcation added that shows components
specifically not part of the standard requirements. (Medium voltage bus).
2. Battery charger should be removed from table of components when a storage battery is
used for the DC supply.
Response: Thank you for your comments.
1. The figures are intended to be general information and not to be inclusive of all situations.
2. The modification of the Protection System definition from “station battery” to “station dc supply” is intended to include battery
chargers, and Table 1-4 within draft PRC-005-2 includes activities specifically related to battery chargers.
JEA
No
The Supplementary Reference document is critical in our current compliance environment
to be approved as part of the standard and any standard modifications need to be kept in
synchronization with the FAQ and the Supplementary Reference.
Response: Thank you for your comments.
1. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference
document, accompanying the S. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc.,
and is not to include explanatory information like that included in the FAQ and Supplementary Reference. The Supplementary
Reference and FAQ have been revised to make them consistent with the new version of PRC-005-2.
Long Island Power
Authority
No
1. There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an
entity can count components however; an example in the reference document will
provide clarity.
2. Page 7 of the redline version of Supplemental Reference - bullet 1 under Maintenance
Services, paragraph 2, it says “ If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time clock
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
is reset for those components. LIPA believes that resetting the time clock will make
tracking difficult (unless entities have a sophisticated automated tool for tracking).
Another option where an entity can take credit for a correct performance within
specifications at the time of the maintenance cycle should be included.
Response: Thank you for your comments.
1. A definition of “Component” has been added to the draft Standard to provide guidance. The Standard and the Tables have also
been revised throughout for clarity.
2. The example cited is only offered as an option for entities that may wish to make use of observed real-time operations within their
PSMP. An entity may, if desired, reset the time clock on a correct real-time occurrance. An entity does not have to “reset the time
clock” if it chooses to maintain all of its components on a set schedule. The example given is merely one method to log a
completed tripping action, which would alleviate the need to validate that same trip path. The SDT acknowledges that there are
many ways to prove circuits; real-time switching or fault-clearing activities can be used but are not the only methods.
Northeast Power
Coordinating Council
No
1. There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an
entity can count components.
2. However; an example in the reference document will provide clarity. Page 7 of the
redline version of Supplemental Reference - bullet 1 under Maintenance Services,
paragraph 2 states “ If specific protection scheme components have demonstrated
correct performance within specifications, the maintenance test time clock is reset for
those components.” Resetting the time clock will make tracking difficult (unless entities
have a sophisticated automated tool for tracking). Another option where an entity can
take credit for a correct performance within specifications at the time of the maintenance
cycle should be included.
Response: Thank you for your comments.
1. A definition of “Component” has been added to the draft Standard to provide guidance. The Standard and the Tables have also
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 5 Comment
been revised throughout for clarity.
2. The example cited is only offered as an option for entities that may wish to make use of observed real-time operations within their
PSMP. An entity may, if desired, reset the time clock on a correct real-time occurrance. An entity does not have to “reset the time
clock” if it chooses to maintain all of its components on a set schedule. The example given is merely one method to log a
completed tripping action, which would alleviate the need to validate that same trip path. The SDT acknowledges that there are
many ways to prove circuits; real-time switching or fault-clearing activities can be used but are not the only methods.
Northeast Utilities
No
There is no guidance on how to calculate the total number of components and thus, the
percentages under different severity levels. FAQ provides some insight into how an entity
can count components however; an example in the reference document will provide clarity.
Response: Thank you for your comments. A definition of “Component” has been added to the draft Standard to provide guidance.
The Standard and the Tables have also been revised throughout for clarity.
Tennessee Valley Authority
No
1. There needs to be a defined method of deferral when equipment can’t be gotten out
of service until a scheduled outage.
2. Give some examples of what “inputs and outputs that are essential to proper
functioning of the Protection System” are.
3. a) Define what a “Control and Trip Circuit” is.
4. b) Is there one per relay?
5. c) Do I have to have a list of them in my work management system?
Response: Thank you for your comments.
1. “Grace periods” within the Standard are not measurable, and could lead to persistently increasing intervals.
2. Some examples of outputs may include but are not limited to: trip, initiate zone timer, initiate breaker fail. Some examples of input
may include but are not limited to: breaker fail initiate, start timer. This cannot be an all-inclusive list as any given scheme could
have many variations. In short, if your scheme requires a specific input to function properly then you must have that input
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Organization
Yes or
No
Question 5 Comment
maintained; if your scheme has a specific output that must function then it must be maintained. If the input or output is used for a
non-protective function (such as, but not limited to, Sequence-of-Events Recorder, alarm or indication) then it does not have to be
maintained under this Standard. See Section 15.3 of the Supplementary Reference and FAQ II.2.L.
3. a) Circuitry needed for the correct operation of the protective relay. A definition of “Component” has been added to the draft
Standard to provide guidance. See Section Section 15.3 of the Supplementary Reference.
4. b) This depends on your scheme and your relay. A definition of “Component” has been added to the draft Standard to provide
guidance.
5. c) The SDT believes that a PSMP that requires maintenance upon all of the circuits, and includes a check-off (list) system that
accounts for all circuits being verified would suffice.
American Electric Power
Yes
American Transmission
Company
Yes
Arizona Public Service
Company
Yes
BGE
Yes
Black Hills Power
Yes
Constellation Power
Generation
Yes
Consumers Energy
Company
Yes
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Duke Energy
Yes
Dynegy Inc.
Yes
Entergy Services
Yes
Exelon
Yes
Great River Energy
Yes
Hydro One Networks
Yes
Manitoba Hydro
Yes
MidAmerican Energy
Company
Yes
MRO’s NERC Standards
Review Subcommittee
(NSRS)
Yes
NERC Staff
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PacifiCorp
Yes
November 17, 2010
Question 5 Comment
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
PNGC Power
Yes
Progress Energy Carolinas
Yes
ReliabilityFirst Corp.
Yes
South Carolina Electric and
Gas
Yes
Southern Company
Transmission
Yes
The Detroit Edison
Company
Yes
We Energies
Yes
Western Area Power
Administration
Yes
Y-W Electric Association,
Inc.
Yes
WECC
Yes
November 17, 2010
Question 5 Comment
Compliance does agree with the clarity and the Supplementary Reference should be
specially referenced where appropriate the Tables 1a, 1b, 1c and Attachment A that are
included with the Standard. But this reference is not a part of the approved standard and
there are no controls which prevent changes in the reference document that could impact
the scope or intent of the standard. If the standard is approved with reference to the
Supplementary Reference then future changes to the Supplementary Reference should not
be allowed without due process. Only the version in existence at the time of approval of the
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Organization
Yes or
No
Question 5 Comment
standard could be used to clarify or explain the standard.
Response: Thank you for your comments. The SDT intends that the Supplementary Reference document be updated as the Standard is
revised to maintain its relevance to the application of the Standard. The Standards Committee has a formal process for determining
whether to authorize posting a reference document with an approved standard. That process is posted on the Standard Resources web
page – here is a link to the procedure: http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
Nebraska Public Power
District
Yes
Is this document considered part of the standard and may be referenced during audit and
self-certification as an authentic source of information?
Response: Thank you for your comments. This document provides supporting discussion, but is not part of the Standard. The SDT
intends that these be posted as reference documents, accompanying the Standard. The Standards Committee has a formal process for
determining whether to authorize posting a reference document with an approved standard. That process is posted on the Standard
Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
Springfield Utility Board
Yes
SUB appreciates that Time Based, Performance Based, and Condition Based programs
can be combined into one program. However it should be clear that a utility may include
one, two or all three of these types of programs for each individual device type. Currently
the language reads:"TBM, PBM, and CBM can be combined for individual components, or
within a complete Protection System." The "and" requires all three to be combined if they
are combined. SUB suggests the “and” be changed to "or". Language Change: "TBM,
PBM, or CBM can be combined for individual components, or within a complete Protection
System."
Response: Thank you for your comments. The SDT modified Requirement R1 of the Standard.
FirstEnergy
November 17, 2010
Yes
We support the reference document and appreciate the SDT's hard work developing this
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Yes or
No
Question 5 Comment
document. We offer the following suggestions for possible improvements:
1. The reference document should be linked in Section F of the standard. Otherwise it may
be difficult for someone to navigate the NERC website in search of the document.
2. Section 2.2 - It would be helpful if a short discussion of the reasons for the changes to
the definition of Protection System was included in this reference document. In addition, it
would be beneficial to discuss what is included in "dc supply" components, such as "dc
supplies include battery chargers which are required to be maintained per the Tables in
PRC-005-2."
3. Section 8.1 - The fourth bullet which reads "If your PSMP (plan) requires more then you
must document more." Should be removed. This is already covered in the sixth bullet
which states "If your PSMP (plan) requires activities more often than the Tables
maximum then you must document those activities more often."
Response: Thank you for your comments.
1. This issue may be a good idea. The Standards Committee has a formal process for determining whether to authorize posting a
reference document with an approved standard. That process is posted on the Standard Resources web page – here is a link to the
procedure: http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf.
2. The reasons for the definition change are transitory and should not be in the Supplementary Reference document. The reasons may
be found in the SAR for Project 2007-17. See Section 15.4 of the Supplementary Reference for discussion about batteries and dc
supply.
3. The SDT disagrees with your assertion. The first cited example applies to the activities within your program, and the second applies
to the intervals. These are related but separate. The fourth bullet in Section 8.1 has been revised to clarify.
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6. The SDT has revised the “Frequently-Asked Questions” (FAQ) document which is supplied to
address anticipated questions relative to the standard. Do you agree with these changes?
If not, please provide specific suggestions for change.
Summary Consideration: Most commenters seemed to appreciate the information provided within the
FAQ document. Many commenters asked whether the FAQ was part of the Standard, to which the SDT
replied, “No.” Several commenters also were concerned that the FAQ document may not be kept current
with the Standard itself. There were assorted individual technical comments about the FAQ, to which the
SDT responded. Several comments irrelevant to the FAQ were also offered; the SDT offered responses
relevant to the comments.
Organization
Yes or
No
Question 6 Comment
MEAG Power
No comment.
PPL Supply
No Comment.
Santee Cooper
No comment.
SERC Protection and
Control Sub-committee
(PCS)
The SERC PCS expresses no opinion on this question.
Indeck Energy Services
No
San Diego Gas & Electric
No
Consumers Energy
No
November 17, 2010
1. FAQ II.3A attempts to clarify the requirements of “Verify the proper functioning of the
current and voltage signals necessary for Protection System operation from the voltage
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Organization
Yes or
No
Company
Question 6 Comment
and current sensing devices to the protective relays” suggesting that “simplicity can be
achieved” by verifying that the protective relays are receiving “expected values.” It
concludes with a statement of the need to “ensure that all of the individual components
are functioning properly ...” implying that just verifying “expected values” at the protective
relay end of the circuit may be inadequate.
2. FAQ II.4D describes what is required for testing of aux relays to include, “that their trip
output(s) perform as expected”. Does that include timing tests? (Example - high speed
ABB AR relays vs. standard AR relays).
3. The SDT responses to the Draft 1 comments regarding “grace periods” essentially says,
“Absolutely not”. However, FAQ IV.1.D reflects data retention requirements relative to an
entities’ program which includes a grace period!
Response: Thank you for your comments.
1. “Expected values” was intended to convey that the current and/or voltage sensing devices were functioning properly. The SDT
intentionally left out any Requirement in the Standard that the values being read at the protective relays be within a specific
tolerance because each entity may have valid rationale for tolerances at any level. To find a current or voltage value that is wrong
would indicate that something in the voltage or current secondary delivery system is not functioning properly and needs corrective
action. Typically an entity can review values measured at the relay and determine that the values are as expected and that the
maintenance activity has been satisfied.
2. If an entity has designed a protection scheme which contains parts that need to function in a specific manner then those parts need
to be routinely maintained to assure that they perform at that level. The SDT believes that Protection Systems exist at all levels of
complexity and that some systems will be easier to test than others, but that all components that are necessary for the proper
functioning of the Protection System must be maintained. In short, if an entity decided that specific parts were necessary for the
proper operation of the Protection System then those parts need to be routinely maintained.
3. There is no “grace period” allowed by the Standard; a “grace period” is not measurable. That means that the intervals between the
specified maintenance activities in the Standard cannot exceed those established within the Tables. However, many entities have
built in “allowable extensions” to their intervals (thus creating “grace periods” within their own PSMP). In these particular PSMP’s
the total time allowed between the specified maintenance activities (including any allowable extensions or “grace periods”) does not
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No
Question 6 Comment
exceed the maximum allowed time interval established in the Standard. For example, an entity has in their PSMP that “…the
electro-mechanical relays will be tested every 3 calendar years with a maximum allowable extension of 18 additional calendar
months to allow for scheduling difficulties and unplanned emergencies.” In this way the entity will be audited to their PSMP, they
have added 50% time in the form of their own grace period and the maximum time between the specified maintenance activities
does not exceed the time interval established in the Standard. Also see FAQ IV.2.H for additional discussion on this.
Xcel Energy
No
1. As we commented on in the previous draft of the standard that proposed the
Supplementary Reference and FAQ, we are concerned as to what role these
documents will play in compliance/auditing. It is also unclear how these documents will
be controlled (i.e. Revised and approved, if at all).
2. Inconsistencies have been identified between proposed standard and the documents
(e.g. page 29 of FAQ example 1).
Response: Thank you for your comments.
1. This document provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference
document, accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements,
etc., and is not to include explanatory information like that included in the Supplementary Reference document. The FAQ and the
Supplementary Reference documents have been revised to make them consistent with the new version of PRC-005-2. 1. The
Standards Committee has a formal process for determining whether to authorize posting a reference document with an approved
standard. That process is posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. Thank you. The FAQ has been revised to be consistent with the new version of the Standard.
Nebraska Public Power
District
November 17, 2010
No
1. FAQ 2.G, page 24 - NPPD believes system reliability will be decreased if an entity is
considered non-compliant for exceeding a PSMP stated interval that is within the PRC005-2 Maximum Maintenance Interval. Considering an entity non-compliant for such a
situation will encourage establishment of intervals that only meet the minimum standard.
There should be one standard interval that all entities must be monitored against. If an
entity wants to perform maintenance more frequently, it should not be subject to non131
Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Question 6 Comment
compliance if it misses its target but meets the Maximum Maintenance Interval in the
standard.
2. There are definitions at the beginning of the FAQ that should be contained in the NERC
definitions and not in an FAQ. Placing these in an approved definition will help avoid
interpretation issues that would arise during future audits.
Response: Thank you for your comments.
1. The SDT believes that there are many reasons that would prompt an entity to have some intervals that are more frequent than
those intervals established in the Standard (performance-based maintenance is but a single example). If an entity chooses to
perform maintenance more often than the limits set within the Standard then it may do so. If an entity chooses to perform
maintenance more often than the limits set within its own PSMP then it may do so.
2. The SDT desires to conform to certain rules regarding this issue. If a term appears in the NERC Glossary then all Standards will
have to conform to the definition established. If the terms are shown elsewhere, in the FAQ for example, then clarity can be
achieved when the Standard is read. The SDT intends to help clarify by creating the two supporting reference documents, but not
to restrict other Standards to the uses of some words that will inevitably be shared amongst Standards. The SDT has also moved
several of these definitions to the Standard with the intent that they be part of only this Standard and not a general definition within
the NERC Glossary of Terms.
Progress Energy Carolinas
No
1. FAQ II.2.A: What degree of testing is required for a relay firmware upgrade? Complete
commissioning tests?
2. FAQ V.1.A. There appears to be a typo in Example #1 for “Vented lead-acid battery
with low voltage alarm connected to SCADA (level 2)”: Table 1b does not list any level
2 requirements. Rather, the table refers reader back to the Level 1 requirements.
Same comment for Example #2 as well.
3. FAQ III.1.A: Project 2009-17 provides a response to a request for interpretation of the
term “transmission Protection System” as related to PRC-004-1 and PRC-005-1. The
interpretation addresses the boundaries of the transmission system. NERC should
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Organization
Yes or
No
Question 6 Comment
investigate whether this same boundary should be defined within the new PRC-005-2.
4. Also, numerous potential boundary issues exist between entities which should be
contemplated and addressed. See the examples below:
a) Utility A may own equipment in Utility B’s substation. Utility A contracts Utility B to
perform maintenance on their equipment. However, the two utilities have different
maintenance programs and intervals for the same types of equipment. Who is
responsible for NERC compliance? Would Utility A be found in violation because their
equipment is being maintained under Utility B’s program which deviates from Utility
A’s maintenance basis?
b) EMC protection is fed from a utility’s instrument transformers. Who is responsible for
validation of the relay inputs and testing of the instrument transformers?
c) Utility-owned communication units (used for transfer trip or carrier blocking) are
coupled to the utility’s power line using customer-owned CCVTs. Who is responsible
for maintenance and testing of these CCVTs?
d) Utility A owns all equipment at one end of line (line terminal A) and Utility B owns all
equipment at other end of line (line terminal B). Who is responsible for demonstrating
the carrier blocking scheme or POTT scheme works correctly?
Response: Thank you for your comments.
1. Complete commissioning tests can be required by the entity. Commissioning tests are not specified within the Standard. The status
of the relay should be that it is ready for use after the firmware upgrade. If the maintenance activities were performed that are
specified within the Standard and its PSMP, then the entity may choose to reset the time clock for maintenance for that device.
2. The Tables within the Standard have been completely revised, and the FAQ revised to align.
3. When the interpretation (Project 2009-17) is approved, the SDT for PRC-005-2 will consider if the interpretation is appropriate for
PRC-005-2 and make associated changes.
a) The owner of the equipment is responsible for assuring that the equipment is maintained according to its PSMP. This is
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Organization
Yes or
No
Question 6 Comment
consistent with the concepts in the Functional Model. b) The owner of the equipment is responsible for assuring that the equipment
is maintained according to its PSMP.
c) The owner of the equipment is responsible for assuring that the equipment is maintained according to its PSMP.
d) The owner of the equipment is responsible for assuring that the equipment is maintained according to its PSMP. The entities
should coordinate on equipment that affects each other to assure that the equipment is tested in such a fashion that it complies with
both entities’ PSMP.
Tennessee Valley Authority
No
If a relay is tested during a generator outage, what date is allowed to be used for
compliance - actual test date or date equipment was returned to service? These are
usually only a few weeks apart, but may be as much as three months different.
Response: Thank you for your comments.
An entity’s own records are used to judge compliance. The date placed on the evidence should be the date on which testing of the
relevant Protection System component is completed.
Northeast Utilities
No
Page 2 under Component definition, term “somewhat arbitrary” is used by the drafting team
to address what constitutes a dc control circuit. Though the drafting team has provided
entities with flexibility to define as per their methodologies, it is recommended to clearly
determine “what constitutes a dc control circuit” since it will be used to determine
compliance.
Response: Thank you for your comments.
The SDT believes that if the circuit is needed for the Protection System to operate or function correctly, then that circuit must be
maintained.
South Carolina Electric and
Gas
November 17, 2010
No
Question/Answer 4-C (Pg. 10 of FAQ) seems to indicate that by documenting breaker
operations for fault conditions the table 1b requirements for control circuitry (Trip Coils and
Auxiliary relays) can be satisfied. It is possible that even though a breaker successfully
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Organization
Yes or
No
Question 6 Comment
operates for a fault condition one trip coil of a primary/backup design can be inoperable and
“masked” by the good trip coil. Although it is likely that a faulty trip coil would be caught by
monitoring of continuity it is not a certainty that both trip coils actually operated to clear a
fault (example-mechanical binding)
Response: Thank you for your comments.
The SDT agrees. While a successful trip operation can fulfill requirements of the Standard, it is useful only for the trip paths for which
successful operation was demonstrated and documented.
BGE
No
The FAQ is a very helpful document. A few more changes would be beneficial. See
comments regarding manufactures’ advisories and R1.1 under section 7 below. It is our
recommendation that manufacturers service advisories not be an implied part of the PMSP
requirements and that the expectations for R1.1 be more explicitly described in the FAQ.
Response: Thank you for your comments.
The Supplementary Reference and the FAQ are not a part of the Standard. The intent of the SDT is that the documents help provide
clarity, not to imply additional maintenance. The required minimum maintenance activities are listed in the Standard. Requirement R1
and the tables have been extensively revised.
American Transmission
Company
No
The FAQs are helpful, however, with the revised standard as written; ATC has issues with
the answers provided. Please refer to Question #7 for areas of concern.
Response: Thank you for your comments.
The Standard and the Tables have been revised to add clarity. The FAQ and the Supplementary Reference documents have been
revised to make them consistent with the new version of PRC-005-2. Please see our responses to your comments in Question 7.
MRO’s NERC Standards
Review Subcommittee
November 17, 2010
No
The FAQs are helpful, however, with the revised standard as written, The NSRS has issues
with the answers provided. Please refer to Question #7 for areas of concern.
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Organization
Yes or
No
Question 6 Comment
(NSRS)
Response: Thank you for your comments.
The Standard and the tables have been revised to improve clarity. The FAQ and the Supplementary Reference documents have been
revised to make them consistent with the new version of PRC-005-2. Please see our responses to your comments in Question 7.
Constellation Power
Generation
No
The PT/CT testing section is implying that the testing must be completed while energized,
which is counter to industry practice at generation facilities. Leeway should be given to the
entities to devise their own methods for testing voltage and current sensing devices and
wiring to the protection system.
Response: Thank you for your comments.
The required minimum maintenance activities are listed in the Standard. The intent of the cited section is to provide examples of how
an entity might perform the testing. Any examples listed in either of the supporting documents should be looked upon as suggestions;
these suggestions are not considered to be a complete list of the methods available. To the contrary, the Standard and the supporting
documents were written considering that there are many ways to achieve a good test. Leeway is certainly available in how an entity
complies with the Standard as the maintenance activities generally specify “what” must be achieved but not “how” an entity achieves it.
Please see FAQ II.3.D.
Pepco Holdings, Inc. Affiliates
No
1. The three month inspection interval for communication equipment mentioned in FAQ II 6
B should be extended to 12 - 18 months (see response to Question #1).
2. In addition, the example used in this section should address what is expected for ONOFF carrier systems. Checking that the equipment is free from alarms and still powered
up does not seem sufficient to verify functionality. The FAQ states that the concept
should be that the entity verifies that the communication equipment...is operable
through a cursory inspection and site visit. However, unlike FSK schemes where
channel integrity can easily be verified by the presence of a guard signal, ON-OFF
carrier schemes would require a check-back or loop-back test be initiated to verify
channel integrity. If the carrier set was not equipped with this feature, verification would
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Organization
Yes or
No
Question 6 Comment
require personnel to be dispatched to each terminal to perform these manual checks.
Response: Thank you for your comments.
1. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
2. As you suggest, this funcitionality would normally be verified by a manual or automatic checkback system, and, even then, a
station visit would be necessary if alarms are not provided. Where such equipment is not available, a station visit would be
necessary.
Public Service Enterprise
Group ("PSEG
Companies")
No
This is a very useful document and provides a good source of additional information; there
are some cases where it could be interpreted as a standard requirement that can lead to
confusion if conflicts exist. For example, the group by monitoring level example V.1.A
shown on page 29 describes a level 2 partial monitoring as circuits alerting a 24Hr staffed
operations center, page 38 shows level 2 monitoring as detected issues are reported daily.
The actual standard table 1b level 2 monitor describes alarms are automatically provided
daily to a location where action can be taken for alarmed failures within 1 day or less. This
is listed as a supplemental reference document in the standard. The FAQ document
“supports” the standard but is or is not an official interpretation tool, or if it is state as such.
Response: Thank you for your comments.
The FAQ provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference document,
accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc., and is
not to include explanatory information like that included in the FAQ.
The United Illuminating
Company
November 17, 2010
No
What actions are taken if the owner can not perform a specific activity elaborated on the
tables due to the design of the equipment? Is the owner in non-compliance? Must the
owner only accept equipment solutions that allow the maintenance activities elaborated in
the standard to be performed?
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Organization
Yes or
No
Question 6 Comment
Response: Thank you for your comments.
The SDT is not aware of any activities that cannot be performed as you cite.
JEA
No
Yes the FAQ is also a very important document to be approved along with the standard.
There must be a way to have the standard and the FAQ go hand-in-hand or the standard
must be revised to include much of the FAQ.
Response: Thank you for your comments.
The FAQ provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference document,
accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc., and is not
to include explanatory information like that included in the Supplementary Reference and the FAQ. The FAQ and the Supplementary
Reference documents have been revised to make them consistent with the new version of PRC-005-2. The Standards Committee has
a formal process for determining whether to authorize posting a reference document with an approved standard. That process is posted
on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
American Electric Power
Yes
Arizona Public Service
Company
Yes
Black Hills Power
Yes
Duke Energy
Yes
Dynegy Inc.
Yes
November 17, 2010
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
Entergy Services
Yes
Exelon
Yes
Great River Energy
Yes
Hydro One Networks
Yes
Long Island Power
Authority
Yes
Manitoba Hydro
Yes
MidAmerican Energy
Company
Yes
NERC Staff
Yes
Northeast Power
Coordinating Council
Yes
Pacific Northwest Small
Public Power Utility
Comment Group
Yes
PacifiCorp
Yes
PNGC Power
Yes
November 17, 2010
Question 6 Comment
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Consideration of Comments on PSMTSDT — Project 2007-17
Organization
Yes or
No
ReliabilityFirst Corp.
Yes
Southern Company
Transmission
Yes
Springfield Utility Board
Yes
The Detroit Edison
Company
Yes
We Energies
Yes
Y-W Electric Association,
Inc.
Yes
Ameren
Yes
Question 6 Comment
1) Is this document considered part of the standard? We expect to use it as a reference in
developing our PSMP, during audits, and for self-certification as an authentic source of
information. It is also unclear how this document will be controlled (i.e. Revised and
Approved, if at all).
2) The FAQ needs to be aligned with the tables. The FAQ also contains a duplicate
decision tree chart for DC Supply. The FAQ contains a note on the Decision tree that
reads, "Note: Physical inspection of the battery is required regardless of level of
monitoring used", this statement should be placed on the table itself, and should include
the word quarterly to define the inspection period.
3) We appreciate the SDT providing this valuable reference.
Response: Response: Thank you for your comments.
1. The FAQ provides supporting discussion, but is not part of the Standard. The SDT intends that it be posted as a reference document,
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Yes or
No
Question 6 Comment
accompanying the Standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc., and is
not to include explanatory information like that included in the Supplementary Reference and the FAQ. The FAQ and the
Supplementary Reference documents have been revised to make them consistent with the new version of PRC-005-2. The
Standards Committee has a formal process for determining whether to authorize posting a reference document with an approved
standard. That process is posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. The FAQ has been revised to make it consistent with the new version of PRC-005-2. The decision trees were removed.
3. Thank you.
Western Area Power
Administration
Yes
Clarification
1) FAQ, page 36, Control Circuit Monitor Level Decision Tree: It’s not clear if the note on
Level 1 device operation is required for Level 3 monitoring.
Response: Thank you for your comments. The Standard and Tables have been extensively revised. The FAQ has been revised to
make it consistent with the new version of PRC-005-2. The decision trees were removed from the FAQ.
WECC
Yes
Compliance does agree with the clarity. The FAQ answers should be referenced
specifically to the Standard and the Supplementary Reference to further understand those
two documents. However, endorsement of the Standard should not imply endorsement of
the FAQ and vice versa.
Response: Thank you for your comments.
FirstEnergy
Yes
We support the FAQ document and appreciate the SDT's hard work developing this
document. The reference document should be linked in Section F of the standard.
Otherwise it may be difficult for someone to navigate the NERC website in search of the
document.
4. Response: Thank you for your comments. The Standards Committee has a formal process for determining whether to authorize
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Yes or
No
Question 6 Comment
posting a reference document with an approved standard. That process is posted on the Standard Resources web page – here is a
link to the procedure: http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
If approved as a permanent reference to a standard, then on the “Reliability Standard” web page, there will be a link (in the same cell
as the link to the standard and its archive) to any reference documents approved for posting with the standard.
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7. If you have any other comments on this Standard that you have not already provided in
response to the prior questions, please provide them here.
Summary Consideration: Comments were offered on virtually every aspect of the draft Standard. Many
of these comments resulted in changes to the Standard. The Tables were commented on heavily, and
they were completely revised in response. Many commenters were concerned about not having provision
for a “grace period,” and the SDT responded that this was not allowable. “100% compliance” was also a
concern, and the SDT responded that there was not a means of permitting some level of non-conformance
without being also non-compliant.
Organization
GDS Associates
Question 7 Comment
Definition of Terms Used in the Standard. Protection System Maintenance Program
1. Monitoring. Concerned about the interpretation of this activity description
2. Upkeep. Not sure about how this activity will be enforced –
A. Introduction. 4.2. Facilities.
3. The applicability does not address the current issues regarding radial + load serving
only situation when Protection System not designed to provide protection for the BES.
Standard should clearly state this exemption.
B. Requirements.
4. 1.1. The standard does not provide guidance in how to identify the components of a
transmission Protection System (tPS). See prior comment referring to the case of a
radial load serving transmission topology.
5. 1.3. Requirement should read “For each identified Protection System component from
Requirement 1, part 1.1, include all maintenance activities listed in PSMP and
specified in Tables 1a, 1b, or 1c associated with the maintenance method used per
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Requirement 1, part 1.2.”
6. 1.4. This requirement should be eliminated since already included in Table 1a and
covered through Requirement 1, part 1.3.
7. 4.3. Footnote 3 shall be eliminated since duplicates footnote 2 –
C. Measures
8. M1. The added wording in the Protection System definition, requirements and
measures with respect to the inclusion of the “associated circuitry from the voltage
and current sensing devices” and control circuitry “through the trip coil(s) of the
circuit breakers or other interrupting devices” seem right but a bit excessive under
current circumstances (form of the standard). The standard should clearly specify how
the maintenance program will address the verification, monitoring, etc. of the actual
wiring and the trip coils. We suggest that the wording of the standard to reflect that
the maintenance activities on the wiring will be conducted in a visual fashion without
implying activities that require disconnecting the primary equipment.
9. We recommend to change the Protection System definition to read “up to the trip
coils(s)” instead the word “through” (see comment on the definition as well). We
consider that the gain in reliability by pursuing a thorough maintenance program that
require to take primary equipment out of service (which in many instances will lead to
the entire substation being put out of service) cannot counterweight the sole purpose
of the standard and the economics emerging from this program.
Response: Thank you for your comments.
1. The SDT is unable to determine the nature of your concern. “Monitoring” is used within PRC-005-2 only as discussed in the new
Table 2.
2. The SDT has removed “Upkeep” from the PSMP definition in response to your comment.
3. This is an issue for your regional BES definition.
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4. The SDT has extensively revised Requirement R1 and its sub-requirements.
5. The SDT has extensively revised Requirement R1 and its sub-requirements.
6. The SDT has removed Requirement R1, part 1.4, in consideration of your comment.
7. The footnotes have been removed.
8. The SDT is not specifying the means of achieving requirements. This allows entities the flexibility to determine their own optimal
methods.
9. The SDT considers that the electrical trip coils are an integral portion of the dc control circuit, and therefore must be exercised.
Western Area Power
Administration
1) Standard, Page 4, R 4.3: Is the utility free to define its own “acceptable limits”?
2) Standard, Page 4, R 4.3: Must the “acceptable limits” be stated in the PSMP?
3) Standard, Page 4, Footnotes 2 and 3 are the same.
4) Attachment A says we can go to a performance based program; does this apply to every part of the
standard? In other words, does this apply to component testing, functional testing, etc., and do we
define the intervals of the test. That is, do we determine how long we test the sample of at least 30
units that Attachment A discusses?
Response: Thank you for your comments.
1. As “acceptable limits” may vary with the specific application, the entity is expected to determine appropriate acceptable limits.
2. There is no requirement within the draft Standard for an entity to specify the acceptable limits within its own PSMP.
3. The footnotes have been removed.
4. The draft Standard allows entities to implement a performance-based program for all component types except batteries if they have
appropriate populations. Attachment A specifies that the entity “Maintain the components in each segment according to the timebased maximum allowable intervals established in Tables 1-1through 1-5 until results of maintenance activities for the segment are
available for a minimum of 30 individual components of the segment.” After that period, the entity may shift to the performancebased program for the entire segment.
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Ameren
Question 7 Comment
1) We commend the SDT for developing a generally clear and well documented second draft. The SDT
considered and adopted many industry comments from the first draft. It generally provides a well
reasoned and balanced view of Protection System Maintenance, and good justification for its
maximum intervals. Ameren generally agrees that this second draft will be beneficial to BES
reliability, but several inconsistencies, unclear items, and a couple issues need to be addressed
before we will be able to support it.
2) Facilities Section 4.2.1 “or designed to provide protection for the BES” needs to be clarified so that it
incorporates the latest Project 2009-17 interpretation. The industry has deliberated and reached a
conclusion that provides a meaningful and appropriate border for the transmission Protection System;
this needs to be acknowledged in PRC-005-2 and carried forward.
3) We are concerned over R1.1, where all components must be identified, without a definition for the
word component or the granularity specified. While the FAQ gives a definition, and allows for entity
latitude in determining the granularity, the FAQ is not part of the standard. Certainly this could
confuse an entity or an auditor and lead to much wasted work and / or violations for unintended or
insignificant issues. We suggest that the FAQ definitions be included within the standard.
4) Implementation of the PSMP must coincide with the beginning of a calendar year.
5) Generating Plant system-connected Station Service transformers should not be included as a Facility
because they are serving load. Omit 4.2.5.5 from the standard. There is no difference between a
station service transformer and a transformer serving load on the distribution system. This has no
impact on the BES, which is defined as the system greater than 100 kV.
6) The term “maintenance correctable issue” used in Requirement 4 seems to be at odds with the
definition given for it. It seems that an issue that cannot be resolved by repair or calibration during the
maintenance activity would be a maintenance non-correctable issue. Also, in Requirement 4, the
term “identification of the resolution” is ambiguous. Suggested changes for Requirements 4 and 4.1
are: “R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its
PSMP, and resolve any performance problems as follows: 4.3 Ensure either that the components are
within acceptable parameters at the conclusion of the maintenance activities or initiate actions to
replace the component or restore its performance to within acceptable parameters.”
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Question 7 Comment
Response: Thank you for your comments.
1. Thank you.
2. When the interpretation (Project 2009-17) is approved, the SDT for PRC-005-2 will consider if the interpretation is appropriate for
PRC-005-2 and make associated changes.
3. Requirement R1 has been extensively revised, and the SDT has added a definition of “Component” and “Component Type” to the
draft Standard. The SDT’s intent is that this definition will be used only in PRC-005-2, and thus will remain with the Standard when
approved, rather than being relocated to the Glossary of Terms.
4. The SDT Guidelines, which were endorsed by the NERC Standards Committee in April 2009, establishes that proposed effective
dates “must be the first day of the first calendar quarter after entities are expected to be compliant.” The Implementation Plan is in
accordance with these guidelines.
5. The “load” being served by the station service transformer may be essential to operation of the generating plant, and therefore is not
the same as general distribution system load. Therefore, the SDT believes that these system components must remain within the
Applicability section of the Standard.
6. The definition of “maintenance correctable issue” is consistent with the way it is used within the Standard.
PPL Supply
1. For applicability to generators, the responsibility for a maintenance program will usually rest with the
plant operator when the operator and plant owner(s) are different entities. Consider changing the
applicability as it applies to the generator in such situations.
2. Time-based frequency should allow for flexibility; i.e. engineering analysis should allow the entity to
exceed the intervals noted in the table. An engineering evaluation that defines a test interval
differently than those intervals prescribed in the table should allow an entity to build a program with
different intervals.
3. A Grace Period should be defined. This allows a tolerance window to allow for unforeseen
occurrences. A grace period would allow for some schedule flexibility and reduce the number of
reports to the regulator for exceeding an interval by a reasonable about.
4. The implementation plan for this revision should take into account that a generator outage may be
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required to implement a new maintenance frequency. The implementation plan should account for
outage time, especially nuclear plants that have extended operating cycles.
5. Table 1b Protective Relays Level 2 Monitoring Attributes includes input voltage or current waveform
sampling three or more times per power cycle. No further guidance is provided in the reference
documents. If this sampling rate is not provided in the specification by the manufacturer, what can
the entity use to demonstrate that the attribute is satisfied? Please provide additional guidance.
6. Consider numbering the tables to improve cross-referencing the entries in program documentation.
This will allow entities to reference in program documents exactly which activities are being
implemented in accordance with the standard.
7. Requirement 1.1 states, “Identify all Protection System components.” This is too broad and must be
clarified.
Response: Thank you for your concern.
1. The Generator Owner, as defined within V5 of the NERC Functional Model, includes, “Design and authorize maintenance of
generation plant protective relaying systems…” No maintenance activities are assigned to the Generation Operator within the
Functional Model.
2. Requirement R3 and Attachment A provide the framework and requirements to develop and implement a performance-based
maintenance program as you suggest.
3. “Grace periods” within the Standard are not measurable, and would probably lead to persistently increasing intervals. However, an
entity may establish an internal program with grace-period allowance, as long as the entire program (including grace periods) does
not exceed the intervals within the Standard.
4. The Implementation Plan has been revised in consideration of your comment.
5. This attribute is only relevant to microprocessor-based relays; no other technology possesses this attribute. The entity should
contact the manufacturer to obtain this information.
6. The Tables have been completely revised in consideration of your comment.
7. Requirement 1, part 1.1 has been modified to state, “Address all Protection System component types.”
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Consumers Energy
Company
Question 7 Comment
In the Standard, Footnote 2 and Footnote 3 are identical. We presume that some information has been
omitted. We do not agree that Footnotes are an appropriate method of providing information that is
important to the application of the Standard. Important information should be provided within the
standard text.
Response: Thank you for your comments. The footnotes have been removed.
Nebraska Public Power
District
1. 4.2.5.1 (And elsewhere in the standard) Please define auxiliary tripping relays.
2. 4.2.5.5 Do station “system connected” service transformers that do not supply house load for the
generating unit, other than during start up or emergency conditions, fall under this clause? If so, can
these transformers be eliminated if the house load can be back-fed from “generator connected”
service transformer switchgear? What if there are redundant “system connected” feeds?
3. R1 1.4 Clarification requested. This wording would suggest all battery activities fall under Table 1.a.
exclusively.
4. R4 4.3 Does initiation of activities require documentation, or is inclusion of “initiation” in the testing
procedure sufficient evidence?
5. Tables 1b &1c: Suggestion: If at all possible, combine and simplify. The number of sub clauses and
nuances that are being described in these sections (with little change to interval or procedures for
that matter) is overwhelming. These two tables are setting RE’s and System Owners up for making
errors. Implementation and auditability should be the focus of this standard, SIMPLIFY.
6. SPS - Does the output signal need to be verified, or does the actual expected action need to be
verified. Actual expected action would affect electrical generation production for NPPD’s SPS.
Response: Thank you for your comments.
1. Please see FAQ II.4.C, II.4.D, II.4.E, II.4.F, II.4.G, and Sections 2.4 and 15.3 of the Supplementary Reference document for
discussion regarding auxiliary relays.
2. The “load” being served by the station service transformer may be essential to operation of the generating plant, and therefore is not
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the same as general distribution system load. Therefore, the SDT believes that these system components must remain within the
Applicability section of the Standard. This is not affected by redundancy.
3. The Tables have been completely revised in consideration of your comment. Please see the new Table 1-4 for these activities.
4. As indicated in Measure M4, the SDT believes that documentation such as work orders, etc., is necessary.
5. The Tables have been completely revised.
6. The draft Standard requires that the expected action is verified. This may be conducted in overlapping segments, and a simulation
may be sufficient to verify in some cases.
CenterPoint Energy
CenterPoint Energy believes the proposed Standard is overly prescriptive and too complex to be
practically implemented. An entity making a good faith effort to comply will have to navigate through the
complexities and nuances, as illustrated by the extensive set of documents the SDT has provided in an
attempt to explain all the requirements and nuances. The need for an extensive “Supplementary
Reference Document” and an extensive “Frequently Asked Questions Document”, in addition to 13
pages of tables and an attachment in the standard itself, illustrate that the proposal is too prescriptive
and complex for most entities to practically implement. CenterPoint Energy is opposed to approving a
standard that imposes unnecessary burden and reliability risk by imposing an overly prescriptive
approach that in many cases would “fix” non-existent problems. To clarify this point, CenterPoint
Energy is not asserting that maintenance problems do not exist. However, requiring all entities to
modify their practices to conform to the inflexible approach embodied in this proposal, regardless of how
existing practices are working, is not an appropriate solution. Among other things, requiring entities to
modify practices that are working well to conform to the rigid requirements proposed herein carries the
downside risk that the revised practices, made solely to comply with the rigid requirements, degrade
reliability.
Response: Thank you for your comments. The SDT has extensively revised the Tables and the Standard in efforts to simplify and
remove complexity. FERC Order 693 and the approved SAR for this project directed the SDT to establish both maximum maintenance
intervals and minimum maintenance activities within the revised Standard.
BGE
1. Comment 7.1. The standard, FAQs, and supplementary reference all make references to upkeep
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and include in “upkeep” changes associated with manufacturer’s service advisories. The FAQs
include statements that the entity should assure the relay continues to function after implementation
of firmware changes. This statement is uncontestable as general principle but is problematic in its
inclusion in an enforceable standard because there is no elaboration on what the standard expects,
if anything, as demonstration of an entity’s execution of this responsibility. PRC-005-2 appropriately
focuses on implementation of time-based, condition based, or performance based PSMPs; but
addressing service advisories does not fit well with any of these ongoing preventive maintenance
activities. It is instead episodic, more like commissioning after upgrades, or corrective maintenance
work generated by condition-based alarms or anomalies discovered by analyzing operations. The
standard appropriately steers clear of imposing requirements for these latter responsibilities as long
as execution of an ongoing maintenance program is being demonstrated. BGE recommends that
implied inclusion of service advisories should be removed from the standard and supporting
documents.
2. Comment 7.2 R1.1 Requires the identification of all protection systems components. But it provides
no elaboration on the level of granularity expected or acceptable means of identification. It is unlikely
that the SDT expected the unique identification of every discrete component down to individual test
switches or dc fuses. In the case of current transformers, several of which, or even dozens of which
may be connected to a single relay there is no apparent reliability benefit that comes from
indentifying them uniquely so long as it is proven that a protection system is receiving accurate
current signals from the aggregate connection. (It may be argued that the revised definition of
“protection systems” eliminates the need to include CT’s under R1.1 but that’s just one
interpretation.) Some discrete components of communication systems may exist in an environment
that is not owned by or known to the protection system owner. Additionally all protection system
components may be indentified in documents that are current and maintained but not in the form of a
specific searchable list that is limited to components that are within the scope of PRC-005.
Examples may be indexed engineering drawings that indentify relays and other components for each
protection systems or scanned relay setting and calibration documents that are current but not
attached to searchable metadata. It is unclear whether or not these would be considered acceptable
identification meeting R1.1. If they are not then the implementation plan for R1 is in all probability
unachievable. BGE requests that the SDT provide more elaboration on R1.1 in the standard and in
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the supporting documents.
3. Comment 7.3 For clarity footnote 1 to R1 which excludes devices that sense non-electrical signals
should explicitly say that the auxiliary relays, lockout relays and other control circuitry components
associated with such devices are included. The matter is well-addressed in the FAQ’s but could
easily be misunderstood if not included here.
Response: Thank you for your comments.
1. “Upkeep” has been removed from the definition of Protection System Maintenance Program, and from the Supplementary
Reference and FAQ documents.
2. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types.”
3. The SDT believes that these components are clearly included within the scope of dc control circuits.
WECC
1. Compliance believes it will be difficult to demonstrate compliance when an entity chooses Condition
Based Level 2 or Level 3 maintenance as the details of the requirements are still open to
interpretation. The FAQ has answers to specific questions that are multiple choices.
2. Breaking down this standard into this level of granularity requires supplementary documents to
understand it and for auditors to understand how to determine compliance. Industry standards are
specific to equipment types and should be allowed to set intervals and maintenance tasks rather
than a one-size fitting all approach.
Response: Thank you for your comments.
1. The Tables have been completely revised to clarify the monitoring attributes and related intervals and activities.
2. FERC Order 693 and the approved SAR for this project directed the SDT to establish both maximum maintenance intervals and
minimum maintenance activities within the revised Standard.
Constellation Power
Generation
November 17, 2010
1. Constellation Power Generation does not agree with the changes to Voltage and Current Sensing
inputs to protective relays in Table 1a. It is inferring that the only way to complete testing on these
components to satisfy NERC is to complete online testing, which is dangerous and does not improve
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the reliability of the BES. In fact, it can be argued that it decreases the reliability of the BES. The
verbiage should be changed back to what was originally proposed to allow for offline testing.
2. Furthermore, Constellation Power Generation does not agree with several of the inclusions of
generator Facilities in this standard. For example, in 4.2.5.1, the proposed standard looks to include
any components that can trip the generator. At a nuclear facility, this could include protection of
motors at the 4 kV level that may trip the generator due to NRC regulated safety issues. This should
not fall under NERC jurisdiction.
3. The inclusion of station service transformers is another inclusion that should not be in this standard.
There is no difference between a station service transformer and a transformer serving load on the
distribution system. This has no impact on the BES, which is defined as the system greater than 100
kV.
4. Additionally, CPG has concerns regarding the vague language of R1.1, which requires the
identification of all protection systems components. It provides no elaboration on the level of
granularity expected or acceptable means of identification. It is unlikely that the SDT expected the
unique identification of every discrete component down to individual test switches or dc fuses. In the
case of current transformers, several of which, or even dozens of which may be connected to a
single relay there is no apparent reliability benefit that comes from identifying them uniquely so long
as it is proven that a protection system is receiving accurate current signals from the aggregate
connection. (It may be argued that the revised definition of “protection stems” eliminates the need to
include CT’s under R1.1 but that’s just one interpretation.) Some discrete components of
communication systems may exist in an environment that is not owned by or known to the protection
system owner. Additionally all protection system components may be identified in documents that
are current and maintained but not in the form of a specific search-able list that is limited to
components that are within the scope of PRC-005. Examples may be indexed engineering drawings
that identify relays and other components for each protection systems or scanned relay setting and
calibration documents that are current but not attached to search-able meta data. It is unclear
whether or not these would be considered acceptable identification meeting R1.1. If they are not
then the implementation plan for R1 is in all probability unachievable.
5. CPG requests that the SDT provide more elaboration on R1.1 in the standard and in the supporting
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documents. In that vein, to clarify footnote 1 to R1 which excludes devices that sense non-electrical
signals, it should explicitly say that the auxiliary relays, lockout relays and other control circuitry
components associated with such devices are included. The matter is well-addressed in the FAQ’s
but could easily be misunderstood if not included here.
6. Lastly, Constellation Power Generation would like to voice concern over the expedited process in
which this standard is being developed. Voting within a week of submitting comments does not leave
enough time for the drafting team to thoroughly vet through the issues and identify much needed
changes, let alone implement them.
Response: Thank you for your comments.
1. The intent of the cited section is to provide examples of how an entity might perform the testing. Any examples listed in either of the
supporting documents should be looked upon as suggestions; these suggestions are not considered to be a complete list of the
methods available. To the contrary, the Standard and the supporting documents were written considering that there are many ways
to achieve a good test. Leeway is certainly available in how an entity complies with the Standard as the maintenance activities
generally specify “what” must be achieved but not “how” an entity achieves it. Please see FAQ II.3.D.
2. FAQ III.2.A specifies that relays that trip breakers serving station auxiliary loads such as fans, pumps, and fuel handling equipment
need not be included in the program even if loss of those loads could result in the tripping of the generator.
3. The “load” being served by the station service transformer may be essential to operation of the generating plant, and therefore is not
the same as general distribution system load. Therefore, the SDT believes that these system components must remain within the
Applicability section of the Standard.
4. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types.”
5. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types.” The SDT believes that the
components associated with devices that sense non-electrical signals are clearly included within the scope of dc control circuits.
6. This Standard has been designated for an expedited process in order to achieve approval in the minimum time possible.
Pepco Holdings, Inc. Affiliates
November 17, 2010
Dates of the Supplemental Reference Documents in Section F of the standard need to be updated.
1. The word “calendar” is used widely to define month and year intervals. Sometimes causes
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confusion, need definition/examples.
2. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are
to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1.
Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the
18 month interval is missing.
3. Req 1.1: “All Components” wording should say something like all components covered in our plan
Response: Thank you for your comments.
1. Section 8.4 of the Supplementary Reference document provides an example to assist in this determination. A “calendar year” is a
single number year on the Gregorian calendar; a calendar month is any one of the twelve months within a single calendar year.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
SERC Protection and
Control Sub-committee
(PCS)
1. Descriptors in the "type of the protection system component" column need to be consistent between
1A, 1B and 1C.
2. Also, in the tables, please clarify “complete functional trip test” for UVLS and UVLS trip tests since
the breaker is not being tripped. Facilities Section 4.2.1 “or designed to provide protection for the
BES” needs to be clarified so that it incorporates the latest Project 2009-17 interpretation. The
industry has deliberated and reached a conclusion that provides a meaningful and appropriate
border for the transmission Protection System; this needs to be acknowledged in PRC-005-2 and
carried forward.
3. We commend the SDT for developing such a clear and well documented second draft. The SDT
considered and adopted many industry comments on the first draft. It generally provides a well
reasoned and balanced view of Protection System Maintenance, and good justification for its
maximum intervals. The SERC Protection & Control Subcommittee generally agrees that this
second draft will be beneficial to BES reliability.
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Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
3. Thank you for your comment.
Dynegy Inc.
For protection system component verification, flexibility is needed subsequent to a system event to allow
the analysis of a protection system operation to be utilized as a protection system component
verification. We believe this flexibility is needed and should be incorporated in Requirement R4.
Response: Thank you for your comments. Operational results, if desired by an entity, MAY be used to meet maintenance
requirements to the degree that they verify, etc., the relevant performance. The entity must determine if their use is effective.
MidAmerican Energy
Company
1. From the compliance registry criteria for generator owner/operator and the language in 4.2.5.3 it is
implied that the intent is that protection systems for individual generators less than 20 MVA would not be
covered by PRC-005. To make this clear in the PRC-005-2 standard, the following footnote to section
4.2.5.3 is recommended: Protection systems for individual generating units rated at less than 20 MVA in
aggregated generation facilities are not included within the scope of this standard. The Request for
Interpretation of a Reliability Standard submitted March 25, 2009 indicates that a protection system is
only subject to the NERC standards if the protection system interrupts the BES and is in place to protect
the BES.
The following changes are recommended to clarify this in the standard:
A.3. Purpose: To ensure all transmission and generation Protection Systems protecting and affecting
the reliability of the Bulk Electric System (BES) are maintained.
A.4.2.1. Protection Systems applied on, or and designed to provide protection for the BES.B.R1. Each
Transmission Owner, Generator Owner, and Distribution Provider shall establish a PSMP for its
Protection Systems that use measurements of voltage, current, frequency and/or phase angle to
determine anomalies and to trip a portion of the BES and that are applied on, or and are designed to
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provide........
2. FERC Order 693 includes the directive that “testing of a protection system must be carried out within
a maximum allowable interval that is appropriate to the type of the protection system and its impact
on the reliability of the Bulk-Power System”. If unanticipated conditions (e.g. force majeure) of the
bulk-power system do not allow outages to complete protection system maintenance as required by
the standard without compromising the reliability of the system delay of the particular maintenance
activity should be allowed. This provision should be included in the standard in R4.
Response: Thank you for your comments.
1. This is an issue for your regional BES definition. The SDT has drafted the Standard to apply to all NERC entities with due regard
for the applicable BES definition.
2. “Grace periods” within the Standard are not measurable, and would probably lead to persistently increasing intervals. However, an
entity may establish an internal program with grace-period allowance, as long as the entire program (including grace periods) does
not exceed the intervals within the Standard.
Southern Company
Transmission
1. General FAQ1) Attached is an elementary drawing showing a typical transmission line relay
protection scheme utilizing SEL-351S and SEL-321 microprocessor relays. Does this qualify as
partially monitored control circuitry? See pdf file Control Elementary_1-07-13 & Control
Elementary_2-07-13in email documentation sent to Al McMeekin. If not, and this is an unmonitored
circuit, what would be the appropriate maintenance interval (6 years or 12 years) for the Control and
Trip Circuits from page 9 of PRC-005-2? The description of the two choices is ambiguous See pdf
file PRC-005-2_clean_2 010June8.pdf in email documentation sent to Al McMeekin. If not, what
would it take to make this circuit partially monitored (including inputs)?
2) Table 1a, page 9, row 2 (Voltage and Current Sensing Inputs) Question - Does this mean secondary
quantities from CT’s and VT’s only? If so, please consider changing the wording from “Voltage and
Current Sensing Inputs” to “CT and VT secondary quantities”.
3) Table 1a, page 9, row 3 (Control and trip circuits with EM contacts)Question - Does
"electromechanical trip or auxiliary contacts" mean EM protective relay outputs and EM
tripping/lockout tripping contacts only? Or does it also include any part of the trip circuitry such as
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cutout switch contacts and breaker trip coils plus associated aux. breaker contacts. For example, the
schematic with a microprocessor relay described in the first bulleted item could be considered an
unmonitored EM control circuitry (6 year interval). Is this because of the mechanical breaker aux
contacts, breaker maintenance switch, and FT-1 test switch? If so, how could any control circuitry fall
in the solid state trip contacts category (12 year interval)?
4) Table 1a, page 9, rows 3, 4, 5, 6 - Please consider rewording these to make it clear where control
schemes with MP relays that do have trip coil / circuit monitors but don’t meet the Partially Monitored
requirements fit. (Does this type scheme fit in the 6 year trip test category or the 12 year category?)
5) Table 1a, page 12, row 1 - The maintenance requirements are not the latest wording used for all
other Protective Relays. Please consider changing for consistency.
6) Table 1b, page 13, row 1 (Protective Relays) - Line three of the maintenance activities requires us to
check inputs and outputs. The last maintenance item is to verify correct operation of output actions
that are used for tripping. Question - How is this different than the line three maintenance
requirements to check inputs and “outputs”?
7) Table 1b, page 14, rows 1 and 2 - Consider combining these into one row. The maintenance
intervals and maintenance activities are these same. Please specify what is required for UFLS and
UVLS control schemes).
8) Table 1b, page 14, rows 1 - The first sentence is very general for a monitoring attribute. (“Monitoring
of Protection System component inputs, outputs, and connections with reporting of monitoring alarms
to a location where action can be taken.”) Consider deleting this row or make it more specific.
9) Table 1b, page 14, row 2 [Control Circuitry (Trip Circuits) (except for UFLS/UVLS)]Question: Should
there be a 12 year functional trip test requirement for this partially monitored control circuitry? Should
this be added to Table 1b?
10) Table 1b, page 14, row 1 [Control Circuitry (Trip Circuits) (except for UFLS/UVLS)] - It states
Monitoring of Protection System component inputs, outputs, and connections ... Question - what
does “inputs” mean? There are Protection System components such as protective relays, control
circuitry, station dc supply, associated communications systems, etc. Does this mean we must
monitor inputs to any or all of these Protection System components? How would this be
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accomplished?
11) Table 1c, page 18, row 4 - Should there still be a requirement to trip breakers by all trip coils every 6
years?
Supplementary Reference Document
12) Question on Figure 1, page 27 - Box 1 denoting Protection Relays includes Aux devices, Test or
Blocking Switches. The Aux devices Test or Blocking Switches should be part of Box 3 (Control
Circuitry). Please correct or note accordingly.
FAQ Document
13) On Page 30, please add an Example with Partially Monitored (Level 2) Control Circuit.
14) On the Control Circuit Decision Tree on page 36, the flow chart does not match the current Table 1
requirements. They match the previous version which is described in the first question of this
document. We still propose leaving the flow chart on page 36 as is and change Table 1 to match the
original requirements.
15) Please consider adding a diagram /elementary drawing of a Partially Monitored Control Circuit
showing the trip output contacts, inputs, etc that must be monitored to meet the Monitoring Attributes
/ Requirements. A diagram showing an Unmonitored control scheme and what it would take to make
it Partially Monitored would be helpful too.
Additional General FAQ
16) PRC-005-2, R1 requires the Functional Entity to establish a Protection System Maintenance
Program (PSMP). It is not clear if this standard establishes a specified frequency for reviewing and
updating the PSMP itself or the PSMP criteria outlined in subparts 1.1 through 1.4. By comparison,
EOP-005-1 System Restoration Plans, requires the Functional Entity to (a) have a restoration plan
and (b) to review and update the restoration plan annually (see EOP-005-1, R1 and R2). This
approach to a comprehensive and periodic review considers the PSMP as a whole and is
independent of the specific maintenance methods (time-based, condition-based, or performancebased) and maintenance intervals for those respective methods. It is noted however that PRC-005
Attachment A mentions annual updates to the list of Protection System component. According to the
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Attachment’s subtitle, Criteria for a Performance-Based Protection System Maintenance Program,
this annual update seems limited to performance-based maintenance and not inclusive of other
maintenance methods. The recommendation is to evaluate the need for a periodic review of the
PSMP as a whole.
17) R1, Criteria 1.1, and companion VSL. This Criterion requires the identification of all Protection
System components. The VSL for R1 uses a percent-based approach to parse out different
quantities of components across the four VSL categories. This implies that a Functional Entity must
have the ability to put a numerical quantity on its various components and should be able to
demonstrate within certain tolerances that its components are included (or counted). If the number of
components within scope amount to hundreds or thousands of individual items, the PSMT SDT
should consider the Functional Entities’ ability to track and quantify the items for a compliance
demonstration. If an entity is not able to reasonably quantify which components are in scope,
demonstrating compliance on a percent-basis may prove difficult or impossible. Further review may
indicate the need to reformat the VSL. Similar concerns are noted in other VSLs (R2, R3, and R4)
and in Attachment A where percentage-of-components are mentioned.
18) R4 essentially requires the Functional Entity to implement its PSMP. R4 takes care to highlight the
specific task of “identification of the resolution of all maintenance correctable issues.” It is noted that
other “identification tasks” are included as criterion for the PSMP in R1. If these tasks are all
appropriately categorized as identification-type tasks, it may be more efficient to restructure the
standard by incorporating this task into R1 with the other criteria. R4 could remain as a basic
implementation requirement with more detail provided in subparts 4.1, 4.2, and 4.3.
19) Footnote No. 2 describes maintenance correctable issues and could be interpreted as a potential
new term for inclusion in NERC’s Glossary of Terms. The PSMT SDT should conduct further review
of this terminology as a potential new Glossary term.
20) At R4, subpart 4.3, insert “design” such that it reads as follows: “Ensure that the components are
within acceptable design parameters at the...” Also, this subpart duplicates Footnote No. 3 which
describes “maintenance correctable issues” and was established in the main requirement R4 at
Footnote No. 2.
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Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. This portion of the definition of Protection System has been revised. Also, the Tables have been rearranged and considerably
revised to improve clarity. Please see new Table 1-3.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
5. The Tables have been rearranged and considerably revised to improve clarity.
6. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
7. The Tables have been rearranged and considerably revised to improve clarity.
8. The Tables have been rearranged and considerably revised to improve clarity.
9. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
10. Some examples of input may include, but are not limited to: breaker fail initiate, start timer. This cannot be an all-inclusive list as
any given scheme could have many variations. In short, if your scheme requires a specific input to function properly then you must
have that input maintained; if your scheme has a specific output that must function then it must be maintained. If the input or output
is used for a non-protective function (such as, but not limited to, Sequence-of-Events Recorder, alarm or indication) then it does not
have to be maintained under this Standard. See Section 15.3 of the Supplementary Reference and FAQ II.2.L.
11. Yes.
12. The diagram is for illustrative purposes only, and is intended to demonstrate all devices which need to be included within a PSMP.
Box 1 shows the cited devices as being within the relay panel, and makes no distinction regarding what specific type of Protection
System component is being addressed. The preceding Table has been revised to avoid this conclusion.
13. The Tables have been revised to remove descriptions of various levels of monitoring.
14. The decision trees have been removed.
15. The Tables have been revised to remove descriptions of various levels of monitoring.
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16. The expectation is that an entity’s PSMP will be current. No periodicity is provided. However, in Attachment A, the performancebased program necessarily requires an ongoing review of the program to assure that it is still relevant.
17. Requirement R1, part 1.1, has been revised to state, “Address all Protection System component types.”
18. The SDT believes that the identification of maintenance-correctable issues is properly an issue for implementation of the PSMP,
not establishment of the PSMP.
19. The referenced footnote has been removed and a new definition established for this Standard only.
20. The SDT disagrees. The acceptable parameters for a specific application may not be identical to the design parameters for the
component.
FirstEnergy
Implementation Plan
a. We do not support the 3 month implementation timeframe for Requirement 1. For many entities, it will
take some time to develop a sound PSMP that meets the new PRC-005-2 standard. We suggest a 12
month implementation which we believe is more logical and in alignment with the implementation
timeframe for Protection System Components with maximum allowable intervals of less than 1 year, as
established in Table 1a.
b. Although we support the implementation timeframes for Requirements R2, R3, and R4, we do not
support the required periodic percentages of protections systems to be completed. There could be
numerous reasons where an entity has to adjust its program schedule which could lead to
noncompliance with these percentage milestones. We suggest simply requiring 100% completion of the
maintenance per the maximum maintenance intervals. Alternatively an entity should have the flexibility
to indicate they have fully transitioned to the new standard during the early stages of the implementation
plan if their existing maintenance practices meet or exceed the standards minimum expectations. Doing
so should negate the need to produce the "% complete" implementation status.
Response: Thank you for your comments.
a. The Implementation Plan has been modified in consideration of your comment.
b. The SDT disagrees and feels that a “phased” Implementation Plan is appropriate. The Implementation Plan has been revised to
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clarify that the percentages are minimums, not absolute.
American Transmission
Company
1. It is appreciated that the SDT is attempting to provide options for maintenance and testing programs.
Practically speaking, it will be difficult to perform any type of program outside of Time-Based
Maintenance (TBM). Too many circuits are a mix of technology. For example, a line may have
microprocessor relays for detecting and tripping line faults, but the bus differential lockout could also
trip the line breaker. One may be partially monitored and the other unmonitored. It will force the
utility to perform maintenance at the shorter of the maintenance cycles. Additional time and cost will
be required to organize and switch out the applicable equipment for the outage, approximately
doubling the cost associated with performing these trip tests. When entities are required to maintain
tens of thousands of these devices, the simplest approach will be to revert to TBM. ATC does not
support the existing 2nd Draft of PRC-005-2 Standard because it is our opinion that:
o There is a high probability that system reliability will be reduced with this revised standard.
o The number of unplanned outages due to human error will increase considerably.
o Availability of the BES will be reduced due to an increased need to schedule planned outages for
test purposes (to avoid unplanned outages due to human error). o To implement this standard, an
entity will need to hire additional skilled resources that are not readily available. (May require
adjustments to the implementation timeline.)
o The cost of implementing the revised standard will approximately double our existing cost to
perform this work.
2. ATC requests that relevant reliability performance data (based on actual data and/or lessons learned
from past operating incidents, Criteria for Approving Reliability Standards per FERC Order 672) be
provided to justify the additional cost and reliability risks associated with functional testing.
3. Under a Performance-Based Program, what happens if the population of components drops below 60
(as all will eventually)? Is there an implementation period to default to TBM?
4. Are the internal relays and timers associated with a circuit breaker included as part of the protection
scheme? In the Independent Pole Operation breakers (IPO), there are various internal schemes built
to protect for pole discordance (one pole open, two closed, event measured over time frame
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(milliseconds)), these schemes may re-trip the breaker, initiate breaker failure protection or trip a bus
lock out relay. In DC control schemes fuses and panel circuit breakers protect for wiring faults. Do
these devices need to be tested? Is there an obligation to test the distribution circuit breakers for
correct operation points? Is there an obligation to replace fuses after a defined time period?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see the new Tables.
2. The Standard does not preclude an entity from largely utilizing other methods of verification, although functional testing may be the
easiest to achieve.
3. The entity must revert to TBM if the population falls below 60. There is no implementation period; the SDT believes that the annual
PBM review will alert the entity that the population is nearing 60, and allow the entity to react to the diminishing component
population accordingly.
4. Only those control circuit components necessary for proper Protection System operation are included. As noted, many breakers
have numerous other internal auxiliary functions (gas pressure, etc.) that are not relevant. A purely-functional test may address
many of the issues cited. There is no obligation to test either distribution circuit breakers or dc panel fuses.
NERC Staff
NERC staff is pleased with the current iteration of this standard. The staff understands that while PRC005-2 has historically been the most frequently violated standard, it has mostly been due to
documentation issues. The standard has not been much of a heavy hitter in causal or contributive
aspects, and with respect to relay operations, there have been very few times that lack of maintenance
has been the problem.
1. NERC staff does propose a slight change to 4.2.5.1. The concern is that 4.2.5.1 could be interpreted
to apply to devices that protect the generator as opposed to those that protect the Bulk Electric
System. The suggested language is as follows: “Protection System components that act to trip
generators that are part of the BES, either directly or via generator lockout or auxiliary tripping
relays.”
2. Additionally, staff suggests some changes to R1. In that requirement, the PSMP covers “Protection
Systems that use measurements of voltage, current, frequency and/or phase angle to determine
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anomalies and to trip a portion of the BES...” It probably would be better if the list was limited to
voltage and current or if the list was replaced with electrical quantities. The former would be okay
since voltage and current are the only two electrical quantities that relays measure directly. To
remove ambiguity, the most inclusive way to rephrase this is probably the latter alternative, to
change the requirement to, “...that use measurements of electrical quantities to determine
anomalies...”
3. Finally, Footnotes 2 and 3 (in Requirement 4) are identical. Unless that’s intentional, one should be
removed. (And note that Footnote 2 is missing a period.)
Response: Thank you for your comments.
1. The essence of your suggestion is already addressed within 4.2.5 itself.
2. The definition of Protection System has been revised to address your suggestion.
3. The footnotes have been removed.
MEAG Power
No comment.
Exelon
1. Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission
(NRC). Each licensee operates in accordance with plant specific Technical Specifications (TS)
issued by the NRC which are part of the stations’ Operating License. TS allow for a 25% grace
period that may be applied to TS Surveillance Requirements.
Referencing NRC issued NUREGs for Standard Issued Technical Specifications (NUREG-143
through NUREG-1434) Section 3.0, "Surveillance Requirement (SR) Applicability," SR 3.02 states
the following: "The specified Frequency for each SR is met if the Surveillance is performed within
1.25 times the interval specified in the Frequency, as measured from the previous performance or as
measured from the time a specified condition of the Frequency is met."
The NRC Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness of maintenance to
ensure reliable operation of equipment within the scope of the Rule. Adjustments are made to the
PM (preventative maintenance) program based on equipment performance. The Maintenance Rule
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program should provide an acceptable level of reliability and availability for equipment within its
scope.
The NRC has provided grace periods for certain maintenance and surveillance activities. Exelon
strongly believes that SDT should consider providing this grace period to be in agreement and be
consistent with the NRC methodology. Not providing this grace period will directly affect the existing
nuclear station practices (i.e., how stations schedule and perform the maintenance activities) and
may lead to confusion as implementing dual requirements is not the normal station process. Nuclear
generating stations have refueling outage schedule windows of approximately 18 months or 24
months (based on reactor type). If for some reason the schedule window shifts by even a few days,
an issue of potential non-compliance could occur for scheduled outage-required tasks. The
possibility exists that a nuclear generator may be faced with a potential forced maintenance outage in
order to maintain compliance with the proposed standard.
For the requirements with a maximum allowable interval that vary from months to years (including 18
Months surveillance activities), the SDT should consider an allowance for NRC-licensed generating
units to default to existing Operating License Technical Specification Surveillance Requirements if
there is a maintenance interval that would force shutting down a unit prematurely or face noncompliance with a PRC-005 required interval.
Therefore, at a minimum, maintenance intervals should include an allowance for any equipment
specifically controlled within each licensee’s plant specific Technical Specifications to implement
existing Operating License requirements if such a conflict were to occur.
2. PECO would like to have the implementation plan provide at least 1 year for full implementation of
the new standard. This will provide adequate time for development of documentation, training for all
personnel, and testing then implementation of the new process(es).
Response: Thank you for your comments.
1. The SDT understands that nuclear power plants are licensed and regulated by the NRC, has a general understanding of the role
that plant Technical Specifications (TS) and associated Surveillance Requirements (SR) in the facilities’ operating licenses, and has
tried to be sensitive to potential conflicts between PRC-005-2 and NRC requirements.
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The SDT believes that the majority of components making up the protection systems for in-scope generating facilities as discussed
in Section 4.2.5 of the Standard would be considered balance of plant equipment and, therefore, not subject to NRC-issued TS and
associated SR requirements. While availability of plant auxiliary sources to the plant’s safety related equipment is addressed by TS
and associated SR requirements, these documents are focused on the effects that the availability of these transformers have on
reactor safety rather than specifying maintenance and testing requirements for the Protection Systems for these transformers.
The SDT recognizes that some battery systems may serve as a source of DC power to both reactor safety systems and to
Protection Systems discussed in Section 4.2.5. The SDT acknowledges that there might be plant TS and SR applicable to these
batteries. However, the SDT believes that the 3-month and 18-month inspection requirements called for in PRC-005-2 would be no
more onerous than plant TS requirements for routine online safety system battery inspections and, furthermore, would not
necessitate a plant outage. The SDT recognizes that the PRC-005-2 requirement for validating battery design capability via battery
capacity testing would require a plant outage. However, it is the opinion of the SDT that the maximum allowed battery capacity
testing intervals of not to exceed 6 calendar years for vented lead acid or NiCad batteries (not to exceed 3 calendar years for VRLA
batteries) could easily be integrated within the plant’s routine 18-month to 2-year interval refueling outage schedule.
The SDT believes that PRC-005-2 is complementary to the NRC Maintenance Rule in that PRC-005-2 requirements allow for the
leveraging of the entire electrical power industry experience in establishing minimum maintenance activities and maximum allowed
maintenance intervals necessary to ensure reliable Protection System performance.
Please see Supplemental Reference Section 8.4 for further discussion for the SDT’s rationale for exclusion of grace periods.
Please see FAQ IV.2.C for further discussion of impact of PRC-005-2 testing requirements on power plant outage schedules. The
challenge of integrating PRC-005-2 testing requirements with a plant’s outage schedule is not unique to nuclear plants.
Finally, the SDT notes that an entity may build grace periods into its own PSMP as long as the maximum allowed time intervals of
PRC-005-2 are not exceeded. If an entity wishes to build a 25% grace period into its program, it may do so by setting its program
maintenance and testing intervals at <80% of the PRC-005-2 maximum allowable time interval.
2. The Implementation Plan has been modified in consideration of your comments.
Hydro One Networks
1. Footnotes 2 and 3 on page 4 are identical. Delete footnote 3.
2. UFLS systems by design can suffer random failures to trip. It would make sense for a requirement to
exist to perform maintenance on the UFLS relay as their failure to operate may affect numerous
distribution level feeders. However maintenance on associated DC schemes connected to the
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devices should only be done on the same frequency as maintenance on the relevant interrupting
devices. Consideration should be given to exempting schemes that have a maintenance program in
place on those distribution level devices from PRC-005 Standard-specified maintenance intervals.
Such Standard-specified intervals could apply to interrupting devices that have no maintenance
program in place.
Response: Thank you for your comments.
1. The footnotes have been removed.
2. The Tables have been rearranged and considerably revised to improve clarity, and many activities related to UFLS have been
removed. Please see the new Tables.
Progress Energy Carolinas
1. R1.1.1 states that “all” protection system components be identified. Does the term “all” refer to the
major components identified in the Protection System definition (protective relays, communication
systems, voltage and current sensing devices, station dc supply, and control circuitry) or does it
include all sub-components (jumpers, fuses, and auxiliary relays used in dc control circuits and
communication paths/wavetraps/tuners/filters)? We assume the former but request clarification.
2. Draft Implementation Plan for PRC-005-02: The phased implementation plan for R2, R3, and R4
seems reasonable. However, the three-month implementation plan for R1 seems extremely short.
Utilities will have to change procedures, job plans, basis documents, provide training, and change
intervals in their work tracking databases. In addition, if the utility wants to take advantage of the
longer intervals allowed by partial monitoring, significant print work must be performed up front.
3. Descriptors in the type of the protection system column needs to be consistent between 1A, 1B and
1C. In the tables, please clarify “complete functional trip test” for UVLS and UVLS trip tests since the
breaker is not being tripped.
Response: Thank you for your comments.
1. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
2. This portion of the Implementation Plan has been revised to twelve months in consideration of your comment.
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3. The Tables have been rearranged and considerably revised to improve clarity. Please see the new Tables.
Manitoba Hydro
1. Once the new Standard is approved, NERC must allow for a greater implementation stage and no
further changes proposed for the foreseeable future. It does take a lot of resources for a Utility to
make the required changes in maintenance frequency templates or type of maintenance required as
per the proposed "Standard".
2. Regarding the use of the term “Calendar” (i.e. end of calendar year) for maximum maintenance
interval. Our utility uses end of fiscal year as our cutoff date for completing maintenance tasks for a
given year. It would be considerable work for us to have to switch to end of calendar year with zero
improvement in our overall reliability. We suggest it be left up to each utility to define their calendar
yearly maintenance cycle when all tasks for that year must be completed.
Response: Thank you for your comments.
1. The implementation period for Requirement R1 has been extended from 3 months to 12 months in consideration of your comments.
2. With the vast array of entities subject to compliance monitoring, it would be very difficult for the ERO to assess compliance for
varying “years.” Additionally, the SDT understands that most compliance monitors currently request data on a calendar year basis
when assessing compliance.
Grant County PUD
PRC005-02 Comment
We offer some comment for your consideration for incorporation into the Standard PRC-005-02 (draft)
as presented in the May 27th 2010 PRC 005-02 “Standard Development Roadmap.” RE: Comment on
the 2nd Draft of the Standard for Protection System Maintenance and Testing”
1) The term “The Protection System Maintenance Program” (Page 2) appears to be centered on the
concept of maintaining specific components as stand alone objects, and therefore infers that the
resultant documentation be organized in a similar fashion. Neither is optimal from a practical or a
functional perspective. Many rational work practices combine components (example, meggering from
the relay input test switch through the cables and the CTs) in the interest of minimizing circuit
intrusion and human error. For this reason, such maintenance practices are superior from a reliability
standpoint. The emphasis on “components” in the current draft is, at best, tangential to NERC’s
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stated goal and purpose of PRC-005 to improve reliability. How would we fix this? We would insert
the phrase “or Element”-as defined in NERC’s Glossary of Terms to include “one or more
components / devices with terminals that measures voltage, current, frequency and/or phase angle”
to determine anomalies and to trip a portion of the BES” immediately after any occurrence of the word
“component” in each of the Requirements or in a Definition paragraph, intending it to be applied
globally to R-1 through R4. This would foster the validity of maintenance activities being applied to
aggregations of components - “Elements”-such as would occur during Verification of DC control
circuitry or through the employment of fault data analysis.
2) Protection System Maintenance Program. The categorization of maintenance into 7 maintenance
activities is welcomed as advancing practices which foster BES reliability. Likewise we find the
clarifications denoted by superscripts 1 and 2 helpful. However....under C: MEASURES: M1, the last
sentence of the paragraph provides: “For each protection system component, the documentation
shall include the type of maintenance program applied (time based, etc), maintenance activities (1 or
more of the 7 identified) and maintenance intervals.....” This measure goes beyond the requirements
of the standard and should be revised consistent with the deletion of the previous R.1.1 as shown in
track changes under the version 2 draft which had included the identification of the maintenance
activity associated with each component. COMMENT: It should be apparent in reviewing the
evidence that one or more of the 7 listed activity categories are represented. The proscription to
explicitly call out these categories is thus redundant---the requirement being that at least one has to
be identifiable in the program-and will cause unnecessary complications to the Entity and
interpretation issues in the Compliance monitoring effort. We recommend that the words
“maintenance activities” be removed from the last sentence in the paragraph pertaining to C:
MEASURES: M1.We also believe it is unnecessary to restate the definition of “Protection System” in
the Measure.
3) A fundamental incompatibility exists between NERC’s proposition of “maximum maintenance (time
based) interval” and the typical CMMS PM generation algorithm. SPCTF members and regional
compliance engineers have verbally represented that the “maximum maintenance interval” is a
precise term “not to exceed-even by one day---” maximum, otherwise generating a fine-able Violation
and that fixed intervals plus or minus a certain additional period of time to account for other
operational exigencies are no longer going to be permitted. There is always an interval between the
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time a CMMS PM is issued and its completion. The time interval between the issue date and the
completion date is normally a period of time to allow maintenance staff to schedule their work in an
orderly fashion. The maximum time based interval is fixed by the time period specified for issuance of
the planned maintenance (PM) work order (e.g. every 3 years) and the defined period of time to
complete the work (usually described as a percentage of the PM interval e.g. 25%). So predicating a
PM issue date based on the last issue date plus a percentage of the interval time to complete the
work is not inconsistent with a fixed time interval. Under the proposed tables, however, there is no
accommodation for this predominate maintenance practice.
Even if maintenance intervals were shortened to ensure that the required completion date as defined
by program intervals does not exceed the NERC maximum interval as described in the tables, this
will not be sufficient because auditors may conclude that the tables permit the use of only a single
defined interval and not permit an additional defined period of time to schedule and complete the
work. Remember, it is immaterial whether the Entity’s interval is more stringent than the NERC
maximum, a violation may occur if the maintenance is not performed within the Entity’s maintenance
interval, even if it is shorter than the NERC maximum. A precise maximum interval requires constant
managerial intervention on the part of the Entity to ensure that operational exigencies do not cause
violations on a component-by component (or element) basis. The shortened interval would tend to
destroy the sense of rhythm and pattern which should be manifest in a time based program.
Further, after one or more iterations, seasonal restrictions on outages begin to impinge requiring
adjustments to be made to the Maintenance Program document to adjust the interval or maintenance
activity. At best, it results in a clumsy way of doing business and requiring significantly more
oversight into keeping the maintenance program document updated for presentation to auditors
rather than focusing on prudent maintenance activities as desired by FERC Order 693. Auditing is
not any more difficult if the Maintenance Program also specifies that a percentage of a fixed target /
time interval is allowed to schedule and complete the work-as meeting the interval requirements of a
time based maintenance program. This method allows for a fixed time for issuance of the work order
and maintenance personnel some flexibility to schedule and complete their work within a defined
period of time. We recommend to vote against adoption until some more workable solution is
identified and disseminated, satisfying both the Compliance Authority and the affected Entities.
Specifically, we recommend that the drafting team adopt “target” intervals with a +/- range of
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acceptability, based on percentage or a fixed time per interval, which can be global for the Program
or specific to the elements or components in question. The target intervals must be stated in the
PSMP, the range of acceptability easily calculable and enforceable, and within the maximum intervals
to be identified in the tables 1a, b, and c, satisfying compliance issues. This also allows the Entities
to rationally plan their maintenance using existing CMMS technologies.
4) Within the Violation Security levels, we are aware of no activity by NERC to differentiate the relative
criticality of components or Elements of the BES system. For example, protection system
components or Elements in a regional switchyard may present a larger potential for disruption of the
BES in the event of a mis-operation than does one associated with one generator among fifteen
others and which is more electrically remote from and of less consequence to the BES. Unless and
until this issue is addressed, both the PRC-005 maintenance and documentation will be less effective
and more expensive than it could be.
5) PRC-005-02’s proposed effective date is “See Implementation Plan.” This is not adequate to provide
regulated entities with appropriate notice of the Effective Date of PRC-005-2 standard. “
6) Additionally, NERC has not posted the “Implementation Plan” for comment in the same manner as
the proposed standard and thus we are not able to comment on the schedule provided in the Plan.
We understand that the retention and documentation cycles go back three years and that a regulated
entity, depending on the effective date of this standard and the entity’s audit cycle, will be audited to
both PRC-005-1 and PRC-005-2 during the same audit period. Some further discussion should be
given to allowing comment on the Implementation Plan because of the potential overlapping
requirements during a single audit cycle.
Response: Thank you for your comments.
1. The draft Standard supports a variety of methods of designing the PSMP.
2. A definition of “Component” and “Component Type” has been added to the draft Standard. The SDT’s intent is that this definition
will be used only in PRC-005-2, and thus will remain with the Standard when approved, rather than being relocated to the Glossary
of Terms. The Requirements and Measures have been modified to use these terms in a consistent manner. These defintions will
assist in addressing your concern.
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3. This comment seems to suggest that a “grace period” should be permitted. “Grace periods” within the Standard are not
measurable, and would probably lead to persistently increasing intervals. However, an entity may establish an internal program
with grace-period allowance, as long as the entire program (including grace periods) does not exceed the intervals within the
Standard.
4. Thank you for your comment. The VRFs address the reliability impact of the Requirements, while the VSLs simply address “how
bad did you miss it?”
5. The Implementation Plan for Requirement R1 has been revised from 3 months to 12 months to address this comment.
6. The Implementation Plan was posted for comment, with a question on the comment form during the first posting. The
Implementation Plan was not substantially revised for the second posting. During the implementation period, there will be some
overlap between PRC-005-1 and PRC-005-2. An unattractive alternative would be to minimize the implementation period for PRC005-2.
Xcel Energy
1. R1.1 “Identify all Protection System Components” - does this mean that the PSMP must contain a
“list”? Please explain what this means. If it is a list, then essentially it will be a dynamic database,
not necessarily a “program” as defined in the PSMP
2. R1.3 “include all maintenance activities...” seems to be an indirect way of indicating that the entities
PSMP must comply with the tables. Tables the components related to DC Supply and battery
are confusing. It the battery is the specific component then state “battery". If the charger is the
specific component, then state “charger”. As currently written, one must sort through all of the
different “Station DC Supply” line items to figure out what is required.3. In tables 1b and above, it is written “no level 2 monitoring attributes are defined - use level 1
maintenance activities” but then maintenance activities are listed that don’t match with Level 1
maintenance activities. Please clarify what exactly needs to be done if using Table 1 b and above.
Response: Thank you for your comments.
1. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
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3. The Tables have been rearranged and considerably revised to improve clarity.
Northeast Utilities
1. R1.1 It is not clear what would constitute “all Protection System components”. Suggest the addition
of a definition for “Protection System components”.R1.4 Suggest revise to read: “all batteries or dc
sources”
2. Table 1a vented lead acid -- “Verify that the station battery can perform as designed by evaluating
...” -- Please define evaluating, including:
a. What is the basis for the evaluation?
b. Is 5% 10% 20% etc acceptable?
c. Where does baseline come from for older batteries?
3. Request clarification of 2.3 Applicability of New Protection System Maintenance Standards from
Supplementary Reference. Specifically, please clarify if a functional trip test is needed to be
performed on the distribution circuit breakers to protect the Bulk Electric System (BES) if these low
side breakers are not part of the transmission path. (A diagram identifying the applicable breakers
would be helpful in the Supplementary Reference)
Response: Thank you for your comments.
1. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types”..(a) The basis is related to
the variation from the baseline. Please see FAQ II.5.G and II.5.F. (b) This is determined by the entity based on the application. (c)
The baseline can be provided by the battery manufacturer or the test equipment OEMs.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
South Carolina Electric and
Gas
R1.1 states “Identify all Protection System Components”. To avoid confusion this should be clarified. It
could be interpreted that discreet components must be individually identified. An example would be as
individual aux relays used in the tripping path.
Response: Thank you for your comment. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System
component types”.
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PacifiCorp
Question 7 Comment
1. R1.1: Please clarify what the requirements for “identify” means. Does each component need to be
“identified” in our maintenance system, or at least referenced in the maintenance program or labeled
in the field???
2. R4.3: Please provide guidance on what will be required to prove compliance that “maintenance
correctable issues” have been identified and corrective actions initiated.
3. What is the implication of finding maintenance correctable issues as it relates to other requirements
for no single points of failure? In other words, if during maintenance a relay is found to have failed, is
there an acceptable time period under which we may operate the system without redundancy until a
repair can be made? Similarly, if part of a redundant relay system is taken out of service for
maintenance, may the facility it was protecting be left in service? If not, then is the implication that
protection systems must be triple redundant in order to do relay maintenance on in service
equipment? Otherwise facilities would always have to be removed from service to do relay
maintenance.
4. Section D / 1.3: The data retention requirement for the two most recent performances of each
maintenance activity is excessive. The requirement should be limited to the most recent or all
activities since the last on-site audit. At the worse case an entity would have to retain records for up
to 35 years for maintenance performed on a 12 year cycle.
5. Table 1a “Protective Relay” entry: The last maintenance activity is listed as “for microprocessor
relays verify acceptable measurement of power system input values “ for which a 6 year interval is
provided”. How is this different than the next item “Voltage and Current Sensing Inputs to Protective
Relays and associated circuitry” which is on a 12 year interval?? Please clarify this.
6. Implementation Plan: This revised standard will drive significant revisions in existing maintenance
programs. 3 months is not adequate time after approval to ensure compliance with R1. A minimum
of 6 months should be utilized after regulatory approval. The Implementation plan requirements
should also recognize that if the requirement to maintain records of the two previous maintenance
tasks is implemented, it may not be possible to produce this information upon implementation. The
implementation plan should be structured that the requirement to produce previous maintenance
records should be phased in as the maintenance is performed. (ie. The requirement to produce two
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previous records for maintenance performed on a two year cycle should not be enforced until four
years after implementation).
Response: Thank you for your comments.
1. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types”.
2. Various means may be used. One suggestion would be work orders that addressed the issue.
3. It is left to the entity to determine HOW to address maintenance-correctable issues. It is reasonable that an entity would do so in a
manner that presents the least disruption to the system and considers the impact of the malfunctioning component on reliability.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data
of the most recent performance of the maintenance, as well as the data of the preceding one, as well as data to validate that entities
have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified
the data retention in the posted Standard to establish this level of documentation. The Tables have been rearranged and
considerably revised to improve clarity. Please see new Table 1-1.
5. The Implementation Plan for Requirement R1 had been revised from 3 months to 12 months.
Springfield Utility Board
SUB is supportive of the intent behind the standard and appreciates the ability to provide input into this
process.
1.The following is a repeat of the comment in Question #5 with regard to the supplemental reference.
SUB appreciates that Time Based, Performance Based, and Condition Based programs can be
combined into one program. However it should be clear that a utility may include one, two or all three of
these types of programs for each individual device type.
Currently the language reads:"TBM, PBM, and CBM can be combined for individual components, or
within a complete Protection System." The "and" requires all three to be combined if they are combined.
SUB suggests the “and” be changed to "or" language.
Change:"TBM, PBM, or CBM can be combined for individual components, or within a complete
Protection System."
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Response: Thank you for your comments. Please see our response to your comment in Question 5.
The Detroit Edison
Company
1. Suggest that the implementation plan for R1 (PSMP) be changed to 12 months.
2. The statement in R1.1, “Identify all Protection System components” regarding the PSMP should be
clarified. Is a complete list of every “component” of each specific protection system required to be
included in the PSMP?
Response: Thank you for your comments.
1. The Implementation Plan for Requirement R1 has been revised from 3 months to 12 months.
2. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
Long Island Power
Authority
1. Table 1a under Maintenance Activities for Control and trip circuits with unmonitored solid-state trip or
auxiliary contacts (UFLS/UVLS Systems Only) states: Perform a complete functional trip test that
includes all sections of the Protection System control and trip circuit, including all solid-state trip and
auxiliary contacts (e.g. paths with no moving parts), devices, and connections essential to proper
functioning of the Protection System., except that verification does not require actual tripping of
circuit breakers or interrupting devices. The word complete may be removed as it requires actually
tripping the breakers. The sentence that tripping of the circuit breakers is not required contradicts
with the word complete.
2. More specifics are required to spell out the adequate testing e.g. up to the lockout with the trip paths
isolated etc.
3. Table 1a under Maintenance Activities for Station dc Supply (used only for UVLS or UFLS) states:
Verify proper voltage of the dc supply. Is this requirement applicable to the distribution substations
only?
4. Table 1a under Maintenance Activities for Station dc supply (battery is not used) - states Verify that
the dc supply can perform as designed when the ac power from the grid is not present. - Please
clarify this requirement.
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5. Table 1a for Associated communications systems - specify the group for the applicability of this
requirement. BPS,BES,UFLS etc.
6. Table 1a under Maintenance Activities for Associated communications systems states - Verify that
the performance of the channel meets performance criteria, such as via measurement of signal level,
reflected power, or data error rate. Why is this required? The requirement "Verify proper functioning
of communications equipment inputs and outputs that are essential to proper functioning of the
Protection System. Verify the signals to/from the associated protective relays seems sufficient to
ensure reliability.
7. Table 1a under Maintenance Activities for Relay sensing for Centralized UFLS OR UVLS systems
UVLS and UFLS relays that comprise a protection scheme distributed over the power system states:
Perform all of the Maintenance activities listed above as established for components of the UFLS or
UVLS systems at the intervals established for those individual components. The output action may
be breaker tripping, or other control action that must be verified, but may be verified in overlapping
segments. A grouped output control action need be verified only once within the specified time
interval, but all of the UFLS or UVLS components whose operation leads to that control action must
each be verified. Clarify what is meant by overlapping segments? What is the specified interval? Is
actual breaker tripping required?
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
4. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
6. Communications systems are subject to a variety of problems. The listed activities will detect many of these problems. The Tables
have been rearranged and considerably revised to improve clarity. Please see new Table 1-2.
7. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1. Please see Section 8 of
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the Supplementary Reference document regarding “overlapping segments.”
American Electric Power
1. The "Supplementary Reference" and the "Frequently-Asked Questions" document should be
combined into a single document. This document needs to be issued as a controlled NERC
approved document. AEP suggests that the document be appended to the standard so it is clear
that following directions provided by NERC via the document are acceptable, and to avoid an entity
being penalized during an audit if the auditor disagrees with the document’s contents.
2. NiCAD batteries should not be treated differently from Lead-Acid batteries. NiCAD battery condition
can be detected by trending cell voltage values. Ohmic testing will also trend battery conditions and
locate failed cells (although will usually lag behind cell voltages). A required load test is detrimental
to the NiCAD manufacturer's business, and will definitely hurt the NiCAD business for T&D
applications. Historically NiCADs may have been put into service because of greater reliability,
smaller space constraints, and wider temperature operation range.”Individual cell state of charge” is
a bad term because it implies specific gravity testing. Specific gravity cannot be measured
automatically (without voiding battery warranty or using an experimental system), and when it is
measured, it is unreliable due to stratification of the electrolyte and differing depths of electrolyte
taken for samples. “Battery state of charge” can be verified by measuring float current. Once the
charging cycle is over the battery current drops dramatically, and the battery is on float, signaling
that the battery has returned to full state of charge. This is an appropriate measure for Level 3
monitoring as float current monitoring is a commercially viable option and electrolyte level monitoring
is not.
3. In Table 2b, why is Ohmic testing required if the battery terminal resistance is monitored? Cell to cell
and battery terminal resistance should not be monitored because they will be taken in 18 month
intervals. This further supports the argument that the battery charger alarms would be sufficient for
level 2 monitoring, while keeping an 18 month requirement for Ohmic testing, electrolyte level
verification, and battery continuity (state of charge). Automatic monitoring of the float current should
be sufficient for level 3 monitoring as it gives state of charge of the string, and battery continuity
(detect open cells). Shorted cells will still be found during the Ohmic testing and a greater interval is
sufficient to locate these problems.
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Response: Thank you for your comments.
1. The SDT disagrees that the documents should be combined. The Supplementary Reference is a holistic presentation of rationale
and basis for the various elements of the Standard – discussing mostly the “what” behind the requirements. The FAQ, on the other
hand, presents responses to specific frequently-asked questions, and, as such, offers more-focused advice on specific subjects, and
is more of a how-to/example discussion. The FAQ is primarily a means of capturing some of the most prevalent comments offered
on the Standard by various entities, with the SDT’s response. The SDT believes that the format of the FAQ is a more effective
means of presenting the included information than it would be to include this information within the text of the Supplementary
Reference document. The Standards Committee has a formal process for determining whether to authorize posting a reference
document with an approved standard. That process is posted on the Standard Resources web page – here is a link to the procedure:
http://www.nerc.com/files/SC_Process_Approve_Supporting_References_Approved_10Mar08.pdf
2. The SDT believes that, since the IEEE Stationary Battery Committee has determined that VRLA batteries and Ni-Cad batteries are
different enough to require separate IEEE Standards (IEEE 1188 and IEEE 1106, respectively), these battery technologies are
different enough to be treated separately within PRC-005-2. The SDT has drawn upon these IEEE Standards, as well as other
sources (EPRI, etc) to develop the Requirements of PRC-005-2. The trending activity cited has not been shown to be effective for
Ni-Cad batteries (see FAQ II.5.G), and thus a performance tests must be performed; the performance test may take many forms.
The Tables have been rearranged and considerably revised to improve clarity, and all references to specific gravity have been
removed. Please see new Table 1-4. Determining the “state of charge” by monitoring the float voltage may be relevant to the
overall station battery, but does not provide an indication of the condition of individual cells as required within the new Table 1-4.
3. Battery terminal resistance shows the condition of the external connections, but reveals nothing regarding the internal condition of
the individual cells. Measuring the internal cell/unit resistance provides an opportunity to trend the cell condition over time by
verifying the electrical path through the electrolyte within the battery. The ohmic testing is not intended to look for open cells/units,
but instead at the ability of the individual cell/unit to perform properly. The new Table 1-4 clarifies that, if the electrolyte level is
monitored, the internal ohmic testing need only be performed every six years. Please see FAQ II.5.B, II.5,C, and II.5.D for a
discussion about continuity.
JEA
The current interpretation by the SDT of partially monitored is set at a higher bar than most utilities use
in their current designs today. We all wish to take advantage of the microprocessor relays and their
renowned and improved monitoring capability. If TC1 is monitored by primary relay A and TC2 is
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monitored by primary relay B, and these relays in turn monitor their DC supplies, the vast majority of the
system is monitored - (partially monitored), including all the control cable out to the remote breakers and
their trip coils. To add to this some additional contacts within the scheme, located very near the primary
relays, is extending the partially monitored bar to a higher level than most designs incorporate today. If
you know that 98% of the DC control system is monitored - isn't that partially monitored? Please
consider changes to the SDT's current view of a partially monitored protection systems.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity. Please see
new Tables 1-1 through 1-5.
Arizona Public Service
Company
1. The generator Facilities subsections 4.2.5.1 through 5 are too prescriptive and inconsistent with
sections 4.2.1 through 4. Recommend this section be limited to description of the function as in the
preceding sections.
2. Clarification is needed on how the “Note 1” in Table 1a, which appears to be used in to define a
calibration failure would be used in Time Based Maintenance. In PRC-005-2 Attachment A: Criteria
for a Performance-Based Protection System Maintenance Program, a calibration failure would be
considered an event to be used in determining the effectiveness of Performance Based
Maintenance. It is unclear in how it will be used in time based maintenance.
Response: Thank you for your comments.
1. The SDT believes that transmission lines, UFLS, UVLS, and SPS are clear without additional granularity, but that the additional
granularity regarding generation plants is necessary. This is illustrated by numerous questions regarding “what is included for
generation facilities?” relative to PRC-005-1.
2. The Tables have been rearranged and considerably revised to improve clarity. In addition, the Note was removed, and
Requirement 4 has been considerably revised.
Pacific Northwest Small
Public Power Utility
Comment Group
November 17, 2010
1. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are
to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1.
Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the
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18 month interval is missing.
2. IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not
maximums. An entity wishing to avoid non-compliance for an interval that might extend past three
calendar months due to storms and outages must set a target interval of two months thereby
increasing the number of inspections each year by half again. This is unnecessarily frequent. We
suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4
calendar months.
3. We are concerned over R1.1, where all components must be identified, without a definition for the
word component or the granularity specified. While the FAQ gives a definition, and allows for entity
latitude in determining the granularity, the FAQ is not part of the standard. We believe this will allow
REs to claim non-compliance for every three inch long terminal jumper wire not identified in a trip
circuit path. We suggest that the FAQ definitions be included within the standard.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4.
2. The SDT disagrees. The entity should schedule routine inspections to complete the specified activities within the specified 3-month
interval.
3. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
PNGC Power
The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to
be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1.
Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the 18
month interval is missing.
Response: Thank you for your comments. The Tables have been rearranged and considerably revised to improve clarity.
MRO’s NERC Standards
Review Subcommittee
November 17, 2010
1. The NSRS does not support the existing 2nd Draft of PRC-005-2 Standard because it is our opinion
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(NSRS)
Question 7 Comment
that:
o There is a high probability that system reliability will be reduced with this revised standard.
o The utility industry is in the business of keeping the lights on, but these requirements will force the
industry to take customers out of service in order to fulfill these requirements. A possible solution is
to increase the test intervals, set performance targets, test set on a basis of past performance, etc.
o The number of unplanned outages due to human error will increase considerably.
o The requirement of a complete functional trip test will reduce the level of reliability and all levels of
the BES to include distribution systems.
o Availability of the BES will be reduced due to an increased need to schedule planned outages for
test purposes (to avoid unplanned outages due to human error).
o To implement this standard, an entity will need to hire additional skilled resources that are not
readily available. (May require adjustments to the implementation timeline.)
o The cost of implementing the revised standard will approximately double our existing cost to
perform this work.
2. Requests that relevant reliability performance data (based on actual data and/or lessons learned
from past operating incidents, Criteria for Approving Reliability Standards per FERC Order 672) be
provided to justify the additional cost and reliability risks associated with functional testing.
3. Under a Performance-Based Program, what happens if the population of components drops below
60 (as all will eventually)? Is there an implementation period to default to TBM?
4. Please clarify In R1, the statement “or are designed to provide protection for the BES” re-opens the
argument about transformer protection or breaker failure protection for transformer high-side
breakers tripping BES breakers being included in the transmission protection systems.
5. Also, for Table 1b “Verify that each breaker trip coil, each auxiliary relay, and each lockout relay is
electrically operated within this time interval” should be changed from a 6 year interval to a 12 year
interval similar to the relay input and outputs. Experience has shown that these both have very
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similar reliability.
6. The standard as currently drafted raises concern as it relates to the identification of all Protection
System components, particularly those with associated communications equipment. In the case of
leased lines, a utility would be expected to maintain equipment they do not own. Recommend
revising the standard to consider maintenance activities on a communications channel basis in which
intermediate device functioning can be verified by sending a signal from one relay to another.
7. Clarification should be given as to the reason for stating control circuitry separately, such as in
“Control and trip circuits”. As currently stated, this implies that close circuit DC paths are now
subject to a protection system maintenance program when reclosing and closing of breakers have
never before been considered part of a Protection System.
8. Statements 3 (For microprocessor relays, check the relay inputs and outputs that are essential to
proper functioning of the Protection System. ) and 6 (Verify correct operation of output actions that
are used for tripping. in Table 1b for Protective Relays essentially address the same issue. Please
clarify if these are addressing the same issue or not. If the purpose is to describe the functionality of
the protection system, that should be covered under another section in the table, such as DC
circuitry.
9. How one identifies a voltage and current sensing input is not well defined. In most cases, this should
already be identified with the relay. Also, the scope of detail required is ambiguous. Would
individual cables, terminal blocks, etc. need to be identified as would be implied by “associated
circuitry”? Please clarify. The NSRS recommends that individual cables, terminal blocks, etc are not
included in this program.
10. Recommend removing “proper functioning of” from the maintenance activities for voltage and current
sensing inputs in Table 1b. A utility is not verifying the functionality of the signal(s), they are verifying
the signals themselves. Any functioning of the signals, which is related to ensuring proper relay
interpretation, would be covered under the protective relay section.
11. In general, has thought been put into the possibility of degrading reliability by implementing such a
rigorous maintenance program? To implement such a program, the number of scheduled outages
would greatly increase resulting in scheduling conflicts that will increase, as well as degrading
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system conditions by taking lines, transformers, etc. out of service. Because of past design
practices many of the requirements for maintenance will only be able to be performed by lifting wires
to isolated trip paths. Potential error is introduced anytime a wire is lifted, especially numerous
wires, by means of ensuring they are put back in the correct place. Redundancy is one thing that
has been implemented in great detail throughout the history of protection systems to ensure that
they work as intended. Diligent commissioning may need to be given its due credit.
Response: Thank you for your comments.
1. Thank you for your opinions.
2. The Standard does not preclude an entity from largely utilizing other methods of verification, although functional testing may be the
easiest to achieve.
3. The entity must revert to TBM if the population falls below 60. There is no implementation period; the SDT believes that the annual
PBM review will alert the entity that the population is nearing 60, and allow the entity to react to the diminishing component
population accordingly.
4. This comment relates to your regional BES definition, not the Standard.
5. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-5. The SDT believes that
mechanical solenoid-operated devices share performance attributes (and failure modes) with electromechanical relays and need to
be tested at similar intervals. Performance-based maintenance is an option to increase the intervals if the performance of these
devices supports those intervals.
6. The functional testing of the channel will verify that the communications system operates properly. If the communications system
does not perform properly, the applicable entity is responsible to assure that it is restored to service; the physical actions to do so
may have to be performed by other parties. Your suggested end-to-end test is one effective way of performing this maintenance;
however, this is only one of several ways of doing this.
7. This component of the definition is stated to apply as “associated with protective functions” and thus excludes close/reclosing
circuits. Please see FAQ II.1.A.
8. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-1.
9. This component of the Protection System definition is to generally include this functionality as a part of the Protection System. The
November 17, 2010
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Question 7 Comment
detailed applicability of this component within PRC-005-2 is addressed within the Standard. The “protective relay” only addresses
how the relay itself uses these signals, but does not address the concern regarding whether these signals are accurate. The Tables
have been rearranged and considerably revised to improve clarity. Please see new Table 1-3. Requirement R1, part 1.1, has been
revised to state, “Address all Protection System component types” to clarify that “individual cables, terminal blocks, etc.” need not
be discretely addressed. The definition has also been revised to remove “associated circuitry” from this portion. Please see FAQ
II.3.A.
10. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-3.
11. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.
Indiana Municipal Power
Agency
1. The proposed effective date working is confusing and maybe incorrect. It looks like the second part
of the paragraph refers to the additional maintenance and testing required by requirement 2 of the
current version of PRC-005-1. PRC-005-2 will be adding additional maintenance and testing. Since
the current wording is confusing, we are not sure when we have to ensure the new testing is done on
the protection equipment.
2. When it comes to battery maintenance, the battery cell to cell connection resistance has to be
verified. IMPA is not sure how the SDT wants this maintenance performed. Some battery banks are
made up of individual battery cases with two posts at each end that contain two to four individual
battery cells inside of each case. To actually tear down the individual cells in a case would be
extremely hard and maybe impossible on the sealed cases without destroying the cases. It would be
nice to describe how the SDT wants the connection resistance of battery cell to cell verified in the
FAQ guide.
3. In the same guide, the SDT might give insight on what is meant by verifying the state of charge of
the individual battery cell/units (table 1A). It seems like measuring the voltage level of the individual
battery would work for this verification, but additional information of what the SDT wants for this
verification would eliminate any doubt and help with being in compliant with this requirement.
Response: Thank you for your comments.
1. The SDT does not understand your concern. Perhaps you are referring to the Implementation Plan for the definition rather than the
Implementation Plan for the Standard. The second bullet in the introductory portion of the Implementation Plan for the Standard has
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Question 7 Comment
been modified to state, “ ... is being performed according to …” rather than “has been moved to” to be more concise.
2. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. The term “cell” has been
modified to “cell/unit” to address part of your concern. Please see FAQ II.5.L.
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Table 1-4. IEEE Standards 1188,
450, and 1106 provide “how-to” guidance specific to various battery technologies.
ReliabilityFirst Corp.
The SDT should be congratulated on its hard work in making substantial improvements to an existing
standard.
1. In revising the draft standard, the SDT should consider the difficulty an entity will have in providing
the evidence required to show compliance.
2. R1 unnecessarily limits PSMPs to “Protection Systems that use measurements of voltage, current,
frequency and or phase angle to determine anomalies.” However, if an entity applies devices that
protect equipment based on other non-electrical quantities or principles such as temperature or
changes in pressure, the entity is not required to maintain them. These types of devices have long
been considered by many organizations as important forms of protection and therefore in some
instances are connected to trip. There are also many organizations that consider these types of
devices too unreliable to use as protection and therefore only connect them for monitoring (and not
to trip). If protection based on non-electrical quantities is not properly maintained, it will Misoperate
and will negatively impact reliability. The standard cannot simply ignore a type of protection that can
ultimately affect the reliability of the BES.
Response: Thank you for your comments.
1. The SDT has considered this, and has provided examples in the Measures. Please see Section 15.7 of the Supplementary
Reference document and FAQ IV.1.B.
2. Requirement R1 does not preclude entities from maintaining such devices or including them in the PSMP.
Indeck Energy Services
November 17, 2010
The standard should include an assessment of, and criteria for, determining whether a Protective
System is important to reliability. It presently treats a fault current relay on a 345 kV or higher voltage
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Question 7 Comment
transformer the same as one on a small generator on the 115 kV system. The impact of failures on both
on a hot summer day like we've had recently in NY, would be very different. As discussed at the FERC
Technical Conference on Standards Development, the goal of the standards program is to avoid or
prevent cascading outages--specifically not loss of load. This seems to have been lost in the drafting
process. Much of the effort expended on complying with the existing PRC maintenance standards, as
well as that to be expended on PRC-005-2, has little to no significant in terms of improving reliability.
That effort could be better utilized if focused on activities that could significantly improve reliability. As
one of the Commissioners at the FERC Technical Conference on Standards Development characterized
the relationship between FERC and NERC as a wheel off the track. The whole standards program, and
especially PRC-005-2, is off the track.
Response: Thank you for your comments. Your comments seem to be related to NERC Standards Development in general, and to
BES definitions. The 2007-17 SDT is unable to address these concerns. The SDT is addressing its assignment from the approved
SAR, and believes that performing maintenance on Protection Systems will benefit the reliability of the BES.
US Bureau of Reclamation
1. The sub-requirements for R1, are not criteria, rather implementation requirements more suitable to
be included in R4. Examples of what the PSMP shall address which would be more consistent with
the language in R1 would be:
•
How are changes to the PSMP administered?
•
Who approves the determination of the use of time-based, condition based or performance
based maintenance.
•
Who reviews activities under the PSMP
2. References used within the standard are not consistent. In R1.2 Attachment as is referred to as
Attachment A. In R3 Attachment A is referred to as PRC-005 Attachment A. This implies a
difference. Under a voluntary world, we could draft criteria and procedures with these problems and
interpret them correctly. Today in the compliance world, the language must be precise and
unambiguous. The reference must be the same it means something different.
3. The requirement in R1, which is consistent with the purpose, does not support the applicability in
November 17, 2010
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Question 7 Comment
R4.2.5.4. Protection systems associated with stations service are not designed to provide protection
for the BES. In particular we have been told that intent was not to look at every device that tripped
the generator but devises that sensed problems on the BES and trip the generator. Hence we
include such things as frequency relays, Differential relays, zone relays, over current, and under
voltage relays. Even a loss of field looks at the system as included. Speed sensing devices were
explicitly excluded. As such, if the stations service transformer protection looks toward the BES (e.g.
differential relays and zone relays) they would be included. Over current would not as it would be on
the station side. If a Station Service transformer saw excess current, the system would in most
cases fail over to other side. If not, it would cause the generator to trip much like a generator thermal
device which is also excluded. Maintenance programs offer a unique problem to the FERC and
regulatory world. The knee jerk reaction is to define them. What happens if the solution is bad, who
will accept the consequences that narrow prescription was wrong and the interval caused a reliability
impact. It would no longer be the Entity. History is replete with examples of this type of micro
managing. Rather than fall into the same trap, and suffer the consequences of the unknown, allow
Entities to optimize their programs to ensure reliability of the BES and create a standard of
disallowed practices which have a demonstrated impact on reliability.
Response: Thank you for your comments.
1. Requirement R1 presents the requirements to establish a PSMP; Requirement R4 presents the implementation of the program.
The SDT believes that this arrangement is correct. The examples cited seem to be related more to the internal administration of the
PSMP within an entity, and not to the requirements.
2. The Standard has been modified to make these phrases consistent in consideration of your comment.
3. The SDT believes that the station service transformers may be essential to the operation of the generator (which is the BES
element), and thus that the protection of these needs to be addressed as part of PRC-005-2.
Bonneville Power
Administration
November 17, 2010
1. The term “maintenance correctable issue” used in Requirement 4 seems to be at odds with the
definition given for it. It seems that an issue that cannot be resolved by repair or calibration during
the maintenance activity would be a maintenance non-correctable issue. Also, in Requirement 4, the
term “identification of the resolution” is ambiguous. Suggested changes for Requirements 4 and 4.1
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Consideration of Comments on PSMTSDT — Project 2007-17
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Question 7 Comment
are:
a. R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement
its PSMP, and resolve any performance problems as follows:
b. 4.3 Ensure either that the components are within acceptable parameters at the conclusion of
the maintenance activities or initiate actions to replace the component or restore its
performance to within acceptable parameters.
Response: Thank you for your comments.
1. The definition of “maintenance correctable issue” is consistent with the way it is used within the Standard.
Santee Cooper
There is some discussion in the documents, such as the definition of component in the FrequentlyAsked Questions, about the idea that an entity has some latitude in determining the level of “protection
system component” that they use to identify protection systems in their program and documentation.
The example given is about DC control circuitry. There are requirements in this standard that are
specific to a component, such as R1.1 - Identify all protection system components. Historically, if your
maintenance and testing program is defined as (say, for relays) testing all the relays in a station at one
time, your program, test dates, etc. could be identified by the station. There needs to be some addition,
possibly to the Frequently asked questions, to explain what kind of documentation will be required with
this new standard. For example, if your program is to test all the relays at a station every 4 years, and all
the relays are tested at the same time, can your documentation of your schedule (the “date last tested”
and previous date) be listed by station (accepting that you should have the backup data to show the
testing was thorough) or must you be able to provide a list by each relay. Without some clarification, it
seems like this could get confusing at an audit with many of the requirements pertaining to “each
component.”
Response: Thank you for your comments. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System
component types.” The remaining issues within your comment are dependent on how your PSMP addresses them.
Northeast Power
November 17, 2010
1. UFLS systems by design can suffer random failures to trip. A requirement should exist that
stipulates to perform maintenance on the UFLS relay as their failure to operate may affect numerous
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Coordinating Council
Question 7 Comment
distribution level feeders. However maintenance on associated DC schemes connected to the
devices should only be done on the same frequency as maintenance on the relevant interrupting
devices. Consideration should be given to exempting schemes that have a maintenance program in
place on those distribution level devices from PRC-005 Standard-specified maintenance intervals.
Such Standard-specified intervals could apply to interrupting devices that have no maintenance
program in place.
2. This standard is overly prescriptive. Owners of protection system equipment establish maintenance
procedures and timelines based on manufacturers’ recommendations and experiences to ensure
reliability. Maintenance intervals change with improved practices and equipment designs, and
whenever that occurs PRC-005 will have to go through the revision process, which would be
frequent and unnecessary if the standard were more general.
Response: Thank you for your comments.
1. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-1 through 1-5.
2. FERC Order 693 and the approved SAR for this project directed the SDT to establish both maximum maintenance intervals and
minimum maintenance activities within the revised Standard.
Entergy Services
We support this project and believe it is a positive step towards BES reliability. However, we believe the
draft document needs additional work as per our comments. Also, as indicated by the amount of
industry input on the last version draft comments, we believe revisions are still needed to properly
address this technically complex standard.
If this standard is to deviate from the original project schedule and follow a fast track timeline for
approval, then we disagree with the 3 month implementation for Requirement 1 and ask for at least 12
months. The original schedule provided sufficient advance notice to work on an implementation plan
and it included the typical time required for NERC Board of Trustees and regulatory approvals. If the
project schedule and typical NERC Board of Trustees and regulatory approval times are to be
accelerated, the implementation plan should be extended.
Response: Thank you for your comments. The Implementation Plan for Requirement R1 has been revised from 3 months to 12
November 17, 2010
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months.
Utility Services
With regard to DPs who own transmission Protection Systems, the standard is still very unclear on when
a DP owns a transmission Protection System. Many DPs own equipment that is included within the
definition of a Protection System; however, ownership of such equipment does not necessarily translate
directly into a transmission Protection System under the compliance obligations of this standard. DPs
need to know if this standard applies to them and right now, there is no certain way of determining that
from within this language or previous versions of this standard. Additionally, the NPCC Regional
Standards Committee withdrew a SAR on this very subject as we informed the question would be
addressed in this proposal.
Response: Thank you for your comments. Your concern seems to be primarily related to the applicable regional BES definition.
Y-W Electric Association,
Inc.
1. Y-WEA concurs with Central Lincoln regarding the timing of required battery tests. The IEEE
standards referenced indicate target maintenance intervals. In order to remain reasonable, then, this
compliance standard needs to allow some buffer between a targeted maintenance and inspection
interval and a maximum enforceable maintenance and inspection interval. Central Lincoln’s
suggestion of a four-month maximum window is reasonable and should be incorporated into the
standard.
2. Y-WEA is also concerned with R1.1’s language indicating that all components must be identified with
no defined “floor” for the significance of a component to the Protection System. The SDT cannot
possibly expect that a parts list containing every terminal block, wire and jumper, screw, and lug is
going to be maintained with every single part having all the compliance data assigned to it, but
without clearly stating this, that is exactly the degree of record-keeping that some overzealous auditor
could attempt to hold the registered entity to. The FAQ is much clearer as to what is and is not a
component and should be considered for the standard.
3. Y-WEA also concurs with FMPA’s comments regarding the testing of batteries and DC control circuits
associated with UFLS relaying. Many UFLS relays are installed on distribution equipment.
Furthermore, many distribution equipment vendors are including UFLS functions in their distribution
equipment. For example, many recloser controls incorporate a UFLS function in them. These
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Question 7 Comment
controls and the reclosers they are attached to, however, are strictly distribution equipment. 16 USC
824o (a)(1) limits the definition of the Bulk-Power System to “not include facilities used in the local
distribution of electric energy.” A distribution recloser and its control clearly fall into this exclusion. 16
USC 824o (i)(1) prohibits the ERO from developing standards that cover more than the Bulk-Power
System. As such, the DC control circuitry and batteries associated with many UFLS relaying
installations are precluded from regulation under NERC’s reliability standards and may not be
included in this standard because they are distribution equipment and therefore not part of the BulkPower System. The proposed standard needs to be rewritten to allow for this exclusion and to allow
for the testing of only the UFLS function of any distribution class controls or relays.
Response: Thank you for your comments.
1. The SDT disagrees. You should complete the activities within the intervals specified.
2. Requirement R1, Part 1.1, has been revised to state, “Address all Protection System component types.”
3. The Tables have been rearranged and considerably revised to improve clarity. Please see new Tables 1-4 and 1-5.
November 17, 2010
193
The new proposed definition of Protection System reads as follows:
Protection System:
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply, and
• Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
Protection System Definition
Current Approved Definition:
Protective relays, associated communication systems, voltage and current sensing
devices, station batteries and DC control circuitry.
The drafting team initially proposed changes to the definition as shown below:
Protective relays, associated communication systems necessary for correct operation of
protective devices, voltage and current sensing inputs to protective relays devices,
station DC supply batteries, and DC control circuitry from the station DC supply through
the trip coil(s) of the circuit breakers or other interrupting devices.
Based on stakeholder comments, the drafting team made minor changes to the proposed
definition as shown below.
Protective relays, associated communication systems necessary for correct operation of
protective devicesfunctions, voltage and current sensing inputs to protective relays and
associated circuitry from the voltage and current sensing devices, station dc supply, and
DC control circuitry associated with protective functions from the station dc supply
through the trip coil(s) of the circuit breakers or other interrupting devices.
The proposed definition of Protection System reads as follows:
Protective relays which respond to electrical quantities, communication systems
necessary for correct operation of protective functions, voltage and current sensing
devices providing inputs to protective relays and associated circuitry from the voltage
and current sensing devices, station dc supply, and control circuitry associated with
protective functions from the station dc supply through the trip coil(s) of the circuit
breakers or other interrupting devices.
The new proposed definition of Protection System reads as follows:
Protection System:
•
Protective relays which respond to electrical quantities,
•
Communications systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply, and
•
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
Implementation Plan for the Revised Definition of Protection System
Prerequisite Approvals or Activities:
The implementation of the revised definition is not dependent upon any other activity.
Recommended Modifications to Already Approved Standards
The non-capitalized version of the term, “protection system” is used in the following approved
standards:
•
•
•
NUC-001-2 Nuclear Plant Interface Coordination
PER-005-1 System Personnel Training
PRC-001-1 System Protection Coordination
The term, “protection system” shall be capitalized where used in these standards when the
definition of “Protection System” is approved by applicable regulatory authorities.
Proposed Effective Date:
Each responsible entity (Distribution Provider that owns a transmission Protection System,
Transmission Owner, and Generator Owner) shall modify its protection system maintenance and
testing program description and basis document(s) (required in Requirement R1 of PRC-005-1 –
Transmission and Generation Protection System Maintenance and Testing) as necessary to
reflect the modified definition of ‘Protection System’ by the first day of the first calendar quarter
twelve months following regulatory approvals and implement any additional maintenance and
testing (required in Requirement R2 of PRC-005-1 – Transmission and Generation Protection
System Maintenance and Testing) by the end of the first complete maintenance and testing cycle
described in the entity’s program description and basis document(s) following establishment of
the program changes resulting from the revised definition.
The original definition of “Protection System” shall be retired at the same time the revised
definition becomes effective.
Implementation Plan for the Revised Definition of Protection System
Prerequisite Approvals or Activities:
The implementation of the revised definition is not dependent upon any other activity.
Recommended Modifications to Already Approved Standards
The non-capitalized version of the term, “protection system” is used in the following approved
standards:
•
NUC-001-2 – Nuclear Plant Interface Coordination
•
PER-005-1 – System Personnel Training
•
PRC-001-1 – System Protection Coordination
The term, “protection system” shall be capitalized where used in these standards when the
definition of “Protection System” is approved by applicable regulatory authorities.
Proposed Effective Date:
Each responsible entity (Distribution Provider that owns a transmission Protection System,
Transmission Owner, and Generator Owner) shall modify its protection system maintenance and
testing program description and basis document(s) (required in Requirement R1 of PRC-005-1 –
Transmission and Generation Protection System Maintenance and Testing) as necessary to
reflect the modified definition of ‘Protection System’ by the end first day of the first calendar
quarter six twelve months following regulatory approvals and implement any additional
maintenance and testing (required in Requirement R2 of PRC-005-1 – Transmission and
Generation Protection System Maintenance and Testing) by the end of the first complete
maintenance and testing cycle described in the entity’s program description and basis
document(s) following establishment of the program changes resulting from the revised
definition.
The original definition of “Protection System” shall be retired at the same time the revised
definition becomes effective.
July 22, 2010
Standards Announcement
Second Ballot Window Open
July 23–August 2, 2010
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-17: Protection System Maintenance and Testing
A second ballot window for the definition of “Protection System” is now open until 8 p.m.
Eastern on August 2, 2010.
Instructions
Members of the ballot pool associated with this project may log in and submit their votes from
the following page: https://standards.nerc.net/CurrentBallots.aspx
Recirculation Ballot Process
The Standards Committee encourages all members of the ballot pool to review the consideration
of comments submitted with the initial ballots and those submitted through the formal comment
period. In this second ballot, votes are counted by exception only — if a ballot pool member
does not submit a revision to that member’s original vote, the vote remains the same as in the
first ballot. Members of the ballot pool may:
-
Reconsider and change their vote from the first ballot.
- Vote in the second ballot even if they did not vote on the first ballot.
- Take no action if they do not want to change their original vote.
Next Steps
Voting results will be posted and announced after the ballot window closes.
Project Background
When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was
written by the Protection System and Maintenance Standard Drafting Team, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of
"protection system" and directed that work to close this reliability gap should be given
“priority.” The Standards Committee directed the team to advance the definition of Protection
System in parallel with the development of PRC-005-2.
Project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Special Notes:
On March 18, 2010, FERC issued several orders and notices of proposed rulemakings pertaining
to standards development activities and processes, suggesting a lack of progress in responding to
directives from Order 693 as well in the timeliness of standards development in general. At the
May 2010 NERC Board meeting, Gerry Cauley, NERC’s President, also expressed these
concerns, indicating that the resolution to these concerns is one of NERC’s top priorities in the
near term. As a result, the Standards Committee has authorized deviations from the normal
standards development process for the Protection System Maintenance and Testing project, as
well as other projects, to demonstrate that the NERC enterprise is responsive to FERC directives,
and is making progress in developing standards.
The Standards Committee approved the following deviations from the standards development
process for the definition of Protection System:
•
The proposed changes to the definition will be posted for a 35-day comment period
(rather than 45-day comment period). The ballot pool will be formed during the first 21
days of the 35-day comment period;
•
The initial ballot will be conducted during the last 10 days of the 35-day comment
period; and
•
The drafting team may make modifications between the initial and successive ballots
based on stakeholder comments to improve the overall quality of the standard and
definition.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Lauren Koller at [email protected]
-2-
Standards Announcement
Final Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
Project 2007-17: Protection System Maintenance and Testing
The second ballot for the definition of “Protection System” ended on August 2, 2010.
Ballot Results
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum: 94.70%
Approval: 58.61%
Next Steps
The drafting team will review and respond to the comments received, and will determine whether to make
additional changes to the definition or its implementation plan, based on those comments. Should the team decide
to make revisions the revised item(s) will be posted for a 30-day comment period with another ballot conducted
during the last ten days of that comment period.
Project Background
When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the
Protection System and Maintenance Standard Drafting Team, the board acknowledged the reliability gap
identified by the drafting team caused by the definition of "protection system" and directed that work to close this
reliability gap should be given “priority.” The Standards Committee directed the team to advance the definition of
Protection System in parallel with the development of PRC-005-2.
More information is available on the project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.htmlb
Standards Development Process
For this project, the Standards Committee authorized using the standard development process in the Standard
Processes Manual. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
Ballot Criteria (from Standard Processes Manual)
Approval requires both a (1) quorum, which is established by at least 75% of the members of the ballot pool for
submitting either an affirmative vote, a negative vote, or an abstention, and (2) A two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and negative
votes, excluding abstentions and nonresponses. If there are no negative votes with reasons from the first ballot, the
results of the first ballot shall stand. If, however, one or more members submit negative votes with reasons, at least
one more ballot must be conducted. If the drafting team makes no substantive changes following the initial ballot,
then a “recirculation” ballot is conducted – however if the drafting team makes substantive changes, the revised
standard (or definition) must be posted for a 30-day comment period, with a successive ballot conducted during the
last 10 days of that comment period. If the drafting team does not make substantive changes following the
successive ballot, then the standard moves forward to a recirculation ballot.
For more information or assistance, please contact Courtney Camburn at [email protected]
NERC Standards
Newsroom • Site Map • Contact NERC
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User Name
Ballot Results
Project 2007-17 Protection System Maintenance (Protection System
Ballot Name:
definition)_rc
Password
Ballot Period: 7/23/2010 - 8/2/2010
Log in
Ballot Type: recirculation
Register
Total # Votes: 304
Total Ballot Pool: 321
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Quorum: 94.70 % The Quorum has been reached
Weighted Segment
58.61 %
Vote:
Ballot Results: The Standard has NOT Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
89
9
71
24
67
37
0
11
6
7
321
#
Votes
1
0.4
1
1
1
1
0
0.8
0.5
0.5
7.2
#
Votes
Fraction
50
3
43
11
31
21
0
4
4
2
169
Negative
Fraction
0.617
0.3
0.662
0.524
0.517
0.6
0
0.4
0.4
0.2
4.22
Abstain
No
# Votes Vote
31
1
22
10
29
14
0
4
1
3
115
0.383
0.1
0.338
0.476
0.483
0.4
0
0.4
0.1
0.3
2.98
3
4
4
0
3
1
0
2
1
2
20
5
1
2
3
4
1
0
1
0
0
17
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Robert D Smith
John Bussman
Scott Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b3970df5-938b-4159-be22-804441ebd7d8[8/4/2010 11:25:57 AM]
Ballot
Comments
Affirmative
Negative
Negative
Affirmative
Negative
View
View
Negative
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnesota Power, Inc.
National Grid
Nebraska Public Power District
New York Power Authority
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
John J. Moraski
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Ronald D. Schellberg
Michael Moltane
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
Doug Bantam
Robert Ganley
Martyn Turner
Michelle Rheault
Ernest Hahn
Terry Harbour
Randi Woodward
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
Richard J Kafka
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Chad Bowman
Catherine Koch
Tim Kelley
Robert Kondziolka
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b3970df5-938b-4159-be22-804441ebd7d8[8/4/2010 11:25:57 AM]
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
View
View
View
View
View
Negative
View
Negative
Negative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
View
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Santee Cooper
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Arizona Public Service Co.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Leesburg
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V. Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Jason L. Murray
Faramarz Amjadi
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Thomas R. Glock
James V. Petrella
Pat G. Harrington
Rebecca Berdahl
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C Parent
Steven Grego
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b3970df5-938b-4159-be22-804441ebd7d8[8/4/2010 11:25:57 AM]
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
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View
View
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View
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View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salem Electric
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Tri-State G & T Association Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
Y-W Electric Association, Inc.
AEP Service Corp.
Amerenue
APS
Avista Corp.
Black Hills Corp
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David T. Anderson
Ballard Keith Mutters
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Anthony Schacher
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
David Schiada
Jeff Nelson
Ronald L Donahey
Janelle Marriott
James R. Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Timothy Beyrle
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Christopher Plante
Joseph G. DePoorter
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
View
View
View
View
View
View
View
View
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
John D. Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
James A Ziebarth
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
George Tatar
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b3970df5-938b-4159-be22-804441ebd7d8[8/4/2010 11:25:57 AM]
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
View
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View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Entergy Corporation
FirstEnergy Solutions
Florida Municipal Power Agency
Green Country Energy
Horizon Wind Energy
Indeck Energy Services, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
New Harquahala Generating Co. LLC
New York Power Authority
Northern Indiana Public Service Co.
Otter Tail Power Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Public Utility District No. 1 of Lewis County
Reedy Creek Energy Services
RRI Energy
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Centralia Generation, LLC
Tri-State G & T Association Inc.
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Amir Y Hammad
James B Lewis
Bob Essex
Mike Garton
Robert Smith
Dan Roethemeyer
Stephen Ricker
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Doug Ramey
Affirmative
Kenneth Parker
Stanley M Jaskot
Kenneth Dresner
David Schumann
Greg Froehling
Brent Hebert
Rex A Roehl
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Daniel Duff
Dennis Florom
Charlie Martin
Mike Laney
Mark Aikens
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
David Gordon
Affirmative
Nicholas Q Hayes
Gerald Mannarino
Michael K Wilkerson
Stacie Hebert
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A Heimbach
Wayne Lewis
David Murray
Steven Grega
Bernie Budnik
Thomas J. Bradish
Bethany Wright
Glen Reeves
Daniel Baerman
Michael J. Haynes
Brenda K. Atkins
Richard Jones
Jerry W Johnson
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Joanna Luong-Tran
Barry Ingold
Affirmative
Negative
Negative
Affirmative
Negative
Karl Bryan
Affirmative
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
Terri F Benoit
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b3970df5-938b-4159-be22-804441ebd7d8[8/4/2010 11:25:57 AM]
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
View
View
View
View
View
View
View
View
View
View
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View
Affirmative
Affirmative
Abstain
Affirmative
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NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Energy
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
OTP Wholesale Marketing
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Ascendant Energy Services, LLC
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
SPS Consulting Group Inc.
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P Mitchell
Donna Stephenson
Thomas Saitta
Paul Shipps
Eric Ruskamp
Daryn Barker
Brad Jones
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
David Ried
Bruce Glorvigen
James Eckelkamp
James D. Hebson
Hugh A. Owen
Trent Carlson
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
View
View
View
View
View
View
Abstain
Affirmative
John Stonebarger
Affirmative
David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Kristina M. Loudermilk
Merle Ashton
Raymond Tran
Jim D. Cyrulewski
Margaret Ryan
Peggy Abbadini
Jim R Stanton
Brian Evans-Mongeon
Terry Volkmann
William Mitchell Chamberlain
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
View
View
Negative
Negative
Affirmative
Negative
View
View
Donald E. Nelson
Affirmative
Diane J. Barney
Affirmative
Jerome Murray
Philip Riley
Ric Campbell
Linda Campbell
Dan R. Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B Edge
Louise McCarren
Abstain
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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NERC Standards
Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
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Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Date of Second Ballot: 07/23/10 - 08/02/10
Summary Consideration: There were numerous comments opposing balloting the definition separately from the definition; the NERC BOT has
directed that a revised definition be approved as quickly as possible to close a reliability gap. Many other comments were offered relative to the
standard, not the definition, and the SDT noted this in its responses.
Some commenters suggested the “station dc supply” portion of the definition be modified to specifically address battery chargers; the SDT
modified the definition as suggested. The revised definition is shown below:
Protection System –
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply associated with protective functions (including station batteries, battery chargers, and non-battery-based dc supply), and
• Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting devices.
The SDT did not make any other modifications to the definition and did not make any modifications to the implementation plan based on
stakeholder comments submitted with ballots.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb
1
Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
1
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Kirit S. Shah
Entity
Ameren Services
Segment
1
Vote
Negative
Comment
1. Remove “devices providing” yielding ‘voltage and current
sensing inputs to protective relays’. This will match the SDT intent
with which we concur. "The definition has been changed for
clarity; the SDT intends that the output of these devices,
measured at the relay should properly represent the primary
quantities."
2. The 12 month implementation plan is an improvement, but will
result in multiple maintenance plan changes within a short time.
We believe that the implementation of the revised definition and
PRC-005-2 PSMP must align on the same date.
Response: Thank you for your comments.
1. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed applicability of this element of the definition
relative to maintenance within PRC-005-2 is addressed within the standard by specifying, “Verify that acceptable measurements of the current and voltage
signals are received by the protective relays”.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the
reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be
given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply
the new definition to PRC-005-1.
Terri F Benoit
Entergy Services, Inc.
6
Negative
2007-17 the definition - Negative with Comments: The following
are the reasons associated with our Negative Ballot.
1. We agree with the definition, however we do not agree with the
implementation plan. We believe implementation of the definition
needs to coincide with the implementation of Standard PRC-005-2.
To do otherwise, will cause entities to address equipment,
documentation, work management process, and employee training
changes needed for compliance twice within an unreasonably
short timeframe.
2. A 12 month minimum timeframe is need to implement this
definition
Response: Thank you for your comments.
September 10, 2010
2
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
1. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the reliability
gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply the
new definition to PRC-005-1.
2. The SDT modified the implementation plan to provide a 12-month implementation period with the previous posting.
Brenda L Truhe
PPL Electric Utilities Corp.
1
Affirmative
Although PPL EU previously voted against this definition, due to
the change in language, we now support this definition.
Although the applicable relays to which protective relays are
outlined in the NERC PRC-005-2 Protection system Maintenance
Draft Supplementary Reference dated May 27, 2010, they are not
defined in the NERC Glossary of terms. Until it is clearly defined
which relays are included inconsistencies will exists from region to
region in their audit approaches and which relays they will be
looking at. Also, there is still debate why the protective relays
would extend to mechanical devices such as the lock-out relay and
tripping for trip-free relays. In our system configuration we risk
reliability to customer load by testing the lock-out relays which we
feel out weights the benefit of testing devices that we see little to
no evidence of failure in.
Response: Thank you for your comments.
John C. Collins
Platte River Power
Authority
1
Negative
Terry L Baker
Platte River Power
Authority
3
Negative
Response: Thank you for your comments. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed
applicability of the definition relative to maintenance within PRC-005-2 is addressed within the standard. Your comments appear to be on the draft standard
PRC-005-2, rather than on the definition. Failure of a lock-out relay or tripping relay can keep a circuit (or multiple circuits) from clearing a fault. Routine
testing of these devices could find problems before the system needs them to clear a fault.
Mel Jensen
APS
5
Negative
Robert D Smith
Arizona Public Service
Co.
1
Negative
September 10, 2010
Although the SDT has made changes in trying to define the
Protection System the definition remains too prescriptive. In
particular, the devices providing current and voltage inputs as well
as the dc supply. These items are also used for other functions not
related to the reliability of the BES. They are critical to business
and operation of the generating systems and not solely dedicated
to protective relaying. Including them in the definition obligates
the utility to methods where there should be some discretion.
3
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments. The SDT is aware that many devices have multiple functions within the business of supplying power to loads.
Regardless of these other functions, if a device is a part of a Protection System then it must be maintained in accordance withPRC-005. The definition of
Protection System is for all applications of this term throughout NERC Standards. The detailed applicability of the definition relative to maintenance within PRC005-2 is addressed within the standard.
Stan T. Rzad
Keys Energy Services
1
Negative
As written, is opens up the PRC-005 standard to Technical
Feasibility Exceptions because some batteries are not able to
accommodate all of the tests proscribed in the draft standard. The
draft standard would cause NERC to regulate through the
standards battery testing, DC circuit testing, etc. on distribution
elements with no significant improvement to BES reliability, which
is beyond the statutary scope of the standards The standard
unreasonably retains the "100% compliance" paradigm for
thousands, if not millions of protection system components.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Joseph S.
Stonecipher
Beaches Energy Services
1
Negative
Thomas W. Richards
Fort Pierce Utilities
Authority
4
Negative
Because the definition changes the scope of what PRC-005 covers,
the definition should not be balloted separately from PRC-005 so
that the industry knows what is being committed to. What
happens if the standard is voted down but the definition change is
passed? For instance, the circuitry connecting the voltage and
current sensing devices to the relays is a scope expansion. Station
DC supply increases the scope to include the charger, etc. This
scope increase needs to have an appropriate implementation
period.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Paul Rocha
CenterPoint Energy
1
Negative
CenterPoint Energy does not support any Protection System
definition that includes the trip coils of the interrupting devices.
Response: Thank you for your comments. The current definition includes “DC Control Circuitry”; the SDT attempted to clarify the definition by stating which
September 10, 2010
4
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
of the many control circuits are included. Because the current definition is vague, it can certainly include the trip coils, close coils, and alarm circuits of the
interrupting device. The SDT believes that the electrically-operated trip coils are an important part of the control circuitry.
Christopher L de
Graffenried
Consolidated Edison Co.
of New York
1
Negative
Nickesha P Carrol
Consolidated Edison Co.
of New York
6
Negative
Comment: There is not enough clarity on whether a Distribution
Provider (DP) will be able to clearly identify which protection
system components it does own and needs to maintain. Many DPs
own and/or operate equipment identified in the existing or
proposed definition. However, not all such equipment translates
into a transmission Protection System. The definition needs
clarification on when such equipment is a part of the transmission
protection system. Also, the time provided for the first phase "at
least six months" is too open ended and does not provide entities
with a clear timeline. It is suggested that one year is appropriate
for the first phase phasing out the second year in stages.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to
ballot comments and the consideration of comments on the standard itself.
Regarding the comment that the definition needs to identify when equipment is part of the transmission system, this is properly an issue to address in the
various standards that use this definition.
Hugh A. Owen
Public Utility District No.
1 of Chelan County
6
Negative
Comments have convinced me that ambiguities in the
requirements will make compliance/enforcement difficult and the
testing procedures may not lead to greater reliability.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had
not completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Charles A. Freibert
Louisville Gas and
Electric Co.
3
Affirmative
Comments will be submitte4d under the comment form
Response: Thank you for your comments. There was no formal comment period with the second ballot of the proposed definition.
September 10, 2010
5
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Ralph Frederick
Meyer
Entity
Empire District Electric
Co.
Segment
1
Vote
Negative
Comment
Comments: It is still unclear whether relays that respond to
mechanical inputs, such as sudden pressure relays, are included in
the proposed definition as protective relays. While PRC-005-2 R1
limits the scope of that particular standard to protection systems
that sense electrical quantities, it is remains unclear in other
standards that use the defined term whether mechanical input
protections are included. We suggest that “Protective Relay” also
be defined, and that the definition clearly exclude devices that
respond to mechanical inputs in line with the NERC interpretation
of PRC-005-1 in response to the CMPWG request.
Response: Thank you for your comments. The definition has been modified to include only protective relays that respond to electrical quantities. The SDT
sees no need to either repeat or modify the IEEE definition of protective relays.
Michael J. Haynes
Seattle City Light
5
Negative
Control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices. - In
order to comply with this statement utilities would need to conduct
functional tests of their relay system. This type of test is
problematic. A better definition would be to test the output of the
relay.
Response: Thank you for your comments. This component of the Protection System definition is to generally include this functionality as a part of the
Protection System for all applications of the definition throughout NERC Standards. The detailed applicability of this component relative to maintenance within
PRC-005-2 is addressed within the standard, which defines the maintenance required relative to control circuits. The SDT agrees that testing will be required in
the standard itself.
Jim D. Cyrulewski
JDRJC Associates
8
Negative
1. Definition needs to be more specific. Case in point if the
drafting team wants to include battery chargers should
state so.
2. Also implementation plan does not appear to be in synch
with proposed changes.
Response: Thank you for your comments.
1. The current definition uses the term batteries in place of dc supply. The use of the term batteries was quite specific and as such excluded battery chargers.
The definition has been modified to specifically include battery chargers. Battery chargers are now expected to be covered within the proposed definition
and the term dc supply, so too are systems that do not use batteries and/or battery chargers.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the reliability
gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
September 10, 2010
6
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply the
new definition to PRC-005-1.
Daniel Brotzman
Commonwealth Edison
Co.
1
Affirmative
Exelon suggests that the definition further clarify protective relays
that are in scope by adding the following to the frequently asked
questions: 1. “devices providing inputs to protective relays” - this
is to clarify that testing for CTs and PTs will only ensure proper
voltage and current into the relay - therefore not requiring CT and
PT testing. 2. Elimination of “from the station dc supply” - the
intent here is that the DC is testing only the trip functionality to
ensure that certain relays actuate (e.g., 86 and 94 devices) and to
ensure that breaker trip coils are exercised on a 6 year periodicity.
Therefore, the ancillary wiring part of the controls will be on a
longer periodicity (e.g., 12 years)
Response: Thank you for your comments. Your comments appear to be relative to the FAQs for PRC-005-2, rather than the definition. The SDT will
consider these comments when it updates the FAQs.
Robert Martinko
FirstEnergy Energy
Delivery
1
Affirmative
Kevin Querry
FirstEnergy Solutions
3
Affirmative
Kenneth Dresner
FirstEnergy Solutions
5
Affirmative
Mark S Travaglianti
FirstEnergy Solutions
6
Affirmative
Douglas Hohlbaugh
Ohio Edison Company
4
Affirmative
September 10, 2010
FirstEnergy appreciates the hard work of the drafting team, but
ask that the team consider the following suggestions: It is our
understanding that the phrase "Station DC supply" in the definition
is intended to cover the Battery, Battery Charger, and other DC
supplies sources such as flywheels, fuel cells, and motor-generator
sets. However, since the current Protection System Maintenance
and Testing standard PRC-005-1 does not specify maintenance
activities, as does the proposed Version 2 of PRC-005, it therefore
does not provide compliance certainty related to mandatory
expectations. This is because the current standard only requires
that an entity develop a maintenance program and follows their
program. Therefore, it is not clear from the definition that Battery
Chargers must be included in the maintenance program developed
per PRC-005-1. As we stated in our Initial Ballot comments, the
phrase "Station DC supply" should be clarified. In response to our
Initial Ballot comments the SDT stated "Clarifications such as this
properly belong in supplementary materials. This is described in
the FAQ posted in June 2010 (FAQ II.5.A)". We do not agree that
supplementary materials should be relied upon to determine
7
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
"what" is required and should only give you guidance on "how" to
comply. The "what" should be described in the standard
requirements and definitions.
Response: Thank you for your comments. It is the intent of the SDT that battery chargers and other devices that supply power to Protection System devices be
included within the definition. As such, those devices have been included within the minimum maintenance activities of PRC-005-2. However, in the interim
before PRC-005-2 is accepted, under the present PRC-005-1 an entity must have a maintenance program that includes the devices within the definition. PRC005-1 does not prescribe the maintenance, only that the PSMP must include maintenance for the device. The definition has been modified to specifically include
battery chargers.
Pawel Krupa
Seattle City Light
1
Negative
Dana Wheelock
Seattle City Light
3
Negative
Hao Li
Seattle City Light
4
Negative
Functional testing is impractical.
Response: Thank you for your comments. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed
applicability of this element relative to maintenance within PRC-005-2 is addressed within the standard, which defines the maintenance required relative to
control circuits. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not completed the
consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to ballot
comments and the consideration of comments on the standard itself. The SDT agrees that testing will be required in the standard itself.
Dennis Sismaet
Seattle City Light
6
Negative
Functional testing is impractical. Control circuitry associated with
protective functions through the trip coil(s) of the circuit breakers
or other interrupting devices. - " In order to comply with this
statement utilities would need to functional test their relay system.
A better definition would be to test the output of the relay"
Response: Thank you for your comments. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed
applicability of this element relative to maintenance within PRC-005-2 is addressed within the standard, which defines the maintenance required relative to
control circuits. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not completed the consideration
of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to ballot comments and the
consideration of comments on the standard itself. The SDT agrees that testing will be required in the standard itself.
Mark Ringhausen
Old Dominion Electric
Coop.
September 10, 2010
4
Affirmative
I am voting Yes on the ballot, but I do have a small issue with the
wording of 'station DC supply'. In some of our UFLS locations, we
are not in a substation, but out on the feeder circuit and utilizing
the DC supply on the feeder recloser. I think my reading of this
definition would apply to this recloser DC supply as well as the
8
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
Station DC Supply.
Response: Thank you for your comments. Your concern is appreciated. A review of the standard itself shows that the dc supply maintenance activities are
minimal related to UFLS.
Jeff Mead
City of Grand Island
5
Negative
I echo MRO NSRS comments.
Response: Thank you for your comments. The station dc supply element has been modified essentially as you suggest. As to your suggestion regarding
inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
John Yale
Chelan County Public
Utility District #1
5
Negative
If the new definition is: The new proposed definition of Protection
System reads as follows: Protection System:
o Protective relays which respond to electrical quantities,
o Communications systems necessary for correct operation of
protective functions,
o Voltage and current sensing devices providing inputs to
protective relays,
o Station dc supply, and
o Control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices.
In this list format, it appears it is the entire station dc supply not
just that portion and circuitry associated with the protective
circuits. This is an unreasonable burden as many parts of the
station dc supply are used for non-protective functions.
Response: Thank you for your comments. The SDT has modified the definition in consideration of your comments. That bullet now reads: station dc supply
associated with protective functions (including station batteries, battery chargers, and non-battery-based dc supply)
Joseph O'Brien
Northern Indiana Public
Service Co.
6
Negative
1. It is still not clear whether battery chargers fall under this
definition.
2.
The implementation plan should be coordinated with the new
PRC-005-2, not -1.
3. It's not clear if a breaker trip has to be actuated to
test/maintain the control circuitry through the trip coils.
September 10, 2010
9
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments.
1. The definition has been modified to specifically include battery chargers.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged the reliability
gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical - not years from now. The
implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give entities time to apply the
new definition to PRC-005-1.
3. The draft standard PRC-005-2 includes the minimum maintenance activities. Until PRC-005-2 is approved, you need to define the activities and provide a
basis for those activities in accordance with PRC-005-1.
Thomas E Washburn
Florida Municipal Power
Pool
6
Negative
It is still unclear whether relays that respond to mechanical inputs,
such as sudden pressure relays, are included in the proposed
definition as protective relays. While PRC-005-2 R1 limits the
scope of that particular standard to protection systems that sense
electrical quantities, it is remains unclear in other standards that
use the defined term whether mechanical input protections are
included. We suggest that “Protective Relay” also be defined, and
that the definition clearly exclude devices that respond to
mechanical inputs in line with the NERC interpretation of PRC-0051 in response to the CMPWG request
Response: Thank you for your comments. The definition has been modified to include only protective relays that respond to electrical quantities. The SDT sees
no need to either repeat or modify the IEEE definition of protective relays.
Frank Gaffney
Florida Municipal Power
Agency
4
Affirmative
David Schumann
Florida Municipal Power
Agency
5
Affirmative
Richard L.
Montgomery
Florida Municipal Power
Agency
6
Affirmative
Bob C. Thomas
Illinois Municipal Electric
Agency
4
Affirmative
September 10, 2010
It is unclear in the Implementation Plan if the expectation is to
complete the first maintenance and testing cycle, or whether the
entities need to be auditably compliant within the one year
implementation plan, e.g., prove that they have performed
maintenance and testing within the interval defined in the
maintenance and testing program of R1, which essentially could
mean two maintenances and tests of the same component during
the first year for the components identified in the expansion of
scope of the definition of Protection System (e.g., battery
charger). We encourage the SDT to make this crystal clear, i.e.,, is
only the first maintenance and test needed as long as the end of
the maintenance and testing interval identified in the maintenance
10
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
and testing program of R1 has not been reached yet, or are two
maintenance and tests needed to be auditably compliant?
Response: Thank you for your comments. The SDT observes that the implementation plan for the definition requires that the entity implement the revised
program. The implementation plan also requires completion of maintenance within one full cycle of the revised program.
Martin Bauer P.E.
U.S. Bureau of
Reclamation
5
Negative
1. It is unfortunate that the definition did not retain
consistency in the terms. As an example, the definition
indicates it includes protective relays and communication
systems for the correct operation of protective functions.
It would have been better to use the term relays instead
of the term functions.
2. Now it is unclear what the communication systems are for,
since a different term was used rather than protective
relays. Since it is not clear what the communications have
to do with protective relays, as it may also include those
that do not just respond to electrical quantities, the
definition cannot be used to support the standard.
3. The change to insert the term "devices providing” when
referring to voltage and current sensing unfortunately
eliminates the circuitry form the voltage and current
sensing devices to the relays. This was caused by inserting
the word “devices”. I do not believe it was the SDT intent,
however, we are in a literal word world. Since we are
primarily focused on the performance of the device as a
function of the burden on the device, I cannot vote in
favor. My company believes the circuit from the PT and CT
must be a part of the Protection System and is arguably of
greater concern. Consider that if a PT or CT fails partially
or completely it will be known immediately. Maintenance
practices will rarely help that predict failure. On the other
hand, the circuitry from the voltage and current sensing
devices can have a problem that will affect relay
performance through instrument transformer error and in
most cases is only found through testing. Had you
changed “devices” to “circuits” I would agree with
providing the first issue addressed as well. The term
September 10, 2010
11
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
“circuits” could have included both (devices and circuits),
but as I explained, the latter is more important, more
variable, and has been attributed to many protection
system failures.
Response: Thank you for your comments.
1. “Protective relays which respond to electrical quantities” is a description intended to clarify which relays are excluded (those not responding to electrical
quantities are excluded). However a different descriptor was aimed at communications devices; after all there are many communication circuits employed
that are not used for protective functions (voice, alarm data, revenue data, etc.).
2. The term “communications systems necessary for correct operation of protective functions” was chosen to include all methods of conveying tripping,
permissive and blocking signals that are used now or may be used in the future. The SDT saw no need to include language that might result in the inclusion
of voice equipment.
3. The change to insert the term “devices providing” was to improve clarity while also excluding voltage and current measuring devices that provide data
exclusively to metering equipment as opposed to Protection Systems. The SDT agrees with the commenter that an appropriate maintenance activity is to
ensure that the measured voltage and current values correctly make it to the relays. The maintenance activity is a part of the standard. The absence of this
activity from the definition is not intended to lead one to believe that the activity is not important.
John J. Moraski
Baltimore Gas & Electric
Company
September 10, 2010
1
Negative
It seems not to be the intention of the SDT to require testing of
CT’s and PT’s beyond verifying that they that are delivering
acceptable signals to relays. Table 1 a of the standard includes: Voltage & Current Sensing Devices / 12 Calendar Years / Verify
proper functioning of the current and voltage circuit inputs from
the voltage and current sensing devices to the protective relays.
The FAQ’s are even clearer and say:
*********************************** 3. Voltage and Current
Sensing Device Inputs to Protective Relays A. What is meant by
“...verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays ...” Do we
need to perform ratio, polarity and saturation tests every few
12
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Amir Y Hammad
Entity
Constellation Power
Source Generation, Inc.
Segment
5
Vote
Negative
Comment
years? No. You must prove that the protective relay is receiving
the expected values from the voltage and current sensing devices
(typically voltage and current transformers). This can be as
difficult as is proposed by the question (with additional testing on
the cabling and substation wiring to ensure that the values arrive
at the relays); or simplicity can be achieved by other verification
methods. Some examples follow: - Compare the secondary values,
at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay
circuit. - Compare the values, as determined by the questioned
relay, to another protective relay monitoring the same line, with
currents supplied by different CTs. - Query SCADA for the power
flows at the far end of the line protected by the questioned relay,
compare those SCADA values to the values as determined by the
questioned relay. - Totalize the Watts and VARs on the bus and
compare the totals to the values as seen by the questioned relay.
The point of the verification procedure is to ensure that all of the
individual components are functioning properly; and that, an
ongoing proactive procedure is in place to re-check the various
components of the protective relay measuring systems.
*********************************** But the neither the
originally revised or newly revised definitions carry that implication
very well. Suppose the phrase in the definition were changed
from: “Voltage and current sensing devices providing inputs to
protective relays” to; “Voltage and current sensing device output
circuits and the associated circuits to the inputs of protective
relays”. This would make the whole definition read: Protection
System: Protective relays which respond to electrical quantities,
communication systems necessary for correct operation of
protective functions, voltage and current sensing device output
circuits and the associated circuits to the inputs of protective
relays, station dc supply, and control circuitry associated with
protective functions through the trip coil(s) of the circuit breakers
or other interrupting devices.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had
not completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
September 10, 2010
13
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
responses to ballot comments and the consideration of comments on the standard itself. You have put together a complete discussion of the fact that there is
more to a system than merely 5 listed devices.
Garry Baker
JEA
3
Negative
JEA believes the change in the definition should coordinate with
the new standard PRC-005-002.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
William Mitchell
Chamberlain
California Energy
Commission
9
Negative
Lack of clarity or apparent conflict between certain requirements
would make compliance assessment difficult.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had
not completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Bruce Merrill
Lincoln Electric System
3
Negative
Dennis Florom
Lincoln Electric System
5
Negative
Eric Ruskamp
Lincoln Electric System
6
Negative
LES would like to thank the Drafting Team for its time and effort in
developing the definition. However, at this time LES believes that
the implementation plan for the definition should be directly linked
to the approval and implementation schedule for PRC-005-2 and
the proposed definition of Protection System is incomplete as
written and remains open to interpretation.
LES offers the following Protection System definition for the SDT’s
consideration: “Protection System” is defined as: A system that
uses measurements of voltage, current, frequency and/or phase
angle to determine anomalies and trips a portion of the BES and
consists of 1) Protective relays, and associated auxiliary relays,
that initiate trip signals to trip coils, 2) associated communications
channels, 3) current and voltage transformers supplying protective
relay inputs, 4) dc station supply, excluding battery chargers, and
5) dc control trip path circuitry to the trip coils of BES connected
breakers, or equivalent interrupting device, and lockout relays.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
September 10, 2010
14
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
The SDT disagrees with several aspects of your suggested changes: Auxiliary relays are not a protective relay, but are instead a part of the dc control circuit;
“associated” communication systems is too vague to address existing concerns with the definition; battery chargers specifically should NOT be excluded; and “to
the trip coils” does not include trip coils as intended by the SDT. The SDT has made changes to the definition which may address other parts of your comment
Robert Ganley
Long Island Power
Authority
1
Affirmative
LIPA offers the following definition which we feel is clearer:
Protective relays which respond to electrical quantities,
communication systems required for operation of protective
functions, voltage and current sensing devices to protective relays,
station dc supply, and control circuitry from the associated
protective functions through the trip coil(s) of the circuit breakers
or other interrupting devices.
Response: Thank you for your comments. The SDT has adopted your suggestion regarding Protective Relays.
Saurabh Saksena
National Grid
September 10, 2010
1
Affirmative
National Grid suggests adding “Protection System Components
including” in the beginning. This is because the word
“components” has been used extensively throughout the standard
and there is no mention of what constitutes a protection system
component in the standard. The word “component” does find
mention in FAQs, however, it is recommended to mention it in the
main standard. Also, National Grid proposes a change in the
proposed definition (changing "voltage and current sensing inputs"
to "voltage and current sensing devices providing inputs"). The
revised definition should read as follows: Protective System
Components including Protective relays, communication systems
necessary for correct operation of protective functions, voltage
and current sensing devices providing inputs to protective relays
and associated circuitry from the voltage and current sensing
devices, station dc supply, and control circuitry associated with
protective functions from the station dc supply through the trip
coil(s) of the circuit breakers or other interrupting devices. The
time provided for the first phase “at least six months” is too open
ended and does not give entities a clear timeline. National Grid
15
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
suggests 1 year for the first phase. As a result, National Grid
suggests phasing out the second phase in stages.
Response: Thank you for your comments. The SDT believes that inclusion of the defined term within its own definition is not appropriate, and declines to adopt
your suggestion regarding the definition. The Implementation Plan and definition have both been modified in a manner that supports your comments.
Liam Noailles
Xcel Energy, Inc.
5
Negative
David F. Lemmons
Xcel Energy, Inc.
6
Negative
NERC has indicated that this definition is being processed to close
a reliability gap. It is not clear as to what gap this proposed
definition is closing. The use of the term “Station DC Supply”
actually introduces more confusion since some entities may view
this as only batteries, and not include chargers. It would appear
that the intent is to ensure that during a loss of substation service
power scenario that the source of power (whatever that may be)
to the Protection System is available and able to perform as
designed. Recommend the definition be re-written to make it clear
as to what components related to this assured source of power
are required to be maintained as part of the Protection System, or
alternatively define “Station DC Supply”.
Response: Thank you for your comments. The definition has been modified to specifically include battery chargers.
David H.
Boguslawski
Northeast Utilities
1
Negative
NU believes that a protection system includes: 1) Protective relays
which respond to electrical quantities, 2) Communications systems
necessary for correct operation of protective functions, 3) Voltage
and current sensing devices providing inputs to protective relays",
and associated circuitry from the voltage and current sensing
devices" 4) Station dc supply, and 5) Control circuitry associated
with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices The proposed definition
excludes "and associated circuitry from the voltage and current
sensing devices" from item 3. NU believes that the associated
circuitry for voltage and current sensing devices should be
included. It is our concern that the proposed definition implies
PRC-005 will apply specifically to the voltage and current sensing
devices and not include the AC circuitry between these devices
and the relay inputs.
Response: Thank you for your comments. The words of the definition were chosen to help clarify and exclude devices used exclusively for non-protective
functions (metering, etc.), while the maintenance standard itself has a minimum maintenance activity that seeks to demonstrate the importance of the entire
September 10, 2010
16
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
scheme.
Chifong L. Thomas
Pacific Gas and Electric
Company
1
Affirmative
PG&E believes the definition should identify that the protection
system is associated with direct BES electrical quantities with the
intention of protecting the BES from any device from propagating
a problem in one part of the BES to another. The definition should
not include associated systems, i.e. auxiliary systems including
their transformers, motors, etc. For generating stations the
protection included should only be the generator itself and its
associated main bank transformer that delivers the power to the
system. Likewise, for distribution substations, the protection
should only include equipment such as the main transformer that
draws power from the BES and not equipment such as distribution
feeders.
6
Affirmative
Please reference comments submitted by the PSEG companies on
the official comment form for this standard.
Response: Thank you for your comments.
James D. Hebson
PSEG Energy Resources
& Trade LLC
Response: Thank you for your comments. For this second ballot, there was no formal comment period.
Rebecca Berdahl
Bonneville Power
Administration
3
Negative
Please see BPA's comments submitted during the concurrent
formal comment period ending July 16, 2010.
Response: Thank you for your comments. The SDT changed the definition following the formal comment period that ended July 16, 2010.
Mark A Heimbach
PPL Generation LLC
5
Negative
Please see comments submitted by "PPL Supply" on 7/16/10.
Response: Thank you for your comments. The SDT changed the definition following the formal comment period that ended July 16, 2010.
Laurie Williams
Public Service Company
of New Mexico
1
Negative
PNM rejects this definition as too broad and not consistent with
the way utilities treat the various items in the definition, but
agrees with the proposed changes to the implementation plan.
Response: Thank you for your comments. Absent specific comments on the definition, the SDT is unable to respond to your concerns.
September 10, 2010
17
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Wayne Lewis
Entity
Progress Energy
Carolinas
Segment
5
Vote
Affirmative
Comment
Progress Energy does not believe that the definition should be
implemented separately from and prior to the implementation of
PRC-005-2. We believe there should be a direct linkage between
the definition’s effective date to the approval and implementation
schedule of PRC-005-2. Since this new definition should be directly
linked to the proposed revised standard, it would be premature to
make this new definition effective prior to the effective date of the
new standard. We believe that changes to the maintenance
program should be driven by the revision of the PRC standard, not
by the revision of a definition.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Kenneth D. Brown
Public Service Electric
and Gas Co.
1
Affirmative
PSE&G is now voting affirmative. Thanks to the drafting team for
improving the clarity of the definition.
10
Negative
Revise Protection System definition to: o BES Protective relays
which respond to electrical quantities, o Communications systems
necessary for correct operation of the BES protective functions, o
Voltage and current sensing devices providing inputs to BES
protective relays, o Battery and battery chargers that supply dc
to BES protective relays, communications, and control circuitry,
and o Control circuitry associated with the BES protective
functions through the trip coil(s) of the circuit breakers or other
interrupting devices.
Response: Thank you for your comments.
Dan R. Schoenecker
Midwest Reliability
Organization
Response: Thank you for your comments. The station dc supply component type has been modified essentially as you suggest. As to your suggestion
regarding inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
September 10, 2010
18
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Thomas C. Mielnik
Entity
MidAmerican Energy Co.
Segment
3
Vote
Negative
Comment
Revise Protection System definition to: BES Protective relays which
respond to electrical quantities, Communications systems
necessary for correct operation of the BES protective functions,
Voltage and current sensing devices providing inputs to BES
protective relays, Battery and battery chargers that supply dc to
BES protective relays, communications, and control circuitry, and
Control circuitry associated with the BES protective functions
through the trip coil(s) of the circuit breakers or other interrupting
devices.
Response: Thank you for your comments. The station dc supply component type has been modified essentially as you suggest. As to your suggestion
regarding inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
Brian EvansMongeon
Utility Services, Inc.
8
Negative
see filed comments
Response: Thank you for your comments. The SDT changed the definition following the formal comment period that ended July 16, 2010; there was no formal
comment period during the second ballot of the proposed definition.
Glen Reeves
Salt River Project
5
Affirmative
SRP believes the requirements of the Standard are confusing and
may be problematic in determining compliance. We also believe
the required functional testing of the breaker trip coil may
potentially increase maintenance outages of circuit breakers. In
most cases, circuit breaker maintenance outages can be
coordinated such that Protection System maintenance and testing
can be done simultaneously. However, in some cases this may not
be possible. Outages of any BES facility whether planned or
unplanned can impact system reliability. SRP suggests that trip coil
monitoring devices be included as an acceptable means of
ensuring the trip coil is functioning properly. This will help to avoid
unnecessary outages.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. The SDT provides the following response, in accordance with the
responses to comments on the standard itself.
James V. Petrella
Atlantic City Electric
Company
September 10, 2010
3
Affirmative
Suggested improvement: add "and associated circuitry" to
"Voltage and current sensing devices and associated circuitry
providing inputs to protective relays".
19
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
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Comment
Response: Thank you for your comments. Many other commenters have previously expressed concern with the definition as you suggest, and the SDT
believes that the definition as currently posted best expresses this portion of the definition.
Thomas R. Glock
Arizona Public Service
Co.
3
Negative
The change to the definition relative to the voltage and current
sensing devices is too prescriptive. Methods of determining the
integrity of the voltage and current inputs into the relays to ensure
reliability of the devices should be up to the discretion of the
utility.
Response: Thank you for your comments. Absent any specific comment regarding how the definition is too prescriptive, the SDT is unable to respond to your
concerns. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not completed the consideration of
comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to ballot comments and the
consideration of comments on the standard itself.
William D Shultz
Southern Company
Generation
5
Negative
The definition alone is acceptable, but the existing version of PRC005 does not guarantee any additional maintenance or testing will
occur with its ratification. Maintenance methodology documents
will have to be revised to include the new definition, but entities
may still dictate limited maintenance activities and lengthy
intervals which require no additional maintenance to be done. The
PRC-005-2 version of the standard includes this revised definition
and requires specific maintenance activities at specific intervals.
Establishing only a new definition does not close the perceived
reliability gap that is the basis for the current vote. The new
definition needs to be ratified along with the revised standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Raj Rana
American Electric Power
September 10, 2010
3
Negative
The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could
be construed by an auditor to include a lot of equipment and
infrastructure not intended by the PSMT SDT. For example, station
battery chargers are typically supplied by station auxiliary power
transformers, which in turn are supplied by primary-voltage bus
work, primary-voltage fuses, or primary-voltage circuit breakers.
20
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
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Entity
Segment
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Comment
An auditor for either PRC-005 or any other Standard referencing
"Protection System" could read that such primary-voltage
equipment is part of the Protection System and therefore subject
to certain requirements in either PRC-005 or any other Standard
referencing Protection System. The definition as drafted includes
"Communications systems necessary. . . ". Once again, this term
appears innocuous, but it is actually unclear. For example, if a
transfer-trip channel is carried on a microwave path, an auditor
may decide that the entire microwave equipment, microwave
building battery, and microwave building emergency generator are
all part of the Protection System, and thus subject to requirements
in either PRC-005 or other existing or future Standards that refer
to Protection System. AEP recommends that the term be phrased
"communications paths" opposed to "communications systems".
Similar to the above two items, we are concerned about the
inclusion of voltage and current-sensing "devices" in the Definition.
As written, applicability can be inferred to the entire device and
not merely its output quantities, not only for this Standard but any
other that references a Protection System. AEP recommends the
phrase "circuitry from voltage and current-sensing devices
providing inputs to protective relays" instead of "voltage and
current-sensing devices providing inputs to protective relays"
Response: Thank you for your comments. The definition has been modified to specifically include battery chargers. As to your other comments, it appears
that your comments apply more to the application of the definition within PRC-005-1 or PRC-005-2 than they do to the definition itself. Within the reference
materials associated with PRC-005-2, the SDT advises that equipment associated with microwave systems is part of the communications system. The SDT
believes that the proposed definition is less vague than the current definition on the issues you cite, and would improve the situation that you discuss from the
current level.
Michael Moltane
International
Transmission Company
Holdings Corp
1
Negative
The definition contained in this ballot really needs to be part and
parcel of the PRC-005-2 Standard Ballot, since the definition has
such a huge impact on the standard itself. It is problematic to vote
on a definition and on the standard independent of one another.
Therefore, ITC must vote negative on this Ballot.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
September 10, 2010
21
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Michael Schiavone
Niagara Mohawk
(National Grid Company)
3
Affirmative
The definition could be worded better
Response: Thank you for your comments. The SDT has modified the definition for improved clarity.
Kenneth Parker
Entegra Power Group,
LLC
5
Negative
The definition infers testing of CTs and PTs which should not be
necessary.
Response: Thank you for your comments. The definition of Protection System is for all applications of this term throughout NERC Standards. The detailed
applicability of this element of the definition relative to maintenance within PRC-005-2 is addressed within the standard by specifying, “Verify that acceptable
measurements of the current and voltage signals are received by the protective relays”.
Christopher Plante
Integrys Energy Group,
Inc.
4
Negative
1. The definition should state what is meant by “station dc
supply”. There continues to be questions in the industry
regarding if dc supply includes the battery charger. We
believe the charger is not included in station dc supply and
that the Definition of Protection System should specifically
address the point.
2. Also, the definition should specify BES relays, BES
protection functions and elements associated with BES
relays and functions.
Response: Thank you for your comments.
1. The definition has been modified to specifically include battery chargers.
2. This is properly an issue to address in the various standards that use this definition.
Terry Harbour
MidAmerican Energy Co.
September 10, 2010
1
Negative
The following changes should be incorporated in the definition to
insure it is used consistently in PRC-005 and any other standards
where it appears. Revise Protection System definition to: o BES
Protective relays which respond to electrical quantities, o
Communications systems necessary for correct operation of the
BES protective functions, o Voltage and current sensing devices
providing inputs to BES protective relays, o Battery and battery
chargers that supply dc to BES protective relays, communications,
and control circuitry, and Control circuitry associated with the BES
22
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
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Comment
protective functions through the trip coil(s) of the circuit breakers
or other interrupting devices.
Response: Thank you for your comments. The station dc supply component type has been modified essentially as you suggest. As to your suggestion
regarding inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
Robert W. Roddy
Dairyland Power Coop.
1
Negative
The implementation of the revised definition should not take place
until the revised standard PRC-005-2 is in effect.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
John Tolo
Tucson Electric Power
Co.
1
Negative
The mention of communication systems maintenance (M1.) needs
more clarity as to the depth of the maintenance required. Also,
Table 1a, a 3-month interval to verify that the Protection System
communications system is functional is too frequent to be
practical.
Response: Thank you for your comments. Your comments do not seem relevant to the definition, but instead appear to be related directly to the revisions to
the draft PRC-005-2 itself. The SDT had not completed consideration of comments on the standard when the definition was re-posted. The SDT provides the
following response, in accordance with the responses to comments on the standard itself.
Scott Kinney
Avista Corp.
1
Negative
The modified definition of Protection System now refers to
“functions” rather than “devices.” What are the “functions?” This
new term adds confusion without being defined in the standard.
Response: Thank you for your comments. The reference to “functions” is intended to reflect that there is increasing use, particularly in SPS, of devices which
mimic protective relays but are not actually traditional relays.
Michael Gammon
Kansas City Power &
Light Co.
September 10, 2010
1
Negative
The proposed changes in the Standard are far too prescriptive and
do not take into account the multitude of manufacturers
23
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Charles Locke
Kansas City Power &
Light Co.
3
Negative
Scott Heidtbrink
Kansas City Power &
Light Co.
5
Negative
Thomas Saitta
Kansas City Power &
Light Co.
6
Negative
Comment
equipment by establishing broad maintenance cycles and testing
intervals.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. In Order 693, the
FERC directed that NERC establish maximum allowable intervals for maintenance of protection systems.
Jack Stamper
Clark Public Utilities
1
Negative
The proposed definition does not provide the level of clarity that is
needed.
Response: Thank you for your comments. The SDT has modified the definition for improved clarity.
Ajay Garg
Hydro One Networks,
Inc.
1
Affirmative
The proposed definition of Protection System needs clarification on
when such equipment is a part of the transmission protection
system. Emphasis should be on systems and not individual
components.
Response: Thank you for your comments. This issue is better addressed in the various standards that use the definition.
Mace Hunter
Lakeland Electric
3
Affirmative
The proposed draft may introduce TFEs into the PRC standards,
not a good thing. The proposed draft reaches beyond the
statutory scope of the reliability standards. Perfection is not a
realistic goal.
Response: Thank you for your comments. The SDT has modified the definition for improved clarity.
Kim Warren
Independent Electricity
System Operator
September 10, 2010
2
Affirmative
The proposed revision to the definition has removed the
"associated circuitry from the voltage and current sensing devices"
which we believe should be included since failure of this wiring will
render the Protection System inoperative. On this basis we
recommend the following change to once again include this
circuitry in the definition: “Protective relays which respond to
electrical quantities, communication systems necessary for correct
operation of protective functions, voltage and current sensing
devices AND ASSOCIATED CIRCUITRY [emphasis added] providing
inputs to protective relays, station dc supply, and control circuitry
24
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
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Comment
associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.”
Response: Thank you for your comments. The change to insert the term “devices providing” was to improve clarity while also excluding voltage and current
measuring devices that provide data exclusively to metering equipment as opposed to Protection Systems. The SDT agrees with the commenter that an
appropriate maintenance activity is to ensure that the measured voltage and current values correctly make it to the relays. The maintenance activity is a part of
the standard. The absence of this activity from the definition is not intended to lead one to believe that the activity is not important.
Roger C
Zaklukiewicz
8
Negative
The proposed rewording of the definition implies that the wiring
from the current transformers and voltage transformers to the
protective relay systems are independent of the protection system
being tested and that separate maintenance standards will have to
be established to test the integrity of the wiring and the Potential
device and current transformer. The definition of the Protection
System should not exclude the wiring and devices which generate
the current and voltage sources to the protective relays.
Response: Thank you for your comments. The change to insert the term “devices providing” was to improve clarity while also excluding voltage and current
measuring devices that provide data exclusively to metering equipment as opposed to Protection Systems. The SDT agrees with the commenter that an
appropriate maintenance activity is to ensure that the measured voltage and current values correctly make it to the relays. The maintenance activity is a part of
the standard. The absence of this activity from the definition is not intended to lead one to believe that the activity is not important.
Jim R Stanton
SPS Consulting Group
Inc.
8
Negative
The reference to "communication systems" should be deleted from
the definition. It is confusing to Registered Entities who do not
consider the circuits that connect components of a protection
system to be a communication "system" such as a telephone
system, postal service or computer network which is more
properly called a communication system. Suggest changing it to
"signal carrying circuitry."
Response: Thank you for your comments. The SDT believes that “Communication Systems” is a term that is generally well understood within the industry.
September 10, 2010
25
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Brock Ondayko
Entity
AEP Service Corp.
Segment
5
Vote
Negative
Comment
The term "station" should either be defined or removed from the
definition, as it implies transmission and distribution assets while
the term "plant" is used to define generation assets. It would
suffice to simply refer to the "DC Supply". As written, the
implementation plan only specifies a time frame for entities to
update their documentation for PRC-005-1 and PRC-005-2
compliance. The implementation plan also needs to give entities a
time frame to address any required changes to their
documentation for other standards that use the term "Protection
System", including but not limited to NUC-001-2, PER-005-1, PRC001-1, etc.
Response: Thank you for your comments. The term ‘station’ was used because it could include both a substation and a generation station while at the same
time excluded installations that were strictly communications repeater sites. As noted on the “Assessment of Impact of Proposed Modification to the Definition
of “Protection System” which was posted with the first comment period, the SDT believes that the bulk of the implementation of the new definition will be
regarding PRC-005 (generically) and that there will be very little implementation associated with the other standards that utilize this term.
Paul B. Johnson
American Electric Power
1
Negative
1. The term "station" should either be defined or removed from
the definition, as it implies transmission and distribution assets
while the term "plant" is used to define generation assets. It
would suffice to simply refer to the "DC Supply". As written, the
implementation plan only specifies a time frame for entities to
update their documentation for PRC-005-1 and PRC-005-2
compliance. The implementation plan also needs to give entities a
time frame to address any required changes to their
documentation for other standards that use the term "Protection
System", including but not limited to NUC-001-2, PER-005-1, PRC001-1, etc. we still support a "negative" ballot with the following
comments:
2. The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could
be construed by an auditor to include a lot of equipment and
infrastructure not intended by the PSMT SDT. For example, station
battery chargers are typically supplied by station auxiliary power
transformers, which in turn are supplied by primary-voltage
buswork, primary-voltage fuses, or primary-voltage circuit
September 10, 2010
26
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
breakers. An auditor for either PRC-005 or any other Standard
referencing "Protection System" could read that such primaryvoltage equipment is part of the Protection System and therefore
subject to certain requirements in either PRC-005 or any other
Standard referencing Protection System.
The definition as drafted includes "Communications systems
necessary. . . ". Once again, this term appears innocuous, but it is
actually unclear. For example, if a transfer-trip channel is carried
on a microwave path, an auditor may decide that the entire
microwave equipment, microwave building battery, and microwave
building emergency generator are all part of the Protection
System, and thus subject to requirements in either PRC-005 or
other existing or future Standards that refer to Protection System
Similar to the above two items, we are concerned about the
inclusion of voltage and current-sensing "devices" in the Definition.
As written, applicability can be inferred to the entire device and
not merely its output quantities, not only for this Standard but any
other that references a Protection System.
Response: Thank you for your comments.
1. The term ‘station’ was used because it could include both a substation and a generation station while at the same time excluded installations that were
strictly communications repeater sites. As noted on the “Assessment of Impact of Proposed Modification to the Definition of “Protection System” which
was posted with the first comment period, the SDT believes that the bulk of the implementation of the new definition will be regarding PRC-005
(generically) and that there will be very little implementation associated with the other standards that utilize this term.
2. The definition has been modified to specifically include battery chargers. As to your other comments, it appears that your comments apply more to the
application of the definition within PRC-005-1 or PRC-005-2 than they do to the definition itself. Within the reference materials associated with PRC-0052, the SDT advises that equipment associated with microwave systems is part of the communications system. The SDT believes that the proposed
definition is less vague than the current definition on the issues you cite, and would improve the situation that you discuss from the current level.
Peter T Yost
Consolidated Edison Co.
of New York
September 10, 2010
3
Negative
1. There is not enough clarity on whether a Distribution Provider
(DP) will be able to clearly identify which protection system
components it does own and needs to maintain. Many DPs
own and/or operate equipment identified in the existing or
proposed definition. However, not all such equipment
translates into a transmission Protection System. The
definition needs clarification on when such equipment is a part
of the transmission protection system.
27
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
2. Also, the time provided for the first phase "at least six months"
is too open ended and does not provide entities with a clear
timeline. It is suggested that one year is appropriate for the
first phase phasing out the second year in stages.
Response: Thank you for your comments.
1. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not completed the consideration of
comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the responses to ballot comments
and the consideration of comments on the standard itself. “When such equipment is part of the transmission protection system” is properly a matter to
be resolved within the various standards that use this term.
2. The implementation period has been revised from six months to twelve months.
Greg Lange
Public Utility District No.
2 of Grant County
3
Negative
These systems are not always maintained at the component level.
ie. meggering from the relay input test switch through the cable
and the CT. This has not closed all the issues around professional
judgement (interpretations) that make us nervous when faced
with the human element of an audit. We need more specificity to
close that gap.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Silvia P Mitchell
Florida Power & Light Co.
6
Affirmative
This revision is better written.
Response: Thank you for your comments.
September 10, 2010
28
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Joseph G. DePoorter
Madison Gas and Electric
Co.
Segment
4
Vote
Negative
Comment
Upon review of the updated proposed “Protection System”
definition and its main use in describing PRC-005, which applies to
BES Protective Systems, the definition needs to incorporate BES
within it. Without BES used within the definition, it will be used to
interpret every protection system that the industry uses. This is
not the course that we wish to travel. Please note the following
recommended definition: o BES Protective relays which respond
to electrical quantities, o Communications systems necessary for
correct operation of the BES protective functions, o Voltage and
current sensing devices providing inputs to BES protective relays,
o Battery and battery chargers that supply dc power to BES
protective relays, communications, and control circuitry, and o
Control circuitry associated with the BES protective functions
through the trip coil(s) of the circuit breakers or other interrupting
devices.
Response: Thank you for your comments. The station dc supply component type has been modified essentially as you suggest. As to your suggestion
regarding inclusion of “BES’ within the definition – this is properly an issue to address in the various standards that use this definition.
Richard J. Mandes
Alabama Power Company
3
Affirmative
Anthony L Wilson
Georgia Power Company
3
Affirmative
Gwen S Frazier
Gulf Power Company
3
Affirmative
Don Horsley
Mississippi Power
3
Affirmative
Horace Stephen
Williamson
Southern Company
Services, Inc.
1
Affirmative
We agree that the definition provides clarity and will enhance the
reliability of the Protection Systems to which it is applicable.
However, we feel that there needs to be a direct linkage of the
definition’s effective date to the approval and implementation
schedule of PRC-005-2. Since this new definition is directly linked
to the proposed revised standard, it would be premature to make
this definition effective prior to the effective date of the new
standard.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Jason L Marshall
Midwest ISO, Inc.
2
Abstain
We are abstaining because a number of our stakeholders have
concerns regarding the definition of Protection System.
Response: Thank you for your comments. The SDT responded to the individual stakeholder comments submitted.
September 10, 2010
29
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Claudiu Cadar
Entity
GDS Associates, Inc.
Segment
1
Vote
Negative
Comment
We do not agree with inclusion of the trip coil. The trip coil is not a
protective device; it does not sense voltage or current and
operates based on a faulted condition. It is supplied the necessary
input from the DC system which is based on protective relays
signaling and contact operation. The trip coil is part of the circuit
breaker; it is not separate equipment. Does this mean that the
circuit breaker is now part of the protection system?
Response: Thank you for your comments. The current definition includes “DC Control Circuitry”; the SDT attempted to clearly define which of the many control
circuits and the limit of the definition. While the current definition is vague, it can certainly include the trip coils and close coils and alarm circuits of the
interrupting device. The SDT believes that the electrically-operated trip coils are an important part of the control circuitry.
Anthony Jankowski
Wisconsin Energy Corp.
September 10, 2010
4
Negative
We Energies does not agree to the implementation plan proposed.
While it makes common sense to proceed with R1 prior to
proceeding with implementing R2, R3, and R4, the timeline to be
compliant for R1 is too short. It will take a considerable amount of
resources to migrate the maintenance plan from today’s standard
to the new standard in phase one. ATC recommends that time to
develop and update the revised program be increased to at least
one year followed by a transition time for the entity to collect all
the necessary field data for the protection system within its first
full cycle of testing. (In ATC’s case would be 6 years) To address
phase two, We Energies believes human and technological
resources will be overburdened to implement this revised standard
as written. The transition to implementing the new program will
take another full testing cycle once the program has been
updated. Increased documentation and obtaining additional
resources to accomplish this will be challenging. Implementation
of PRC-005-2 will impact We Energies in the following manner: a.
Increase costs: double existing maintenance costs. b. Since there
will be a doubling of human interaction (or more), it is expected
that failures due to human error will increase, possibly
proportionately. c. Breaker maintenance may need to be aligned
with protection scheme testing, which will always contain elements
that are include in the non-monitored table for 6 yr testing. d. We
Energies is developing standards for redundant bus and
transformer protection schemes. This would allow We Energies to
30
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
test the protection packages without taking the equipment out of
service. Further if one system fails, there is full redundancy
available. With the current version of PRC-005-2, We Energies
would need to take an outage to test the protection schemes for a
transformer or a bus, there is not an incentive to install redundant
schemes. We Energies is working with a condition based breaker
maintenance program. This program’s value would be greatly
diminished under PRC-005-2 as currently written. Consideration
also needs to be given for other NERC standards expected to be
passed and in the implementation stage at the same time, such as
the CIP standards.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had
not completed the consideration of comments on the standard when the definition was re-posted. The SDT has responded to similar comments within the
responses to ballot comments and the consideration of comments on the standard itself.
Linda Horn
Wisconsin Electric Power
Co.
5
Negative
James R. Keller
Wisconsin Electric Power
Marketing
3
Negative
We object strongly to the addition of the term "voltage and
current sensing devices...". This revised definition will make it a
requirement to perform actual tests on the voltage and current
transformers. The previous definition was "voltage and current
inputs to protective relays" and this is much preferred to allow the
needed flexibility in maintenance practices.
Response: Thank you for your comments. The current definition of Protection System uses the term “voltage and current sensing devices”. The current
standard PRC-005-1 requires the entity to have a PSMP for those devices. The proposed revision PRC-005-2 would require minimum maintenance activities that
verify other than an annual IR Scan of the voltage and current sensing devices. As there is no method listed in the standard, some of the process flexibility that
you seek has been maintained.
Brandy A Dunn
Western Area Power
Administration
1
Affirmative
Western agrees with the revised definition of a Protection System
and disagreese with the Implementation Plan under PRC-005-1.
The definition implementation should be delayed until approval of
PRC-005-2.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
September 10, 2010
31
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
entities time to apply the new definition to PRC-005-1.
Henry Delk, Jr.
SCE&G
1
Negative
While SCE&G believes the majority of the PRC-005-2 standard is
ready to be affirmed there are still inconsistencies with areas of
the standard that need to be corrected prior to approval. These
inconsistencies are addressed in SCE&G’s comments which have
been submitted for the current draft of this standard.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. Please see the response to your comments on the first draft of
the standard.
Richard J Kafka
Potomac Electric Power
Co.
1
Affirmative
While voting in the affirmative, PHI feels the definition could be
improved by adding and associated circuitry to the third item
Voltage and current sensing devices and associated circuitry
providing inputs to protective relays
Response: Thank you for your comments. The SDT agrees with the commenter of the importance of this as a maintenance activity and has attempted to
capture relevant maintenance activities within the revised standard itself.
David A. Lapinski
Consumers Energy
3
Negative
David Frank Ronk
Consumers Energy
4
Negative
Without the context of draft PRC-005-2, the changes to this
definition are difficult to understand and even more difficult to
implement. We therefore strongly recommend that this definition
NOT be approved independently from the draft of PRC-005-2, and
that development of both the definition and the standard proceed
as a single activity.
Response: Thank you for your comments. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT
SDT, the board acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as practical
- not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Gregory L Pieper
Xcel Energy, Inc.
1
Negative
Michael Ibold
Xcel Energy, Inc.
3
Negative
Xcel Energy believes the standard still contains many aspects that
are not clearly understood by entities, including what is needed to
demonstrate a compliant PSMP. Comments have been submitted
concurrently to NERC via the draft comment response form.
Response: Thank you for your comments. Your comments appear to be relative to the draft standard PRC-005-2, rather than the definition. The SDT had not
completed the consideration of comments on the standard when the definition was re-posted. Please see the response to your comments on the first draft of
September 10, 2010
32
Consideration of Comments on Second Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Voter
Entity
Segment
Vote
Comment
the standard.
James A Ziebarth
Y-W Electric Association,
Inc.
4
Affirmative
Y-WEA thanks the SDT for clarifying what relays are and are not
included in this definition.
Response: Thank you for your comments.
September 10, 2010
33
Proposed Definition of Protection System:
Protection System –
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
• Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
Protection System Definition
The definition posted for the second ballot of Protection System reads as follows:
Protection System –
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply, and
• Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
Based on stakeholder comments submitted with the second ballot, the drafting
team made minor changes to the proposed definition as shown below:
Protection System –
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
• Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
Protection System Definition
The previously approved (Board of Trustees) definition of Protection System reads
as follows:
Protection System: Protective relays, associated communication systems, voltage and
current sensing devices, station batteries and DC control circuitry.
Proposed Changes to Board of Trustees Approved Version of Definition:
Protection System: Protective relays which respond to electrical quantities, associated
communication systems necessary for correct operation of protective functions, voltage and
current sensing devices providing inputs to protective relays, station dc supply associated
with protective functions (including station batteries, battery chargers, and non-battery
based and DC dc supply), and control circuitry associated with protective functions through
the trip coil(s) of the circuit breakers or other interrupting devices.
Implementation Plan for the Revised Definition of Protection System
Prerequisite Approvals or Activities:
The implementation of the revised definition is not dependent upon any other activity.
Recommended Modifications to Already Approved Standards
The non-capitalized version of the term, “protection system” is used in the following approved
standards:
•
NUC-001-2 – Nuclear Plant Interface Coordination
•
PER-005-1 – System Personnel Training
•
PRC-001-1 – System Protection Coordination
The term, “protection system” shall be capitalized where used in these standards when the
definition of “Protection System” is approved by applicable regulatory authorities.
Proposed Effective Date:
Each responsible entity (Distribution Provider that owns a transmission Protection System,
Transmission Owner, and Generator Owner) shall modify its protection system maintenance and
testing program description and basis document(s) (required in Requirement R1 of PRC-005-1 –
Transmission and Generation Protection System Maintenance and Testing) as necessary to
reflect the modified definition of ‘Protection System’ by the first day of the first calendar quarter
twelve months following regulatory approvals and implement any additional maintenance and
testing (required in Requirement R2 of PRC-005-1 – Transmission and Generation Protection
System Maintenance and Testing) by the end of the first complete maintenance and testing cycle
described in the entity’s program description and basis document(s) following establishment of
the program changes resulting from the revised definition.
The original definition of “Protection System” shall be retired at the same time the revised
definition becomes effective.
September 13, 2010
Comment Form for the definition of Protection System [Project 2007-17]
Please DO NOT use this form to submit comments on the proposed definition of “Protection
System.” Comments must be submitted by October 12, 2010. If you have questions
please contact Al McMeekin at [email protected] or by telephone at 803-530-1963.
Background Information:
A second ballot for the definition of “Protection System” was conducted from July 23 –
August 2, 2010. There were numerous comments opposing balloting the definition
separately from the definition; the NERC Board of Trustees directed that a revised definition
be approved as quickly as possible to close a reliability gap.
Some commenters suggested the “station dc supply” portion of the definition be modified to
specifically address battery chargers; the SDT modified the definition as suggested. The
revised definition is shown below with the new language shown in red:
Protection System –
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
• Control circuitry associated with protective functions through the trip coil(s) of
the circuit breakers or other interrupting devices.
The SDT did not make any other modifications to the definition and did not make any
modifications to the implementation plan following the second ballot. The implementation
plan allows at least 12 months beyond the regulatory approval date for entities to
implement the new definition.
1. Do you agree with the proposed definition of “Protection System?” If not, please provide
specific suggestions for improvement.
Yes
No
Comments:
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Standards Announcement
Successive Ballot Open
October 2-14, 2010
Available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-17 Protection System Maintenance Definition
A successive ballot for the definition of “Protection System” is now open through 8 p.m. Eastern on October 14,
2010.
Instructions
Members of the ballot pool associated with this project may log in and submit their votes from the following page:
https://standards.nerc.net/CurrentBallots.aspx
The Standards Committee encourages all members of the ballot pool to review the consideration of comments for
the previous ballot and the modifications that team made to the definition. In a successive ballot, votes are not
carried forward from the previous ballot.
Transition from Reliability Standards Development Procedure Version 7 – to Standard Processes
Manual
Under the Reliability Standards Development Procedure Version 7, consensus was built with successive formal
comment periods, followed by a 30-day pre-ballot review, followed by an initial ballot, and then a recirculation ballot.
The intent was to use stakeholder views submitted through the formal comment periods to achieve consensus, and then
to confirm that consensus during the balloting. This process did not allow a drafting team to make any changes to a
standard (or definition) between ballots, which incented teams to avoid making improvements once a standard (or
definition) had gone through an initial ballot. If a team made a change between ballots, then the standard (or definition)
was required to be posted for a new comment period and then another pre-ballot review and another initial ballot, and
finally if there were no more changes made to the standard (or definition), a recirculation ballot was conducted to
confirm consensus.
Under the new Standard Processes Manual, consensus is achieved through parallel comment and ballot periods.
Successive comment and ballot periods are conducted until there is consensus – and then a recirculation ballot is
conducted to confirm that consensus. There is no 30-day pre-ballot review period, and drafting teams are encouraged to
make revisions to the standard between successive ballots to improve the quality of the standard (or definition).
Next Steps
Voting results will be posted and announced after the ballot window closes.
Project Background
When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the Protection
System and Maintenance Standard Drafting Team, the board acknowledged the reliability gap identified by the drafting
team caused by the definition of "protection system" and directed that work to close this reliability gap should be given
“priority.” The Standards Committee directed the team to advance the definition of Protection System in parallel with the
development of PRC-005-2.
Project page: http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our thanks to
all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Successive Formal Comment Period Open
September 13 – October 12, 2010
Now available at:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Project 2007-17: Protection System Maintenance and Testing
A formal comment period for the revised definition of “Protection System” is now open until 8 p.m. Eastern
on October 12, 2010.
This is the fourth draft of the proposed definition. As envisioned, the definition, once approved, will apply to
PRC-005-1 approximately twelve months following regulatory approval. The new definition will replace the
existing definition of “protection system.” The existing definition has some identified deficiencies that result in
a reliability gap, where some protection system owners do not consider components such as battery chargers
associated with protective functions as components of a protection system, and do not include the maintenance
of these components in their protection system maintenance programs.
Transition from Reliability Standards Development Procedure Version 7 – to Standard
Processes Manual
Under the Reliability Standards Development Procedure Version 7, consensus was built with successive formal
comment periods, followed by a 30-day pre-ballot review, followed by an initial ballot, and then a recirculation
ballot. The intent was to use stakeholder views submitted through the formal comment periods to achieve
consensus, and then to confirm that consensus during the balloting. This process did not allow a drafting team
to make any changes to a standard (or definition) between ballots, which incented teams to avoid making
improvements once a standard (or definition) had gone through an initial ballot. If a team made a change
between ballots, then the standard (or definition) was required to be posted for a new comment period and then
another pre-ballot review and another initial ballot, and finally if there were no more changes made to the
standard (or definition), a recirculation ballot was conducted to confirm consensus.
Under the new Standard Processes Manual, consensus is achieved through parallel comment and ballot periods.
Successive comment and ballot periods are conducted until there is consensus – and then a recirculation ballot
is conducted to confirm that consensus. There is no 30-day pre-ballot review period, and drafting teams are
encouraged to make revisions to the standard between successive ballots to improve the quality of the standard
(or definition).
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Next Steps
During the last 10 days of the 30-day formal comment period a successive ballot will be conducted for 10 days.
All members of the ballot pool must cast a new ballot – the votes and comments from the last ballot will not be
carried over. The drafting team will consider all comments (those submitted with a comment form, and those
submitted with a ballot) and will determine whether to make additional changes to the definition. The team
will post its response to comments and, if the definition has only minor changes, will post the definition and
conduct a 10-day recirculation ballot.
Project Background
When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the
Protection System and Maintenance Standard Drafting Team, the board acknowledged the reliability gap
identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” The Standards Committee directed the team to advance the
definition of Protection System in parallel with the development of PRC-005-2.
Project page: http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Successive Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
Project 2007-17 Protection System Maintenance Definition
A successive ballot for the definition of “Protection System” ended on October 14, 2010.
Successive Ballot Results
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum: 84.11%
Approval: 84.52 %
Since at least one negative ballot included a comment, these results are not final. Another ballot (either a
successive ballot or a recirculation ballot) must be conducted.
Transition from Reliability Standards Development Procedure Version 7 – to Standard
Processes Manual
Under the Reliability Standards Development Procedure Version 7, consensus was built with successive
formal comment periods, followed by a 30-day pre-ballot review, followed by an initial ballot, and then a
recirculation ballot. The intent was to use stakeholder views submitted through the formal comment periods
to achieve consensus, and then to confirm that consensus during the balloting. This process did not allow a
drafting team to make any changes to a standard (or definition) between ballots, which incented teams to
avoid making improvements once a standard (or definition) had gone through an initial ballot. If a team
made a change between ballots, then the standard (or definition) was required to be posted for a new
comment period and then another pre-ballot review and another initial ballot, and finally if there were no
more changes made to the standard (or definition), a recirculation ballot was conducted to confirm
consensus.
Under the new Standard Processes Manual, consensus is achieved through parallel comment and ballot
periods. Successive comment and ballot periods are conducted until there is consensus – and then a
recirculation ballot is conducted to confirm that consensus. There is no 30-day pre-ballot review period, and
drafting teams are encouraged to make revisions to the standard between successive ballots to improve the
quality of the standard (or definition).
Next Steps
The drafting team will review the comments submitted with ballots and post its consideration of those
comments.
Project Background
When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the
Protection System and Maintenance Standard Drafting Team, the board acknowledged the reliability gap
identified by the drafting team caused by the definition of "protection system" and directed that work to close
this reliability gap should be given “priority.” The Standards Committee directed the team to advance the
definition of Protection System in parallel with the development of PRC-005-2.
Project Page: http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_200717.html
Ballot Criteria
Approval requires both a (1) quorum, which is established by at least 75% of the members of the ballot pool
submitting either an affirmative vote, a negative vote, or an abstention, and (2) a two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and
negative votes, excluding abstentions and non-responses. If there are no negative votes with reasons from the
first (or successive) ballot, the results of that ballot shall stand. If, however, one or more members submit
negative votes with reasons, another ballot shall be conducted. If the team makes significant changes to the
definition, then another successive ballot must be conducted. If the team does not make any significant
changes to the definition, then a final recirculation ballot is conducted.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate.
For more information or assistance, please contact Monica Benson at [email protected].
NERC Standards
Newsroom • Site Map • Contact NERC
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Project 2007-17 Protection System Maintenance (Protection System
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Ballot Period: 10/2/2010 - 10/14/2010
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Ballot Type: Initial
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Total # Votes: 270
Total Ballot Pool: 321
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Quorum: 84.11 % The Quorum has been reached
Weighted Segment
84.52 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
89
9
71
24
67
37
0
11
6
7
321
#
Votes
1
0.5
1
1
1
1
0
0.8
0.5
0.5
7.3
#
Votes
Fraction
60
3
53
17
38
26
0
6
5
5
213
Negative
Fraction
0.833
0.3
0.93
0.895
0.745
0.867
0
0.6
0.5
0.5
6.17
Abstain
No
# Votes Vote
12
2
4
2
13
4
0
2
0
0
39
0.167
0.2
0.07
0.105
0.255
0.133
0
0.2
0
0
1.13
4
1
2
2
6
1
0
1
0
1
18
13
3
12
3
10
6
0
2
1
1
51
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Robert D Smith
John Bussman
Scott Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0cbc4988-d870-4cd4-9490-99f883e2aec1[10/18/2010 3:28:38 PM]
Ballot
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnesota Power, Inc.
National Grid
Nebraska Public Power District
New York Power Authority
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
John J. Moraski
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Ronald D. Schellberg
Negative
Affirmative
Affirmative
View
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Michael Moltane
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
Doug Bantam
Robert Ganley
Martyn Turner
Michelle Rheault
Ernest Hahn
Terry Harbour
Randi Woodward
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
Richard J Kafka
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Chad Bowman
Catherine Koch
Tim Kelley
Robert Kondziolka
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0cbc4988-d870-4cd4-9490-99f883e2aec1[10/18/2010 3:28:38 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Santee Cooper
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Arizona Public Service Co.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Leesburg
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V. Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Faramarz Amjadi
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Thomas R. Glock
James V. Petrella
Pat G. Harrington
Rebecca Berdahl
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C Parent
Steven Grego
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0cbc4988-d870-4cd4-9490-99f883e2aec1[10/18/2010 3:28:38 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
View
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salem Electric
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Tri-State G & T Association, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
Y-W Electric Association, Inc.
AEP Service Corp.
Amerenue
APS
Avista Corp.
Black Hills Corp
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David T. Anderson
Ballard Keith Mutters
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Anthony Schacher
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
David Schiada
Jeff Nelson
Ronald L Donahey
Janelle Marriott
James R. Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
View
View
View
View
Affirmative
Abstain
Abstain
Affirmative
Timothy Beyrle
Affirmative
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Christopher Plante
Joseph G. DePoorter
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
John D. Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
James A Ziebarth
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
George Tatar
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0cbc4988-d870-4cd4-9490-99f883e2aec1[10/18/2010 3:28:38 PM]
View
Negative
Affirmative
Negative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Entergy Corporation
FirstEnergy Solutions
Florida Municipal Power Agency
Green Country Energy
Horizon Wind Energy
Indeck Energy Services, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
New Harquahala Generating Co. LLC
New York Power Authority
Northern Indiana Public Service Co.
Otter Tail Power Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Public Utility District No. 1 of Lewis County
Reedy Creek Energy Services
RRI Energy
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Centralia Generation, LLC
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Amir Y Hammad
James B Lewis
Bob Essex
Mike Garton
Robert Smith
Dan Roethemeyer
Stephen Ricker
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Doug Ramey
Affirmative
Kenneth Parker
Stanley M Jaskot
Kenneth Dresner
David Schumann
Greg Froehling
Brent Hebert
Rex A Roehl
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Daniel Duff
Dennis Florom
Charlie Martin
Mike Laney
Mark Aikens
Affirmative
Affirmative
David Gordon
Nicholas Q Hayes
Gerald Mannarino
Michael K Wilkerson
Stacie Hebert
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A Heimbach
Wayne Lewis
David Murray
Steven Grega
Bernie Budnik
Thomas J. Bradish
Bethany Wright
Glen Reeves
Daniel Baerman
Michael J. Haynes
Brenda K. Atkins
Richard Jones
Jerry W Johnson
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Joanna Luong-Tran
Barry Ingold
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
View
View
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Karl Bryan
Affirmative
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
Terri F Benoit
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0cbc4988-d870-4cd4-9490-99f883e2aec1[10/18/2010 3:28:38 PM]
View
View
Negative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Energy
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
OTP Wholesale Marketing
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Ascendant Energy Services, LLC
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
SPS Consulting Group Inc.
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P Mitchell
Donna Stephenson
Thomas Saitta
Paul Shipps
Eric Ruskamp
Daryn Barker
Brad Jones
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
David Ried
Bruce Glorvigen
James Eckelkamp
James D. Hebson
Hugh A. Owen
Trent Carlson
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
John Stonebarger
Affirmative
David F. Lemmons
James A Maenner
Roger C Zaklukiewicz
Kristina M. Loudermilk
Merle Ashton
Raymond Tran
Jim D. Cyrulewski
Margaret Ryan
Peggy Abbadini
Jim R Stanton
Brian Evans-Mongeon
Terry Volkmann
William Mitchell Chamberlain
Affirmative
Affirmative
Affirmative
Donald E. Nelson
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
View
View
View
Affirmative
Diane J. Barney
Jerome Murray
Philip Riley
Ric Campbell
Linda Campbell
Dan R. Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B Edge
Louise McCarren
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
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Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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NERC Standards
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A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0cbc4988-d870-4cd4-9490-99f883e2aec1[10/18/2010 3:28:38 PM]
Individual or group. (27 Responses)
Name (20 Responses)
Organization (20 Responses)
Group Name (7 Responses)
Lead Contact (7 Responses)
Question 1 (25 Responses)
Question 1 Comments (27 Responses)
Individual
James Stanton
SPS Consulting Group Inc.
No
The revised definition perpetuates the confusion over "communications systems" embedded or
otherwise associated with Protection Systems. The term "communications components" is more
accurate.
Individual
Martin Bauer
US Bureau of Reclamation
No
The term "protection functions" is ambiguous as it is not related to the protection function associated
with the protective relays. There are other protection functions not associated with protective relays
that respond to electrical quantities. The language for Communication systems should be changed to
remove the ambiguity. The following change would be clear, "Communication system necessary for
the correct operation of the protective relays" The input to the relays is from voltage and current
sensing devices through their respective circuits. Since the definition for protective relays separates
the term "control circuitry" associated with protective relays, it is clear that protective relays does not
also include the "control circuitry". By the same token, voltage and current sensing devices do not
include their related circuits. The definition for voltage and current sensing devices should be revised
to include the term "circuits". The following language change would serve make it clear: "Voltage and
current sensing devices and their respective circuits providing inputs protective relays,".
Individual
Karl Bryan
US Army Corps of Engineers
No
The use of the term "protection functions" is not a defined NERC term and either the term should be
defined or it should not be used. At best the term is ambiguous and could lead to scope growth by
auditors. Recommend that the following changes be made: "Communication system necessary for the
correct operation of the protective relays." "Control circuitry associated with protective relays through
the trip coil(s) of the circuit breaker or other interrupting device." See the next paragraph for the
proposed correction to the DC Supply part of the definition. The input to the relay is from voltage and
currenct sensing devices yet there is no mention of the associated circuits. The same can be said
about the station DC supply circuits. The definition should apply to the circuits providing inputs or
control power to the protective relays and from the output of the relays to the tripping coils of the
circuit breaker. Recommend the following: "Voltage and current sensing devices and their respective
circuits providing inputs to the protective relays." "Station DC supply associated with protective relays
(including station batteries, battery charger, non-battery-based DC supply,circuitry to the protective
relays and from the relay to the trip coil(s)of the circuit breaker), and"
Group
NERC Staff
Mallory Huggins
No
NERC staff does not support the phrase “voltage and current sensing devices providing input to
protective relays.” While no version of the definition has been all-inclusive with respect to this phrase,
we believe that the best phrase would be a combination of several drafts and should state the
following: “voltage and current sensing devices and associated circuitry from the voltage and current
sensing devices to the protective relay inputs.” As currently written, the definition represents a step
backward from the language in the previous definition (“voltage and current sensing inputs to
protective relays and associated circuitry from the voltage and current sensing devices”) and should
be modified.
Individual
Kirit S. Shah
Ameren
Yes
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
Yes
Group
Northeast Power Coordinating Council
Guy Zito
No
This project addresses the definition of a Protection System. However, an ongoing issue that needs to
be addressed is clarification of when a Bulk Electric System transmission Protection System applies to
a Distribution Provider. An example would be for a tee-tap off a Bulk Power System 345kV line to a
step down transformer supplying distribution--would the relaying on the low side of the transformer
be expected to comply with the requirements of PRC-005-2? Would the protection system
configuration be considered a Protection System? Will this issue be addressed within the scope of
Project 2007-17?
Individual
Greg Froehling
Green Country Energy
Yes
Individual
Dan Roethemeyer
Dynegy Inc.
No
The majority of the definition is good; however, the term "non-battery-based dc supply' is still
somewhat vague. Can you please further define or provide some examples?
Individual
Paul Rocha
CenterPoint Energy
No
(a) CenterPoint Energy believes the proposed re-definition of “Protection System” is technically
incorrect due to the inclusion of trip coils as part of the control circuitry. A protection system has
correctly performed its function if it provides tripping voltage up to the terminals of trip coils. From
that point, the circuit breaker can fail to timely interrupt fault current due to several factors, such as a
binding mechanism, stuck mechanism, broken pull rod, bad insulating medium, or bad trip coils. Local
breaker failure protection, or remote backup protection, is installed to address the various possible
causes of circuit breaker failure. The proposed re-definition of “Protection System” should be revised
to indicate control circuitry associated with protective functions UP TO THE TERMINALS OF the trip
coil(s) of the circuit breakers or other interrupting devices. (b) On the surface, the proposed redefinition of “Protection System” appears mainly applicable to PRC-005 based upon the Standards
Announcement and proposed Implementation Plan. However, NERC standard PRC-004-1 Analysis and
Mitigation of Transmission and Generation Protection System Misoperations also uses the capitalized
term “Protection System”. CenterPoint Energy believes it is inappropriate to require reporting of
Misoperations of transmission Protection Systems and generator Protection Systems for bad trip coils
within a circuit breaker. For application to PRC-004-1, CenterPoint Energy recommends revising the
proposed re-definition to indicate control circuitry associated with protective functions UP TO THE
TERMINALS OF the trip coil(s) of the circuit breakers or other interrupting devices.
Individual
Robert Ganley
LIPA
Yes
Station dc supply associated with protective functions ( including station batteries, battery chargers,
and non-battery-based dc supply), and .... Change to Station dc supply associated with protective
functions, and....
Individual
Andrew Z. Pusztai
American Transmission Company
Yes
None.
Individual
Thad Ness
American Electric Power (AEP)
No
This change in definition needs to occur concurrently with other related projects (PRC-005-2). The
SDT nor the SC should establish a practice of making changes to definitions outside the parameters of
changes to standards. This will introduce opportunities to confuse and does not provide the
appropriate signals to the Registered Entities to adjust their programs and make the appropriate
changes. If this has to be done faster than the pace of the current PRC-005-2 project, we suggest it
still be paired with that project, but a smaller scope be considered to allow for this to pass quickly as
possible and then the remaining work can be accomplished in PRC-005-3. We suggest that the SDT
consider the creation of sub-definitions opposed to crafting a single term for complex and diverse
components that could make up the “Protection System.” As it stands, AEP cannot support this as it
still does not remove the degree of ambiguity that could result in interpretation challenges during
later enforcement and monitoring activities. We understand the urgency to make progress; however,
the deliverables of this team can have significant collateral impacts in the compliance process. The
bullet for Protective relays should be further clarified with the addition of “applied on or designed to
provide protection for the BES that respond to the electrical fault or disturbance conditions.” Below
are the comments that were provided in the second draft that were not adequately addressed in the
consideration of the comments. The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could be construed by an auditor to
include a lot of equipment and infrastructure not intended by the PSMT SDT. For example, station
battery chargers are typically supplied by station auxiliary power transformers, which in turn are
supplied by primary-voltage bus work, primary-voltage fuses, or primary-voltage circuit breakers. An
auditor for either PRC-005 or any other Standard referencing "Protection System" could read that
such primary-voltage equipment is part of the Protection System and therefore subject to certain
requirements in either PRC-005 or any other Standard referencing Protection System. The definition
as drafted includes "Communications systems necessary. . . ". Once again, this term appears
innocuous, but it is actually unclear. For example, if a transfer-trip channel is carried on a microwave
path, an auditor may decide that the entire microwave equipment, microwave building battery, and
microwave building emergency generator are all part of the Protection System, and thus subject to
requirements in either PRC-005 or other existing or future Standards that refer to Protection System.
AEP recommends that the term be phrased "communications paths" opposed to "communications
systems". Similar to the above two items, we are concerned about the inclusion of voltage and
current-sensing "devices" in the Definition. As written, applicability can be inferred to the entire
device and not merely its output quantities, not only for this Standard but any other that references a
Protection System. AEP recommends the phrase "circuitry from voltage and current-sensing devices
providing inputs to protective relays" instead of "voltage and current-sensing devices providing inputs
to protective relays."
Group
Bonneville Power Administration
Denise Koehn
Yes
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
Individual
Kathleen Goodman
ISO New England Inc.
Yes
Individual
Patti Metro
NRECA
My comment is related to the Implementation plan which will modify the PER-005. I am specifically
concerned with changing in R3.1 “established operating guides or “protection systems” to mitigate
IROL violations” to “established operating guides or “Protection Systems” to mitigate IROL violations”.
This modification changes the intent of requirement PER-005 R3.1. The requirement was developed
by the drafting team to address an Order 693 directive to require the use of simulators by reliability
coordinators, transmission operators and balancing authorities that have operational control over a
significant portion of load and generation. The System Personnel Training SDT felt that the use of the
phrase “established IROLs or has established operating guides or protection systems to mitigate IROL
violations” appropriately represents the impact of entities on the reliability of the BES. In the context
of PER-005 R3.1, this specific language was used to broadly include anything that an entity utilizes to
prevent an IROL which could be an “operating guide or a protection system” like a RAS in WECC or an
SPS in the Eastern Interconnection. It was not intended to include all the items included in the term
that is being defined in Project 2007-17.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
Individual
Terry Harbour
MidAmerican Energy
No
The drafting team did not properly address previous comments to include BES references in each
PRC-005 sub bullet definitions and left "DC system" wording in the definition with only a comment in
parentheses. The Protection System definition affects multiple standards and must stand alone across
those standards. Therefore: 1. BES references are still needed in each sub bullet definition to
eliminate ambiguity and to create clearly auditable requirements, meeting a basic standards drafting
principal being requested both by FERC and the industry. 2. "DC system" remains a wide open
definition. Because regulators and auditors are auditing to "zero" defect requirements and imposing
their own interpretations, only specific wording is acceptable. The term "DC system" needs to be
replaced with explicit pieces of equipment such as "batteries, battery chargers, and AC / DC
converters". To be a credible audit process, both the auditor and audited entity must have a clear
understanding of what is being audited. DC system can be interpreted in many ways by an entity or
auditor and is not an acceptable term. Further, BES references are needed to create clear and
auditable boundaries for this definition.
Group
WECC
Steve Rueckert
The definition is generally accepable. However, we believe that better language for the third bullet is
as follows: DC supply sources affecting the "Protection System" (including station batteries, battery
chargers, and non-battery-based dc supply), and… A definition of non-battery-based dc supply should
be included to avoid confusion and we offer the following: The inverter or rectifier in the circuit,
dependent upon how the end use quipment is designed. Uninterruptible power supply (UPS) such as
on-line, line-interactive or standby that some of the protection system could be on. The intent of the
suggestion would consider that the entire protection system has to operate in order to maintain the
reliability of the BES. An example would be if the protective relay and associated communications
were on a UPS system and the intended device to operate were on station batteries, this would be the
best case scenario as the Micro processors relays and the newer associated communications do not
like the voltage drop when the station switches to the station batteries, hence the use of UPS options.
Micro processors relays do have internal battery backup to keep them up and running, though a
maintenance task would have to be included to be sure that they are properly maintained and tested,
so the UPS option is easier and has been “kind of” an industry standard in the past. In the end the
UPS would have to be on a maintenance schedule also.
Individual
Michael Lombardi
Northeast Utilities
Yes
Individual
Dan Rochester
Independent Electricity System Operator
No
While we agree with the definition itself, we do have a concern about its application. An ongoing issue
that needs to be addressed is clarification of when a Bulk Electric System transmission Protection
System applies to a Distribution Provider. This was addressed in part in the interpretation request
regarding transmission Protection Systems, Project 2009-17. An example would be for a tee-tap off a
Bulk Power System 345kV line to a step down transformer supplying distribution -- would the relaying
on the low voltage side of the transformer be expected to comply with the requirements of PRC-0052? Would the protection system configuration be considered a Protection System? Will this issue be
addressed within the scope of Project 2007-17?
Individual
Jason L. Marshall
Midwest ISO
No
We have an issue with the implementation plan. The implementation plan proposes to capitalize the
term "protection system" in NUC-001-2, PER-005-1, and PRC-001-1. We disagree with capatilizing the
term because protection system was a defined term when these standards were written. Thus, if the
drafting teams of those standards intended for the definition in the NERC glossary of terms to apply,
they would have capatilized the term. Furthermore, capitalizing the term may fundamentally alter the
meaning of the standard. For PER-005-1, we believe the standard is altered because protection
system as used in this standard actually refers to special protection system or remedial action
schemes.
Individual
Greg Rowland
Duke Energy
Yes
We agree with the revised definition. However the added language raises a question regarding how
PRC-005-2 would be applied to DC supply situations where the battery is the backup to the “normal”
source of DC power. Specifically, it’s unclear to us that Uninterruptible Power Supplies (UPS),
rectifiers and motor-generator sets that use batteries as a backup are included in the scope of Table
1.
Individual
Alice Murdock Ireland
Xcel Energy
Yes
The Implementation Plan indicates that the lower case “protection system” in 3 other standards would
be replaced with the capitalized term “Protection System” to properly reflect its use in those
standards. In PRC-001 the term “protective system” is also used, however the Implementation Plan
does not indicate whether this term will also be replaced. If not, then it would seem to imply that the
term “protective system” has different meaning than “protection system/Protection System”. There is
concern that the use of “Protection System” in PRC-001 will require entities to ‘coordinate” changes to
all elements of the Protection System, which could be of no value for elements such as batteries,
battery chargers. It is not clear as to if the intent that ALL elements of the Protection System be
coordinated when a new or changed Protection System occurs.
Group
IRC Standards Review Committee
Ben Li
Yes
Group
Kansas City Power & Light
Michael Gammon
No
The phrase, "non-battery-based dc supply" is ambigous and not well defined. It is critical this
definition be clear in its intent and not introduce confusion to allow maintenance programs to be
effective. Recommend this phrase either needs additional definition or should be considered for
removal.
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Dates of Third Ballot: 10/2/10 - 10/14/10
Summary: A successive ballot of the definition of Protection System was conducted from October 2-14, 2010 and achieved a quorum and an
overall weighted segment approval of 84.52%.
Numerous balloters confused the definition with its applicability in various standards. Several balloters questioned the
applicability of this defined term in PER-005 and the SDT modified the Implementation Plan for the definition to remove the
reference to PER-005.
Several balloters used the ballot period as a forum to show displeasure with the NERC and Regional BES definitions. Modifying
the definition of Bulk Electric System is outside the scope of this drafting team.
Some balloters made suggestions to modify various portions of the definition, however most balloters supported the definition
as posted and the drafting team did not adopt any suggestions for further modifications to the definition.
Several balloters opposed this ballot because they felt the definition of Protection System should not have been balloted
separately from the draft standard PRC-005-2. When the Board of Trustees was asked to approve an interpretation of PRC005-1 that was written by the PSMT SDT, the board acknowledged the reliability gap identified by the drafting team caused by
the definition of "protection system" and directed that work to close this reliability gap should be given “priority.” To close this
reliability gap the BOT directed that the revised definition be applied to PRC-005-1 as soon as practical - not years from now.
The implementation plan allows entities at least 12 months to apply the new definition to PRC-005-1, and that should give
entities time to apply the new definition to PRC-005-1.
Segment
Entity
Member
1
American Electric
Power
Paul B. Johnson
5
AEP Service Corp.
Brock Ondayko
October 28, 2010
Ballot
Negative
Comments
1. This change in definition needs to occur concurrently with other
related projects (PRC-005-2). Neither the SDT nor the SC should
establish a practice of making changes to definitions outside the
parameters of changes to standards. This will introduce opportunities
for confusion and does not provide the appropriate signals to the
Registered Entities to adjust their programs and make the appropriate
1
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
6
Entity
AEP Marketing
Member
Edward P. Cox
Ballot
Comments
changes. If this has to be done faster than the pace of the current
PRC-005-2 project, we suggest it still be paired with that project, but a
smaller scope be considered to allow for this to pass quickly as
possible and then the remaining work can be accomplished in PRC005-3.
2. We suggest that the SDT consider the creation of sub-definitions
opposed to crafting a single term for complex and diverse
components that could make up the Protection System. As it stands,
AEP cannot support this as it still does not remove the degree of
ambiguity that could result in interpretation challenges during later
enforcement and monitoring activities. We understand the urgency to
make progress; however, the deliverables of this team can have
significant collateral impacts in the compliance process.
3. The bullet for Protective relays should be further clarified with the
addition of applied on or designed to provide protection for the BES
that responds to the electrical fault or disturbance conditions.
4. Below are the comments that were provided in the second draft that
were not adequately addressed in the consideration of the comments.
A. The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could be
construed by an auditor to include a lot of equipment and
infrastructure not intended by the PSMT SDT. For example, station
battery chargers are typically supplied by station auxiliary power
transformers, which in turn are supplied by primary-voltage bus work,
primary-voltage fuses, or primary-voltage circuit breakers. An auditor
for either PRC-005 or any other Standard referencing "Protection
System" could read that such primary-voltage equipment is part of the
Protection System and therefore subject to certain requirements in
either PRC-005 or any other Standard referencing Protection System.
B. The definition as drafted includes "Communications systems
necessary. . . ". Once again, this term appears innocuous, but it is
October 25, 2010
2
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
Comments
actually unclear. For example, if a transfer-trip channel is carried on a
microwave path, an auditor may decide that the entire microwave
equipment, microwave building battery, and microwave building
emergency generator are all part of the Protection System, and thus
subject to requirements in either PRC-005 or other existing or future
Standards that refer to Protection System. AEP recommends that the
term be phrased "communications paths" opposed to
"communications systems".
C. Similar to the above two items, we are concerned about the
inclusion of voltage and current-sensing "devices" in the Definition. As
written, applicability can be inferred to the entire device and not
merely its output quantities, not only for this Standard but any other
that references a Protection System. AEP recommends the phrase
"circuitry from voltage and current-sensing devices providing inputs to
protective relays" instead of "voltage and current-sensing devices
providing inputs to protective relays."
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this
reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as
practical - not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and
that should give entities time to apply the new definition to PRC-005-1.
2. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
3. The SDT believes these questions are not within the scope of Project 2007-17 and should be addressed by the Regional Entities.
4A. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry. The definition of Protection System
with regards to dc supply has been modified and now reads: Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply).
4B. The SDT believes your comment pertains to standards and requirements, and not the definition of Protection System.
4C. The SDT believes the current draft of the definition as balloted is better supported by industry.
October 25, 2010
3
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
1
Entity
Baltimore Gas &
Electric Company
Member
John J. Moraski
Ballot
Negative
Comments
The definition can be read to imply an obligation to test PTs and CTs in a way
that exceeds the apparent intention of the SDT as expressed in the FAQs. The
definition should be constructed so as to present no conflict with idea that the
standard can be met by verifying the correctness of signal delivered from PTs
and CTs to protective relays. Suggestive language included with the previous
ballot --- Protection System: Protective relays which respond to electrical
quantities, communication systems necessary for correct operation of
protective functions, voltage and current sensing device output circuits and
the associated circuits to the inputs of protective relays, station dc supply, and
control circuitry associated with protective functions through the trip coil(s) of
the circuit breakers or other interrupting devices.
Response: The SDT believes your comment is aimed at revising the definition so that it achieves a particular outcome when applied to specific
requirements in the proposed PRC-005. The team is trying to develop a definition that would be applicable for use in several standards, and does
not want to make modifications to the definition that would limit the term's applicability.
1
Colorado Springs
Utilities
Paul Morland
Negative
CSU feels that battery chargers should not be included in the "Protection
System" definition based on the following: Battery chargers are not a single
point of immediate failure. As long as real-time station battery monitoring is
provided, a reliable protection system will be maintained.
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now. The implementation plan now proposes at least 12 months for entities to apply the
new definition to PRC-005-1, and that should give entities time to apply the new definition to PRC-005-1.
1
FirstEnergy Energy
Delivery
Robert Martinko
3
FirstEnergy
Solutions
Kevin Querry
6
FirstEnergy
Solutions
Mark S
Travaglianti
October 25, 2010
Affirmative FirstEnergy supports the definition and thanks the drafting team for
incorporating our suggestion for clarification of the phrase "station dc supply".
4
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
Comments
4
Ohio Edison
Company
Douglas
Hohlbaugh
Response: The SDT appreciates your support.
1
MidAmerican
Energy Co.
Terry Harbour
Negative
The drafting team did not properly address previous comments to include BES
references in each PRC-005 sub bullet definitions and left "DC system"
wording in the definition with only a comment in parentheses. The Protection
System definition affects multiple standards and must stand alone across
those standards. Therefore:
1. BES references are still needed in each sub bullet definition to eliminate
ambiguity and to create clearly auditable requirements, meeting a basic
standards drafting principal being requested both by FERC and the industry.
2. "DC system" remains a wide open definition. Because regulators and
auditors are auditing to "zero" defect requirements and imposing their own
interpretations, only specific wording is acceptable. The term "DC system"
needs to be replaced with explicit pieces of equipment such as "batteries,
battery chargers, and AC / DC converters". To be a credible audit process,
both the auditor and audited entity must have a clear understanding of what
is being audited. DC system can be interpreted in many ways by an entity or
auditor and is not an acceptable term. Further, BES references are needed to
create clear and auditable boundaries for this definition.
Response: The SDT believes your comment is aimed at revising the definition so that it achieves a particular outcome when applied to specific
requirements in the proposed PRC-005. The team is trying to develop a definition that would be applicable for use in several standards, and does
not want to make modifications to the definition that would limit the term's applicability.
October 25, 2010
5
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
1
Entity
Nebraska Public
Power District
Member
Richard L. Koch
Ballot
Affirmative
Comments
1.
Please provide the reasoning for including the battery chargers.
Where do you draw the line of what is included. For example, should
the panel providing power to the chargers be included?
2. Better clarification is needed when defining the DC control circuit.
The trip coils are identified on one end of the circuit but nothing is
identified upstream of the trip coils. For example, control switches,
indicators, auxiliary relays, power supply breakers, etc.
Response: 1. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” The definition of Protection System with regards to dc supply has been
modified and now reads: Station dc supply associated with protective functions (including station batteries, battery chargers, and non-batterybased dc supply). The SDT believes this clearly limits the dc supply.
2. The SDT believes the balloted definition includes all the control circuitry essential for the Protection System to function properly.
1
Pacific Gas and
Electric Company
October 25, 2010
Chifong L. Thomas
Negative
We disagree with the drafting team response to comments that the term BES
should be included only in the standard. It is an essential part of the definition
as it pertains to the purpose of NERC Standards. As a result we have changed
our vote to negative. We view the basic intent of this definition is to identify
what protective systems in facilities are to be utilized to protect the BES from
two primary troubles 1) minimize interruption of the flow of electrical power
from one portion of the BES to another, and 2) to prevent the propagation of
BES trouble from one portion of the BES to another. While we agree that
protection systems for all transmission related components can be adequately
limited in scope by utilizing "electrical quantities", we do not feel that it is
adequate for generating facilities. There are multitudes of elements in
generating facilities that can remove the facility from service and impact the
power flow from the facility to other portions of the BES. The efforts utilized
thus far demonstrate that it is not desirable or realistically possible to address
all devices from an oversight point of view and that the current definition
which discriminates solely with the qualifier of "electrical quantities" is too
broad and leaves much open to interpretation to define what types of
protection are included in the definition. The definition, as it currently reads,
leaves many protective devices to the owner/operator to manage for
6
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
Comments
maximum reliability of the generating facility. In the interest of clarity the
definition should limit the scope for protective relays to those relays designed
to prevent the propagation of trouble from one portion of the BES to another.
We recommend changing the proposed definition to read as follows: A control
system designed to detect electrical faults or abnormal conditions in the
power system and initiate corrective action(s). A protection system consists of
the following components: 1. Protective relays which protect: a) Transmission
BES elements, including generating facility step up transformers, and respond
to power system electrical quantities such as voltage and current, b)
Generating facilities by responding to power system electrical quantities, such
as voltage and current, and are designed to protect against potential
problems in the BES on the high side of the generator step up transformer. 2.
Communications systems necessary for correct operation of protective
functions, 3. Voltage and current sensing devices which transform high level
power system quantities to low level inputs for protective relays, and the
associated circuitry to the inputs for protective relays. 4. Station DC supply
associated with protective relay power supplies and control functions
(including station batteries, battery chargers, and non-battery-based DC
supply), and 5. Control circuitry associated with protective relay functions
(including auxiliary relays) through the trip coil(s) of the circuit breakers or
other interrupting devices.
Response: The SDT believes your comment is aimed at revising the definition so that it achieves a particular outcome when applied to specific
requirements in the proposed PRC-005. The team is trying to develop a definition that would be applicable for use in several standards, and does
not want to make modifications to the definition that would limit the term's applicability. The applicability of the definition of Protection System will
be addressed in the various standards which utilize the definition. The SDT believes the current draft of the definition as balloted is better supported
by industry.
1
Seattle City Light
Pawel Krupa
3
Dana Wheelock
4
Hao Li
5
Michael J. Haynes
October 25, 2010
Affirmative Seattle supports this definition with the understanding that issues that have
been previously addressed through comment will be considered during the
Standard development process.
7
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
6
Member
Ballot
Comments
Dennis Sismaet
Response: The SDT appreciates your support.
1
Tri-State G & T
Association, Inc.
3
Keith V. Carman
Janelle Marriott
Negative
2nd bullet - Add communication-aided before protective functions. We think
that this is important because you can have correct operation of protective
functions without the communication-aided tripping functions operating
correctly, especially with POTT or DCUB schemes.
5th bullet - replace through with including. We think that the phrase through
the trip coil could be misinterpreted to mean protective functions that cause
current to flow through the trip coil rather than the inclusive meaning such as
from A through Z. If the intent of the drafting team is to exclude the trip coil,
then we think it should be changed to control circuitry associated with
protective functions required to operate the trip coil(s) of the circuit breakers
or other interrupting devices.
Response: The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
October 25, 2010
8
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
1
Western Area
Power
Administration
Brandy A Dunn
Negative
5
U.S. Bureau of
Reclamation
Martin Bauer P.E.
Negative
October 25, 2010
Comments
The term "protection functions" is ambiguous as it is not related to the
protection function associated with the protective relays. There are other
protection functions not associated with protective relays that respond to
electrical quantities.
The language for Communication systems should be changed to remove the
ambiguity. The following change would be clear, "Communication system
necessary for the correct operation of the protective relays" The input to the
relays is from voltage and current sensing devices through their respective
circuits. Since the definition for protective relays separates the term "control
circuitry" associated with protective relays, it is clear that protective relays do
not also include the "control circuitry". By the same token, voltage and
current sensing devices do not include their related circuits. The definition for
voltage and current sensing devices should be revised to include the term
"circuits". The following language change would serve make it clear: "Voltage
and current sensing devices and their respective circuits providing inputs
protective relays,".
The term "protection functions" is ambiguous as it is not related to the
protection function associated with the protective relays. There are other
protection functions not associated with protective relays that respond to
electrical quantities.
The language for Communication systems should be changed to remove the
ambiguity. The following change would be clear, "Communication system
necessary for the correct operation of the protective relays" The input to the
relays is from voltage and current sensing devices through their respective
circuits. Since the definition for protective relays separates the term "control
circuitry" associated with protective relays, it is clear that protective relays do
not also include the "control circuitry". By the same token, voltage and
current sensing devices do not include their related circuits. The definition for
voltage and current sensing devices should be revised to include the term
"circuits". The following language change would serve make it clear: "Voltage
and current sensing devices and their respective circuits providing correct
inputs to protective relays."
9
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
Entity
Member
Ballot
Comments
Response: The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
2
Midwest ISO, Inc.
Jason L Marshall
Negative
We disagree with the implementation plan. The implementation plan calls for
capitalizing protection system in NUC-001-2 and PER-005-1. Because
Protection System had been included in the NERC Glossary of Terms before
the development of these standards, we believe the drafting teams would
have capitalized those terms in these standards if they had intended for the
Protection System definition to apply. Furthermore, we believe the use of
protection system PER-005-1 was actually intended to be special protection
systems or remedial actions schemes. To capitalize protection system in PER005-1 will fundamentally alter the requirement in which it is contained.
Response: The SDT agrees and will revise the Implementation Plan to remove PER-005 from the list of standards to be modified. However, the SDT
believes the term Protection System should be capitalized as described in the Implementation Plan for NUC-001-2.
3
Consumers Energy
David A. Lapinski
4
David Frank Ronk
5
James B Lewis
Negative
We understand that this posting is intended to address perceived flaws in the
currently approved definition. However, since this change, if approved, is
likely to result in changes to an entity's PRC-005-1 maintenance program, we
feel that it is inappropriate to approve this definition without simultaneous
approval of the revised PRC-005-2 which will clarify the related changes to
maintenance programs.
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now. The implementation plan now proposes at least 12 months for entities to apply the
new definition to PRC-005-1, and that should give entities time to apply the new definition to PRC-005-1.
3
MidAmerican
Energy Co.
Thomas C. Mielnik
Negative
BES references are needed in each sub bullet definition to eliminate ambiguity
and to create clearly auditable requirements. The term "DC system" needs to
be replaced with explicit pieces of equipment such as "batteries, battery
chargers, and AC / DC converters".
Response: The SDT believes these comments relative to BES are not within the scope of Project 2007-17 and should be addressed by the Regional
Entities; and that the current draft of the definition as balloted is clear, concise, and contains the specific dc systems equipment you mention.
October 25, 2010
10
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
3
Entity
San Diego Gas &
Electric
Member
Scott Peterson
Ballot
Comments
Affirmative SDG&E believes that the following changes should be incorporated. Third
item: DC supply sources affecting the "Protection System" (including station
batteries, battery chargers, and non-battery-based dc supply), and SDG&E also
believe that a definition of non-battery-based dc supply should be included to
avoid confusion and recommend the following: "The inverter or rectifier in the
circuit, dependent upon how the end use equipment is designed.
Uninterruptible power supply (UPS) such as on-line, line-interactive or standby
that some of the protection system could be on."
Response: The SDT appreciates your support, and believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
3
Wisconsin Electric
Power Marketing
James R. Keller
4
Wisconsin Energy
Corp.
Anthony
Jankowski
5
Wisconsin Electric
Power Co.
Linda Horn
Negative
1. The Protection System definition needs to indicate that the listed
items after relays are intended to be associated with relays. As
written, most of the items apply to undefined "protective functions".
The Implementation Plan's change to PER-005-1 R3.1 restricts where
R3.1 applies. For example, changing "protection systems" to
"Protection Systems" will exclude an SPS that does not operate relays.
Replace term "voltage & current sensing devices" with "voltage &
current sensing inputs to protective relays".
2. Remove the battery chargers from the definition and make reference
to station batteries only. There needs to be improved coordination
between proposed changes and definitions and the associated
proposed changes and testing.
Response: 1. The drafting team does not believe that the additional language is needed in the definition. The SDT agrees with the comment on
PER-005 and will revise the Implementation Plan to remove PER-005 from the list of standards to be modified.
2. When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board acknowledged
the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and directed that
work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC005-1 as soon as practical. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
October 25, 2010
11
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
4
Entity
Madison Gas and
Electric Co.
Member
Joseph G.
DePoorter
Ballot
Comments
Affirmative Believe that Communication systems necessary for correct operation of
protective "relay" functions be considered as an enhancement to the
definition. This would also need to be added within the Station dc supply and
Control circuitry bullets. This will provide clarity to exactly what the definition
is describing.
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry.
5
Constellation
Power Source
Generation, Inc.
October 25, 2010
Amir Y Hammad
Negative
Constellation has previously voted against these revised definitions because
as written, it implies that the testing of PTs and CTs in PRC-005 is required.
This latest proposal is no different. Constellation agrees with the SDT in that
current and voltage sensing devices are an important aspect of the Protection
System. However, by including PTs and CTs in the definition, auditors have
been interpreting that as stating that dielectric testing and other tests are
necessary on them. This does not seem to be the intention of the SDT. The
intention of the SDT seems to be to verify that the sensing devices are
delivering acceptable signals to relays. Table 1 a of the PRC-005-2 standard
includes: Voltage & Current Sensing Devices / 12 Calendar Years / Verify
proper functioning of the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays. The FAQ for PRC-005-2 is
even clearer in stating that ensuring the protection system is receiving the
expected values from current and voltage sensing devices. But neither the
originally revised or newly revised definitions carry that implication very well.
The definitions are still including the devices themselves and not their
outputs. To make the definition less ambiguous with PTs and CTs,
Constellation proposes the following change in the definition: Voltage and
current sensing devices providing inputs to protective relays to; Voltage and
current sensing device output circuits and the associated circuits to the inputs
of protective relays.
12
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
6
Entity
Member
Ballot
Constellation
Energy
Commodities
Group
Brenda Powell
Negative
Comments
Constellation has previously voted against these revised definitions because
as written, it implies that the testing of PTs and CTs in PRC-005 is required.
This latest proposal is no different. Constellation agrees with the SDT in that
current and voltage sensing devices are an important aspect of the Protection
System. However, by including PTs and CTs in the definition, auditors have
been interpreting that as stating that dielectric testing and other tests are
necessary on them. This does not seem to be the intention of the SDT. The
intention of the SDT seems to be to verify that the sensing devices are
delivering acceptable signals to relays. Table 1 a of the PRC-005-2 standard
includes: Voltage & Current Sensing Devices / 12 Calendar Years / Verify
proper functioning of the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays. The FAQ for PRC-005-2 is
even clearer in stating that ensuring the protection system is receiving the
expected values from current and voltage sensing devices. The definitions are
still including the devices themselves and not their outputs. To make the
definition less ambiguous with PTs and CTs, Constellation proposes the
following change in the definition: Voltage and current sensing devices
providing inputs to protective relays to; Voltage and current sensing device
output circuits and the associated circuits to the inputs of protective relays.
Response: The SDT believes your comment is aimed at revising the definition so that it achieves a particular outcome when applied to specific
requirements in the proposed PRC-005. The team is trying to develop a definition that would be applicable for use in several standards, and does
not want to make modifications to the definition that would limit the term's applicability.
5
Dynegy Inc.
Dan Roethemeyer
Affirmative Please clarify "non-battery-based dc supply". It is vague.
Response: The SDT appreciates your support, and believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
October 25, 2010
13
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
5
Entity
Indeck Energy
Services, Inc.
Member
Rex A Roehl
Ballot
Negative
Comments
Neither batteries nor battery chargers are part of protection systems. They
may be included in protection system maintenance procedures, but are not
part of a protection system. Similarly, current and voltage measuring devices
that are used for metering or monitoring and not exclusively for protection,
are not part of the protection system, but may be included in protection
system maintenance. THE SDT seems to have tried to incorporate some of the
PRC standards with this definition rather than focusing on the one element
being defined.
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now.
5
Liberty Electric
Power LLC
Daniel Duff
Negative
Battery chargers are not protection system elements. This part of the
definition should be redacted.
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now.
5
Public Utility
District No. 1 of
Lewis County
Steven Grega
Negative
Do not support the expanded definition of the protection system. Battery
chargers are not part of the protection system.
Response: : When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now.
October 25, 2010
14
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
5
Entity
RRI Energy
Member
Thomas J. Bradish
Ballot
Negative
Trent Carlson
6
Comments
It is not appropriate to define the battery or chargers as protection system
elements. For DC circuits or supply, the definition and subsequent boundary
of the protection system should end at the fuses or circuit breakers of the
sources supplying the individual DC control circuits of the protection system.
For a typical power plant station battery, the percent of the battery capacity
sized for the protection system is very small. The battery and chargers are
power source elements, not protection elements. Likewise, all intermediate
power distribution elements between the battery, chargers, and dedicated
protection system branch circuits, do not belong in the definition of the
Protection System.
Response: : When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" not including battery chargers, and
directed that work to close this reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be
applied to PRC-005-1 as soon as practical - not years from now.
5
TransAlta Centralia
Generation, LLC
Joanna LuongTran
Negative
To increase the clarity of the definition, TransAlta proposes the following:
Control circuitry associated with protective functions through to and including
the trip coil(s) of the circuit breakers or other interrupting devices
Response: The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
October 25, 2010
15
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
8
Entity
SPS Consulting
Group Inc.
Member
Ballot
Jim R Stanton
Negative
Comments
The term "Communication System" remains in the definition, despite the
reality that at least for most generators, there is no communication system
within the Protection System. Communication from device to device, such as a
protective relay to a trip coil or alarm, it not a "system" per se but merely a
wire connecting the devices. Keeping this definition as is perpetuates the
confusion of generators when they design, modify and execute their
protection system maintenance and testing program as the definition of the
Protection System requires addressing a "communication system" which they
do not have. Keeping the definition as is could lead to confused auditors who
insist on literal adherence to the requirement language, clouding the audit
and imposing ad hoc and perhaps inconsistent interpretations for audits, spot
checks and self reports. What will most surely happen if this definition is
approved is a quick request for interpretation by one or more entities seeking
clarification on the requirement to include "communication systems" within
their maintenance and testing program when they in fact have no such
system. All this can be avoided by changing the term "communication
systems" to "communication components." This is a primary example of fixing
something on the front end so we don't have to go through interpretations
and revisions to fix an ambiguity. This definition would also not pass a Quality
Review due to the ambiguity of terms.
Response: The SDT believes the language is clear and addresses relay communication systems currently used by industry.
8
Utility Services,
Inc.
Brian EvansMongeon
Negative
While the language by itself is supportable, the definition is not complete. The
SDT has still not addressed the question of when the definition will apply to
Distribution Providers. Many DPs own and or operate the elements listed in
the definition; however, the definition lacks clarity when such ownership or
operation is subject to the performance obligations under the standard.
Response: This clarification is provided in each requirement that uses the term, “Protection System” by identifying the responsible entity. The
comment relates to "application" of the definition, not to the definition.
October 25, 2010
16
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
9
Entity
California Energy
Commission
Member
William Mitchell
Chamberlain
Ballot
Comments
Affirmative The proposed definition is generally acceptable. However, a slight
modification to the third bullet in the definition would be an improvement to
the proposed wording: "DC supply sources affecting the 'Protection System'
(including station batteries, battery chargers, and non-battery-based dc
supply), and " In addition, a definition of non-battery-based dc supply should
be included to avoid confusion we recommend the following: "The inverter or
rectifier in the circuit, dependent upon how the end use equipment is
designed. Uninterruptible power supply (UPS) such as on-line, line-interactive
or standby that some of the protection system could be on."
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
9
Oregon Public
Utility Commission
Jerome Murray
Affirmative Although I voted yes, I recommend the following proposed wording for the
third bullet: DC supply sources affecting the "Protection System" (including
station batteries, battery chargers, and non-battery-based dc supply), and
Also the definition of non-battery-based dc supply should be included to avoid
confusion. I recommend the following: The inverter or rectifier in the circuit,
dependent upon how the end use equipment is designed. Uninterruptible
power supply (UPS) such as on-line, line-interactive or standby that some of
the protection system could be on.
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
10
Midwest Reliability
Organization
Dan R.
Schoenecker
Affirmative Suggest the second bullet language replace the term correct with the
intended. Communications systems necessary for the intended operation of
protective functions.
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry.
October 25, 2010
17
Consideration of Comments on Third Ballot — Project 2007-17 Protection System Maintenance (Protection System definition)
Segment
10
Entity
Western Electricity
Coordinating
Council
Member
Louise McCarren
Ballot
Comments
Affirmative The definition is generally acceptable. However, we believe that better
language for the third bullet is as follows: DC supply sources affecting the
"Protection System" (including station batteries, battery chargers, and nonbattery-based dc supply), and A definition of non-battery-based dc supply
should be included to avoid confusion and we offer the following: The inverter
or rectifier in the circuit, dependent upon how the end use equipment is
designed. Uninterruptible power supply (UPS) such as on-line, line-interactive
or standby that some of the protection system could be on. The intent of the
suggestion would consider that the entire protection system has to operate in
order to maintain the reliability of the BES. An example would be if the
protective relay and associated communications were on a UPS system and
the intended device to operate were on station batteries, this would be the
best case scenario as the Micro processors relays and the newer associated
communications do not like the voltage drop when the station switches to the
station batteries, hence the use of UPS options. Micro processors relays do
have internal battery backup to keep them up and running, though a
maintenance task would have to be included to be sure that they are properly
maintained and tested, so the UPS option is easier and has been kind of an
industry standard in the past. In the end the UPS would have to be on a
maintenance schedule also.
Response: The SDT appreciates your support. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by
industry. The term “non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel
cells, or any other emerging technology which is capable of supplying dc power to the Protection System.
October 25, 2010
18
Consideration of Comments on Protection System Maintenance & Testing —
Project 2007-17 – Definition of Protection System
The Protection System Maintenance & Testing Standard Drafting Team thanks all
commenters who submitted comments for the revised definition of “Protection System.”
The revised definition was posted for a 30-day public comment period from September 13,
2010 through October 12, 2010. Stakeholders were asked to provide feedback on the
definition through a special Electronic Comment Form. There were 27 sets of comments,
including comments from more than 62 different people from approximately 53 companies
representing 7 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
While several commenters made suggestions to further refine the definition of Protection
System, the team did not make any additional changes to the definition based on
stakeholder comments. The team did, however remove the proposed modification to PER005 from the implementation plan. No other changes were made.
•
Some commenters made suggestions for modifications to various portions of the
proposed definition of Protection System. There was no commonality to the
proposed revisions and these modifications did not seem to provide greater clarity
than was provided with the last version of the proposed definition posted for
comment and ballot. Since most stakeholders agreed with the latest version of the
proposed definition, no changes were made to the definition.
•
Several commenters questioned the applicability of the defined term “Protection
System” in PER-005; the SDT agreed and modified the Implementation Plan for the
definition of Protection System to remove the reference to PER-005.
•
Several commenters also used the comment period as a forum to show displeasure
with the NERC and regional BES definitions. Making modifications to the definition of
BES is outside the scope of work assigned to this drafting team.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is
a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Protection System Maintenance & Testing Definition of
Protection System — Project 2007-17
Index to Questions, Comments, and Responses
1.
Do you agree with the proposed definition of “Protection System?” If not, please
provide specific suggestions for improvement.…. ................................................. 8
October 28, 2010
2
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Mallory Huggins
Phil Tatro
NERC NA - Not Applicable NA
2.
Bob Cummings
NERC NA - Not Applicable NA
Additional Member Additional Organization Region
Phil Tatro
NERC NA - Not Applicable NA
2.
Bob Cummings
NERC NA - Not Applicable NA
Additional
Member
Additional
Organization
6
7
8
9
10
X
Northeast Power Coordinating Council
Region
Segment
Selection
1.
Alan Adamson
New York State Reliability Council,
LLC
NPCC
10
2.
Gregory Campoli
New York Independent System
Operator
NPCC
2
October 28, 2010
5
Segment
Selection
1.
Guy Zito
4
Segment
Selection
1.
Group
3
NERC Staff
Additional Member Additional Organization Region
2.
2
3
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
Kurtis Chong
Independent Electricity System
Operator
NPCC
2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5.
Chris de Graffenried
Consolidated Edison Co. of New York,
NPCC
Inc.
1
6.
Gerry Dunbar
Northeast Power Coordinating Council NPCC
10
7.
Dean Ellis
Dynegy Generation
NPCC
5
8.
Brian Evans-Mongeon
Utility Services
NPCC
8
9.
Mike Garton
Dominion Resources Services, Inc.
NPCC
5
10.
Brian L. Gooder
Ontario Power Generation
Incorporated
NPCC
5
11.
Kathleen Goodman
ISO - New England
NPCC
2
12.
Chantel Haswell
FPL Group, Inc.
NPCC
5
13.
David Kiguel
Hydro One Networks Inc.
NPCC
1
14.
Michael R. Lombardi
Northeast Utilities
NPCC
1
15.
Randy MacDonald
New Brunswick System Operator
NPCC
2
16.
Bruce Metruck
New York Power Authority
NPCC
6
17.
Lee Pedowicz
Northeast Power Coordinating Council NPCC
10
18.
Robert Pellegrini
The United Illuminating Company
NPCC
1
19.
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
20.
Saurabh Saksena
National Grid
NPCC
1
21.
Michael Schiavone
National Grid
NPCC
1
Peter Yost
Consolidated Edison Co. of New York,
NPCC
Inc.
3
22.
3.
Group
Denise Koehn
Additional
Member
1.
Additional
Organization
Dean Bender
October 28, 2010
X
Bonneville Power Administration
Region
BPA, Transmission SPC Technical
Svcs
2
3
X
4
5
X
6
7
8
9
X
Segment
Selection
WECC
1
4
10
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4.
Group
Steve Rueckert
2
3
4
5
6
7
8
9
X
WECC
Additional Member Additional Organization Region Segment Selection
1. Mary Rieger
WECC
WECC 10
2. John McGee
WECC
WECC 10
5.
Ben Li
Group
x
IRC Standards Review Committee
Additional Member Additional Organization Region Segment Selection
1. Matt Goldberg
ISO-NE
NPCC
2
2. Charles Yeung
SPP
SPP
2
3. Bill Phillips
MISO
MRO
2
4. Greg Van Pelt
CAISO
WECC 2
5. Patrick Brown
PJM
RFC
6. Steve Myers
ERCOT
ERCOT 2
7. Mark Thompson
AESO
WECC 2
8. James Castle
NYISO
NPCC
6.
Michael Gammon
Group
2
2
Kansas City Power & Light
x
x
x
x
x
x
x
x
Additional Member Additional Organization Region Segment Selection
1. Todd Moore
KCPL
SPP
1, 3, 5, 6
7.
Individual
Jana Van Ness
Arizona Public Service Company
8.
Individual
James Stanton
SPS Consulting Group Inc.
9.
Individual
Martin Bauer
US Bureau of Reclamation
10.
Individual
Karl Bryan
US Army Corps of Engineers
October 28, 2010
10
X
X
X
X
5
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
X
3
X
4
5
X
6
8
9
X
11.
Individual
Kirit S. Shah
Ameren
12.
Individual
Greg Froehling
Green Country Energy
X
13.
Individual
Dan Roethemeyer
Dynegy Inc.
X
14.
Individual
Paul Rocha
CenterPoint Energy
X
15.
Individual
Robert Ganley
LIPA
X
16.
Individual
Andrew Z. Pusztai
American Transmission Company
X
17.
Individual
Thad Ness
American Electric Power (AEP)
X
X
X
X
18.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
19.
Individual
Kathleen Goodman
ISO New England Inc.
20.
Individual
Patti Metro
NRECA
X
X
21.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
22.
Individual
Terry Harbour
MidAmerican Energy
X
23.
Individual
Michael Lombardi
Northeast Utilities
X
X
X
24.
Individual
Dan Rochester
Independent Electricity System Operator
X
25.
Individual
Jason L. Marshall
Midwest ISO
X
October 28, 2010
7
X
6
10
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
26.
Individual
Greg Rowland
Duke Energy
27.
Individual
Alice Murdock
Ireland
Xcel Energy
October 28, 2010
2
3
4
5
6
X
X
X
X
X
X
X
X
7
8
9
7
10
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
1. Do you agree with the proposed definition of “Protection System?” If not, please provide specific suggestions for
improvement.
Summary Consideration: Numerous commenters confused the definition with its applicability in various standards. Other
commenters made suggestions to modify various portions of the definition. No changes were made to the definition in response
to these comments. Several commenters questioned the applicability of the defined term “Protection System” in PER-005; the
SDT agreed and modified the Implementation Plan for the definition of Protection System to remove the reference to PER-005.
Several commenters also used the comment period as a forum to show displeasure with the NERC and regional BES definitions.
Making changes to the definition of Bulk Electric System is outside the scope of work assigned to this drafting team.
Organization
Yes or No
NERC Staff
No
Question 1 Comment
NERC staff does not support the phrase “voltage and current sensing devices providing input to protective
relays.” While no version of the definition has been all-inclusive with respect to this phrase, we believe that the
best phrase would be a combination of several drafts and should state the following: “voltage and current
sensing devices and associated circuitry from the voltage and current sensing devices to the protective relay
inputs.” As currently written, the definition represents a step backward from the language in the previous
definition (“voltage and current sensing inputs to protective relays and associated circuitry from the voltage and
current sensing devices”) and should be modified.
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is better supported by industry.
Northeast Power Coordinating
Council
No
This project addresses the definition of a Protection System. However, an ongoing issue that needs to be
addressed is clarification of when a Bulk Electric System transmission Protection System applies to a
Distribution Provider. An example would be for a tee-tap off a Bulk Power System 345kV line to a step down
transformer supplying distribution--would the relaying on the low side of the transformer be expected to comply
with the requirements of PRC-005-2? Would the protection system configuration be considered a Protection
System? Will this issue be addressed within the scope of Project 2007-17?
Response: Thank you for your comment. The SDT believes these questions are not within the scope of Project 2007-17 and should be addressed by
the Regional Entities.
WECC
The definition is generally acceptable. However, we believe that better language for the third bullet is as
follows: DC supply sources affecting the "Protection System" (including station batteries, battery chargers, and
non-battery-based dc supply), and...A definition of non-battery-based dc supply should be included to avoid
confusion and we offer the following: The inverter or rectifier in the circuit, dependent upon how the end use
quipment is designed. Uninterruptible power supply (UPS) such as on-line, line-interactive or standby that some
of the protection system could be on. The intent of the suggestion would consider that the entire protection
system has to operate in order to maintain the reliability of the BES. An example would be if the protective relay
October 28, 2010
8
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
and associated communications were on a UPS system and the intended device to operate were on station
batteries, this would be the best case scenario as the Micro processors relays and the newer associated
communications do not like the voltage drop when the station switches to the station batteries, hence the use of
UPS options. Micro processors relays do have internal battery backup to keep them up and running, though a
maintenance task would have to be included to be sure that they are properly maintained and tested, so the
UPS option is easier and has been “kind of” an industry standard in the past. In the end the UPS would have to
be on a maintenance schedule also.
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is better supported by industry. The term
“non-battery-based dc supply” is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel cells, or any other
emerging technology which is capable of supplying dc power to the Protection System.
Kansas City Power & Light
No
The phrase, "non-battery-based dc supply" is ambiguous and not well defined. It is critical this definition be
clear in its intent and not introduce confusion to allow maintenance programs to be effective. Recommend this
phrase either needs additional definition or should be considered for removal.
Response: Thank you for your comment. The SDT believes the language is clear and supported by industry. The term “non-battery-based dc supply”
is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel cells, or any other emerging technology which is
capable of supplying dc power to the Protection System.
SPS Consulting Group Inc.
No
The revised definition perpetuates the confusion over "communications systems" embedded or otherwise
associated with Protection Systems. The term "communications components" is more accurate.
Response: Thank you for your comment. The SDT believes the language is clear and addresses relay communication systems currently used by
industry.
US Bureau of Reclamation
No
The term "protection functions" is ambiguous as it is not related to the protection function associated with the
protective relays. There are other protection functions not associated with protective relays that respond to
electrical quantities. The language for Communication systems should be changed to remove the ambiguity.
The following change would be clear, "Communication system necessary for the correct operation of the
protective relays" The input to the relays is from voltage and current sensing devices through their respective
circuits. Since the definition for protective relays separates the term "control circuitry" associated with
protective relays, it is clear that protective relays do not also include the "control circuitry". By the same token,
voltage and current sensing devices do not include their related circuits. The definition for voltage and current
sensing devices should be revised to include the term "circuits". The following language change would serve
make it clear: "Voltage and current sensing devices and their respective circuits providing inputs protective
relays".
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
US Army Corps of Engineers
October 28, 2010
No
The use of the term "protection functions" is not a defined NERC term and either the term should be defined or
it should not be used. At best the term is ambiguous and could lead to scope growth by auditors. Recommend
9
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
that the following changes be made: "Communication system necessary for the correct operation of the
protective relays." "Control circuitry associated with protective relays through the trip coil(s) of the circuit
breaker or other interrupting device." See the next paragraph for the proposed correction to the DC Supply part
of the definition. The input to the relay is from voltage and current sensing devices yet there is no mention of
the associated circuits. The same can be said about the station DC supply circuits. The definition should apply
to the circuits providing inputs or control power to the protective relays and from the output of the relays to the
tripping coils of the circuit breaker. Recommend the following: "Voltage and current sensing devices and their
respective circuits providing inputs to the protective relays." "Station DC supply associated with protective
relays (including station batteries, battery charger, non-battery-based DC supply circuitry to the protective
relays and from the relay to the trip coil(s)of the circuit breaker), and"
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
Dynegy Inc.
No
The majority of the definition is good; however, the term "non-battery-based dc supply' is still somewhat vague.
Can you please further define or provide some examples?
Response: Thank you for your comment. The SDT believes the language is clear and supported by industry. The term “non-battery-based dc supply”
is meant to be a broad term to capture other methods such as flywheels, compressed air, fuel cells, or any other emerging technology which is
capable of supplying dc power to the Protection System.
CenterPoint Energy
No
(a) CenterPoint Energy believes the proposed re-definition of “Protection System” is technically incorrect due
to the inclusion of trip coils as part of the control circuitry. A protection system has correctly performed its
function if it provides tripping voltage up to the terminals of trip coils. From that point, the circuit breaker can fail
to timely interrupt fault current due to several factors, such as a binding mechanism, stuck mechanism, broken
pull rod, bad insulating medium, or bad trip coils. Local breaker failure protection, or remote backup protection,
is installed to address the various possible causes of circuit breaker failure. The proposed re-definition of
“Protection System” should be revised to indicate control circuitry associated with protective functions UP TO
THE TERMINALS OF the trip coil(s) of the circuit breakers or other interrupting devices.
(b) On the surface, the proposed re-definition of “Protection System” appears mainly applicable to PRC-005
based upon the Standards Announcement and proposed Implementation Plan. However, NERC standard
PRC-004-1 Analysis and Mitigation of Transmission and Generation Protection System Misoperations also
uses the capitalized term “Protection System”. CenterPoint Energy believes it is inappropriate to require
reporting of Misoperations of transmission Protection Systems and generator Protection Systems for bad trip
coils within a circuit breaker. For application to PRC-004-1, CenterPoint Energy recommends revising the
proposed re-definition to indicate control circuitry associated with protective functions UP TO THE TERMINALS
OF the trip coil(s) of the circuit breakers or other interrupting devices.
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is better supported by industry.
Midwest ISO
October 28, 2010
No
We have an issue with the implementation plan. The implementation plan proposes to capitalize the term
10
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
"protection system" in NUC-001-2, PER-005-1, and PRC-001-1. We disagree with capitalizing the term
because protection system was a defined term when these standards were written. Thus, if the drafting teams
of those standards intended for the definition in the NERC glossary of terms to apply, they would have
capitalized the term. Furthermore, capitalizing the term may fundamentally alter the meaning of the standard.
For PER-005-1, we believe the standard is altered because protection system as used in this standard actually
refers to special protection system or remedial action schemes.
Response: Thank you for your comment. The SDT agrees and will revise the Implementation Plan to remove PER-005 from the list of standards to be
modified. However, the SDT believes the term Protection System should be capitalized as described in the Implementation Plan for NUC-001-2 and
PRC-001-1.
American Electric Power (AEP)
October 28, 2010
No
1.
This change in definition needs to occur concurrently with other related projects (PRC-005-2). Neither
the SDT nor the SC should establish a practice of making changes to definitions outside the parameters of
changes to standards. This will introduce opportunities for confusion and does not provide the appropriate
signals to the Registered Entities to adjust their programs and make the appropriate changes. If this has to be
done faster than the pace of the current PRC-005-2 project, we suggest it still be paired with that project, but a
smaller scope be considered to allow for this to pass quickly as possible and then the remaining work can be
accomplished in PRC-005-3.
2.
We suggest that the SDT consider the creation of sub-definitions opposed to crafting a single term for
complex and diverse components that could make up the Protection System. As it stands, AEP cannot support
this as it still does not remove the degree of ambiguity that could result in interpretation challenges during later
enforcement and monitoring activities. We understand the urgency to make progress; however, the deliverables
of this team can have significant collateral impacts in the compliance process.
3.
The bullet for Protective relays should be further clarified with the addition of applied on or designed to
provide protection for the BES that responds to the electrical fault or disturbance conditions.
4.
Below are the comments that were provided in the second draft that were not adequately addressed in
the consideration of the comments. A. The definition as drafted includes "Station dc supply." While this
appears reasonable and innocuous, the term is unclear and could be construed by an auditor to include a lot of
equipment and infrastructure not intended by the PSMT SDT. For example, station battery chargers are
typically supplied by station auxiliary power transformers, which in turn are supplied by primary-voltage bus
work, primary-voltage fuses, or primary-voltage circuit breakers. An auditor for either PRC-005 or any other
Standard referencing "Protection System" could read that such primary-voltage equipment is part of the
Protection System and therefore subject to certain requirements in either PRC-005 or any other Standard
referencing Protection System. B. The definition as drafted includes "Communications systems necessary. . . ".
Once again, this term appears innocuous, but it is actually unclear. For example, if a transfer-trip channel is
carried on a microwave path, an auditor may decide that the entire microwave equipment, microwave building
battery, and microwave building emergency generator are all part of the Protection System, and thus subject to
requirements in either PRC-005 or other existing or future Standards that refer to Protection System. AEP
11
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
recommends that the term be phrased "communications paths" opposed to "communications systems".
C. Similar to the above two items, we are concerned about the inclusion of voltage and current-sensing
"devices" in the Definition. As written, applicability can be inferred to the entire device and not merely its output
quantities, not only for this Standard but any other that references a Protection System. AEP recommends the
phrase "circuitry from voltage and current-sensing devices providing inputs to protective relays" instead of
"voltage and current-sensing devices providing inputs to protective relays."
Response: When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the PSMT SDT, the board
acknowledged the reliability gap identified by the drafting team caused by the definition of "protection system" and directed that work to close this
reliability gap should be given “priority.” To close this reliability gap the BOT has directed that revised definition be applied to PRC-005-1 as soon as
practical - not years from now. The implementation plan now proposes at least 12 months for entities to apply the new definition to PRC-005-1, and that
should give entities time to apply the new definition to PRC-005-1.
2. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry.
3. The SDT believes these questions are not within the scope of Project 2007-17 and should be addressed by the Regional Entities.
4A. The SDT believes the current draft of the definition as balloted is clear, concise, and supported by industry. The definition of Protection System with
regards to dc supply has been modified and now reads: Station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply).
4B. The SDT believes your comment pertains to standards and requirements, and not the definition of Protection System.
4C. The SDT believes the current draft of the definition as balloted is better supported by industry.
Independent Electricity System
Operator
No
While we agree with the definition itself, we do have a concern about its application. An ongoing issue that
needs to be addressed is clarification of when a Bulk Electric System transmission Protection System applies to
a Distribution Provider. This was addressed in part in the interpretation request regarding transmission
Protection Systems, Project 2009-17. An example would be for a tee-tap off a Bulk Power System 345kV line to
a step down transformer supplying distribution -- would the relaying on the low voltage side of the transformer
be expected to comply with the requirements of PRC-005-2? Would the protection system configuration be
considered a Protection System? Will this issue be addressed within the scope of Project 2007-17?
Response: Thank you for your comment. This clarification is provided in each requirement that uses the term, “Protection System” by identifying the
responsible entity. The question relates to "application" of the definition, not to the definition."
NRECA
My comment is related to the Implementation plan which will modify the PER-005. I am specifically concerned
with changing in R3.1 “established operating guides or “protection systems” to mitigate IROL violations” to
“established operating guides or “Protection Systems” to mitigate IROL violations”. This modification changes
the intent of requirement PER-005 R3.1. The requirement was developed by the drafting team to address an
Order 693 directive to require the use of simulators by reliability coordinators, transmission operators and
balancing authorities that have operational control over a significant portion of load and generation. The System
Personnel Training SDT felt that the use of the phrase “established IROLs or has established operating guides
October 28, 2010
12
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
or protection systems to mitigate IROL violations” appropriately represents the impact of entities on the
reliability of the BES. In the context of PER-005 R3.1, this specific language was used to broadly include
anything that an entity utilizes to prevent an IROL which could be an “operating guide or a protection system”
like a RAS in WECC or an SPS in the Eastern Interconnection. It was not intended to include all the items
included in the term that is being defined in Project 2007-17.
Response: Thank you for your comment. The SDT agrees and will revise the Implementation Plan to remove PER-005 from the list of standards to be
modified.
MidAmerican Energy
No
The drafting team did not properly address previous comments to include BES references in each PRC-005
sub bullet definitions and left "DC system" wording in the definition with only a comment in parentheses. The
Protection System definition affects multiple standards and must stand alone across those standards.
Therefore: 1. BES references are still needed in each sub bullet definition to eliminate ambiguity and to create
clearly auditable requirements, meeting a basic standards drafting principal being requested both by FERC and
the industry. 2. "DC system" remains a wide open definition. Because regulators and auditors are auditing to
"zero" defect requirements and imposing their own interpretations, only specific wording is acceptable. The
term "DC system" needs to be replaced with explicit pieces of equipment such as "batteries, battery chargers,
and AC / DC converters". To be a credible audit process, both the auditor and audited entity must have a clear
understanding of what is being audited. DC system can be interpreted in many ways by an entity or auditor
and is not an acceptable term. Further, BES references are needed to create clear and auditable boundaries
for this definition.
Response: Thank you for your comments. These comments all relate to "application" of the definition; "auditable boundaries" and "auditable requirements" are
part of the standard.
Duke Energy
Yes
We agree with the revised definition. However the added language raises a question regarding how PRC-0052 would be applied to DC supply situations where the battery is the backup to the “normal” source of DC power.
Specifically, it’s unclear to us that Uninterruptible Power Supplies (UPS), rectifiers and motor-generator sets
that use batteries as a backup are included in the scope of Table 1.
Response: Thank you for your comment. The SDT believes your comment pertains to the standard PRC-005-2 and not the definition of Protection
Systems.
Xcel Energy
October 28, 2010
Yes
The Implementation Plan indicates that the lower case “protection system” in 3 other standards would be
replaced with the capitalized term “Protection System” to properly reflect its use in those standards. In PRC-001
the term “protective system” is also used, however the Implementation Plan does not indicate whether this term
will also be replaced. If not, then it would seem to imply that the term “protective system” has different meaning
than “protection system/Protection System”. There is concern that the use of “Protection System” in PRC-001
will require entities to ‘coordinate” changes to all elements of the Protection System, which could be of no value
for elements such as batteries, battery chargers. It is not clear as to if the intent that ALL elements of the
13
Consideration of Comments on Protection System Maintenance & Testing Definition of Protection System — Project 2007-17
Organization
Yes or No
Question 1 Comment
Protection System be coordinated when a new or changed Protection System occurs.
Response: Thank you for your comment. The term “protective system” is not a defined term in the NERC glossary and is not addressed by the
Implementation Plan.
LIPA
Yes
Station dc supply associated with protective functions (including station batteries, battery chargers, and nonbattery-based dc supply), and ....Change to Station dc supply associated with protective functions, and....
Response: Thank you for your comment. The SDT believes the current draft of the definition as balloted is better supported by industry.
American Transmission Company
Yes
Manitoba Hydro
Yes
ISO New England Inc.
Yes
South Carolina Electric and Gas
Yes
Northeast Utilities
Yes
IRC Standards Review Committee
Yes
Bonneville Power Administration
Yes
Arizona Public Service Company
Yes
Ameren
Yes
Green Country Energy
Yes
October 28, 2010
None.
14
Proposed Definition of Protection System:
Protection System –
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions,
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
• Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
Protection System Definition
The previously approved (Board of Trustees) definition of Protection System reads
as follows:
Protection System: Protective relays, associated communication systems, voltage and
current sensing devices, station batteries and DC control circuitry.
Proposed Changes to Board of Trustees Approved Version of Definition:
Protection System: Protective relays which respond to electrical quantities, associated
communication systems necessary for correct operation of protective functions, voltage and
current sensing devices providing inputs to protective relays, station dc supply associated
with protective functions (including station batteries, battery chargers, and non-battery
based and DC dc supply), and control circuitry associated with protective functions through
the trip coil(s) of the circuit breakers or other interrupting devices.
Implementation Plan for the Revised Definition of Protection System
Prerequisite Approvals or Activities:
The implementation of the revised definition is not dependent upon any other activity.
Recommended Modifications to Already Approved Standards
The non-capitalized version of the term, “protection system” is used in the following approved
standards:
•
NUC-001-2 – Nuclear Plant Interface Coordination
•
PRC-001-1 – System Protection Coordination
The term, “protection system” shall be capitalized where used in these standards when the
definition of “Protection System” is approved by applicable regulatory authorities.
Proposed Effective Date:
Each responsible entity (Distribution Provider that owns a transmission Protection System,
Transmission Owner, and Generator Owner) shall modify its protection system maintenance and
testing program description and basis document(s) (required in Requirement R1 of PRC-005-1 –
Transmission and Generation Protection System Maintenance and Testing) as necessary to
reflect the modified definition of ‘Protection System’ by the first day of the first calendar quarter
twelve months following regulatory approvals and implement any additional maintenance and
testing (required in Requirement R2 of PRC-005-1 – Transmission and Generation Protection
System Maintenance and Testing) by the end of the first complete maintenance and testing cycle
described in the entity’s program description and basis document(s) following establishment of
the program changes resulting from the revised definition.
The original definition of “Protection System” shall be retired at the same time the revised
definition becomes effective.
October 28, 2010
Implementation Plan for the Revised Definition of Protection System
Prerequisite Approvals or Activities:
The implementation of the revised definition is not dependent upon any other activity.
Recommended Modifications to Already Approved Standards
The non-capitalized version of the term, “protection system” is used in the following approved
standards:
•
NUC-001-2 – Nuclear Plant Interface Coordination
•
PER-005-1 – System Personnel Training
•
PRC-001-1 – System Protection Coordination
The term, “protection system” shall be capitalized where used in these standards when the
definition of “Protection System” is approved by applicable regulatory authorities.
Proposed Effective Date:
Each responsible entity (Distribution Provider that owns a transmission Protection System,
Transmission Owner, and Generator Owner) shall modify its protection system maintenance and
testing program description and basis document(s) (required in Requirement R1 of PRC-005-1 –
Transmission and Generation Protection System Maintenance and Testing) as necessary to
reflect the modified definition of ‘Protection System’ by the first day of the first calendar quarter
twelve months following regulatory approvals and implement any additional maintenance and
testing (required in Requirement R2 of PRC-005-1 – Transmission and Generation Protection
System Maintenance and Testing) by the end of the first complete maintenance and testing cycle
described in the entity’s program description and basis document(s) following establishment of
the program changes resulting from the revised definition.
The original definition of “Protection System” shall be retired at the same time the revised
definition becomes effective.
July 22, 2010October 28, 2010
Standards Announcement
Recirculation Ballot Open
November 1-11, 2010
Available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-17 Protection System Maintenance Definition
A recirculation ballot period is open through 8 p.m. Eastern on November 11, 2010.
Instructions
Members of the ballot pool associated with this project may log in and submit their votes from the following
page: https://standards.nerc.net/CurrentBallots.aspx
Ballot Process
The Standards Committee encourages all members of the ballot pool to review the consideration of comments
submitted during the successive ballot window that ended October 14, 2010 and the consideration of comments
submitted during the formal comment period that ended October 12, 2010.
In the recirculation ballot, votes are counted by exception only. If a ballot pool member does not submit a
revision to that member’s original vote, the vote remains the same as in the first ballot. Members of the ballot
pool may:
- Reconsider and change their vote from the first ballot.
- Vote in the second ballot even if they did not vote on the first ballot.
- Take no action if they do not want to change their original vote.
Additional Information
The Standard Processes Manual allows drafting teams to make changes following an initial or successive ballot
with a goal of improving the quality of a standard (or definition), provided those changes do not alter the
applicability or scope of the proposed standard (or definition). The Protection System Maintenance and Testing
drafting team made the following minor edit to the implementation plan for the definition of Protection System:
•
Removed PER-005-1 – System Personnel Training from the set of standards with conforming changes
associated with the approval of the proposed definition of Protection System
A redline version of the Implementation Plan showing the above change has been posted for stakeholder
review.
Next Steps
Voting results will be posted and announced after the ballot window closes. If approved, the definition and
associated implementation plan will be submitted to the Board of Trustees.
Project Background
When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the
Protection System and Maintenance Standard Drafting Team, the board acknowledged the reliability gap
identified by the drafting team caused by the definition of "protection system," and directed that work to close
this reliability gap should be given “priority.” The Standards Committee directed the team to advance the
definition of Protection System in parallel with the development of PRC-005-2.
Project Page: http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Recirculation Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
Project 2007-17 Ballot Results for Definition of Protection System
The recirculation ballot window to vote on a proposed revision to the definition of the term, “Protection
System” and its associated implementation plan closed on November 11, 2010. The ballot pool approved the
revised definition and its associated implementation plan. Voting statistics are listed below, and the Ballot
Results Web page provides a link to the detailed results:
Quorum: 89.41 %
Approval: 86.83 %
Next Steps
The revised definition and its associated implementation plan will be submitted to the NERC Board of Trustees
for approval.
Project Background
When the Board of Trustees was asked to approve an interpretation of PRC-005-1 that was written by the
Protection System Maintenance and Testing Standard Drafting Team, the board acknowledged the reliability
gap identified by the drafting team caused by the definition of "protection system," and directed that work to
close this reliability gap should be given “priority.” The Standards Committee directed the team to advance the
definition of Protection System in parallel with the development of PRC-005-2.
Project Page: http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Ballot Criteria
Approval requires both a (1) quorum, which is established by at least 75% of the members of the ballot pool for
submitting either an affirmative vote, a negative vote, or an abstention, and (2) a two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and
negative votes, excluding abstentions and non-responses.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
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User Name
Ballot Results
Project 2007-17 Protection System Maintenance (Protection System
Ballot Name:
definition)_rc
Password
Ballot Period: 11/1/2010 - 11/11/2010
Log in
Ballot Type: recirculation
Register
Total # Votes: 287
Total Ballot Pool: 321
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Quorum: 89.41 % The Quorum has been reached
Weighted Segment
86.83 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
89
9
71
24
67
37
0
11
6
7
321
#
Votes
1
0.5
1
1
1
1
0
0.8
0.4
0.5
7.2
#
Votes
Fraction
65
5
56
19
40
28
0
6
4
5
228
Negative
Fraction
0.855
0.5
0.903
0.905
0.741
0.848
0
0.6
0.4
0.5
6.252
Abstain
No
# Votes Vote
11
0
6
2
14
5
0
2
0
0
40
0.145
0
0.097
0.095
0.259
0.152
0
0.2
0
0
0.948
5
1
2
1
6
1
0
1
1
1
19
8
3
7
2
7
3
0
2
1
1
34
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Member
Ballot
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Robert D Smith
John Bussman
Scott Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2fb89d64-e1c6-4e1e-ad26-559449870f46[11/18/2010 10:50:03 AM]
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Comments
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnesota Power, Inc.
National Grid
Nebraska Public Power District
New York Power Authority
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
John J. Moraski
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Ronald D. Schellberg
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
Michael Moltane
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
Doug Bantam
Robert Ganley
Martyn Turner
Michelle Rheault
Ernest Hahn
Terry Harbour
Randi Woodward
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
Richard J Kafka
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Chad Bowman
Catherine Koch
Tim Kelley
Robert Kondziolka
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2fb89d64-e1c6-4e1e-ad26-559449870f46[11/18/2010 10:50:03 AM]
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Santee Cooper
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Arizona Public Service Co.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Leesburg
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V. Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Faramarz Amjadi
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Thomas R. Glock
James V. Petrella
Pat G. Harrington
Rebecca Berdahl
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C Parent
Steven Grego
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2fb89d64-e1c6-4e1e-ad26-559449870f46[11/18/2010 10:50:03 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salem Electric
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Tri-State G & T Association, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
Y-W Electric Association, Inc.
AEP Service Corp.
Amerenue
APS
Avista Corp.
Black Hills Corp
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David T. Anderson
Ballard Keith Mutters
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Anthony Schacher
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
David Schiada
Jeff Nelson
Ronald L Donahey
Janelle Marriott
James R. Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
View
View
View
View
Affirmative
Abstain
Affirmative
Affirmative
Timothy Beyrle
Affirmative
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Christopher Plante
Joseph G. DePoorter
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
John D. Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
James A Ziebarth
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
George Tatar
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2fb89d64-e1c6-4e1e-ad26-559449870f46[11/18/2010 10:50:03 AM]
View
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Entergy Corporation
FirstEnergy Solutions
Florida Municipal Power Agency
Green Country Energy
Horizon Wind Energy
Indeck Energy Services, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
New Harquahala Generating Co. LLC
New York Power Authority
Northern Indiana Public Service Co.
Otter Tail Power Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Public Utility District No. 1 of Lewis County
Reedy Creek Energy Services
RRI Energy
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Centralia Generation, LLC
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Amir Y Hammad
James B Lewis
Bob Essex
Mike Garton
Robert Smith
Dan Roethemeyer
Stephen Ricker
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Doug Ramey
Affirmative
Kenneth Parker
Stanley M Jaskot
Kenneth Dresner
David Schumann
Greg Froehling
Brent Hebert
Rex A Roehl
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Daniel Duff
Dennis Florom
Charlie Martin
Mike Laney
Mark Aikens
Affirmative
Affirmative
David Gordon
Nicholas Q Hayes
Gerald Mannarino
Michael K Wilkerson
Stacie Hebert
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A Heimbach
Wayne Lewis
David Murray
Steven Grega
Bernie Budnik
Thomas J. Bradish
Bethany Wright
Glen Reeves
Daniel Baerman
Michael J. Haynes
Brenda K. Atkins
Richard Jones
Jerry W Johnson
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Joanna Luong-Tran
Barry Ingold
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
View
View
View
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Karl Bryan
Affirmative
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
Terri F Benoit
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2fb89d64-e1c6-4e1e-ad26-559449870f46[11/18/2010 10:50:03 AM]
View
View
Negative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Energy
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
OTP Wholesale Marketing
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Ascendant Energy Services, LLC
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
SPS Consulting Group Inc.
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daryn Barker
Brad Jones
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
David Ried
Bruce Glorvigen
John T Sturgeon
James D. Hebson
Hugh A. Owen
Trent Carlson
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
John Stonebarger
View
View
Negative
David F. Lemmons
James A Maenner
Roger C Zaklukiewicz
Kristina M. Loudermilk
Merle Ashton
Raymond Tran
Jim D. Cyrulewski
Margaret Ryan
Peggy Abbadini
Jim R Stanton
Brian Evans-Mongeon
Terry Volkmann
William Mitchell Chamberlain
Donald E. Nelson
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
View
View
View
Affirmative
Diane J. Barney
Jerome Murray
Philip Riley
Ric Campbell
Linda Campbell
Dan R. Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B Edge
Louise McCarren
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
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NERC Standards
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Standard PRC-005-2 — Protection System Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approves SAR for posting on June 5, 2007.
2. The SAR was posted for comment from June 11, 2007–July 10, 2007.
3. The SC approves development of the standard on August 13, 2007.
4. First posting of revised standard on July 24, 2009.
5. Second posting of revised standard on June 11, 2010
6. Third posting of revised standard on September 24, 2010
Description of Current Draft:
This is the third draft of the Standard. This standard merges previous standards PRC-005-1, PRC-008-0,
PRC-011-0, and PRC-017-0. It also addresses FERC comments from Order 693, and addresses
observations from the NERC System Protection and Control Task Force, as presented in NERC SPCTF
Assessment of Standards: PRC-005-1 — Transmission and Generation Protection System Maintenance
and Testing, PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs, PRC011-0 — UVLS System Maintenance and Testing, PRC-017-0 — Special Protection System Maintenance
and Testing.
Future Development Plan:
Anticipated Actions
1. Post for combined 30-day comment and ballot.
Anticipated Date
November 17-December 17, 2010
2. Conduct successive ballot
December 7– December 17, 2010
3. Drafting Team Responds to Comments
January 5, 2011–January 25, 2011
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1
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Restore — Return malfunctioning components to proper operation.
Protection System (modification)
• Protective relays which respond to electrical quantities,
• communications systems necessary for correct operation of protective functions,
• voltage and current sensing devices providing inputs to protective relays,
• station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
• control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
The following terms are defined for use only within PRC-005-2, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that
it cannot be restored to functional order by repair or calibration during performance of the initial on-site
activity. Therefore this issue requires follow-up corrective action.
Segment – Protection Systems or components of a consistent design standard, or a particular model or
type from a single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60) individual
components.
Component Type - Any one of the five specific elements of the Protection System definition.
Component – A component is any individual discrete piece of equipment included in a Protection
System, such as a protective relay or current sensing device. For components such as control circuits, the
designation of what constitutes a control circuit component is very dependent upon how an entity
performs and tracks the testing of the control circuitry. Some entities test their control circuits on a
breaker basis whereas others test their circuitry on a “local zone of protection” basis. Thus, entities are
Draft 3: November 17, 2010
2
Standard PRC-005-2 — Protection System Maintenance
allowed the latitude to designate their own definitions of “control circuit components.” Another example
of where the entity has some discretion on determining what constitutes a single component is the voltage
and current sensing devices, where the entity may choose either to designate a full three-phase set of such
devices or a single device as a single component.
Countable Event – Any failure of a component which requires repair or replacement, any condition
discovered during the verification activities in Tables 1-1 through 1-5 which requires corrective action, or
a Misoperation attributed to hardware failure or calibration failure. Misoperations due to product design
errors, software errors, relay settings different from specified settings, Protection System component
configuration errors, or Protection System application errors are not included in Countable Events.
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3
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems applied on, or designed to provide protection for, the BES.
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via
generator lockout or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for generator-connected station service transformers for
generators that are part of the BES.
4.2.5.5 Protection Systems for system-connected station service transformers for
generators that are part of the BES.
5.
(Proposed) Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems applied on, or
designed to provide protection for, the BES. The PSMP shall: [Violation Risk Factor:
Medium] [Time Horizon: Long Term Planning]
1.1. Address all Protection System component types.
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Standard PRC-005-2 — Protection System Maintenance
1.2. Identify which Protection System component types are addressed through time-based,
performance-based (per PRC-005 Attachment A), or a combination of these maintenance
methods (per PRC-005-Attachment A). All batteries associated with the station dc
supply component of a Protection System shall be included in a time-based program as
described in Table 1-4.
1.3. Identify the associated maintenance intervals for time-based programs
1.4. Include all monitoring attributes and related maintenance activities applied to each
Protection System component type, to include those specified in Tables 1-1 through 1-5.
1.5. Identify calibration tolerances or other equivalent parameters for each Protection System
component type that establish acceptable parameters for the conclusion of maintenance
activities.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses maintenance
intervals for monitored Protection Systems described in Tables 1-1 through 1-5, shall verify
those components possess the monitoring attributes identified in Tables 1-1 through 1-5 in its
PSMP. [Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement and
follow its PSMP, including identification of the resolution of all maintenance correctable issues
as follows: [Violation Risk Factor: High] [Time Horizon: Operations Planning]
4.1.
4.2.
Perform the maintenance activities for all Protection System components according to
the PSMP established in accordance with Requirement R1:
4.1.1.
For time-based maintenance programs, perform maintenance activities no
less frequently than the maximum allowable intervals established in Tables
1-1 through 1-5.
4.1.2.
For performance-based maintenance programs, perform the maintenance
activities no less frequently than the intervals established in Requirement R3.
Either verify that the components are within the acceptable parameters established in
accordance with Requirement R1, Part 1.5 at the conclusion of the maintenance
activities, or initiate resolution of any identified maintenance correctable issues.
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a current or
updated documented Protection System Maintenance Program that addresses all component
types of its Protection Systems, as required by Requirement R1. For each Protection System
component type, the documentation shall include the type of maintenance program applied
(time-based, performance-based, or a combination of these maintenance methods),
maintenance activities, and maintenance intervals as specified in Requirement R1, Parts 1.1
through 1. 5.
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses maintenance
intervals for monitored Protection Systems shall have evidence such as engineering drawings
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Standard PRC-005-2 — Protection System Maintenance
or manufacturer’s information showing that the components possess the monitoring attributes
identified in Tables 1-1 through 1-5, as required by Requirement R2.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that uses a
performance-based maintenance program shall have evidence such as equipment lists, dated
maintenance records, and dated analysis records and results that its current performance-based
maintenance program is in accordance with Requirement R3.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records or dated work orders as evidence that it has implemented the Protection
System Maintenance Program and initiated resolution of identified maintenance correctable
issues in accordance with Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to demonstrate compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For R1, the Transmission Owner, Generator Owner, and Distribution Provider shall each
keep its current dated Protection System Maintenance Program including the
documentation that specifies the type of maintenance program applied for each Protection
System component type.
For R2, the Transmission Owner, Generator Owner, and Distribution Provider shall each
keep the evidence that proves the Protection System components possess the identified
monitoring attributes as long as they are used to justify the intervals and activities
associated with a performance-based maintenance program as identified within Tables 11 through 1-5.
For R3 and R4, the Transmission Owner, Generator Owner, and Distribution Provider
shall each keep documentation of the two most recent performances of each distinct
maintenance activity for the Protection System components, or to the previous scheduled
audit date, whichever is longer.
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6
Standard PRC-005-2 — Protection System Maintenance
The Compliance Enforcement Authority shall keep the last periodic audit report and all
requested and submitted subsequent compliance records.
1.4. Additional Compliance Information
None.
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7
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
Failed to specify whether one
component type is being addressed
by time-based or performance-based
maintenance.
Failed to specify whether two
component types are being
addressed by time-based or
performance-based maintenance.
Failed to include station batteries in
a time-based program
OR
Failed to include all maintenance
activities relevant for the identified
monitoring attributes specified in
Tables 1-1 through 1-5.
OR
Failed to establish calibration
tolerance or equivalent parameters to
determine if components are within
acceptable parameters.
Entity has not established a PSMP.
OR
The entity’s PSMP failed to address
three or more component types
included in the definition of
‘Protection System’
OR
Failed to specify whether three or
more component types are being
addressed by time-based or
performance-based maintenance.
R2
Entity has Protection System
components in a condition-based
PSMP, but documentation to support
the monitoring attributes used to
determine relevant intervals is
incomplete on no more than 5% of
the Protection System components
maintained according to Tables 1-1
through 1-5.
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support monitoring attributes used
to determine relevant intervals is
incomplete on more than 5%, but
10% or less, of the Protection
System components maintained
according to Tables 1-1 through 1-5.
Entity has Protection System
elements in a condition-based
PSMP, but documentation to support
monitoring attributes used to
determine relevant intervals is
incomplete on more than 10%, but
15% or less, of the Protection
System components maintained
according to Tables 1-1 through 1-5.
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support monitoring attributes used
to determine relevant intervals is
incomplete on more than 15% of
the Protection System components
maintained according to Tables 1-1
through 1-5.
R3
Entity has Protection System
elements in a performance-based
PSMP but has:
1) Failed to reduce countable events
to less than 4% within three years
OR
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for 5% or less of components
in any individual segment
NA
Entity has Protection System
elements in a performance-based
PSMP but has failed to reduce
countable events to less than 4%
within four years.
Entity has Protection System
components in a performancebased PSMP but has:
1) Failed to reduce countable
events to less than 4% within five
years
OR
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for over 5% of components
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Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
OR
in any individual segment
OR
3) Maintained a segment with less
than 54 components
OR
4) Failed to:
• Annually update the list of
components,
• Perform maintenance on the
greater of 5% of the segment
population or 3 components,
• Annually analyze the program
activities and results for each
segment.
3) Maintained a segment with 54-59
components or containing different
manufacturers.
R4
Entity has failed to complete
scheduled program on 5% or less of
total Protection System components.
OR
Entity has failed to initiate resolution
on 5% or less of identified
maintenance-correctable issues.
Draft 3: November 17, 2010
Severe VSL
Entity has failed to complete
scheduled program on greater than
5%, but no more than 10% of total
Protection System components
OR
Entity has failed to initiate
resolution on greater than 5%, but
no more than 10% of identified
maintenance-correctable issues.
Entity has failed to complete
scheduled program on greater than
10%, but no more than 15% of total
Protection System components
OR
Entity has failed to initiate resolution
on greater than 10%, but no more
than 15% of identified.
9
Entity has failed to complete
scheduled program on greater than
15% of total Protection System
components
OR
Entity has failed to initiate
resolution on greater than 15% of
identified maintenance-correctable
issues.
Standard PRC-005-2 – Protection System Maintenance
E. Regional Variances
None
F. Supplemental Reference Documents
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference — July 2009.
2. NERC Protection System Maintenance Standard PRC-005-2 FREQUENTLY ASKED
QUESTIONS — Practical Compliance and Implementation DRAFT 1.0 — June 2009
Version History
Version
Date
Action
2
TBD
Complete revision, absorbing maintenance
requirements from PRC-005-1, PRC-008-0,
PRC-011-0, PRC-017
Draft 3: November 17, 2010
Change Tracking
Complete revision
10
Standard PRC-005-2 – Protection System Maintenance
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Activities
Verify that settings are as specified
For non-microprocessor relays:
• Test and calibrate
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
• Verify acceptable measurement of power system input values.
Verify:
Monitored microprocessor protective relay with the following::
• Settings are as specified.
• Internal self diagnosis and alarming.
• Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics that are also
performing self monitoring and alarming (see Table 2).
12 calendar
years
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values.
• Alarming for power supply failure (see Table 2).
Monitored microprocessor protective relay with preceding row attributes
and the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive
error. (See Table 2)
• Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure. (See Table 2)
12 calendar
years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Alarming for change of settings. (See Table 2)
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11
Standard PRC-005-2 – Protection System Maintenance
Table 1-2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
3 calendar
months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function. (See Table 2)
Any communications system with continuous monitoring or periodic
automated testing for the performance of the channel using criteria such as
signal level, reflected power, or data error rate, and alarming for excessive
performance degradation. (See Table 2)
Draft 3: November 17, 2010
6 calendar
years
12 calendar
years
No periodic
maintenance
specified
Activities
Verify that the communications system is functional.
Verify that the channel meets performance criteria such as signal
level, reflected power, or data error rate.
Verify essential signals to and from other Protection System
components.
Verify that the channel meets performance criteria such as signal
level, reflected power, or data error rate.
Verify essential signals to and from other Protection System
components.
None.
12
Standard PRC-005-2 – Protection System Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value as measured by the microprocessor relay to an
independent ac measurement source, with alarming for unacceptable
error or failure.
Draft 3: November 17, 2010
Maximum
Maintenance
Interval
Activities
12 calendar years
Verify that acceptable measurements of the current and voltage
signals are received by the protective relays.
No periodic
maintenance
specified
None.
13
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Any dc supply for a UFLS or UVLS system.
Maximum
Maintenance
Interval
When control
circuits are
verified
3 Calendar
Months
Any unmonitored station dc supply not having the monitoring
attributes of a category below. (excluding UFLS and UVLS)
18 Calendar
Months
Any unmonitored Station dc supply in which a battery is not used and
not having the monitoring attributes of a category below. (excluding
UFLS and UVLS)
Unmonitored Station dc supply with Valve Regulated Lead-Acid
(VRLA) batteries that does not have the monitoring attributes of a
category below. (excluding UFLS and UVLS)
Draft 3: November 17, 2010
Activities
Verify dc supply voltage
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level (excluding valve-regulated lead acid
batteries)
• For unintentional grounds
Verify:
• State of charge of the individual battery cells/units
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
6 Calendar Years
Verify that the dc supply can perform as designed when ac power
from the grid is not present.
3 Calendar
Months
Verify that the station battery can perform as designed by
evaluating the measured cell/unit internal ohmic values to station
battery baseline.
14
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Activities
--------------------------------- or ---------------------------------
3 Calendar Years
Verify that the station battery can perform as designed by
evaluating the measured cell/unit internal ohmic values to station
battery baseline.
18 Calendar
Months
Unmonitored Station dc supply with Vented Lead-Acid Batteries
(VLA) that does not have the monitoring attributes of a category
below. (excluding UFLS and UVLS)
Unmonitored Station dc supply with Nickel-Cadmium (Ni-Cad)
batteries that does not have the monitoring attributes of a category
below. (excluding UFLS and UVLS)
Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2):
• Station dc supply voltage (voltage of battery charger)
• State of charge of the individual battery cell/units
• Battery continuity of station battery
• Cell-to-cell (if available) and battery terminal resistance
Draft 3: November 17, 2010
Verify that the station battery can perform as designed by
conducting a performance or service capacity test of the entire
battery bank.
--------------------------------- or ---------------------------------
6 Calendar Years
Verify that the station battery can perform as designed by
conducting a performance, service, or modified performance
capacity test of the entire battery bank.
6 Calendar Years
Verify that the station battery can perform as designed by
conducting a performance service, or modified performance
capacity test of the entire battery bank.
18 calendar
months
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
15
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
• Electrolyte level of all cells in a station battery
• Unintentional dc grounds
• Cell/unit internal ohmic values of station battery
Continuously monitored Station dc supply (excludes UFLS and
UVLS) with preceding row attributes and the following:
• The monitoring devices themselves are monitored.
Draft 3: November 17, 2010
Maximum
Maintenance
Interval
6 calendar years
18 calendar
months
Activities
Verify that the monitoring devices are calibrated (where
necessary)
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
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Standard PRC-005-2 – Protection System Maintenance
Table 1-5
Component Type - Control Circuitry
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (excluding UFLS or UVLS systems).
Trip coils of circuit breakers and interrupting devices in UFLS or UVLS
systems.
Maximum
Maintenance
Interval
6 calendar
years
No periodic
maintenance
specified
Activities
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
None.
Electromechanical trip or auxiliary devices
6 calendar
years
Verify electrical operation of electromechanical trip and
auxiliary devices
Unmonitored Control circuitry associated with protective functions
12 calendar
years
Verify all paths of the control and trip circuits.
Control circuitry whose continuity and energization or ability to operate are
monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
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17
Standard PRC-005-2 – Protection System Maintenance
Table 2 – Alarming Paths
In Tables 1-1 through 1-5, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance activities are
subject to the following maintenance requirements
Maximum
Component Attributes
Maintenance
Activities
Interval
Any alarm path through which alarms in Tables 1-1 through 1-5 are conveyed
from the alarm origin to the location of corrective action, and not having all the
attributes of the category below.
Alarms are automatically reported within 24 hours of DETECTION to a
location where corrective action can be taken.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be taken.
Draft 3: November 17, 2010
When alarm
producing device or
system is verified
No periodic
maintenance
specified
Verify that the alarm signals are conveyed to a
location where corrective action can be taken.
None.
18
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of components included in each designated segment of
the Protection System component population.
2. Maintain the components in each segment according to the time-based maximum
allowable intervals established in Tables 1-1through 1-5 until results of maintenance
activities for the segment are available for a minimum of 30 individual components of the
segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events 1 for each included component.
4. Analyze the maintenance program activities and results for each segment to determine the
overall performance of the segment and develop maintenance intervals.
5. Determine the maximum allowable maintenance interval for each segment such that the
segment experiences countable events on no more than 4% of the components within the
segment, for the greater of either the last 30 components maintained or all components
maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
4. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
5. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
1
Countable events include any failure of a component requiring repair or replacement, any condition discovered
during the verification activities in Table 1a through Table 1c which requires corrective action, or a Misoperation
attributed to hardware failure or calibration failure.
Draft 3: November 17, 2010
19
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
Verification — A means of determiningVerify — Determine that the component is
functioning correctly.
•
Monitoring — Observation ofMonitor — Observe the routine in-service operation of
the component.
•
Testing — Application ofTest — Apply signals to a component to observe functional
performance or output behavior, or to diagnose problems.
•
Inspection — To detectInspect — Detect visible signs of component failure, reduced
performance and degradation.
•
Calibration — Adjustment ofCalibrate — Adjust the operating threshold or
measurement accuracy of a measuring element to meet the intended performance
requirement.
•
•
Upkeep — Routine activities necessary to assure that the component remains in
good working order and implementation of any manufacturer’s hardware and
software service advisories which are relevant to the application of the device.
Restoration — The actions to restore proper operation of Restore — Return
malfunctioning components to proper operation.
Protection System (modification)
• — Protective relays, communication which respond to electrical quantities,
• communications systems necessary for correct operation of protective functions,
• voltage and current sensing devices providing inputs to protective relays and associated
circuitry from the voltage and current sensing devices, ,
• station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
• control circuitry associated with protective functions from the station dc supply
through the trip coil(s) of the circuit breakers or other interrupting devices.
The following terms are defined for use only within PRC-005-2, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that
it cannot be restored to functional order by repair or calibration during performance of the initial on-site
activity. Therefore this issue requires follow-up corrective action.
Draft 2: April 163: November 17, 2010
Page 1
Standard PRC-005-2 — Protection System Maintenance
Segment – Protection Systems or components of a consistent design standard, or a particular model or
type from a single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60) individual
components.
Component Type - Any one of the five specific elements of the Protection System definition.
Component – A component is any individual discrete piece of equipment included in a Protection
System, such as a protective relay or current sensing device. For components such as control circuits, the
designation of what constitutes a control circuit component is very dependent upon how an entity
performs and tracks the testing of the control circuitry. Some entities test their control circuits on a
breaker basis whereas others test their circuitry on a “local zone of protection” basis. Thus, entities are
allowed the latitude to designate their own definitions of “control circuit components.” Another example
of where the entity has some discretion on determining what constitutes a single component is the voltage
and current sensing devices, where the entity may choose either to designate a full three-phase set of such
devices or a single device as a single component.
Countable Event – Any failure of a component which requires repair or replacement, any condition
discovered during the verification activities in Tables 1-1 through 1-5 which requires corrective action, or
a Misoperation attributed to hardware failure or calibration failure. Misoperations due to product design
errors, software errors, relay settings different from specified settings, Protection System component
configuration errors, or Protection System application errors are not included in Countable Events.
Draft 2: April 163: November 17, 2010
Page 2
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems applied on, or designed to provide protection for, the BES.
4.2.2
Protection System componentsSystems used for underfrequency load-shedding
systems installed per ERO underfrequency load-shedding requirements.
4.2.3
Protection System componentsSystems used for undervoltage load-shedding
systems installed to prevent system voltage collapse or voltage instability for
BES reliability.
4.2.4
Protection System componentsSystems installed as a Special Protection System
(SPS) for BES reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection System componentsSystems that act to trip the generator either
directly or via generator lockout or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for generator-connected station service transformers for
generators that are part of the BES.
4.2.5.5 Protection Systems for system-connected station service transformers for
generators that are part of the BES.
5.
(Proposed) Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems that use
measurements of voltage, current, frequency and/or phase angle to determine
Draft 2: April 163: November 17, 2010
Page 3
Standard PRC-005-2 — Protection System Maintenance
anomalies and to trip a portion of the BES 1 and that are applied on, or are designed to
provide protection for, the BES. The PSMP mustshall: [Violation Risk Factor: HighMedium]
[Time Horizon: Long Term Planning]
1.1. IdentifyAddress all Protection System components;component types.
1.2. Identify whether eachwhich Protection System component istypes are addressed
through time-based (per Table 1a), condition-based (per Table 1b or 1c),,
performance-based (per PRC-005 Attachment A), or a combination of these maintenance
methods and identify the associated maintenance interval;
1.3. For each Protection System component, include all maintenance activities
specified in Tables 1a, 1b, or 1c associated with the maintenance method used per
Requirement 1, part 1.1; and
1.4.1.2. Include all (per PRC-005-Attachment A). All batteries associated with the station
dc supply component of a Protection System shall be included in a time-based program
as described in Table 1-4.
1.3. Identify the associated maintenance intervals for time-based programs
1.4. Include all monitoring attributes and related maintenance activities applied to each
Protection System component type, to include those specified in Tables 1-1 through 1-5.
1.5. Identify calibration tolerances or other equivalent parameters for each Protection System
component type that establish acceptable parameters for the conclusion of maintenance
activities.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses conditionbased maintenance intervals in its PSMP for partially or fullyfor monitored Protection
Systems described in Tables 1-1 through 1-5, shall ensure theverify those components to
which the condition-based criteria are applied, possess the monitoring attributes identified
in Tables 1b or 1c1-1 through 1-5 in its PSMP. [Violation Risk Factor: Medium] [Time
Horizon: Long Term Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Long TermOperations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement and
follow its PSMP, including identification of the resolution of all maintenance correctable
2
issues as follows: [Violation Risk Factor: MediumHigh] [Time Horizon: Long
TermOperations Planning]
4.1.
For time-based or condition-based maintenance programs, perform Perform the
maintenance activities detailed in Table 1 (for the appropriate monitoring
1
Devices that sense non-electrical conditions, such as thermal or transformer sudden pressure relays are not
included within the scope of this standard.
2
A maintenance correctable issue is a failure of a device to operate within design parameters that cannot be restored
to functional order by repair or calibration while performing the initial on-site maintenance activity, and that
requires follow-up corrective action
Draft 2: April 163: November 17, 2010
Page 4
Standard PRC-005-2 — Protection System Maintenance
level(s)) for all Protection System components according to the PSMP established
perin accordance with Requirement R1withinR1:
4.1.1.
For time-based maintenance programs, perform maintenance activities no
less frequently than the maximum allowable intervals not to exceed those
established in Tables 1a, 1b, and 1c1-1 through 1-5.
4.1.2.
For performance-based maintenance programs, perform the maintenance
activities detailed in Table 1 (forno less frequently than the appropriate
monitoring level(s)) for all Protection System components in
accordance within the maximum allowable intervals established perin
Requirement R3.
4.2.
Ensure eitherEither verify that the components are within the acceptable parameters
established in accordance with Requirement R1, Part 1.5 at the conclusion of the
maintenance activities, or initiate resolution of any necessary activities to correct
unresolved identified maintenance correctable issues3.
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider willshall have a
current or updated documented Protection System Maintenance Program that addresses
protective relays, communication systems necessary for correct operation of protective
functions, voltage and current sensing inputs to protective relays and associated
circuitry from the voltage and current sensing devices, station dc supply, and control
circuitry associated with protective functions from the station dc supply through the
trip coil(s)all component types of the circuit breakers or other interrupting devicesits
Protection Systems, as required by Requirement R1. For each protection systemProtection
System component type, the documentation shall include the type of maintenance program
applied, (time-based, performance-based, or a combination of these maintenance methods),
maintenance activities, and maintenance intervals as specified in Requirement R1, Parts 1.1
through 1.4 5.
M2. Each Transmission Owner and, Generator Owner, and Distribution Provider that uses a
condition-based maintenance program shouldintervals for monitored Protection Systems
shall have evidence such as engineering drawings or manufacturer’s information showing that
the components possess the monitoring attributes identified in Tables 1b or 1c1-1 through 1-5,
as required by Requirement R2.
M3. Each Transmission Owner, Generator Owner, orand Distribution Provider that uses a
performance-based maintenance program shouldshall have evidence such as equipment lists,
dated maintenance records, and dated analysis records and results that its current performancebased maintenance program is in accordance with Requirement R3.
M4. Each Transmission Owner, Generator Owner, orand Distribution Provider shall have evidence
such as dated maintenance records or, dated maintenance summaries (including dates that
the components were maintained) that, dated check-off lists, dated inspection records or
3
A maintenance correctable issue is a failure of a device to operate within design parameters that cannot be restored
to functional order by repair or calibration while performing the initial on-site maintenance activity and that requires
follow-up corrective action.
Draft 2: April 163: November 17, 2010
Page 5
Standard PRC-005-2 — Protection System Maintenance
dated work orders as evidence that it has implemented the Protection System Maintenance
Program and initiated resolution of identified maintenance correctable issues in accordance
with Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
1.2. Compliance Monitoring Period and Reset Time Frame
Not Applicable
1.3.1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4.1.3.
Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each
retainkeep data or evidence to demonstrate compliance as identified below unless
directed by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
For R1, the Transmission Owner, Generator Owner, and Distribution Provider shall each
keep its current dated Protection System Maintenance Program including the
documentation that specifies the type of maintenance program applied for each Protection
System component type.
For R2, the Transmission Owner, Generator Owner, and Distribution Provider shall each
keep the evidence that proves the Protection System components possess the identified
monitoring attributes as long as they are used to justify the intervals and activities
associated with a performance-based maintenance program as identified within Tables 11 through 1-5.
For R3 and R4, the Transmission Owner, Generator Owner, and Distribution Provider
shall each keep documentation of the two most recent performances of each distinct
maintenance activity for the Protection System components, or to the previous onsitescheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last periodic audit report and all
requested and submitted subsequent compliance records.
1.5.1.4.
Additional Compliance Information
None.
Draft 2: April 163: November 17, 2010
Page 6
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels
Requirement
Number
R1
Lower VSL
Moderate VSL
High VSL
The entity’s PSMP included all
of the ‘types’ of components
included in the definition of
‘Protection System’, but, for no
more than 5% of the
components, failedFailed to
either
The entity’s PSMP included
all of the ‘types’ of
components included in the
definition of ‘Protection
System’, but, for grater than
5%, but no more than 10% of
the components, failedFailed to
either
The entity’s PSMP included all
of the ‘types’ of components
included in the definition of
‘Protection System’, but, for
greater than 10%, but no
more than 15%, of the
components, failed to either
The entity’s PSMP failed to
address one or more of the
types of components
included in the definition of
‘Protection System’
• identify the component,
Entity has not established a PSMP.
• identify the component,
specify whether theone component
type is being addressed by timebased, condition-based, or
performance-based maintenance, or .
Include all maintenance
activities specified in Table 1a,
Table 1b, or Table 1c, as
applicable.
• identify the component,
specify whether thetwo component
istypes are being addressed by timebased, condition-based, or
performance-based maintenance, or
.
Include all maintenance
activities specified in Table
1a, Table 1b, or Table 1c, as
applicable.
• specify whether the
component is being
addressed by time-based,
condition-based, or
performance-based
maintenance, or
IncludeFailed to include station
batteries in a time-based program
OR
Failed to include all maintenance
activities relevant for the identified
monitoring attributes specified in
Table 1a, Table 1b, or Table
1c, as applicableTables 1-1
through 1-5.
OR
Failed to establish calibration
tolerance or equivalent parameters to
determine if components are within
acceptable parameters.
Draft 2: April 163: November 17, 2010
Severe VSL
-or-orOR
The entity’s’entity’s PSMP
included all of the ‘types’ of
componentsfailed to address
three or more component types
included in the definition of
‘Protection System’ , but, for
more than 15% of the
components, failed to either
• identify the component,
OR
• Failed to specify whether
thethree or more component
istypes are being addressed by
time-based, condition-based,
or performance-based
maintenance, or
Include all maintenance
activities specified in Table
1a, Table 1b, or Table 1c, as
applicable.
Page 7
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
R2
Lower VSL
Entity has Protection System
components in a condition-based
PSMP, but documentation to support
Partially-Monitored Protection
System classification or FullyMonitored Protection System
classificationthe monitoring
attributes used to determine relevant
intervals is incomplete on no more
than 5% of the Protection System
components maintained according to
Tables 1b and 1c.1-1 through 1-5.
R3
Entity has Protection System
elements in a performance-based
PSMP but has:
1) Failed to reduce countable events
to less than 4% within three years.
-orOR
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for 5% or less of components
in any individual segment
-orOR
3) Maintained a segment with 54-59
components or containing different
manufacturers.
Draft 2: April 163: November 17, 2010
Moderate VSL
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support Partially-Monitored
Protection System
classification or FullyMonitored Protection System
classificationmonitoring attributes
used to determine relevant intervals
is incomplete on more than 5%, but
10% or less, of the Protection
System components maintained
according to Tables 1b and 1c.1-1
through 1-5.
NA
High VSL
Entity has Protection System
elements in a condition-based
PSMP, but documentation to support
Partially-Monitored Protection
System classification or FullyMonitored Protection System
classificationmonitoring attributes
used to determine relevant intervals
is incomplete on more than 10%, but
15% or less, of the Protection
System components maintained
according to Tables 1b and 1c.1-1
through 1-5.
Entity has Protection System
elements in a performance-based
PSMP but has failed to reduce
countable events to less than 4%
within four years.
Severe VSL
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support Partially-Monitored
Protection System
classification or FullyMonitored Protection System
classificationmonitoring
attributes used to determine
relevant intervals is incomplete on
more than 15% of the Protection
System components maintained
according to Tables 1b and 1c1-1
through 1-5.
Entity has Protection System
components in a performancebased PSMP but has:
1) Failed to reduce countable
events to less than 4% within five
years.
-orOR
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for over 5% of components
in any individual segment.
-orOR
3) Maintained a segment with less
than 54 components.
-or-
Page 8
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
OR
4) Failed to annually:
• Annually update the list of
components,
• Perform maintenance on the
greater of 5% of the segment
population or 3 components, or
• Annually analyze the program
activities and results for each
segment.
R4
Entity has failed to complete
scheduled program on 5% or less of
total Protection System components.
OR
Entity has failed to initiate resolution
on 5% or less of identified
maintenance-correctable issues.
Draft 2: April 163: November 17, 2010
Entity has failed to complete
scheduled program on greater than
5%, but no more than 10% of total
Protection System components.
OR
Entity has failed to initiate
resolution on greater than 5%, but
no more than 10% of identified
maintenance-correctable issues.
Entity has failed to complete
scheduled program on greater than
10%, but no more than 15% of total
Protection System components.
OR
Entity has failed to initiate resolution
on greater than 10%, but no more
than 15% of identified.
Entity has failed to complete
scheduled program on greater than
15% of total Protection System
components.
-orOR
Entity has failed to initiate
resolution ofon greater than 15% of
identified maintenance-correctable
issues.
Page 9
Standard PRC-005-2 – Protection System Maintenance
E. Regional DifferencesVariances
None
F. Supplemental Reference Documents
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference — July 2009.
2. NERC Protection System Maintenance Standard PRC-005-2 FREQUENTLY ASKED
QUESTIONS — Practical Compliance and Implementation DRAFT 1.0 — June 2009
Version History
Version
Date
Action
2
TBD
Complete revision, absorbing maintenance
requirements from PRC-005-1, PRC-008-0,
PRC-011-0, PRC-017
Draft 3: November 17, 2010
Change Tracking
Complete revision
10
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Voltage and Current
Sensing Inputs to
Protective Relays and
associated circuitry
12 Calendar
Years
Draft 3: November 17, 2010
Verify proper functioning of the current and voltage signals necessary for Protection System operation from the
voltage and current sensing devices to the protective relays.
11
Standard PRC-005-2 – Protection System Maintenance
Control and trip circuits with electromechanical trip or auxiliary
contacts (except for Monitored microprocessor relays,
UFLSprotective relay with the following::
• Internal self diagnosis and alarming.
• Voltage and/or current waveform sampling three or UVLS)more
times per power cycle, and conversion of samples to numeric
values for measurement calculations by microprocessor electronics
that are also performing self monitoring and alarming (see Table
2).
Perform a complete functional trip test that includes all
sectionsVerify:
• Settings are as specified.
6 Calendar
Years12
calendar years
• Operation of the Protection System controlrelay inputs and
trip circuits, including all electromechanical trip and auxiliary
contactsoutputs that are essential to proper functioning of the
Protection System.
• Acceptable measurement of power system input values.
• Alarming for power supply failure (see Table 2).
Control and trip circuits with unmonitored solid-state trip or
auxiliary contacts (except for UFLS or UVLS)Monitored
microprocessor protective relay with preceding row attributes and the
following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive
error. (See Table 2)
• Some or all binary or status inputs and control outputs are
monitored by a process that continuously demonstrates ability to
perform as designed, with alarming for failure. (See Table 2)
12 Calendar
Yearscalendar
years
Perform a complete functional trip test that includes all sections
ofVerify only the Protection System controlunmonitored relay
inputs and trip circuits, including all solid-state trip and auxiliary
contacts (e.g. paths with no moving parts), devices, and
connectionsoutputs that are essential to proper functioning of the
Protection System.
• Alarming for change of settings. (See Table 2)
Control and trip circuits with
electromechanical trip or
auxiliary (UFLS/UVLS
Systems Only)
6 Calendar
Years
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuits,
including all electromechanical trip and auxiliary contacts essential to proper functioning of the Protection System,
except .that verification does not require actual tripping of circuit breakers or interrupting devices.
Control and trip circuits with
unmonitored solid-state trip
or auxiliary contacts
(UFLS/UVLS Systems
Only)
12 Calendar
Years
Perform a complete functional trip test that includes all sections of the Protection System control and trip circuit,
including all solid-state trip and auxiliary contacts (e.g. paths with no moving parts), devices, and connections
essential to proper functioning of the Protection System, except that verification does not require actual tripping of
circuit breakers or interrupting devices.
Draft 3: November 17, 2010
12
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Station dc Supply (used
only for UVLS or UFLS)
(when the
associated
UVLS or UFLS
system is
maintained)
Draft 3: November 17, 2010
Verify proper voltage of the dc supply.
13
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Verify:
Station dc supply
18 Calendar
Months
Draft 3: November 17, 2010
•
State of charge of the individual battery cell/units
•
Float voltage of battery charger
•
Battery continuity
•
Battery terminal connection resistance
•
Battery cell-to-cell connection resistance
Inspect:
•
Cell condition of all individual battery cells where cells are visible – or measure battery cell/unit internal
ohmic values where the cells are not visible
•
Physical condition of battery rack
•
The condition of non-battery-based dc supply
14
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Check:
Station dc supply (that has
as a component any type of
battery)
3 Calendar
Months
Draft 3: November 17, 2010
•
Electrolyte level (excluding valve-regulated lead acid batteries)
•
Station dc supply voltage
•
For unintentional grounds
15
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Station dc supply (that has
as a component Valve
Regulated Lead-Acid
batteries)
3 Calendar
Years
- or 3 Calendar
Months
Draft 3: November 17, 2010
Verify that the station battery can perform as designed by conducting a performance or service capacity test of the
entire battery bank. (3 calendar years)
- or Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values
to station battery baseline. (3 months)
16
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Station dc supply
(that has as a component
Vented Lead-Acid
Batteries)
Station dc supply (that has
as a component NickelCadmium batteries)
6 Calendar
Years
- or -
Verify that the station battery can perform as designed by conducting a performance, service, or modified
performance capacity test of the entire battery bank. (6 calendar years)
- or -
18 Calendar
Months
Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values
to station battery baseline. (18 Months)
6 Calendar
Years
Verify that the substation battery can perform as designed by conducting a performance service, or modified
performance capacity test of the entire battery bank.
Draft 3: November 17, 2010
17
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Station dc supply (battery is
not used)
6 Calendar
Years
Draft 3: November 17, 2010
Verify that the dc supply can perform as designed when the ac power from the grid is not present.
18
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Verify proper voltage of the station dc supply.
Verify that no unintentional dc supply grounds are presen t.
Station dc Supply (battery
is not used)
18 Calendar
Months
Perform a visual inspection, of all components of the station dc supply to verify that the physical condition of the
station dc supply is as desired and any visual inspection if required by the manufacturer on the condition of the dc
supply that is the source of dc power when ac power is unavailable.
Verify where applicable the proper voltage level of each component of the station dc supply.
Verify the correct operation of ac powered dc power supplies.
Verify the continuity of all circuit connections that can be affected by wear or corrosion. Inspect all circuit
connections that can be affected by wear and corrosion
Draft 3: November 17, 2010
19
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Associated
communications systems
3 Calendar
Months
Verify that the Protection System communications system is functional.
Verify that the performance of the channel and the quality of the channel meets performance criteria, such as via
measurement of signal level, reflected power, or data error rate.
Associated
communications systems
6 Calendar
Years
Verify proper functioning of communications equipment inputs and outputs that are essential to proper functioning
of the Protection System.
Verify the signals to/from the associated protective relay(s).
Draft 3: November 17, 2010
20
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Test and calibrate the relays (other than microprocessor relays) with simulated electrical inputs. (Note 1)
UVLS and UFLS relays that
comprise a protection
scheme distributed over the
power system
6 Calendar
Years
Verify proper functioning of the relay trip outputs.
For microprocessor relays verify the proper functioning of the A/D converters.
Verify that settings are as specified.
Draft 3: November 17, 2010
21
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
Relay sensing for
Centralized UFLS or UVLS
systems UVLS and UFLS
relays that comprise a
protection scheme
distributed over the power
system
See
Maintenance
Activities
Draft 3: November 17, 2010
Perform all of the Maintenance activities listed above as established for components of the UFLS or UVLS
systems at the intervals established for those individual components. The output action may be breaker tripping,
or other control action that must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified time interval, but all of the UFLS or UVLS
components whose operation leads to that control action must each be verified.
22
Standard PRC-005-2 – Protection System Maintenance
Table 1a — Time-Based Maintenance — Level 1 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Unmonitored Protection System Components
General Description: Protection System components which do not have self-monitoring alarms, or if self-monitoring alarms are available, the alarms are not
transmitted to a location where action can be taken for alarmed failures.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of Protection System Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Test and calibrate the relays (other than microprocessor relays)
with simulated electrical inputs. (Note 1)
Verify that settings are as specified .
Protective RelaysAny unmonitored protective relay not having all the
monitoring attributes of a category below.
6 Calendar
Yearscalendar
years
For non-microprocessor relays:
• Test and calibrate
For microprocessor relays, check:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• For microprocessor relays, verifyVerify acceptable
measurement of power system input values.
SPS
See
Maintenance
Activities
Draft 3: November 17, 2010
Perform all of the Maintenance activities listed above as established for components of the SPS at the intervals
established for those individual components. The output action may be breaker tripping, or other control action
that must be verified, but may be verified in overlapping segments. A grouped output control action need be
verified only once within the specified time interval, but all of the SPS components whose operation leads to that
control action must each be verified.
23
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
Draft 3: November 17, 2010
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
24
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
Voltag
e and
Current
Sensin
g
No Level 2
Inputs
monitoring
to
are 17, 2010
Draft 3:attributes
November
Protect defined – use
ive
Level 1
Relays Maintenance
and
Activities
associ
12 Calendar Years
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Verify the proper functioning of current and voltage circuit signals necessary for 25
Protection System operation from the voltage and current sensing devices to the
protective relays.
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
Control
Circuitr
y (Trip
Monitoring and
Coils
alarming of
and
continuity of trip
Auxiliar
circuits(s)
yDraft 3: November 17, 2010
Relays
)
6 Calendar Years
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Verify that each breaker trip coil, each auxiliary relay, and each lockout relay is
electrically operated within this time interval.
26
Standard PRC-005-2 – Protection System Maintenance
Monitoring of Protection
System component inputs,
outputs, and connections
with reporting of monitoring
alarms to a location where
action can be taken
Control Circuitry (Trip Circuits) (except for UFLS/UVLS)
6
calend
ar
years
12
Calenda
r Years
Verify that the alarms will be
received at the location where action
can be taken.
Connection paths using
electronic signals or data
messages are monitored
by periodic signal
changes or messages
that verify ability to
convey Protection
System operating
valuesVerify that the
channel meets performance
criteria such as signal
level, reflected power, or
data error rate.
Verify essential signals to
and from other Protection
System components.
Control
and trip
circuitr
y
Monitoring of the continuity of breaker trip circuits along with the
presence of tripping voltage supply all the way from relay
terminals (or from inside the relay) through to the trip coil(s),
including any auxiliary contacts essential to proper Protection
System operation. If a trip circuit comprises multiple paths, each
of the paths must be monitored, including monitoring of the
operating coil circuit(s) and the tripping circuits of auxiliary
tripping relays and lockout relays. Alarming for loss of
continuity or dc supply for trip circuits is reported to a location
where action can be taken.Any communications system with
continuous monitoring or periodic automated testing for the
presence of the channel function, and alarming for loss of
function. (See Table 2)
Draft 3: November 17, 2010
12
Calen
dar
Years
calend
ar
years
Verify that the alarms will be received at the location where action can be
takenchannel meets performance criteria such as signal level, reflected
power, or data error rate.
Verify essential signals to and from other Protection System components.
27
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Monitor and
alarm for:
•
Station
dc
supply
voltage
Draft 3: November 17, 2010
•
Uninte
ntional
dc
ground
28
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
No Level 2
monitoring
attributes are
defined – use
Level 1
Maintenance
Draft 3:Activities
November 17, 2010
Station
dc
supply
Maxi
mum
Main
tena
nce
Inter
val
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Inspect:
•
Cell condition of individual battery cells where cells are visible, or measure
battery cell/unit internal ohmic values where cells are not visible
•
Physical condition of battery rack
•
The condition of non-battery based dc supply
18 Calendar Months
29
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Station
dc
supply
(that
No Level 2
has as
monitoring
a
are 17, 2010
Draft 3:attributes
November
compo
defined – use
nent
Level 1
Valve
Regula Maintenance
Activities
ted
3 Calendar Years
- or 3 Calendar Months
Verify that the station battery can perform as designed by conducting a performance or
service capacity test of the entire battery bank. (3 calendar years)
30
- or Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (3 months)
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
Station
dc
supply
(that
No Level 2
has as
monitoring
a
attributes are
compo
– use 17, 2010
Draft 3:defined
November
nent
Level 1
Vented Maintenance
LeadActivities
Acid
batterie
6 Calendar Years
- or -
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Verify that the substation battery can perform as designed by conducting a
performance service, or modified performance capacity test of the entire battery bank.
(6 calendar years)
- or -
31
18 Calendar Months
Verify that the station battery can perform as designed by evaluating the measured
cell/unit internal ohmic values to station battery baseline. (18 Months)
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
Station
dc
supply
(that
No Level 2
has as
monitoring
a
attributes are
compo
– use 17, 2010
Draft 3:defined
November
nent
Level 1
Nickel- Maintenance
Cadmi
Activities
um
batterie
6 Calendar Years
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Verify that the substation battery can perform as designed by conducting a
performance service, or modified performance capacity test of the entire battery 32
bank.
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
No Level 2
monitoring
attributes are
defined – use
Level 1
Maintenance
Draft 3:Activities
November 17, 2010
Station
dc
Supply
(batter
y is not
used)
Maxi
mum
Main
tena
nce
Inter
val
6 Calendar Years
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Verify that the dc supply can perform as designed when ac power from the grid is not
present.
33
Standard PRC-005-2 – Protection System Maintenance
Associ
ated
commu
nicatio
ns
system
Monitoring and
alarming of
protection
communications
system by
mechanisms
that check for
presence of the
communications
channel.
12
Calenda
r Years
Verify that
Any communications system
with continuous monitoring or
periodic automated testing for
the performance of the channel
and the quality of the channel
meets performance using
criteria, such as via
measurement of signal level,
reflected power, or data error
rate.
Verify proper functioning of
communications equipment
inputs and outputs that are
essential to proper functioning of
the Protection System.
No
period
ic
maint
enanc
e
specif
ied
None.
Verify the signals to/from the
associated protective relay(s).
Verify proper functioning of alarm
notification., and alarming for
excessive performance
degradation. (See Table 2)
Draft 3: November 17, 2010
34
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
Includes internal
self diagnosis
and alarm
capability, which
must assert for
UVLS
power supply
and
Draft 3:failures.
November 17, 2010
UFLS
Includes input
relays
voltage or
that
current
compri
waveform
se a
sampling three
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
35
Verify the status of relays as in service with no alarms.
Verify acceptable measurement of power system input values the proper function of the
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maxi
mum
Main
tena
nce
Inter
val
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
Relay
sensin
See the
g for
attributes of
centrali
Level 2
zed
See Maintenance Intervals for the individual
Monitoring
UFLS
components of the UFLS/UVLS
forthe individual
orDraft 3: November 17, 2010
components of
UVLS
the SPS
system
s
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Perform all of the Maintenance activities listed above as established for components of
the UFLS or UVLS systems at the intervals established for those individual
components. The output action may be breaker tripping, or other control action that
must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified time interval, but all of the
36 be
UFLS or UVLS components whose operation leads to that control action must each
verified.
Standard PRC-005-2 – Protection System Maintenance
Table 1b — Condition-Based Maintenance - Level 2 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Partially Monitored Protection System Components
General Description: Protection System components whose conditions or alarms are automatically provided daily (or more frequently) to a location where action
can be taken for alarmed failures. Detected maintenance-correctable issues for Level 2 Monitored Protection Systems must be reported within 1 day or less of the
maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of the maintenance-correctable issue. Level 2 monitoring
includes all monitoring attributes as listed below for the individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement R4.Table 1-
2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type
of
Protec
tion
Syste
m
Comp
onent
Level 2 MonitoringComponent Attributes for Component
Protect
ive
Relays
Includes
Maintenance Activities
Verify that the status of relays is normal with no alarms indicated.
•
Internal self diagnosis and alarm capability
•
Alarm must assert for power supply failures
•
Input voltage or current waveform sampling three or
more times per power cycle
Conversion of samples to numeric values for measurement
calculations by microprocessor electronics that are also
performing self diagnosis and alarmingAny unmonitored
communications system necessary for correct operation of
protective functions, and not having all the monitoring
attributes of a category below.
SPS
Maxi
mum
Main
tena
nce
Inter
val
See the
attributes of
Level 2
Monitoring for
the individual
components of
the SPS
See Maintenance Intervals for the individual
components of the SPS
Draft 3: November 17, 2010
12
Calen
dar
Years
3
calend
ar
month
s
Verify acceptable measurement of powercommunications system input
values.
For microprocessor relays, check the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify that settings are as specified.
Verify that the relay alarms will be received at the location where action can
be taken.
Verify correct operation of output actions that are used for trippingis
functional.
Perform all of the Maintenance activities listed above as established for components of
the SPS, at the intervals established for those individual components. The output
action may be breaker tripping, or other control action that must be verified, but may be
verified in overlapping segments. A grouped output control action need be verified only
once within the specified time interval, but all of the SPS components whose operation
leads to that control action must each be verified.
37
Standard PRC-005-2 – Protection System Maintenance
Draft 3: November 17, 2010
38
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and
verified, and detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms
and monitored values are transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection
Systems must be reported within 1 hour or less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of
the maintenance-correctable issue. Level 3 Monitoring includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the
individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement
R4.Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of
Protection
System
Component
Level 3 MonitoringComponent Attributes for Component
Relay A/D converters
are continuously
monitored and alarmed
Continuous
Protective
Relays with
trip contacts
All Level attributes,
except relay possesses
mechanical output
contacts
12 Calendar Years
Alarm on change of settings
Verification of the analog values (magnitude and phase angle) measured by the
microprocessor relay or comparable device, by comparing against other
measurements using otherAny voltage and current sensing devices not having
monitoring attributes of the category below.
Draft 3: November 17, 2010
Maintenance Activities
Continuous verification of the status of the relays
Protective
Relays
Voltage and
Current
Sensing
Inputs to
Protective
Relays and
associated
circuitry
Maximum
Maintena
nce
Interval
Verify proper functioning of the relay trip contacts.
Continuous
12 calendar
years
Continuous verification and
comparisonVerify that acceptable
measurements of the current and voltage
signals fromare received by the voltage
and current sensing devices of the
Protection Systemprotective relays.
39
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and
verified, and detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms
and monitored values are transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection
Systems must be reported within 1 hour or less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of
the maintenance-correctable issue. Level 3 Monitoring includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the
individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement
R4.Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of
Protection
System
Component
Protection
System
control and
trip circuitry
Station dc
supply
Station dc
supply (that
has as a
component
Valve
Regulated
Lead-Acid
batteries)
Level 3 MonitoringComponent Attributes for Component
Monitoring and
alarming of the alarm
path itself
No Level 3 monitoring
attributes are defined –
use Level 1
Maintenance Activities
and intervals
No Level 3 monitoring
attributes are defined –
use Level 1
Maintenance Activities
and intervals
Draft 3: November 17, 2010
Continuous
18 Calendar Months
3 Calendar Years
- or 3 Calendar Months
Maximum
Maintena
nce
Interval
Maintenance Activities
Continuous verification of the status of the monitored
control circuits
Inspect:
•
Cell condition of all individual battery cells
where cells are visible – or measure battery
cell/unit internal ohmic values where the cells
are not visible
•
Physical condition of battery rack
•
The condition of non-battery-based dc supply
Verify that the station battery can perform as designed
by conducting a performance or service capacity test of
the entire battery bank. (3 calendar years)
- or Verify that the station battery can perform as designed
by evaluating the measured cell/unit internal ohmic
values to station battery baseline. (3 months)
40
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and
verified, and detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms
and monitored values are transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection
Systems must be reported within 1 hour or less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of
the maintenance-correctable issue. Level 3 Monitoring includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the
individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement
R4.Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of
Protection
System
Component
Level 3 MonitoringComponent Attributes for Component
Station dc
supply (that
has as a
component
Vented LeadAcid
Batteries)
No Level 3 monitoring
attributes are defined –
use Level 1
Maintenance Activities
and intervals
Station dc
supply (that
has as a
component
NickelCadmium
batteries)
No Level 3 monitoring
attributes are defined –
use Level 1
Maintenance Activities
and intervals
6 Calendar Years
- or 18 Calendar Months
Maximum
Maintena
nce
Interval
Maintenance Activities
Verify that the station battery can perform as designed
by conducting a performance service, or modified
performance capacity test of the entire battery bank. (6
calendar years)
- or Verify that the station battery can perform as designed
by evaluating the measured cell/unit internal ohmic
values to station battery baseline. (18 Months)
Draft 3: November 17, 2010
6 Calendar Years
Verify that the substation battery can perform as
designed by conducting a performance service, or
modified performance capacity test of the entire battery
bank.
41
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and
verified, and detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms
and monitored values are transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection
Systems must be reported within 1 hour or less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of
the maintenance-correctable issue. Level 3 Monitoring includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the
individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement
R4.Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of
Protection
System
Component
Station dc
Supply (any
battery
technology)
Level 3 MonitoringComponent Attributes for Component
Monitoring and
alarming for station dc
supply voltage,
unintentional dc
grounds, electrolyte
level of all cells of a
station battery,
individual battery
cell/unit state of charge,
battery continuity of
station battery and cellto-cell and battery
terminal resistance
Draft 3: November 17, 2010
Continuous
Maximum
Maintena
nce
Interval
Maintenance Activities
Continuous monitoring of station dc supply voltage,
unintentional dc grounds, electrolyte level of all cells of
a station battery, individual battery cell/unit state of
charge, battery continuity of station battery and cell-tocell and battery terminal resistance are provided with
alarming to remote location upon any failure of the
monitoring device or when sensors for the devises are
out of calibration.
42
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and
verified, and detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms
and monitored values are transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection
Systems must be reported within 1 hour or less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of
the maintenance-correctable issue. Level 3 Monitoring includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the
individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement
R4.Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of
Protection
System
Component
Level 3 MonitoringComponent Attributes for Component
Station dc
Supply which
do not use a
station
battery
No Level 3 monitoring
attributes are defined –
use Level 1
Maintenance Activities
and intervals
Associated
communicatio
ns systems
Evaluating the
performance of the
channel and its
interface to protective
relays to determine the
quality of the channel
and alarming if the
channel does not meet
performance criteria
Draft 3: November 17, 2010
6 Calendar Years
Maximum
Maintena
nce
Interval
Maintenance Activities
Verify that the dc supply can perform as designed when
the ac power from the grid is not present.
Continuous verification that the performance and quality
of the channel meets performance criteria is provided.
Continuous
Continuous verification of the communications
equipment alarm system is provided.
43
Standard PRC-005-2 – Protection System Maintenance
Table 1c — Condition-based Maintenance — Level 3 Monitoring
Maximum Allowable Testing Intervals and Maintenance Activities for Fully Monitored Protection System Components
General Description: Protection System components in which every function required for correct operation of that component is continuously monitored and
verified, and detected maintenance-correctable issues reported. Level 3 Monitored Protection Systems also includes verification of the means by which alarms
and monitored values are transmitted to a location where action can be taken. Detected maintenance-correctable issues for Level 3 Monitored Protection
Systems must be reported within 1 hour or less of the maintenance-correctable issue occurring, to a location where action can be taken to initiate resolution of
the maintenance-correctable issue. Level 3 Monitoring includes all attributes of Level 2 Monitoring, with additional monitoring attributes as listed below for the
individual type of component.
General Maintenance Requirements: Perform maintenance activities listed and initiate necessary corrective actions in accordance with Requirement
R4.Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Type of
Protection
System
Component
UVLS and
UFLS relays
that comprise
a protection
scheme
distributed
over the
power
system.
Level 3 MonitoringComponent Attributes for Component
Maximum
Maintena
nce
Interval
Maintenance Activities
Continuous verification of the status of the relays
The relay A/D
converters are
continuously monitored
and alarmed.
Draft 3: November 17, 2010
Continuous
Alarm on change of settings
Verification does not require actual tripping of circuit
breakers or interrupting devices
44
Standard PRC-005-2 – Protection System Maintenance
Relay
sensing for
centralized
UFLS or
UVLS
systems.
See the attributes of
Level 3 Monitoring for
the individual
components of the
UFLS/UVLS
See
Maintenan
ce
Activities
Perform all of the Maintenance activities
listed above as established for components
of the UFLS or UVLS systems at the
intervals established for those individual
components. The output action may be
breaker tripping, or other control action that
must be verified, but may be verified in
overlapping segments. A grouped output
control action need be verified only once
within the specified time interval, but all of
the UFLS or UVLS components whose
operation leads to that control action must
each be verified.Voltage and Current
No
periodic
maintenanc
e specified
None.
Sensing devices connected to
microprocessor relays with AC
measurements are continuously verified by
comparison of sensing input value as
measured by the microprocessor relay to an
independent ac measurement source, with
alarming for unacceptable error or failure.
SPS
See the attributes of
Level 3 Monitoring for
the individual
components of the SPS
See Maintenance Activities
Perform all of the Maintenance activities listed above as
established for components of the SPS at the intervals
established for those individual components. The
output action may be breaker tripping, or other control
action that must be verified, but may be verified in
overlapping segments. A grouped output control action
need be verified only once within the specified time
interval, but all of the SPS components whose operation
leads to that control action must each be verified.
Notes for Table 1a, Table 1b, and Table 1c
For some Protection System components, adjustment is required to bring measurement accuracy within parameters established by the asset owner based on the specific application
of the component. A calibration failure is the result if testing finds the specified parameters to be out of tolerance.
Draft 3: November 17, 2010
45
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Any dc supply for a UFLS or UVLS system.
Maximum
Maintenance
Interval
When control
circuits are
verified
3 Calendar
Months
Any unmonitored station dc supply not having the monitoring
attributes of a category below. (excluding UFLS and UVLS)
18 Calendar
Months
Any unmonitored Station dc supply in which a battery is not used and
not having the monitoring attributes of a category below. (excluding
UFLS and UVLS)
Unmonitored Station dc supply with Valve Regulated Lead-Acid
(VRLA) batteries that does not have the monitoring attributes of a
category below. (excluding UFLS and UVLS)
Draft 3: November 17, 2010
Activities
Verify dc supply voltage
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level (excluding valve-regulated lead acid
batteries)
• For unintentional grounds
Verify:
• State of charge of the individual battery cells/units
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
6 Calendar Years
Verify that the dc supply can perform as designed when ac power
from the grid is not present.
3 Calendar
Months
Verify that the station battery can perform as designed by
evaluating the measured cell/unit internal ohmic values to station
battery baseline.
46
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Activities
--------------------------------- or ---------------------------------
3 Calendar Years
Verify that the station battery can perform as designed by
evaluating the measured cell/unit internal ohmic values to station
battery baseline.
18 Calendar
Months
Unmonitored Station dc supply with Vented Lead-Acid Batteries
(VLA) that does not have the monitoring attributes of a category
below. (excluding UFLS and UVLS)
Unmonitored Station dc supply with Nickel-Cadmium (Ni-Cad)
batteries that does not have the monitoring attributes of a category
below. (excluding UFLS and UVLS)
Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2):
• Station dc supply voltage (voltage of battery charger)
• State of charge of the individual battery cell/units
• Battery continuity of station battery
• Cell-to-cell (if available) and battery terminal resistance
Draft 3: November 17, 2010
Verify that the station battery can perform as designed by
conducting a performance or service capacity test of the entire
battery bank.
--------------------------------- or ---------------------------------
6 Calendar Years
Verify that the station battery can perform as designed by
conducting a performance, service, or modified performance
capacity test of the entire battery bank.
6 Calendar Years
Verify that the station battery can perform as designed by
conducting a performance service, or modified performance
capacity test of the entire battery bank.
18 calendar
months
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
47
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
• Electrolyte level of all cells in a station battery
• Unintentional dc grounds
• Cell/unit internal ohmic values of station battery
Continuously monitored Station dc supply (excludes UFLS and
UVLS) with preceding row attributes and the following:
• The monitoring devices themselves are monitored.
Draft 3: November 17, 2010
Maximum
Maintenance
Interval
6 calendar years
18 calendar
months
Activities
Verify that the monitoring devices are calibrated (where
necessary)
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
48
Standard PRC-005-2 – Protection System Maintenance
Table 1-5
Component Type - Control Circuitry
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (excluding UFLS or UVLS systems).
Trip coils of circuit breakers and interrupting devices in UFLS or UVLS
systems.
Maximum
Maintenance
Interval
6 calendar
years
No periodic
maintenance
specified
Activities
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
None.
Electromechanical trip or auxiliary devices
6 calendar
years
Verify electrical operation of electromechanical trip and
auxiliary devices
Unmonitored Control circuitry associated with protective functions
12 calendar
years
Verify all paths of the control and trip circuits.
Control circuitry whose continuity and energization or ability to operate are
monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Draft 3: November 17, 2010
49
Standard PRC-005-2 – Protection System Maintenance
Table 2 – Alarming Paths
In Tables 1-1 through 1-5, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance activities are
subject to the following maintenance requirements
Maximum
Component Attributes
Maintenance
Activities
Interval
Any alarm path through which alarms in Tables 1-1 through 1-5 are conveyed
from the alarm origin to the location of corrective action, and not having all the
attributes of the category below.
Alarms are automatically reported within 24 hours of DETECTION to a
location where corrective action can be taken.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be taken.
Draft 3: November 17, 2010
When alarm
producing device or
system is verified
No periodic
maintenance
specified
Verify that the alarm signals are conveyed to a
location where corrective action can be taken.
None.
50
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
Segment: In this procedure, the term, “segment” is a grouping of Protection Systems or
components from a single manufacturer, with common factors such that consistent performance
is expected across the entire population of the segment, and shall only be defined for a
population of 60 or more individual components. 4
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of components included in each designated segment of
the Protection System component population.
2. Maintain the components in each segment according to the time-based maximum
allowable intervals established in Table 1Tables 1-1through 1-5 until results of
maintenance activities for the segment are available for a minimum of 30 individual
components of the segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events 5 for each included component.
4. Analyze the maintenance program activities and results for each segment to determine the
overall performance of the segment and develop maintenance intervals.
5. Determine the maximum allowable maintenance interval for each segment such that the
segment experiences countable events on no more than 4% of the components within the
segment, for the greater of either the last 30 components maintained or all components
maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
4. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
4
Entities with smaller populations of component devices may aggregate their populations to define a segment and
shall share all attributes of a single performance-based program for that segment.
5
Countable events include any failure of a component requiring repair or replacement, any condition discovered
during the verification activities in Table 1a through Table 1c which requires corrective action, or a Misoperation
attributed to hardware failure or calibration failure.
Draft 3: November 17, 2010
51
Standard PRC-005-2 – Protection System Maintenance
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
5. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
Draft 3: November 17, 2010
52
Implementation Plan for PRC-005-02
Standards Involved:
• Approval:
o PRC-005-2 – Protection System Maintenance and Testing
•
Retirements:
o PRC-005-1 – Transmission and Generation Protection System Maintenance and Testing
o PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding
o Equipment Maintenance Program
o PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
o PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
• Revised definition of “Protection System”
Background:
The Implementation Plan reflects consideration of the following:
1. The requirements set forth in the proposed standard establish maximum allowable maintenance
intervals for the first time. The established maximum allowable intervals may be shorter than those
currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the proposed
standard, it is unrealistic for those entities to be immediately in compliance with the new intervals.
Further, entities should be allowed to become compliant in such a way as to facilitate a continuing
maintenance program.
3. Entities that have previously been performing maintenance within the newly specified intervals may
not have all the documentation needed to demonstrate compliance with all of the maintenance
activities specified.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall follow the protection
system maintenance and testing program it used to perform maintenance and testing to comply with PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 (for the protection system components identified in PRC005-2 Tables 1-1 through 1-5) until that Transmission Owner, Generator Owner or Distribution Provider
meets initial compliance for maintenance of the same protection system component, in accordance with
the phasing specified below.
For audits that are conducted during the time period when entities are modifying their existing protection
system maintenance and testing programs to become compliant with the maintenance activities and
intervals specified in PRC-005-2, each responsible entity must be prepared to identify:
•
All of its applicable protection system components.
•
For each component, whether maintenance of that component is still being addressed under PRC005-1 or is being performed according toPRC-005-2.
•
Evidence that each component has been maintained under the relevant requirements.
116-390 Village Blvd.
Princeton, NJ 08540
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Retirement of Existing Standards:
The existing Standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired upon
regulatory approval of PRC-005-2.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2, R3, and R4 which use this defined term.
Implementation plan for Requirement R1:
•
Entities shall be 100% compliant on the first day of the first calendar quarter twelve months
following applicable regulatory approvals, or in those jurisdictions where no regulatory approval
is required, on the first day of the first calendar quarter six months following Board of Trustees
adoption.
Implementation plan for Requirements R2, R3, and R4:
1. For Protection System Components with maximum allowable intervals of less than 1 year, as
established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 12
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 12 months
following Board of Trustees adoption.
2. For Protection System Components with maximum allowable intervals 1 year or more, but 2
years or less, as established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 2 calendar
years following Board of Trustees adoption.
3. For Protection System Components with maximum allowable intervals of 6 years, as established
in Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval (or, for generating plants with
scheduled outage intervals exceeding two calendar years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter 2 calendar years following Board of
Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 4
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 6
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 6 calendar
years following Board of Trustees adoption.
Draft 3: November 17, 2010
2
4. For Protection System Components with maximum allowable intervals of 12 years, as established
in Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 4
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter
following 8 calendar years following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 8 calendar years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 12
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 12
calendar years following Board of Trustees adoption.
Applicability:
This standard applies to the following functional entities:
•
Transmission Owners
•
Generator Owners
•
Distribution Providers
Draft 3: November 17, 2010
3
Draft Implementation Plan for PRC-005-02
Standards Involved:
• Approval:
o PRC-005-2 – Protection System Maintenance and Testing
•
Retirements:
o PRC-005-1 – Transmission and Generation Protection System Maintenance and Testing
o PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding
o Equipment Maintenance Program
o PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
o PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
• Revised definition of “Protection System”
Background:
In developing the implementation plan, the Standard Drafting Team consideredThe
Implementation Plan reflects consideration of the following:
1. The requirements set forth in the proposed standard establish maximum allowable maintenance
intervals for the first time. The established maximum allowable intervals may be shorter than those
currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the proposed
standard, it is unrealistic for those entities to be immediately in compliance with the new intervals.
Further, entities should be allowed to become compliant in such a way as to facilitate a continuing
maintenance program.
3. Entities that have previously been performing maintenance within the newly specified intervals may
not have all the documentation needed to demonstrate compliance with all of the maintenance
activities specified.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall follow the protection
system maintenance and testing program it used to perform maintenance and testing to comply with PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 (for the protection system components identified in PRC005-2 Table 1aTables 1-1 through 1-5) until that Transmission Owner, Generator Owner or Distribution
Provider meets initial compliance for maintenance of the same protection system component, in
accordance with the phasing specified below.
For audits that are conducted during the time period when entities are modifying their existing protection
system maintenance and testing programs to become compliant with the maintenance activities and
intervals specified in PRC-005-2, each responsible entity must be prepared to identify:
•
All of its applicable protection system components.
•
For each component, whether maintenance of that component is still being addressed under PRC005-1 or has been moved under PRCis being performed according toPRC-005-2.
•
Evidence that each component has been maintained under the relevant requirements.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Retirement of Existing Standards:
The existing Standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired upon
regulatory approval of PRC-005-2.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2, R3, and R4 which use this defined term.
Implementation plan for Requirement R1:
•
Entities shall be 100% compliant on the first day of the first calendar quarter threetwelve months
following applicable regulatory approvals, or in those jurisdictions where no regulatory approval
is required, on the first day of the first calendar quarter six months following Board of Trustees
adoption.
Implementation plan for Requirements R2, R3, and R4:
1. For Protection System Components with maximum allowable intervals of less than 1 year, as
established in Table 1a, Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 12
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 12 months
following Board of Trustees adoption.
2. For Protection System Components with maximum allowable intervals 1 year or more, but 2
years or less, as established in Table 1a, Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 2 calendar
years following Board of Trustees adoption.
3. For Protection System Components with maximum allowable intervals of 6 years, as established
in Table 1a, Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval, (or, for generating plants with
scheduled outage intervals exceeding two calendar years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter 2 calendar years following Board of
Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 4
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 6
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 6 calendar
years following Board of Trustees adoption.
Draft 2: April 163: November 17, 2010
2
4. For Protection System Components with maximum allowable intervals of 12 years, as established
in Table 1a, Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 4
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter
following 8 calendar years following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 8 calendar years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 12
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 12
calendar years following Board of Trustees adoption.
Applicability:
This standard applies to the following functional entities:
•
Transmission Owners
•
Generator Owners
•
Distribution Providers
Draft 2: April 163: November 17, 2010
3
Unofficial Comment Form for 3rd Draft of PRC-005-2 – Protection System
Maintenance [Project 2007-17]
Please DO NOT use this form to submit comments on the 3rd draft of the standard for
Protection System Maintenance and Testing. Comments must be submitted by December
17, 2010. If you have questions please contact Al McMeekin at [email protected] or
by telephone at 803-530-1963.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Background Information:
The Protection System Maintenance and Testing Standard Drafting Team (PSMT SDT) has
made substantial changes to the third posting of PRC-005-2 based on comments received
from the industry. The changes include:
•
Adding more definitions of terms used in the body of the standard.
•
Revisions to the standard and tables to remove complexity.
•
Revisions to the implementation period.
•
Revisions to the Supplemental Reference and the FAQ documents.
•
Revisions to the Measures, Time Horizons, Violation Risk Factors (VRFs) and
Violation Security Levels (VSLs).
The PSMT SDT would like to receive industry comments on this standard.
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The SDT has restructured the tables to improve clarity, but did not appreciably change the content.
Do you agree that the restructured tables are clearer? If not, please provide specific suggestions for
improvement.
Yes
No
Comments:
2. The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do you agree with the
changes? If not, please provide specific suggestions for improvement.
Yes
No
Comments:
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Princeton, New Jersey 08540-5721
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Comment Form — Protection System Maintenance and Testing Project Number 2007-17
3. The SDT has provided the “Supplementary Reference” document to provide supporting discussion
for the Requirements within the standard. Do you have any specific suggestions for improvements?
Yes
No
Comments:
4. The SDT has provided the “Frequently-Asked Questions” (FAQ) document to address anticipated
questions relative to the standard. Do you have any specific suggestions for improvements?
Yes
No
Comments:
5. If you have any other comments on this Standard that you have not already provided in response to
the prior questions, please provide them here.
Comments:
2
NERC Protection System Maintenance Standard
PRC-005-2
FREQUENTLY ASKED QUESTIONS Practical Compliance and Implementation
November 17, 2010
Informative Annex to Standard PRC-005-2
Prepared by the
Protection System Maintenance and Testing Standard Drafting Team
Table of Contents
Table of Contents
Introduction .................................................................................................................................................................2
Executive Summary .....................................................................................................................................................2
Terms Used in PRC-005-2...........................................................................................................................................2
Frequently Asked Questions .......................................................................................................................................2
I
General FAQs: .................................................................................................................................................2
II
Group by Type of Protection System Component:............................................................................................4
1.
All Protection System Components...................................................................................................................4
2.
Protective Relays ..............................................................................................................................................4
3.
Voltage and Current Sensing Device Inputs to Protective Relays ....................................................................8
4.
Protection System Control Circuitry ................................................................................................................9
5.
Station dc Supply ............................................................................................................................................ 11
6.
Protection System Communications Equipment ............................................................................................. 15
7.
UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power System ................ 18
8.
SPS or Relay Sensing for Centralized UFLS or UVLS ................................................................................... 19
III
Group by Type of BES Facility: ..................................................................................................................... 19
1.
All BES Facilities ........................................................................................................................................... 19
2.
Generation ...................................................................................................................................................... 20
3.
Transmission .................................................................................................................................................. 21
IV
Group by Type of Maintenance Program:...................................................................................................... 21
1.
All Protection System Maintenance Programs ............................................................................................... 21
2.
Time-Based Protection System Maintenance (TBM) Programs ..................................................................... 23
3.
Performance-Based Protection System Maintenance (PBM) Programs ........................................................ 25
V
Group by Monitoring Level: ........................................................................................................................... 30
1.
All Monitoring Levels ..................................................................................................................................... 30
2.
Unmonitored Protection Systems ................................................................................................................... 33
3.
Monitored Protection Systems ........................................................................................................................ 33
4.
Monitored Protection Systems that also monitor alarm path failures ............................................................ 34
Appendix A — Protection System Maintenance Standard Drafting Team .......................................................... 35
Index ........................................................................................................................................................................... 36
i
PRC-005-2 Frequently-Asked Questions
Introduction
The following is a draft collection of questions and answers that the PSMT SDT believes could be helpful
to those implementing NERC Standard PRC-005-2 Protection System Maintenance. As the draft standard
proceeds through development, this FAQ document will be revised, including responses to key or frequent
comments from the posting process. The FAQ will be organized at a later time during the development of
the draft Standard.
This FAQ document will support both the Standard and the associated Technical Reference document.
Executive Summary
•
Write later if needed
Terms Used in PRC-005-2
Frequently Asked Questions
I
General FAQs:
1. The standard seems very complicated, and is difficult to understand. Can it be simplified?
Because the standard is establishing parameters for condition-based Maintenance (R2) and
performance-based Maintenance (R3) in addition to simple time-based Maintenance, it does appear
to be complicated. At its simplest, an entity needs to and perform ONLY time-based maintenance
according to the unmonitored rows of the Tables. If an entity then wishes to take advantage of
monitoring on its Protection System components and its available lengthened time intervals then it
may, as long as the component has the listed monitoring attributes. If an entity wishes to use
historical performance of its Protection System components to perform performance-based
Maintenance, then R3 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
2
PRC-005-2 Frequently-Asked Questions
Requirements
Flowchart
Start
PRC-005-2
Note: GO, DP, & TO
may use one or
multiple programs
Each GO, DP, & TO
shall establish a
maintenance
program [R1]
Performance
Based
Time Based
Decide if using Time Based, Condition
Baesd, and/or Performance Based
program
◊
◊
Condition Based
◊
Ensure
components
have necessary
monitoring [R2]
Separate components into
appropriate families of 60 or more
Maintain components for each
segment per Table One until at least
30 components have been tested
Analyze data to determine
appropriate interval for segment(s)
[R3]
Perform maintenance activities from
Table One for each segment with interval
from analysis above and collect data for
future analysis
[R3, R4.4.2]
◊
Maintain components
per Table One
Intervals and
Activities [R4.4.1]
◊
◊
Collect countable events from
maintenance and failures
Analyze data from maintenance of
last 30 components and/or last year
to verify countable events below 4%
Adjust maintenance interval to keep
countable events below 4%
[R3]
Implement corrective
actions as needed [R4]
End
3
PRC-005-2 Frequently-Asked Questions
II
Group by Type of Protection System Component:
1. All Protection System Components
A.
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this standard?
No. As stated in Requirement R1, this standard covers protective relays that use measurements
of voltage, current and/or phase angle to determine anomalies and to trip a portion of the BES.
Reclosers, reclosing relays, closing circuits and auto-restoration schemes are used to cause
devices to close as opposed to electrical-measurement relays and their associated circuits that
cause circuit interruption from the BES; such closing devices and schemes are more
appropriately covered under other NERC Standards. There is one notable exception: if a
Special Protection System incorporates automatic closing of breakers, the related closing
devices are part of the SPS and must be tested accordingly.
B.
Why does PRC-005-2 not specifically require maintenance and testing procedures as
reflected in the previous standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the tables 1-1 through 1-5 and Table 2 (collectively the “Tables”), and the various
components of the definition established for a “Protection System Maintenance Program”,
PRC-005-2 establishes the activities and time-basis for a Protection System Maintenance
Program to a level of detail not previously required.
2. Protective Relays
A.
How do I approach testing when I have to upgrade firmware of a microprocessor relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity
has the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
B.
Please clarify what is meant by restoration in the definition of maintenance.
4
PRC-005-2 Frequently-Asked Questions
The description of “Restoration” in the definition of a Protection System Maintenance
Program, addresses corrective activities necessary to assure that the component is returned to
working order following the discovery of its failure or malfunction. The Maintenance
Activities specified in the Tables do not present any requirements related to Restoration; R4.3
of the standard does require that the entity “initiate any necessary activities to correct
unresolved maintenance correctable issues”. Some examples of restoration (or correction of
maintenance-correctable issues) include, but are not limited to, replacement of capacitors in
distance relays to bring them to working order; replacement of relays, or other Protection
System components, to bring the Protection System to working order; upgrade of electromechanical or solid-state protective relays to micro-processor based relays following the
discovery of failed components. Restoration, as used in this context is not to be confused with
Restoration rules as used in system operations. Maintenance activity necessarily includes both
the detection of problems and the repairs needed to eliminate those problems. This standard
does not identify all of the Protection System problems that must be detected and eliminated,
rather it is the intent of this standard that an entity determines the necessary working order for
their various devices and keeps them in working order. If an equipment item is repaired or
replaced then the entity can restart the maintenance-time-interval-clock if desired, however the
replacement of equipment does not remove any documentation requirements that would have
been required to verify compliance with time-interval requirements; in other words do not
discard maintenance data that goes to verify your work
C.
If I upgrade my old relays then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced then the entity can restart the maintenanceactivity-time-interval-clock if desired, however the replacement of equipment does not remove
any documentation requirements. The requirements in the standard are intended to ensure that
an entity has a maintenance plan and that the entity adheres to minimum activities and
maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
D.
What is meant by “Verify that settings are as specified” maintenance activity in Table 11?
Verification of settings is an activity directed mostly towards microprocessor based relays.
For relay maintenance departments that choose to test microprocessor based relays in the same
manner as electro-mechanical relays are tested, the testing process sometimes requires that
some specific functions be disabled. Later tests might enable the functions previously disabled
but perhaps still other functions or logic statements were then masked out. It is imperative that,
when the relay is placed into service, the settings in the relay be the settings that were intended
to be in that relay or as the Standard states “…settings are as specified.”
Many of the microprocessor based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
5
PRC-005-2 Frequently-Asked Questions
The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is simply to
check that the settings in the relay match the settings specified to those placed into the relay.
E.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection, and thus the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
F.
I use my protective relays only as sources of metered quantities and breaker status for
SCADA and EMS through a substation distributed RTU or data concentrator to the
control center. What are the maintenance requirements for the relays?
This standard addresses only devices “that are applied on, or are designed to provide
protection for the BES.” Protective relays, providing only the functions mentioned in the
question, are not included.
G.
I use my protective relays for fault and disturbance recording, collecting oscillographic
records and event records via communications for fault analysis to meet NERC and
DME requirements. What are the maintenance requirements for the relays?
For relays used only as disturbance monitoring equipment, the NERC standard PRC-018-1 R3
& R6 states the maintenance requirements, and is being addressed by a Standards activity that
is revising PRC-002-1 and PRC-018-1. For protective relays “that are applied on, or are
designed to provide protection for the BES,” this standard applies, even if they also perform
DME functions.
H.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system rating
changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system up-rates, upgrades and overall changes meet any and all other
requirements and standards then the requirements of PRC-005-2 are simple – if the Protection
system component performs a Protection system function then it must be maintained. If the
component no longer performs Protection System functions than it does not require
maintenance activities under the Tables of PRC-005-2. While many entities might physically
remove a component that is no longer needed there is no requirement in PRC-005-2 to remove
such component(s). Obviously, prudence would dictate that an “out-of-service” device is truly
made inactive. There are no record requirements listed in PRC-005-2 for Protection System
components not used.
I.
While performing relay testing of a protective device on our Bulk Electric System it was
discovered that the protective device being tested was either broken or out of calibration.
6
PRC-005-2 Frequently-Asked Questions
Does this satisfy the relay testing requirement even though the protective device tested
bad, and may be unable to be placed back into service?
Yes, PRC-005-2 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-2
requirement although the protective device may be unable to be returned to service under
normal calibration adjustments. R4.3 states (the entity must):
The entity must assure either that the components are within acceptable parameters at the
conclusion of the maintenance activities or initiate any necessary activities to correct
unresolved maintenance correctable issues.
J.
If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R4.3) (in essence) state that the entity assure the
components are within the owner’s acceptable operating parameters, if not then actions must
be initiated to correct the deviance. The type of corrective activity is not stated; however it
could include repairs or replacements. Documentation is always a necessity (“If it is not
documented then it wasn’t done!”)
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
K.
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
L.
What is meant by “verify operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System?”
Any input or output that “affects the tripping” of the breaker is included in the scope of I/O to
be verified. By “affects the tripping” one needs to realize that sometimes there are more Inputs
and Outputs than simply the output to the trip coil. Many important protective functions include
things like Breaker Fail Initiation, Zone Timer Initiation and sometimes even 52a/b contact
inputs are needed for a protective relay to correctly operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay.
Each input detector on a component that is needed for a protective function and each output
action from a component that is needed for a protective function needs to be tested.
In short, if an entity designed a scheme into the protective functions then that scheme needs to
be tested.
7
PRC-005-2 Frequently-Asked Questions
3. Voltage and Current Sensing Device Inputs to Protective Relays
A.
What is meant by “…verify the current and voltage circuit inputs from the voltage and
current sensing devices to the protective relays …” Do we need to perform ratio,
polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current sensing devices (typically voltage and current transformers). This can be as
difficult as is proposed by the question (with additional testing on the cabling and substation
wiring to ensure that the values arrive at the relays); or simplicity can be achieved by other
verification methods. While some examples follow, these are not intended to represent an allinclusive list; technology advances and ingenuity should not be excluded from making
comparisons and verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional testing on the
panel wiring to ensure that the values arrive at those relays) with the other phases, and verify
that residual currents are within expected bounds
•
Observe all three phase currents and the residual current at the relay panel with an oscilloscope,
observing comparable magnitudes and proper phase relationship, with additional testing on the
panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay (such as, but not limited to, a query
to the microprocessor relay), to another protective relay monitoring the same line, with currents
supplied by different CT’s.
•
Compare the secondary values, at the relay with values measured by test instruments (such as,
but not limited to multi-meters, voltmeter, clamp-on ammeters, etc) and verified by calculations
and known ratios to be the values expected. For example a single PT on a 100KV bus will have
a specific secondary value that when multiplied by the PT ratio arrives at the expected bus
value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned relay,
compare those SCADA values to the values as determined by the questioned relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by the
questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that, an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring systems.
B.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral currents, or
3V0 voltages, by comparison, when my system is closely balanced?
8
PRC-005-2 Frequently-Asked Questions
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known fault locations.
C.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify
the insulation of the wiring between the instrument transformer and the relay.
D.
My plant generator and transformer relays are electromechanical and do not have
metering functions as do microprocessor based relays. In order for me to compare the
instrument transformer inputs to these relays to the secondary values of other metered
instrument transformers monitoring the same primary voltage and current signals, it
would be necessary to temporarily connect test equipment like voltmeters and clamp on
ammeters to measure the input signals to the relays. This practice seems very risky and
a plant trip could result if the technician were to make an error while measuring these
current and voltage signals. How can I avoid this risk? Also, what if no other
instrument transformers are available which monitor the same primary voltage or
current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests
to adequately “verify the current and voltage circuit inputs from the voltage and current
sensing devices to the protective relays …” while eliminating the risk of tripping an in service
generator or transformer. Similarly, this same offline test methodology can be used to verify
the relay input voltage and current signals to relays when there are no other instrument
transformers monitoring available for purposes of signal comparison.
4. Protection System Control Circuitry
A.
Is it permissible to verify circuit breaker tripping at a different time (and interval) than
when we verify the protective relays and the instrument transformers?
9
PRC-005-2 Frequently-Asked Questions
Yes, provided the entire Protective System is tested within the individual components’
maximum allowable testing intervals.
B.
The Protection System Maintenance Standard describes requirements for verifying the
tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC-005-2 are intended to verify the integrity of tripping circuits, including
the breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for
energizing the trip coil if a protection function operates. Beyond this, PRC-005-2 sets no
requirements for verifying circuit breaker performance, or for maintenance of the circuit
breaker.
C.
How do I test each dc Control Circuit path, as established in Table 1-5 “Protection
System Control Circuitry (Trip coils and auxiliary relays)”?
Table 1-5 specifies that each breaker trip coil, auxiliary relay, and lockout relay must
be operated within the specified time period. The required operations may be via
targeted maintenance activities, or by documented operation of these devices for other
purposes such as fault clearing.
D.
What does this standard require for testing an Auxiliary Tripping Relay?
Table 1 requires that the trip test must verify that the auxiliary tripping relay(s) and/or lockout
relay(s) operate(s) electrically and that their trip output(s) perform as expected. Auxiliary
outputs not in a trip path (i.e. annunciation or DME input) are not required, by this standard, to
be checked.
E.
What does a functional (or operational) trip test include?
An operational trip test must be performed on a trip device. Each control circuit path that
produces a trip signal must be verified; this includes trip coils, auxiliary tripping relays,
lockout relays, and communications-assisted-trip schemes.
A trip test may be an overall test that verifies the operation of the entire trip scheme at once, or
it may be several tests of the various portions that make up the entire trip path, provided that
testing of the various portions of the trip scheme verifies all of the portions, including parallel
paths, and overlaps those portions.
A circuit breaker or other interrupting device needs to be trip tested at least once per trip coil.
Discrete-component auxiliary relays and lock-out relays must be verified by trip test. The trip
test must verify that the auxiliary or lock-out relay operates electrically and that the relay’s trip
output(s) change(s) state. Software latches or control algorithms, including trip logic
processing implemented as programming component such as a microprocessor relay that take
the place of (conventional) discrete component auxiliary relays or lock-out relays do not have
to be routinely trip tested.
Normally-closed auxiliary contacts from other devices (for example, switchyard-voltage-level
disconnect switches, interlock switches, or pressure switches) which are in the breaker trip
path do not need to be tested.
F.
Is a Sudden Pressure Relay an Auxiliary Tripping Relay?
10
PRC-005-2 Frequently-Asked Questions
No. IEEE C37.2-2008 assigns the device number 94 to auxiliary tripping relays. Sudden
pressure relays are assigned device number 63, and is excluded from the Standard because it
does not utilize voltage and/or current measurements to determine anomalies. Devices that use
anything other than electrical detection means are excluded.
G.
The standard specifically mentions Auxiliary and Lock-out relays; what is an Auxiliary
Tripping Relay?
An auxiliary relay, IEEE Device Number 94, is described in IEEE Standard C37.2-2008 as “A
device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate
tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should
open automatically, even though its closing circuit is maintained closed.”
H.
What is a Lock-out Relay?
A lock-out relay, IEEE Device Number 86, is described in IEEE Standard C37.2 as “A device
that trips and maintains the associated equipment or devices inoperative until it is reset by an
operator, either locally or remotely.”
I.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of the trip circuit. This standard does not
cover circuit breaker maintenance or transformer maintenance. The standard also does not
cover testing of devices such as sudden pressure relays (63), temperature relays (49), and other
relays which respond to mechanical parameters rather than electrical parameters.
5. Station dc Supply
A.
What constitutes the station dc supply as mentioned in the definition of Protective
System?
The station direct current (dc) supply normally consists of two components: the battery
charger and the station battery itself. There are also emerging technologies that provide a
source of dc supply that does not include either a battery or charger.
Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1.
Emerging Technologies - Station dc supplies are currently being developed that use other
energy storage technologies beside the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1 presents maintenance activities and maximum allowable testing
11
PRC-005-2 Frequently-Asked Questions
intervals for these new station dc supply technologies. However, because these technologies
are relatively new the maintenance activities for these station dc supplies may change over
time.
B.
In the Maintenance Activities for station dc supply in Table 1, what do you mean by
“continuity”?
Because the Standard pertains to maintenance not only of the station battery, but also the
whole station dc supply, continuity checks of the station dc supply are required. “Continuity”
as used in Table 1 refers to verifying that there is a continuous current path from the positive
terminal of the station battery set to the negative terminal, otherwise there is no way of
determining that a station battery is available to supply dc current to the station.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path the battery set will not be
available for service.
C.
Why is it necessary to verify the continuity of the dc supply?
In the event of the loss of the ac source or battery charger, the battery must be capable of
supplying dc current, both for continuous dc loads and for tripping breakers and switches.
Without continuity, the battery cannot perform this function.
If the battery charger is not sized to handle the maximum dc current required to operate the
protective systems, it is sized only to handle the constant dc load of the station and the
charging current required to bring the battery back to full charge following a discharge. At
those stations, the battery charger would not be able to trip breakers and switches if the battery
experiences loss of continuity.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
◊
◊
D.
Many battery chargers produce harmonics which can cause failure of dc power supplies in
microprocessor based protective relays and other electronic devices connected to station
dc supply. In these cases, the substation battery serves as a filter for these harmonics.
With the loss of continuity in the battery, the filter provided by the battery is no longer
present.
Loss of electrical continuity of the station battery will cause, regardless of the battery
charger’s output current capability, a delayed response in full output current from the
charger. Almost all chargers have an intentional 1 to 2 second delay to switch from a low
substation dc load current to the maximum output of the charger. This delay would cause
the opening of circuit breakers to be delayed which could violate system performance
standards.
How do you verify continuity of the dc supply?
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery unless the battery charger is taken out of service. At that time
12
PRC-005-2 Frequently-Asked Questions
a break in the continuity of the station battery current path will be revealed because there will
be no voltage on the station dc circuitry.
Although the Standard prescribes what must be done during the maintenance activity it does
not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
◊
◊
◊
◊
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path through
the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of the
various dc-supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor controlled battery chargers have developed methods for
their equipment to periodically (or continuously) test for battery continuity. For example,
one manufacturer periodically reduces the float voltage on the battery until current from
the battery to the dc load can be measured to confirm continuity.
Applying test current (as in an ohmic testing device) will provide a current that when
measured elsewhere in the string, will prove that the circuit is continuous.
No matter how the electrical continuity of a battery set is verified it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1 to insure that the station
dc supply has a path that can provide the required current to the Protection System at all times.
E.
When should I check the station batteries to see if they have sufficient energy to perform
as designed?
The answer to this question depends on the type of battery (valve regulated lead-acid, vented
lead acid, or nickel-cadmium), the maintenance activity chosen, and the type of time based
monitoring level selected.
For example, if you have a Valve Regulated Lead-Acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every three months. While this interval might seem to be quite short, keep in mind that the 3
month interval is consistent with IEEE guidelines for VRLA batteries; this interval provides an
accumulation of data that better shows when a VRLA battery is no longer capable of its design
capacity.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every 3 calendar years.
F.
Why in Table 1 are there two Maintenance Activities with different Maximum
Maintenance Intervals listed to verify that the station battery can perform as designed?
13
PRC-005-2 Frequently-Asked Questions
The two acceptable methods for proving that a station battery can perform as designed are
based on two different philosophies. The first activity requires a capacity discharge test of the
entire battery set to verify that degradation of one or several components (cells) in the set has
not deteriorated to a point where the total capacity of the battery system falls below its
designed rating. The second maintenance activity requires tests and evaluation of the internal
ohmic measurements on each of the individual cells/units of the battery set to determine that
each component can perform as designed and therefore the entire battery set can be verified to
perform as designed.
The maximum maintenance interval for discharge capacity testing is longer than the interval
for testing and evaluation of internal ohmic cell measurements. An individual component of a
battery set may degrade to an unacceptable level without causing the total battery set to fall
below its designed rating under capacity testing. However, since the philosophy behind
internal ohmic measurement evaluation is based on the fact that each battery component must
be verified to be able to perform as designed, the interval for verification by this maintenance
activity must be shorter to catch individual cell/unit degradation. It should be noted that even if
a battery unit is composed of multiple cells the ohmic test can still be accomplished. The data
produced becomes trending data on the multi-cell unit instead of trending individual cells.
G.
What is the justification for having two different Maintenance Activities listed in Table 1
to verify that the station battery can perform as designed?
IEEE Standards 450, 1188, and 1106 for vented lead-acid, valve-regulated lead-acid (VRLA),
and nickel-cadmium batteries, respectively (which together are the most commonly used
substation batteries on the BES) go into great detail about capacity testing of the entire battery
set to determine that a battery can perform as designed.
The first maintenance activity listed in Table 1 for verifying that a station battery can perform
as designed uses maximum maintenance intervals for capacity testing that were designed to
align with the IEEE battery standards. This maintenance activity is applicable for vented leadacid, valve-regulated lead-acid, and nickel-cadmium batteries.
The second maintenance activity listed in Table 1 for verifying that a station battery can
perform as designed uses maximum maintenance intervals for evaluating internal ohmic
measurements in relation to their baseline measurements that are based on industry experience,
EPRI technical reports and application guides, and the IEEE battery standards. By evaluating
the internal ohmic measurements for each cell and comparing that measurement to the cell’s
baseline ohmic measurement (taken at the time of the battery set’s acceptance capacity test),
low-capacity cells can be identified and eliminated to keep the battery set capable of
performing as designed. This maintenance activity is applicable only for vented lead-acid and
VRLA batteries; this trending activity has not shown to be effective for NiCd batteries thus the
only choices for NiCd batteries are the performance tests (see applicable IEEE guideline for
specifics on performance tests). It should be noted that even if a battery unit is composed of
multiple cells the ohmic test can still be accomplished. The data produced becomes trending
data on the multi-cell unit instead of trending individual cells.
H.
Why in Table 1 of PRC-005-2 is there a maintenance activity to inspect the structural
intergrity of the battery rack?
14
PRC-005-2 Frequently-Asked Questions
The three IEEE standards (1188, 450, and 1106) for VRLA, vented lead-acid, and nickelcadmium batteries all recommend that as part of any battery inspection the battery rack should
be inspected. The purpose of this inspection is to verify that the battery rack is correctly
installed and has no deterioration that could weaken its structural integrity. Because the
battery rack is specifically designed for the battery that is mounted on it, weakening of its
structural members by rust or corrosion can physically jeopardize the battery.
I.
What is required to comply with the “Unintentional Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the unintentional
ground that appears on the opposite pole that becomes problematic. Even then many systems
are designed to operate favorably under some unintentional DC ground situations. It is up to
the owner of the Protection System to determine if corrective actions are needed on detected
unintentional DC grounds. The standard merely requires that a check be made for the
existence of Unintentional DC Grounds. Obviously a “check-off” of some sort will have to be
devised by the inspecting entity to document that a check is routinely done for Unintentional
DC Grounds.
J.
Where the standard refers to “all cells” is it sufficient to have a documentation method
that refers to “all cells” or do we need to have separate documentation for every cell? For
example to I need 60 individual documented check-offs for good electrolyte level or
would a single check-off per bank be sufficient?
A single check-off per battery bank is sufficient for documentation, as long as the single
check-off attests to checking all cells/units.
K.
Does this standard refer to Station batteries or all batteries, for example
Communications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC-005-2 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point the corrective actions can be initiated.
L.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on these
units that I cannot get to?
The values that are measured at all available terminals will produce results that can be tracked.
Thus the trended results become the results of a unit instead of an individual cell. Bad units
(regardless of the number of cells per unit) will result in the eventual repair or replacement of
multiple cells even if only a single cell actually went bad. Cell-to-cell tests can equate to unitto-unit tests or jar-to-jar tests. If there is such a thing as a single unit that contains the entire
battery for the facility but only brings out the positive and negative posts (as in a car battery)
then the testing across these only two available posts will produce usable trending test data.
6. Protection System Communications Equipment
15
PRC-005-2 Frequently-Asked Questions
A.
What are some examples of mechanisms to check communications equipment
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on-site integrity checking to be performed at least every three months
during a substation visit. Some examples are, but not limited to:
◊ On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check-back test from one terminal.
◊ Systems which use frequency-shift communications with a continuous guard signal (over a
telephone circuit, analog microwave system, etc.) can be checked by observing for a lossof-guard indication or alarm. For frequency-shift power-line carrier systems, the guard
signal level meter can also be checked.
◊ Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
◊ Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have
different facilities for monitoring the presence of the communications channel, and activating
alarms that can be monitored remotely. Some examples are, but not limited to:
◊ On-off power-line carrier systems can be shown to be operational by automated periodic
power-line carrier check-back tests, with remote alarming of failures.
◊ Systems which use a frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be remotely monitored with a lossof-guard alarm or low signal level alarm.
◊ Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
◊ Digital communications systems can activate remotely monitored alarms for data reception
loss or data error indications.
◊ Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
◊ In many communications systems signal quality measurements including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio, propagation
delay, and data error rates are compared to alarm limits. These alarms are connected for
remote monitoring.
◊ Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment location
is continuously being reflected at the remote monitoring site.
B.
What is needed for the 3-month inspection of communications-assisted trip scheme
equipment?
16
PRC-005-2 Frequently-Asked Questions
The 3-month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms, check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard.
C.
Does a fiber optic I/O scheme used for breaker tripping or control within a station, for
example - transmitting a trip signal or control logic between the control house and the
breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System Control Circuitry
and tested per the portions of Table 1 applicable to Protection System Control Circuitry rather
than those portions of the table applicable to communications equipment.
D.
In Table 1-2, the Maintenance Activities section of the Protective System
Communications Equipment and Channels refers to the quality of the channel meeting
“performance criteria”. What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating
normally an alarm will be indicated. For unmonitored systems this alarm will probably be on
the panel. For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each protective system
communications channel that is consistent with proper functioning of the Protection System.
If that level of nominal performance is not being met, the system will go into alarm.
Following are some examples of protective system communications channel performance
measuring:
◊ For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system is
calibrated and if the signal level drops below an established level, the system will indicate
an alarm.
◊ An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check-back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes this
signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full power
and reduced power tests are typically run. Power levels for these tests are determined at the
time of calibration.
◊ Pilot wire relay systems use a hardwire communications circuit to communicate between
the local and remote ends of the protective zone. This circuit is monitored by circulating a
dc current between the relay systems. A typical level may be 1 mA. If the level drops
below the setting of the alarm monitor, the system will indicate an alarm.
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PRC-005-2 Frequently-Asked Questions
◊ Modern digital relay systems use data communications to transmit relay information to the
remote end relays. An example of this is a line current differential scheme commonly used
on transmission lines. The protective relays communicate current magnitude and phase
information over the communications path to determine if the fault is located in the
protective zone. Quantities such as digital packet loss, bit error rate and channel delay are
monitored to determine the quality of the channel. These limits are determined and set
during relay commissioning. Once set, any channel quality problems that fall outside the
set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be - it
just requires that the entity establish nominal criteria so protective system channel monitoring
can be performed.
7. UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power
System
A.
We have an Under Voltage Load Shedding (UVLS) system in place that prevents one of
our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation as stated indicates that the tripping action was intended to prevent low
distribution voltage to a specific load from a transmission system that was intact except for the
line that was out of service, as opposed to preventing cascading outage or transmission system
collapse.
This Standard is not applicable to this UVLS.
B.
We have a UFLS scheme that sheds the necessary load through distribution-side circuit
breakers and circuit reclosers. Do the trip-test requirements for circuit breakers apply to
our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential Lock-Out Relay. While many failures of
these distribution breakers could add up to be significant, it is also believed that distribution
breakers are operated often on just fault clearing duty and therefore the distribution circuit
breakers are operated at least as frequently as any requirements that might have appeared in
this standard.
C.
What does “distributed over the power system” mean?
This refers to the common practice of applying UFLS on the distribution system, with each
UFLS individually tripping a relatively low value of load. Therefore, the program is
implemented via a large number of individual UFLS components performing independently,
and the failure of any individual component to perform properly will have a minimal impact
on the effectiveness of the overall UFLS program. Some UVLS systems are applied similarly.
18
PRC-005-2 Frequently-Asked Questions
8. SPS or Relay Sensing for Centralized UFLS or UVLS
A.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end-to-end test.
B.
What about SPS interfaces between different entities or owners?
All SPS owners should have maintenance agreements that state which owner will perform
specific tasks. As in all of the Protection System requirements, SPS segments can be tested
individually thus minimizing the need to accommodate complex maintenance schedules.
C.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System
or Special Protection System (as opposed to a monitoring task) must be verified as a
component in a Protection System.
D.
How do I maintain a Special Protection System or Relay Sensing for Centralized UFLS
or UVLS Systems?
Since components of the SPS, UFLS, or UVLS are the same types of components as those in
Protection Systems then these components should be maintained like similar components used
for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control
circuitry maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be
verified in overlapping segments. For example an SPS that trips a remote circuit breaker
might be tested by testing the various parts of the scheme in overlapping segments. Another
method is to document the real-time tripping of an SPS scheme should that occur. Forced trip
tests of circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not
required
E.
What does “centralized” mean?
This refers to the practice of applying sensing units at many locations over the system, with all
these components providing intelligence to an analytical system which then directs action to
address a detected condition. In some cases, this action may not take place at the same
location as the sensing units. This approach is often applied for complex SPS, and may be
used for UVLS (and perhaps even with UFLS) where necessary to address the conditions of
concern.
III
Group by Type of BES Facility:
1. All BES Facilities
A.
What, exactly, is the BES, or Bulk Electric System?
19
PRC-005-2 Frequently-Asked Questions
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms
Used in Reliability Standards, and is not being modified within this draft Standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving
only load with one transmission source are generally not included in this definition.
Each Regional Entity implements a definition of the Bulk Electric System that is based on this
NERC definition, in some cases, supplemented by additional criteria. These regional
definitions have been documented and provided to FERC as part of a June 16, 2007
Informational Filing.
2. Generation
A.
Please provide a sample list of devices or systems that must be verified in a generator,
generator step-up transformer, and generator connected station auxiliary transformer to
meet the requirements of this Maintenance Standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay may include but are not necessarily limited to:
• Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
• Loss-of-field relays
• Volts-per-hertz relays
• Negative sequence overcurrent relays
• Over voltage and under voltage protection relays
• Stator-ground relays
• Communications-based protection systems such as transfer-trip systems
• Generator differential relays
• Reverse power relays
• Frequency relays
• Out-of-step relays
• Inadvertent energization protection
• Breaker failure protection
For generator step up or generator-connected station auxiliary transformers, operation of any
the following associated protective relays frequently would result in a trip of the generating unit
and, as such, would be included in the program:
• Transformer differential relays
• Neutral overcurrent relay
• Phase overcurrent relays
A loss of a system-connected station auxiliary transformer could result in a loss of the
generating plant if the plant was being provided with auxiliary power from that source, and this
auxiliary transformer may directly affect the ability to start up the plant and to connect the plant
20
PRC-005-2 Frequently-Asked Questions
to the system. Thus, operation of any of the following relays associated with system-connected
station auxiliary transformers would be included in the program:
• Transformer differential relays
• Neutral overcurrent relay
• Phase overcurrent relays
Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program even if the loss of the those loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal-conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
3. Transmission
A.
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having relevant
facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
IV
Group by Type of Maintenance Program:
1. All Protection System Maintenance Programs
A. I can’t figure out how to demonstrate compliance with the requirements for the highest
level of monitoring of Protection Systems. Why does this Maintenance Standard describe
a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This Standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring; the Standard establishes the necessary requirements for when
such equipment becomes available.
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PRC-005-2 Frequently-Asked Questions
By creating a roadmap for development, this provision makes the Standard technology-neutral.
The standard drafting team wants to avoid the need to revise the Standard in a few years to
accommodate technology advances that are certainly coming to the industry.
B. What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the Requirement being documented, include but
are not limited to:
•
•
•
•
•
•
•
•
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database lists, records and/or screen shots that demonstrate compliance information
Prints, diagrams and/or schematics
Maintenance records
Logs (operator, substation, and other types of log)
Inspection forms
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
• Check-off forms (paper or electronic)
• Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
C. If I replace a failed Protection System component with another component, what testing
do I need to perform on the new component?
The replacement component must be tested to a degree that assures that it will perform as
intended. If it is desired to reset the Table 1 maintenance interval for the replacement
component, all relevant Table 1 activities for the component should be performed.
D. Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records to
demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electro-mechanical protective relays be
tested, for routine scheduled tests, every 3 calendar years with a maximum allowed grace
period of an additional 18 months. This entity would be required to maintain its records of
maintenance of its last two routine scheduled tests. Thus its test records would have a latest
routine test as well as its previous routine test. The interval between tests is therefore provable
to an auditor as being within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two test
results proving the last interval. The drafting team contends that this minimizes storage
requirements while still having minimum data available to demonstrate compliance with time
intervals.
Realistically, the Standard is providing advanced notice of audit team documentation requests;
this type of information has already been requested by auditors.
If an entity prefers to utilize Performance Based Maintenance then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
22
PRC-005-2 Frequently-Asked Questions
2. Time-Based Protection System Maintenance (TBM) Programs
A. What does this Maintenance Standard say about commissioning? Is it necessary to have
documentation in your maintenance history of the completion of commission testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC-005-2, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are not
generally done routinely like staged-fault-tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation and need not be re-verified
within an ongoing maintenance program. Example – it is not necessary to re-verify correct
terminal strip wiring on an ongoing basis.
PRC-005-2 assumes that thorough commission testing was performed prior to a protection
system being placed in service. PRC-005-2 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content
and therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See next FAQ).
B. How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a facility and its associated
Protection System were placed in service. Alternatively, an entity may choose to use the date
of completion of the commission testing of the Protection System component as the starting
point in determining its first maintenance due dates. Whichever method is chosen, for newly
installed Protection Systems the maintenance program should clearly identify when
maintenance is first due.
It is conceivable that there can be a (substantial) difference in time between the date of testing
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non-compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in-service
dates then the testing date should be followed because it is the degradation of components that
is the concern. While accuracy fluctuations may decrease when components are not energized
23
PRC-005-2 Frequently-Asked Questions
there are cases when degradation can take place even though the device is not energized.
Minimizing the time between commissioning tests and in-service dates will help.
C. The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled outage
following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance intervals
were selected with typical plant outages, among other things, in mind.
D. If I am unable to complete the maintenance as required due to a major natural disaster
(hurricane, earthquake, etc), how will this affect my compliance with this standard.
The Sanction Guidelines of the North American Electric Reliability Corporation effective
January 15, 2008 provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
E. What if my observed testing results show a high incidence of out-of-tolerance relays, or,
even worse, I am experiencing numerous relay misoperations due to the relays being outof-tolerance?
The established maximum time intervals are mandatory only as a not-to-exceed limitation. The
establishment of a maximum is measurable. But, any entity can choose to test some or all of
their Protection System components more frequently (or, to express it differently, exceed the
minimum requirements of the Standard). Particularly, if you find that the maximum intervals in
the Standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest. The BES and an entity’s bottom line both suffer.
F. We believe that the 3-month interval between inspections is unneccessary, why can we not
perform these inspections twice per year?
The standard drafting team believes that routine monthly inspections are the norm. To align
routine station inspections with other important inspections the 3-month interval was chosen. In
lieu of station visits many activities can be accomplished with automated monitoring and
alarming.
G. Our maintenance plan calls for us to perform routine protective relay tests every 3 years;
if we are unable to achieve this schedule but we are able to complete the procedures in less
than the Maximum Time Interval then are we in or out of compliance?
You are out of compliance. You must maintain your equipment to your stated intervals within
your maintenance plan. The protective relays (and any Protection System component) cannot
be tested at intervals that are longer than the maximum allowable interval stated in the Tables
and yet you must conform to your own maintenance plan. Therefore you should design your
maintenance plan such that it is not in conflict with the Minimum Activities and the Maximum
Intervals. You then must maintain your equipment according to your maintenance plan. You
will end up being compliant with both the standard and your own plan.
H. How do I achieve a “grace period” without being out of compliance?
24
PRC-005-2 Frequently-Asked Questions
For the purposes of this example, concentrating on just unmonitored protective relays, because
there are more relays out there than anything else – Table 1-1 specifies a maximum time
interval (between the mandated maintenance activities) of 6 calendar years. Your plan must
ensure that your unmonitored relays are tested at least once every 6 calendar years. You could,
within your PSMP, require that your unmonitored relays be tested every 4 calendar years with a
maximum allowable time extension of 18 calendar months. This allows an entity to have
deadlines set for the auto-generation of work orders but still have the flexibility in scheduling
complex work schedules. This also allows for that 18 calendar months to act as a buffer, a grace
period, in the event of unforeseen events. You will note that this example of a maintenance plan
interval has a planned time of 4 years; it also has a built-in time extension allowed within the
PSMP and yet does not exceed the maximum time interval allowed by the standard. So while
there are no time extensions allowed beyond the standard, an entity can still have substantial
flexibility to maintain their Protection System components.
I. If I miss two battery inspections four times out of 100 protection system components on
my transmission system, does that count as 2 percent or 8 percent when counting
Violation Severity Level (VSL) for R4?
The entity failed to complete its scheduled program on two of its one hundred protection
system components which would equate to two percent for application to the VSL Table for
Requirement R4.
3. Performance-Based Protection System Maintenance (PBM) Programs
A. I’m a small entity and cannot aggregate a population of Protection System components to
establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of
individual Protection System components to create a segment that crosses ownership
boundaries. All entities participating in a joint program should have a single documented joint
management process, with consistent Protection System Maintenance Programs (practices,
maintenance intervals and criteria), for which the multiple owners are individually responsible
with respect to the requirements of the Standard. The requirements established for
performance-based maintenance must be met for the overall aggregated program on an ongoing
basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power-plant
vs. substation, and weather conditions.
B. Can an owner go straight to a performance-based maintenance program schedule, if they
have previously gathered records?
Yes. An owner can go to a performance-based maintenance program immediately. The owner
will need to comply with the requirements of a performance-based maintenance program as
listed in the standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a performance-based maintenance program then they will need to wait until they can prove
compliance.
25
PRC-005-2 Frequently-Asked Questions
C. When establishing a performance-based maintenance program, can I use test data from
the device manufacturer, or industry survey results, as results to help establish a basis for
my performance-based intervals?
No. You must use actual in-service test data for the components in the segment.
D. What types of misoperations or events are not considered countable events in the
performance-based Protection System Maintenance (PBM) Program?
Countable events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned.
For this purpose of tracking hardware issues, human errors resulting in Protection System
misoperations during system installation or maintenance activities are not considered countable
events. Examples of excluded human errors include relay setting errors, design errors, wiring
errors, inadvertent tripping of devices during testing or installation, and misapplication of
Protection System components. Examples of misapplication of Protection System components
include wrong CT or PT tap position, protective relay function misapplication, and components
not specified correctly for their installation. Obviously, if one is setting up relevant data about
hardware failures then human failures should be eliminated from the hardware performance
analysis.
One example of human-error is not pertinent data might be in the area of testing “86” Lock-Out
Relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move
into a performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial
six-year interval they find zero type “X” failures, but human error led to tripping a BES
element 100 times; they find 100 type “Y” failures and had an additional 100 human-error
caused tripping incidents. In this example the human-error caused misoperations should not be
used to judge the performance of either type of LOR. Analysis of the data might lead “Entity
A” to change time intervals. Type “X” LOR can be placed into extended time interval testing
because of its low failure rate (zero failures) while Type “Y” would have to be tested more
often than every 6 calendar years (100 failures divided by 1000 units exceeds the 4% tolerance
level).
Certain types of Protection System component errors that cause misoperations are not
considered countable events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
E. What are some examples of methods of correcting segment perfomance for PerformanceBased Maintenance?
There are a number of methods that may be useful for correcting segment performance for malperforming segments in a performance-based maintenance system. Some examples are listed
below.
26
PRC-005-2 Frequently-Asked Questions
•
The maximum allowable interval, as established by the performance-based maintenance
system, can be decreased. This may, however, be slow to correct the performance of the
segment.
•
Identifiable sub-groups of components within the established segment, which have been
identified to be the mal-performing portion of the segment, can be broken out as an
independent segment for target action. Each resulting segment must satisfy the minimum
population requirements for a performance-based maintenance program in order to remain
within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
Components within the mal-performing segment can be replaced with other components
(electromechanical distance relays with microprocessor relays, for example) to remove the
mal-performing segment.
F. If I find (and correct) a maintenance-correctable issue as a result of a misoperation
investigation (Re: PRC-004), how does this affect my performance-based maintenance
program?
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC-004 required misoperation investigation/corrective action), the actions performed
can count as a maintenance activity, and “reset the clock” on everything you’ve done. In a
performance-based maintenance program, you also need to record the maintenance-correctable
issue with the relevant component group and use it in the analysis to determine your correct
performance-based maintenance interval for that component group. Note that “resetting the
clock” should not be construed as interfering with an entity’s routine testing schedule because
the “clock-reset” would actually make for a decreased time interval by the time the next routine
test schedule comes around.
For example a relay scheme, consisting of 4 relays, is tested on 1-1-11 and the PSMP has a time
interval of 3 calendar years with an allowable extension of 1 calendar year. The relay would be
due again for routine testing before the end of the year 2015. This mythical relay scheme has a
misoperation on 6-1-12 that points to one of the four relays as bad. Investigation proves a bad
relay and a new one is tested and installed in place of the original. This replacement relay
actually could be retested before the end of the year 2016 (clock-reset) and not be out of
compliance. This requires tracking maintenance by individual relays and is allowed. However,
many companies schedule maintenance in other ways like by substation or by circuit breaker or
by relay scheme. By these methods of tracking maintenance that “replaced relay” will be
retested before the end of the year 2015. This is also acceptable. In no case was a particular
relay tested beyond the PSMP of 4 years max, nor was the 6 year max of the standard exceeded.
The entity can reset the clock if they desire or the entity can continue with original schedules
and, in effect, test even more frequently.
G. Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
27
PRC-005-2 Frequently-Asked Questions
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation from
the factory to the job site, length of time before a charge is put on the battery, the method of
installation, the voltage level and duration of equalize charges, the float voltage level used, and
the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a performance-based Protection System Maintenance
(PBM) program. These inherent variances in the aging process of a battery cell make
establishment of a designated segment based on manufacturer and type of battery impossible.
The whole point of PBM is that if all variables are isolated then common aging and
performance criteria would be the same. However, there are too many variables in the electrochemical process to completely isolate all of the performance-changing criteria.
Similarly Functional Entities that want to establish a condition-based maintenance program
using the highest levels of monitoring; resulting in the least amount of hands-on maintenance
activity, of the battery used in a station dc supply cannot completely eliminate some periodic
maintenance. Inspection of the battery is required on a Maximum Maintenance Interval listed
in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1-4).
H. Please provide an example of the calculations involved in extending maintenance time
intervals using PBM.
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60
They start out testing all of the relays within the prescribed Table requirements (6 year max) by
testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is greater
than the minimum sample size requirement of 30.
For the sake of example only the following will show 6 failures per year, reality may well have
different numbers of failures every year. PBM requires annual assessment of failures found per
units tested.
28
PRC-005-2 Frequently-Asked Questions
After the first year of tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure
rate.
This entity is now allowed to extend the maintenance interval if they choose.
The entity chooses to extend the maintenance interval of this population segment out to 10
years.
This represents a rate of 100 units tested per year; entity selects 100 units to be tested in the
following year.
After that year of testing these 100 units the entity again finds 6 failed units. 6/100= 6%
failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate such that the failure rate is found to be less than 4% per
year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 8 years. This
means that they will now test 125 units per year (1000/8). The entity has just two years left to
get the test rate corrected.
After a year they again find 6 failures out of the 125 units tested. 6/125= 5% failures.
In response to the 5% failure rate, the entity decreases the testing interval to 7 years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to get
the test rate corrected.
After a year they again find 6 failures out of the 143 units tested. 6/143= 4.2% failures.
(Note that the entity has tried 5 years and they were under the 4% limit and they tried 7 years
and they were over the 4% limit. They must be back at 4% failures or less in the next year so
they might simply elect to go back to 5 years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to 6 years.
This means that they will now test 167 units per year (1000/6).
After a year they again find 6 failures out of the 167 units tested. 6/167= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 6 years or less. Entity chose 6 year interval and effectively
extended their TBM (5 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; this is there to prevent an
entity from “gaming the system”. An entity might arbitrarily extend time intervals from 6 years
to 20 years. In the event that an entity finds a failure rate greater than 4% then the test rate must
be accelerated such that within three years the failure rate must be brought back down to 4% or
less.
Here is a table that demonstrates the values discussed:
29
PRC-005-2 Frequently-Asked Questions
Year #
Total
Population
Test
Interval
Units to be
Tested
(P)
(I)
(U= P/I)
# of
Failures
Found
Failure
Rate
Decision
to Change
Interval
Interval
Chosen
(=F/U)
(F)
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
V
Group by Monitoring Level:
1. All Monitoring Levels
A.
Please provide an example of the unmonitored versus other levels of monitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be un-monitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but not limited to an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
◊
◊
◊
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center. (monitored)
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented lead-acid battery with low voltage alarm and unintentional grounds detection
alarm connected to SCADA. (monitored except for electrolyte level)
30
PRC-005-2 Frequently-Asked Questions
◊
A circuit breaker with a trip coil and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum
activity intervals of:
◊
◊
◊
◊
Every 3 calendar months check electrolyte level (cell voltage and unintentional ground
detection is being maintained more frequently by the monitoring system).
Every 18 calendar months check battery bank ohmic values (if performance tests are not
opted), battery float voltage and battery rack integrity.
Every 6 calendar years battery performance test (if ohmic tests are not opted), battery
charger alarms verified and trip test circuit breakers, electro-mechanical lock-out relays
and auxiliary relays.
Every 12 calendar years the microprocessor relay, the instrumentation transformers and
the control circuitry are verified.
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
◊
◊
◊
◊
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
Instrument transformers, with no monitoring, connected as inputs to that relay.
(monitored)
A vented lead-acid battery with low voltage and ground-detection alarms connected to
SCADA. (monitored except for electrolyte level)
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum
activity intervals of:
◊
◊
◊
◊
Every 3 calendar months check electrolyte level (cell voltage and unintentional ground
detection is being maintained more frequently by the monitoring system).
Every 18 calendar months check battery bank ohmic values (if performance tests are not
opted), battery float voltage and battery rack integrity.
Every 6 calendar years microprocessor relay is verified, battery performance test (if ohmic
tests are not opted), battery charger alarms verified and trip test circuit breakers, electromechanical lock-out relays and auxiliary relays.
Every 12 calendar years the instrumentation transformers and the control circuitry are
verified.
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
◊
◊
◊
◊
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed operations
center. (monitored)
Instrument transformers, with no monitoring, connected as inputs to that relay
(unmonitored)
Battery without any alarms connected to SCADA (unmonitored)
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
31
PRC-005-2 Frequently-Asked Questions
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components shall have
maximum activity intervals of:
◊ Every 3 calendar months check battery bank voltage, check for unintentional grounds and
check electrolyte level.
◊ Every 18 calendar months check battery bank ohmic values (if performance tests are not
opted), battery float voltage and battery rack integrity.
◊ Every 6 calendar years battery performance test (if ohmic tests are not opted), battery
charger alarms verified and trip test circuit breakers, electro-mechanical lock-out relays
and auxiliary relays.
◊ Every 12 calendar years the microprocessor relay, the instrumentation transformers and
the control circuitry are verified.
B.
What is the intent behind the different levels of monitoring?
The intent behind different levels of monitoring is to allow less frequent manual intervention
when more information is known about the condition of Protection System components.
Condition-Based Maintenance is a valuable asset to improve reliability.
C.
Do all monitoring levels apply to all components in a protection system?
No. For some components in a protection system, certain levels of monitoring will not be
relevant. For example a battery will always need some kind of inspection.
D.
My microprocessor relays and dc circuit alarms are contained on relay panels in a 24hour attended control room. Does this qualify as an extended time interval conditionbased system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
E.
When documenting the basis for inclusion of components into the appropriate levels of
monitoring as per Requirement R2 of the standard, is it necessary to provide this
documentation about the device by listing of every component and the specific
monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are Monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered Monitored and subject to the
rows for monitored equipment of Table 1-4 requirements as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that
are sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered
Monitored and subject to the rows for monitored equipment of Table 1-4 requirements
as all substation dc supply battery chargers are equipped with dc voltage alarms and
32
PRC-005-2 Frequently-Asked Questions
ground detection alarms that are sent to the manned control center. The dc supply
battery chargers of Substation X, Substation Y, and Substation Z are considered
Unmonitored and subject to the rows for unmonitored equipment in Table 1-4
requirements as they are not equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure but should be retrievable if
requested by an auditor.
2. Unmonitored Protection Systems
A.
We have an electromechanical (unmonitored) relay that has a trip output to a lockout
relay (unmonitored) which trips our transformer off-line by tripping the transformer’s
high-side and low-side circuit breakers. What testing must be done for this system?
This system is made up of components that are all unmonitored. Assuming a time-based
protection system maintenance program schedule (as opposed to a performance-based
maintenance program), each component must be maintained per the most frequent hands-on
activities listed in the Tables 1-1 through 1-5.
3.
Monitored Protection Systems
A.
We have a 30 year old oil circuit breaker with a red indicating lamp on the substation
relay panel that is illuminated only if there is continuity through the breaker trip coil.
There is no SCADA monitor or relay monitor of this trip coil. The line protection relay
package that trips this circuit breaker is a microprocessor relay that has an integral
alarm relay that will assert on a number of conditions that includes a loss of power to the
relay. This alarm contact connects to our SCADA system and alerts our 24-hour
operations center of relay trouble when the alarm contact closes. This microprocessor
relay trips the circuit breaker only and does not monitor trip coil continuity or other
things such as trip current. Is this an unmonitored or a partially-monitored system?
How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years or when a
maintenance correctable issue arises. The control circuitry has no electro-mechanical parts
and can be maintained every 12 years. The trip coil(s) has to be electrically operated at least
once every 6 years.
B.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
C.
How is the performance criteria of Protection System communications equipment
involved in the maintenance program?
33
PRC-005-2 Frequently-Asked Questions
An entity determines the acceptable performance criteria depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre-determined performance criteria for that system then these results should be
investigated and resolved.
D.
My system has alarms that are gathered once daily through an auto-polling system; this
is not really a conventional SCADA system but does it meet the Table 1 requirements for
inclusion as a monitored system?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the maintenance-correctable issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
4.
Monitored Protection Systems that also monitor alarm path failures
A.
Why are there activities defined for levels of monitoring a Protection System component
when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels
of monitoring criteria listed in the Tables. However, even if there is no equipment available
today that can meet this level of monitoring the Standard establishes the necessary
requirements for when such equipment becomes available. By creating a roadmap for
development, this provision makes the Standard technology-neutral. The standard drafting
team wants to avoid the need to revise the Standard in a few years to accommodate technology
advances that may be coming to the industry.
34
PRC-005-2 Frequently-Asked Questions
Ap p e n d ix A — P ro te c tio n S ys te m Ma in te n a n c e
S ta n d a rd Dra ftin g Te a m
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle E. Ashton
Tri-State G&T
Mark Lukas
ComEd
Bob Bentert
Florida Power & Light Company
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
John Ciufo
Hydro One Inc
Mark Peterson
Great River Energy
Sam Francis
Oncor
Leonard Swanson, Jr
National Grid USA
Carol A Gerou
Midwest Reliability Organization
Eric A Udren
Quanta Technology
William Shultz
Southern Company Generation
Philip B Winston
Southern Company Transmission
Russell C Hardison
Tennessee Valley Authority
John A Zipp
ITC Holdings
David Harper
NRG Texas Maintenance Services
35
PRC-005-2 Frequently-Asked Questions
In d e x
3-month interval, 25
aggregate, 26
alarm, 17, 18, 19, 31, 32,
34
automated monitoring and
alarming, 25, 26
auto-restoration, 5
auxiliary relay, 11, 12
batteries, 12, 13, 14, 15,
28, 29
battery, 11, 12, 13, 14, 15,
16, 28, 29, 31
broken, 7
capacity, 14, 15
channel performance, 18,
19, 34
charger, 12, 13, 14
check-off, 16
closing circuits, 5
commission, 23, 24
communications, 7, 11, 16,
17, 18, 19, 34
communications channel,
17, 18
Communications Site
Batteries, 16
communications-assistedtrip, 11
component, 2, 11, 15, 20,
23, 24, 26, 27, 28, 31,
33
continuity, 13, 14, 33
corrective, 2, 6, 27, 28
countable events, 2, 26, 27
current and voltage
measurements, 9
data retention, 23
DC ground, 16
documentation, 6, 22, 23,
24, 33
documentation method, 16
electromechanical, 7, 10,
27, 33
electro-mechanical relays,
6
evidence, 6, 22, 23
fiber optic I/O scheme, 18
firmware, 5, 27
frequency-shift, 17
guard, 17, 18
lockout relay, 11, 21, 33
maintenance correctable
issue, 2, 34
maintenance plan, 6, 23,
25
maximum allowable
interval, 25, 27
microprocessor, 5, 6, 7, 9,
10, 11, 13, 14, 27, 31,
32, 34
Misoperations, 2, 27
nickel-cadmium, 14, 15
ohmic, 14, 15
out-of-service, 7
partially monitored, 17
PBM, 26, 28, 29
performance-based
maintenance, 26, 27, 28
pilot wire, 17
PMU, 20
power-line carrier, 17
pressure relays, 12
protective relays, 5, 6, 7, 9,
10, 12, 13, 17, 18, 21
reclosing relays, 5
Restoration, 6
sample list of devices, 21
segment, 2, 26, 27, 29
settings, 2, 6, 7, 12, 23
SPS, 5, 19, 20
Table 1a, 3, 33
Table 1b, 11, 18, 33
Table 1c, 22, 34
TBM, 23
trip coil, 11, 31, 32, 33
trip signal, 11, 18
trip test, 11
tripping circuits, 11
UFLS, 19, 20
unintentional ground, 16
unmonitored, 17, 30, 31,
32, 33, 34
UVLS, 19, 20
valve-regulated lead-acid,
15
vented lead-acid, 15, 31
voltage and current
sensing devices, 2, 9, 10
VRLA, 14, 15
36
NERC Protection System Maintenance Standard
PRC-005-2
FREQUENTLY ASKED QUESTIONS Practical Compliance and Implementation
April 16November 17, 2010
Informative Annex to Standard PRC-005-2
Prepared by the
Protection System Maintenance and Testing Standard Drafting Team
Table of Contents
Table of Contents
Introduction .................................................................................................................................................................2
Executive Summary .....................................................................................................................................................2
Terms Used in PRC-005-2...........................................................................................................................................2
Frequently Asked Questions .......................................................................................................................................3
I
General FAQs: .................................................................................................................................................3
II
Group by Type of Protection System Component:............................................................................................5
1.
All Protection System Components...................................................................................................................5
2.
Protective Relays ..............................................................................................................................................5
3.
Voltage and Current Sensing Device Inputs to Protective Relays ....................................................................9
4.
Protection System Control Circuitry .............................................................................................................. 11
5.
Station dc Supply ............................................................................................................................................ 12
6.
Protection System Communications Equipment ............................................................................................. 17
7.
UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power System ................ 19
8.
SPS or Relay Sensing for Centralized UFLS or UVLS ................................................................................... 20
III
Group by Type of BES Facility: ..................................................................................................................... 21
1.
All BES Facilities ........................................................................................................................................... 21
2.
Generation ...................................................................................................................................................... 21
3.
Transmission .................................................................................................................................................. 22
IV
Group by Type of Maintenance Program:...................................................................................................... 23
1.
All Protection System Maintenance Programs ............................................................................................... 23
2.
Time-Based Protection System Maintenance (TBM) Programs ..................................................................... 24
3.
Performance-Based Protection System Maintenance (PBM) Programs ........................................................ 27
V
Group by Monitoring Level: ........................................................................................................................... 32
1.
All Monitoring Levels ..................................................................................................................................... 32
2.
Level 1 Monitored Protection Systems (Unmonitored Protection Systems) ................................................... 36
3.
Level 2 Monitored Protection Systems (Partially Monitored Protection Systems) ........................................ 42
4.
Level 3 Monitored Protection Systems (Fully Monitored Protection Systems)that also monitor alarm path
failures ......................................................................................................................................................... 43
Appendix A — Protection System Maintenance Standard Drafting Team .......................................................... 44
Index ........................................................................................................................................................................... 45
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
Introduction
The following is a draft collection of questions and answers that the PSMT SDT believes could be helpful
to those implementing NERC Standard PRC-005-2 Protection System Maintenance. As the draft standard
proceeds through development, this FAQ document will be revised, including responses to key or frequent
comments from the posting process. The FAQ will be organized at a later time during the development of
the draft Standard.
This FAQ document will support both the Standard and the associated Technical Reference document.
Executive Summary
•
Write later if needed
Terms Used in PRC-005-2
Maintenance Correctable Issue – As indicated in footnote 2 of the draft standard, a maintenance
correctable issue is a failure of a device to operate within design parameters that can not be restored to
functional order by repair or calibration while performing the initial on-site maintenance activity, and that
requires follow-up corrective action.
Segment – As indicated in PRC-005-2 Attachment A Criteria for a Performance-Based Protection System
Maintenance Program, a segment is a “A grouping of Protection Systems or components of a particular
model or type from a single manufacturer, with other common factors such that consistent performance is
expected across the entire population of the segment, and shall only be defined for a population of 60 or
more individual components.”
Component – This equipment is first mentioned in Requirement 1.1 of this standard. A component is any
individual discrete piece of equipment included in a Protection System, such as a protective relay or current
sensing device. Types of components are listed in Table 1 (“Maximum Allowable Testing Intervals and
Maintenance Activities for Unmonitored Protection Systems”). For components such as dc circuits, the
designation of what constitutes a dc control circuit component is somewhat arbitrary and is very dependent
upon how an entity performs and tracks the testing of the dc circuitry. Some entities test their dc circuits on
a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus, entities are
allowed the latitude to designate their own definitions of “dc control circuit components.” Another example
of where the entity has some discretion on determining what constitutes a single component is the voltage
and current sensing devices, where the entity may choose either to designate a full three-phase set of such
devices or a single device as a single component.
Countable Event – As indicated in footnote 4 of PRC-005-2 Attachment A, Criteria for a Performancebased Protection System Maintenance Program, countable events include any failure of a component
requiring repair or replacement, any condition discovered during the verification activities in Table 1a
through Table 1c which requires corrective action, or a Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different from
specified settings, Protection System component configuration errors, or Protection System application
errors are not included in Countable Events.
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
Frequently Asked Questions
I
General FAQs:
1. The standard seems very complicated, and is difficult to understand. Can it be simplified?
Because the standard is establishing parameters for condition-based Maintenance (R2) and
performance-based Maintenance (R3) in addition to simple time-based Maintenance, it does appear
to be complicated. At its simplest, an entity needs to follow R1 and R4 and perform ONLY timebased maintenance according to Table 1a, eliminating R2 and R3 from consideration altogether.the
unmonitored rows of the Tables. If an entity then wishes to take advantage of monitoring on its
Protection System components, R2 comes into play, along with Tables 1b and 1c and its available
lengthened time intervals then it may, as long as the component has the listed monitoring attributes.
If an entity wishes to use historical performance of its Protection System components to perform
performance-based Maintenance, then R3 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
Requirements
Flowchart
Start
PRC-005-2
Note: GO, DP, & TO
may use one or
multiple programs
Each GO, DP, & TO
shall establish a
maintenance
program [R1]
Performance
Based
Time Based
Decide if using Time Based, Condition
Baesd, and/or Performance Based
program
◊
◊
Condition Based
◊
Ensure
components
have necessary
monitoring [R2]
Separate components into
appropriate families of 60 or more
Maintain components for each
segment per Table One until at least
30 components have been tested
Analyze data to determine
appropriate interval for segment(s)
[R3]
Perform maintenance activities from
Table One for each segment with interval
from analysis above and collect data for
future analysis
[R3, R4.4.2]
◊
Maintain components
per Table One
Intervals and
Activities [R4.4.1]
◊
◊
Collect countable events from
maintenance and failures
Analyze data from maintenance of
last 30 components and/or last year
to verify countable events below 4%
Adjust maintenance interval to keep
countable events below 4%
[R3]
Implement corrective
actions as needed [R4]
End
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PRC-005-2 Frequently-Asked Questions
II
Group by Type of Protection System Component:
1. All Protection System Components
A.
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this standard?
No. As stated in Requirement R1, this standard covers protective relays that use measurements
of voltage, current and/or phase angle to determine anomalies and to trip a portion of the BES.
Reclosers, reclosing relays, closing circuits and auto-restoration schemes are used to cause
devices to close as opposed to electrical-measurement relays and their associated circuits that
cause circuit interruption from the BES; such closing devices and schemes are more
appropriately covered under other NERC Standards. There is one notable exception: if a
Special Protection System incorporates automatic closing of breakers, the related closing
devices are part of the SPS and must be tested accordingly.
B.
Why does PRC-005-2 not specifically require maintenance and testing procedures as
reflected in the previous standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2
requires a documented Maintenancemaintenance program, and is focused on establishing
Requirementsrequirements rather than prescribing methodology to meet those
Requirementsrequirements. Between the activities identified in the tables 1-1 through 1-5 and
Table 2 (collectively the “Tables 1a, 1b, and 1c,”), and the various components of the
definition established for a “Protection System Maintenance Program”, PRC-005-2 establishes
the activities and time-basis for a Protection System Maintenance Program to a level of detail
not previously required.
2. Protective Relays
A.
How do I approach testing when I have to upgrade firmware of a microprocessor relay?
The component “Upkeep” in the definition of a Protection System Maintenance Program,
addresses “Routine activities necessary to assure that the component remains in good working
order and implementation of any manufacturer’s hardware and software service advisories
which are relevant to the application of the device.” The Maintenance Activities specified in
Table 1a, Table 1b, and Table 1c do not present any requirements related to Upkeep for
Protective Relays. However, the entity should assure that the relay continues to function
properly after implementation of firmware changes.
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity
has the latitude to install devices and/or programming that they believe will perform to their
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PRC-005-2 Frequently-Asked Questions
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
B.
Please clarify what is meant by restoration in the definition of maintenance.
The componentdescription of “Restoration” in the definition of a Protection System
Maintenance Program, addresses corrective activities necessary to assure that the component is
returned to working order following the discovery of its failure or malfunction. The
Maintenance Activities specified in Table 1a, Table 1b, and Table 1cthe Tables do not present
any requirements related to Restoration; R4.3 of the standard does require that the entity
“initiate any necessary activities to correct unresolved maintenance correctable issues”. Some
examples of restoration (or correction of maintenance-correctable issues) include, but are not
limited to, replacement of capacitors in distance relays to bring them to working order;
replacement of relays, or other Protection System components, to bring the Protection System
to working order; upgrade of electro-mechanical or solid-state protective relays to microprocessor based relays following the discovery of failed components. Restoration, as used in
this context is not to be confused with Restoration rules as used in system operations.
Maintenance activity necessarily includes both the detection of problems and the repairs
needed to eliminate those problems. This standard does not identify all of the Protection
System problems that must be detected and eliminated, rather it is the intent of this standard
that an entity determines the necessary working order for their various devices and keeps them
in working order. If an equipment item is repaired or replaced then the entity can restart the
maintenance-time-interval-clock if desired, however the replacement of equipment does not
remove any documentation requirements that would have been required to verify compliance
with time-interval requirements; in other words do not discard maintenance data that goes to
verify your work
C.
If I upgrade my old relays then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced then the entity can restart the maintenanceactivity-time-interval-clock if desired, however the replacement of equipment does not remove
any documentation requirements. The requirements in the standard are intended to ensure that
an entity has a maintenance plan and that the entity adheres to minimum activities and
maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance cyclesactivities is intended to demonstrate compliance with the interval.
Therefore, if you upgrade or replace equipment then you still must maintain the documentation
for the previous equipment, thus demonstrating compliance with the time interval requirement
prior to the replacement action.
D.
What is meant by “Verify that settings are as specified” maintenance activity in tables 1a
and 1bTable 1-1?
Verification of settings is an activity directed mostly towards microprocessor based relays.
For relay maintenance departments that choose to test microprocessor based relays in the same
manner as electro-mechanical relays are tested, the testing process sometimes requires that
some specific functions be disabled. Later tests might enable the functions previously disabled
but perhaps still other functions or logic statements were then masked out. It is imperative that,
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PRC-005-2 Frequently-Asked Questions
when the relay is placed into service, the settings in the relay be the settings that were intended
to be in that relay or as the Standard states “…settings are as specified.”
Many of the microprocessor based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement a simple recorded acknowledgement that
this was donethe settings were checked to be as specified is sufficient.
The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is simply to
check that the settings in the relay match the settings specified to those placed into the relay.
E.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in tables 1a and 1bTable 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection, and thus the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
F.
I use my protective relays only as sources of metered quantities and breaker status for
SCADA and EMS through a substation distributed RTU or data concentrator to the
control center. What are the maintenance requirements for the relays?
This standard addresses only devices “that are applied on, or are designed to provide
protection for the BES.” Protective relays, providing only the functions mentioned in the
question, are not included.
G.
I use my protective relays for fault and disturbance recording, collecting oscillographic
records and event records via communications for fault analysis to meet NERC and
DME requirements. What are the maintenance requirements for the relays?
For relays used only as disturbance monitoring equipment, the NERC standard PRC-018-1 R3
& R6 states the maintenance requirements, and is being addressed by a Standards activity that
is revising PRC-002-1 and PRC-018-1. For protective relays “that are applied on, or are
designed to provide protection for the BES,” this standard applies, even if they also perform
DME functions.
H.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system rating
changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system upratesup-rates, upgrades and overall changes meet any and all
other requirements and standards then the requirements of PRC-005-2 are simple – if the
Protection system component performs a Protection system function then it must be
maintained. If the component no longer performs Protection System functions than it does not
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PRC-005-2 Frequently-Asked Questions
require maintenance activities under the Tables of PRC-005-2. While many entities might
physically remove a component that is no longer needed there is no requirement in PRC-005-2
to remove such component(s). Obviously, prudence would dictate that an “out-of-service”
device is truly made inactive. There are no record requirements listed in PRC-005-2 for
Protection System components not used.
I.
While performing relay testing of a protective device on our Bulk Electric System it was
discovered that the protective device being tested was either broken or out of calibration.
Does this satisfy the relay testing requirement even though the protective device tested
bad, and may be unable to be placed back into service?
Yes, PRC-005-2 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-2
requirement although the protective device may be unable to be returned to service under
normal calibration adjustments. R4.3 states (the entity must):
The entity must assure either that the components are within acceptable parameters at the
conclusion of the maintenance activities or initiate any necessary activities to correct
unresolved maintenance correctable issues.
J.
If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R4.3) (in essence) state that the entity assure the
components are within the owner’s acceptable operating parameters, if not then actions must
be initiated to correct the deviance. The type of corrective activity is not stated; however it
could include repairs or replacements. Documentation is always a necessity (“If it is not
documented then it wasn’t done!”)
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
K.
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
L.
What is meant by “verify operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System?”
Any input or output that “affects the tripping” of the breaker is included in the scope of I/O to
be verified. By “affects the tripping” one needs to realize that sometimes there are more Inputs
and Outputs than simply the output to the trip coil. Many important protective functions include
things like Breaker Fail Initiation, Zone Timer Initiation and sometimes even 52a/b contact
inputs are needed for a protective relay to correctly operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
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PRC-005-2 Frequently-Asked Questions
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay.
Each input detector on a component that is needed for a protective function and each output
action from a component that is needed for a protective function needs to be tested.
In short, if an entity designed a scheme into the protective functions then that scheme needs to
be tested.
3. Voltage and Current Sensing Device Inputs to Protective Relays
A.
What is meant by “…verify the current and voltage circuit inputs from the voltage and
current sensing devices to the protective relays …” Do we need to perform ratio,
polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current sensing devices (typically voltage and current transformers). This can be as
difficult as is proposed by the question (with additional testing on the cabling and substation
wiring to ensure that the values arrive at the relays); or simplicity can be achieved by other
verification methods. While some examples follow, these are not intended to represent an allinclusive list; technology advances and ingenuity should not be excluded from making
comparisons and verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional testing on the
panel wiring to ensure that the values arrive at those relays) with the other phases, and verify
that residual currents are within expected bounds
•
Observe all three phase currents and the residual current at the relay panel with an oscilloscope,
observing comparable magnitudes and proper phase relationship, with additional testing on the
panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay (such as, but not limited to, a query
to the microprocessor relay), to another protective relay monitoring the same line, with currents
supplied by different CT’s.
•
Compare the secondary values, at the relay with values measured by test instruments (such as,
but not limited to multi-meters, voltmeter, clamp-on ammeters, etc) and verified by calculations
and known ratios to be the values expected. For example a single PT on a 100KV bus will have
a specific secondary value that when multiplied by the PT ratio arrives at the expected bus
value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned relay,
compare those SCADA values to the values as determined by the questioned relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by the
questioned relay.
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PRC-005-2 Frequently-Asked Questions
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that, an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring systems.
B.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral currents, or
3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be also verified by use of oscillographic records for connected
microprocessor relays as recorded during system disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known fault locations.
C.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify
the insulation of the wiring between the instrument transformer and the relay.
D.
My plant generator and transformer relays are electromechanical and do not have
metering functions as do microprocessor based relays. In order for me to compare the
instrument transformer inputs to these relays to the secondary values of other metered
instrument transformers monitoring the same primary voltage and current signals, it
would be necessary to temporarily connect test equipment like voltmeters and clamp on
ammeters to measure the input signals to the relays. This practice seems very risky and
a plant trip could result if the technician were to make an error while measuring these
current and voltage signals. How can I avoid this risk? Also, what if no other
instrument transformers are available which monitor the same primary voltage or
current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests
to adequately “verify the current and voltage circuit inputs from the voltage and current
sensing devices to the protective relays …” while eliminating the risk of tripping an in service
generator or transformer. Similarly, this same offline test methodology can be used to verify
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PRC-005-2 Frequently-Asked Questions
the relay input voltage and current signals to relays when there are no other instrument
transformers monitoring available for purposes of signal comparison.
4. Protection System Control Circuitry
A.
Is it permissible to verify circuit breaker tripping at a different time (and interval) than
when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual components’
maximum allowable testing intervals.
B.
The Protection System Maintenance Standard describes requirements for verifying the
tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC-005-2 are intended to verify the integrity of tripping circuits, including
the breaker trip coil, as well as the presence of auxiliary supply (usually a dc battery) for
energizing the trip coil if a protection function operates. Beyond this, PRC-005-2 sets no
requirements for verifying circuit breaker performance, or for maintenance of the circuit
breaker.
C.
How do I test each dc Control Circuit path, as established for level 2 (partially monitored
protection systems) monitoring of ain Table 1-5 “Protection System Control Circuitry
(Trip coils and auxiliary relays)”?
Table 1b1-5 specifies that each breaker trip coil, auxiliary relay, and lockout relay
must be operated within the specified time period. The required operations may be via
targeted maintenance activities, or by documented operation of these devices for other
purposes such as fault clearing.
D.
What does this standard require for testing an Auxiliary Tripping Relay?
Table 1 requires that the trip test must verify that the auxiliary tripping relay(s) and/or lockout
relay(s) operate(s) electrically and that their trip output(s) perform as expected. Auxiliary
outputs not in a trip path (i.e. alarmingannunciation or DME input) are not required, by this
standard, to be checked.
E.
What does a functional (or operational) trip test include?
An operational trip test must be performed on each portion of a trip circuitdevice. Each control
circuit path that produces a trip signal must be verified; this includes trip coils, auxiliary
tripping relays, lockout relays, and communications-assisted-trip schemes.
A trip test may be an overall test that verifies the operation of the entire trip scheme at once, or
it may be several tests of the various portions that make up the entire trip path, provided that
testing of the various portions of the trip scheme verifies all of the portions, including parallel
paths, and overlaps those portions.
A circuit breaker or other interrupting device needs to be trip tested at least once per trip coil..
.
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PRC-005-2 Frequently-Asked Questions
Discrete-component auxiliary relays and lock-out relays must be verified by trip test. The trip
test must verify that the auxiliary or lock-out relay operates electrically and that the relay’s trip
output(s) change(s) state. Software latches or control algorithms, including trip logic
processing implemented as programming component such as a microprocessor relay that take
the place of (conventional) discrete component auxiliary relays or lock-out relays do not have
to be routinely trip tested.
Normally-closed auxiliary contacts from other devices (for example, switchyard-voltage-level
disconnect switches, interlock switches, or pressure switches) which are in the breaker trip
path do not need to be tested.
F.
Is a Sudden Pressure Relay an Auxiliary Tripping Relay?
No. IEEE C37.2-2008 assigns the device number 94 to auxiliary tripping relays. Sudden
pressure relays are assigned device number 63, and is excluded from the Standard by footnote
1because it does not utilize voltage and/or current measurements to determine anomalies.
Devices that use anything other than electrical detection means are excluded.
G.
The standard specifically mentions Auxiliary and Lock-out relays; what is an Auxiliary
Tripping Relay?
An auxiliary relay, IEEE Device Number 94, is described in IEEE Standard C37.2-2008 as “A
device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate
tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should
open automatically, even though its closing circuit is maintained closed.”
H.
What is a Lock-out Relay?
A lock-out relay, IEEE Device Number 86, is described in IEEE Standard C37.2 as “A device
that trips and maintains the associated equipment or devices inoperative until it is reset by an
operator, either locally or remotely.”
I.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of the trip circuit. This standard does not
cover circuit breaker maintenance or transformer maintenance. The standard also does not
cover testing of devices such as sudden pressure relays (63), temperature relays (49), and other
relays which respond to mechanical parameters rather than electrical parameters.
5. Station dc Supply
A.
What constitutes the station dc supply as mentioned in the definition of Protective
System?
The station direct current (dc) supply normally consists of two components: the battery
charger and the station battery itself. There are also emerging technologies that provide a
source of dc supply that does not include either a battery or charger.
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PRC-005-2 Frequently-Asked Questions
Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1.
Emerging Technologies - Station dc supplies are currently being developed that use other
energy storage technologies beside the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1 presents maintenance activities and maximum allowable testing
intervals for these new station dc supply technologies. However, because these technologies
are relatively new the maintenance activities for these station dc supplies may change over
time.
B.
In the Maintenance Activities for station dc supply in Table 1, what do you mean by
“continuity”?
Because the Standard pertains to maintenance not only of the station battery, but also the
whole station dc supply, continuity checks of the station dc supply are required. “Continuity”
as used in Table 1 refers to verifying that there is a continuous current path from the positive
terminal of the station battery set to the negative terminal, otherwise there is no way of
determining that a station battery is available to supply dc current to the station.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path the battery set will not be
available for service.
C.
Why is it necessary to verify the continuity of the dc supply?
In the event of the loss of the ac source or battery charger, the battery must be capable of
supplying dc current, both for continuous dc loads and for tripping breakers and switches.
Without continuity, the battery cannot perform this function.
If the battery charger is not sized to handle the maximum dc current required to operate the
protective systems, it is sized only to handle the constant dc load of the station and the
charging current required to bring the battery back to full charge following a discharge. At
those stations, the battery charger would not be able to trip breakers and switches if the battery
experiences loss of continuity.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
◊
Many battery chargers produce harmonics which can cause failure of dc power supplies in
microprocessor based protective relays and other electronic devices connected to station
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PRC-005-2 Frequently-Asked Questions
◊
D.
dc supply. In these cases, the substation battery serves as a filter for these harmonics.
With the loss of continuity in the battery, the filter provided by the battery is no longer
present.
Loss of electrical continuity of the station battery will cause, regardless of the battery
charger’s output current capability, a delayed response in full output current from the
charger. Almost all chargers have an intentional 1 to 2 second delay to switch from a low
substation dc load current to the maximum output of the charger. This delay would cause
the opening of circuit breakers to be delayed which could violate system performance
standards.
How do you verify continuity of the dc supply?
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery unless the battery charger is taken out of service. At that time
a break in the continuity of the station battery current path will be revealed because there will
be no voltage on the substationstation dc circuitry.
Although the Standard prescribes what must be done during the maintenance activity it does
not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
◊
◊
◊
◊
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path through
the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of the
various dc-supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor basedcontrolled battery chargers have developed
methods for their equipment to periodically (or continuously) test for battery continuity.
For example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
Applying test current (as in an ohmic testing device) will provide a current that when
measured elsewhere in the string, will prove that the circuit is continuous.
No matter how the electrical continuity of a battery set is verified it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1 to insure that the station
dc supply willhas a path that can provide the required current to the Protection System at all
times.
E.
When should I check the station batteries to see if they have sufficient energy to perform
as designed?
The answer to this question depends on the type of battery (valve regulated lead-acid, vented
lead acid, or nickel-cadmium), the maintenance activity chosen, and the type of time based
monitoring level selected.
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PRC-005-2 Frequently-Asked Questions
For example, if you have a Valve Regulated Lead-Acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every three months. While this interval might seem to be quite short, keep in mind that the 3
month interval is consistent with IEEE guidelines for VRLA batteries; this interval provides an
accumulation of data that better shows when a VRLA battery is no longer capable of its design
capacity.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every 3 calendar years.
F.
Why in Table 1 are there two Maintenance Activities with different Maximum
Maintenance Intervals listed to verify that the station battery can perform as designed?
The two acceptable methods for proving that a station battery can perform as designed are
based on two different philosophies. The first activity requires a capacity discharge test of the
entire battery set to verify that degradation of one or several components (cells) in the set has
not deteriorated to a point where the total capacity of the battery system falls below its
designed rating. The second maintenance activity requires tests and evaluation of the internal
ohmic measurements on each of the individual cells/units of the battery set to determine that
each component can perform as designed and therefore the entire battery set can be verified to
perform as designed.
The maximum maintenance interval for discharge capacity testing is longer than the interval
for testing and evaluation of internal ohmic cell measurements. An individual component of a
battery set may degrade to an unacceptable level without causing the total battery set to fall
below its designed rating under capacity testing. However, since the philosophy behind
internal ohmic measurement evaluation is based on the fact that each battery component must
be verified to be able to perform as designed, the interval for verification by this maintenance
activity must be shorter to catch individual cell/unit degradation. It should be noted that even if
a battery unit is composed of multiple cells the ohmic test can still be accomplished. The data
produced becomes trending data on the multi-cell unit instead of trending individual cells.
G.
What is the justification for having two different Maintenance Activities listed in Table 1
to verify that the station battery can perform as designed?
IEEE Standards 450, 1188, and 1106 for vented lead-acid, valve-regulated lead-acid (VRLA),
and nickel-cadmium batteries, respectively (which together are the most commonly used
substation batteries on the BES) go into great detail about capacity testing of the entire battery
set to determine that a battery can perform as designed.
The first maintenance activity listed in Table 1 for verifying that a station battery can perform
as designed uses maximum maintenance intervals for capacity testing that were designed to
align with the IEEE battery standards. This maintenance activity is applicable for vented leadacid, valve-regulated lead-acid, and nickel-cadmium batteries.
The second maintenance activity listed in Table 1 for verifying that a station battery can
perform as designed uses maximum maintenance intervals for evaluating internal ohmic
measurements in relation to their baseline measurements that are based on industry experience,
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PRC-005-2 Frequently-Asked Questions
EPRI technical reports and application guides, and the IEEE battery standards. By evaluating
the internal ohmic measurements for each cell and comparing that measurement to the cell’s
baseline ohmic measurement (taken at the time of the battery set’s acceptance capacity test),
low-capacity cells can be identified and eliminated to keep the battery set capable of
performing as designed. This maintenance activity is applicable only for vented lead-acid and
VRLA batteries.; this trending activity has not shown to be effective for NiCd batteries thus
the only choices for NiCd batteries are the performance tests (see applicable IEEE guideline
for specifics on performance tests). It should be noted that even if a battery unit is composed
of multiple cells the ohmic test can still be accomplished. The data produced becomes trending
data on the multi-cell unit instead of trending individual cells.
H.
Why in Table 1 of PRC-005-2 is there a maintenance activity to inspect the structural
intergrity of the battery rack?
The three IEEE standards (1188, 450, and 1106) for VRLA, vented lead-acid, and nickelcadmium batteries all recommend that as part of any battery inspection the battery rack should
be inspected. The purpose of this inspection is to verify that the battery rack is correctly
installed and has no deterioration that could weaken its structural integrity. Because the
battery rack is specifically designed for the battery that is mounted on it, weakening of its
structural members by rust or corrosion can physically jeopardize the battery.
I.
What is required to comply with the “Unintentional Grounds” requirement?
In most cases, the first ground that appears on a battery pole is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously a “check-off” of some sort
will have to be devised by the inspecting entity to demonstratedocument that a check is
routinely done for Unintentional DC Grounds.
J.
Where the standard refers to “all cells” is it sufficient to have a documentation method
that refers to “all cells” or do we need to have separate documentation for every cell? For
example to I need 60 individual documented check-offs for good electrolyte level or
would a single check-off per bank be sufficient???
A single check-off per battery bank is sufficient. for documentation, as long as the single
check-off attests to checking all cells/units.
K.
Does this standard refer to Station batteries or all batteries, for example
CommunicationCommunications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communicationcommunications sites. The batteries covered under PRC005-2 are the batteries that supply the trip current to the trip coils of the interrupting devices
that are a part of the Protection System. The SDT believes that a loss of power to the
communications systems at a remote site would cause the communications systems associated
with protective relays to alarm at the substation. At this point the corrective actions can be
initiated.
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PRC-005-2 Frequently-Asked Questions
L.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on these
units that I cannot get to?
The values that are measured at all available terminals will produce results that can be tracked.
Thus the trended results become the results of a unit instead of an individual cell. Bad units
(regardless of the number of cells per unit) will result in the eventual repair or replacement of
multiple cells even if only a single cell actually went bad. Cell-to-cell tests can equate to unitto-unit tests or jar-to-jar tests. If there is such a thing as a single unit that contains the entire
battery for the facility but only brings out the positive and negative posts (as in a car battery)
then the testing across these only two available posts will produce usable trending test data.
6. Protection System Communications Equipment
A.
What are some examples of mechanisms to check communications equipment
functioning?
For Level 1For unmonitored Protection Systems, various types of communications systems
will have different facilities for on-site integrity checking to be performed at least every three
months during a substation visit. Some examples are: , but not limited to:
◊ On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier checkbackcheck-back test from one terminal.
◊ Systems which use frequency-shift communications with a continuous guard signal (over a
telephone circuit, analog microwave system, etc.) can be checked by observing for a lossof-guard indication or alarm. For frequency-shift power line power-line carrier systems,
the guard signal level meter can also be checked.
◊ Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
◊ Digital communications systems typically have some sort ofa data reception indicator or
data error indicator (based on loss of signal, bit error rate, or frame error checking).
For Level 2 partiallyFor monitored Protection Systems, various types of communications
systems will have different facilities for monitoring the presence of the communications
channel, and activating alarms that can be monitored remotely. Some examples are, but not
limited to:
◊ On-off power-line carrier systems can be shown to be operational by automated periodic
power-line carrier checkbackcheck-back tests, with remote alarming of failures.
◊ Systems which use a frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be remotely monitored with a lossof-guard alarm or low signal level alarm.
◊ Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
◊ Digital communications systems can activate remotely monitored alarms for data reception
loss or data error indications.
◊ For Level 3 fully monitoredSystems can be queried for the data error rates.
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PRC-005-2 Frequently-Asked Questions
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
◊ In many communications systems signal quality measurements including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio, propagation
delay, and data error rates are compared to alarm limits. These alarms are connected for
remote monitoring.
◊ Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment location
is continuously being reflected at the remote monitoring site.
B.
What is needed for the 3-month inspection of communicationcommunications-assisted
trip scheme equipment?
The 3-month inspection applies to Level 1 (Unmonitored)unmonitored equipment. An
example of compliance with this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms, check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (iei.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard.
C.
Does a fiber optic I/O scheme used for breaker tripping or control within a station, for
example - transmitting a trip signal or control logic between the control house and the
breaker control cabinet, constitute a communicationcommunications system?
This equipment is presently classified as being part of the Protection System Control Circuitry
and tested per the portions of Table 1 applicable to Protection System Control Circuitry rather
than those portions of the table applicable to communicationcommunications equipment.
D.
In Table 1b1-2, the Maintenance Activities section of the Protective System
Communications Equipment and Channels refers to the quality of the channel meeting
“performance criteria”. What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating
normally an alarm will be indicated. For Level 1unmonitored systems this alarm will probably
be on the panel. For Level 2 and Level 3monitored systems, the alarm will be transmitted to a
remote location.
Each entity will have established a nominal performance level for each protective system
communications channel that is consistent with proper functioning of the Protection System.
If that level of nominal performance is not being met, the system will go into alarm.
Following are some examples of protective system communications channel performance
criteriameasuring:
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PRC-005-2 Frequently-Asked Questions
◊ For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system is
calibrated and if the signal level drops below an established level, the system will indicate
an alarm.
◊ An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use checkbackcheck-back testing to determine channel
performance. A predetermined signal sequence is sent to the remote end and the remote
end decodes this signal and sends a signal sequence back. If the sending end receives the
correct information from the remote terminal, the test passes and no alarm is indicated.
Full power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
◊ Pilot wire relay systems use a hardwire communications circuit to communicate between
the local and remote ends of the protective zone. This circuit is monitored by circulating a
dc current between the relay systems. A typical level may be 1 mA. If the level drops
below the setting of the alarm monitor, the system will indicate an alarm.
◊ Modern digital relay systems use data communications to transmit relay information to the
remote end relays. An example of this is a line current differential scheme commonly used
on transmission lines. The protective relays communicate current magnitude and phase
information over the communications path to determine if the fault is located in the
protective zone. Quantities such as digital packet loss, bit error rate and channel delay are
monitored to determine the quality of the channel. These limits are determined and set
during relay commissioning. Once set, any channel quality problems that fall outside the
set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be - it
just requires that the entity establish nominal criteria so protective system channel monitoring
can be performed.
7. UVLS and UFLS Relays that Comprise a Protection System Distributed Over the Power
System
A.
We have an Under Voltage Load Shedding (UVLS) system in place that prevents one of
our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation as stated indicates that the tripping action was intended to prevent low
distribution voltage forto a specific load from a transmission system that was intact except for
the line that was out of service. , as opposed to preventing cascading outage or transmission
system collapse.
This Standard is not applicable to this UVLS.
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PRC-005-2 Frequently-Asked Questions
B.
We have a UFLS scheme that sheds the necessary load through distribution-side circuit
breakers and circuit reclosers. Do the trip-test requirements for circuit breakers apply to
our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential Lock-Out Relay. While many failures of
these distribution breakers could add up to be significant, it is also believed that distribution
breakers are operated often on just fault clearing duty and therefore the distribution circuit
breakers are operated at least as frequently as any requirements that might have appeared in
this standard.
C.
What does “distributed over the power system” mean?
This refers to the common practice of applying UFLS on the distribution system, with each
UFLS individually tripping a relatively low value of load. Therefore, the program is
implemented via a large number of individual UFLS components performing independently,
and the failure of any individual component to perform properly will have a minimal impact
on the effectiveness of the overall UFLS program. Some UVLS systems are applied similarly.
8. SPS or Relay Sensing for Centralized UFLS or UVLS
A.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end-to-end test.
B.
What about SPS interfaces between different entities or owners?
All SPS owners should have maintenance agreements that state which owner will perform
specific tasks. As in all of the Protection System requirements, SPS segments can be tested
individually, but must overlap. thus minimizing the need to accommodate complex
maintenance schedules.
C.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
Any Phasor Measurement Unit (PMU) function whose output is used in a protection
systemProtection System or Special Protection System (as opposed to a monitoring task) must
be verified as a component in a Protection System.
D.
How do I maintain a Special Protection System or Relay Sensing for Centralized UFLS
or UVLS Systems?
Components Since components of the SPS, UFLS, or UVLS are the same types of components
as those in Protection Systems then these components should be maintained like similar
components used for other Protection System functions. In many cases the devices for SPS,
UFLS and UVLS are also used for other protective functions. The same maintenance activities
apply with the exception that distributed systems (UFLS and UVLS) have fewer dc supply and
control circuitry maintenance activity requirements.
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PRC-005-2 Frequently-Asked Questions
For the testing of the output action, verification may be by breaker tripping, or other control
action that must be verified, but may be verified in overlapping segments. A grouped output
control action need be verified only once within the specified For example an SPS that trips a
remote circuit breaker might be tested by testing the various parts of the scheme in
overlapping segments. Another method is to document the real-time interval, but all of the
SPS, UFLS, or UVLS components whose operation leads to that control action must each be
verified.tripping of an SPS scheme should that occur. Forced trip tests of circuit breakers (etc)
that are a part of distributed UFLS or UVLS schemes are not required
E.
What does “centralized” mean?
This refers to the practice of applying sensing units at many locations over the system, with all
these components providing intelligence to an analytical system which then directs action to
address a detected condition. In some cases, this action may not take place at the same
location as the sensing units. This approach is often applied for complex SPS, and may be
used for UVLS (and perhaps even with UFLS) where necessary to address the conditions of
concern.
III
Group by Type of BES Facility:
1. All BES Facilities
A.
What, exactly, is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms
Used in Reliability Standards, and is not being modified within this draft Standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving
only load with one transmission source are generally not included in this definition.
Each Regional Entity implements a definition of the Bulk Electric System that is based on this
NERC definition, in some cases, supplemented by additional criteria. These regional
definitions have been documented and provided to FERC as part of a June 16, 2007
Informational Filing.
2. Generation
A.
Please provide a sample list of devices or systems that must be verified in a generator,
generator step-up transformer, and generator connected station auxiliary transformer to
meet the requirements of this Maintenance Standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay may include but are not necessarily limited to:
• Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
• Loss-of-field relays
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PRC-005-2 Frequently-Asked Questions
•
•
•
•
•
•
•
•
•
•
•
Volts-per-hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator-ground relays
Communications-based protection systems such as transfer-trip systems
Generator differential relays
Reverse power relays
Frequency relays
Out-of-step relays
Inadvertent energization protection
Breaker failure protection
For generator step up or generator-connected station auxiliary transformers, operation of any
the following associated protective relays frequently would result in a trip of the generating unit
and, as such, would be included in the program:
• Transformer differential relays
• Neutral overcurrent relay
• Phase overcurrent relays
A loss of a system-connected station auxiliary transformer could result in a loss of the
generating plant if the plant was being provided with auxiliary power from that source, and this
auxiliary transformer may directly affect the ability to start up the plant and to connect the plant
to the system. Thus, operation of any of the following relays associated with system-connected
station auxiliary transformers would be included in the program:
• Transformer differential relays
• Neutral overcurrent relay
• Phase overcurrent relays
Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program even if the loss of the those loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal-conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
3. Transmission
A.
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having relevant
facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
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PRC-005-2 Frequently-Asked Questions
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
IV
Group by Type of Maintenance Program:
1. All Protection System Maintenance Programs
A. I can’t figure out how to demonstrate compliance with the requirements for the highest
level 3 (fully monitored)of monitoring of Protection Systems. Why does this Maintenance
Standard describe a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for level 3 (fully monitored)the highest level
of monitoring any particular component of Protection Systems is likely to be very involved, and
may include detailed manufacturer documentation of complete internal monitoring within a
device, comprehensive design drawing reviews, and other detailed documentation. This
Standard does not presume to specify what documentation must be developed; only that it must
be comprehensivedocumented.
There may actually be some equipment available that is capable of meeting level-3these highest
levels of monitoring criteria, in which case it may be maintained according to Table 1cthe
highest level of monitoring shown on the Tables. However, even if there is no equipment
available today that can meet this level of monitoring,; the Standard establishes the necessary
requirements for when such equipment becomes available.
By creating a roadmap for development, this provision makes the Standard technology-neutral.
The standard drafting team wants to avoid the need to revise the Standard in a few years to
accommodate technology advances that are certainly coming to the industry.
B. What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the Requirement being documented, include but
are not limited to:
•
•
•
•
•
•
•
•
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database lists, records and/or screen shots that demonstrate compliance information
Diagrams, engineering prints,Prints, diagrams and/or schematics, maintenance and testing
Maintenance records, etc.
Logs (operator, substation, and other types of log)
Inspection forms
U.S. or Canadian mailMail, memos, or email proving the required information was
exchanged, coordinated, submitted or received
• Database lists and records
• Check-off forms (paper or electronic)
• Any record that demonstrates that the maintenance activity was known and, accounted for,
and/or performed.
C. If I replace a failed Protection System component with another component, what testing
do I need to perform on the new component?
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PRC-005-2 Frequently-Asked Questions
The replacement component must be tested to a degree that assures that it will perform as
intended. If it is desired to reset the Table 1 maintenance interval for the replacement
component, all relevant Table 1 activities for the component should be performed.
D. Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records to
demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electro-mechanical protective relays be
tested, for routine scheduled tests, every 3 calendar years with a maximum allowed grace
period of an additional 18 months. This entity would be required to maintain its records of
maintenance of its last two routine scheduled tests. Thus its test records would have a latest
routine test as well as its previous routine test. The interval between tests is therefore provable
to an auditor as being within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to haverequire three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements while still having minimum data available to demonstrate compliance with time
intervals.
Realistically, the Standard is providing advanced notice of audit team documentation requests;
this type of information has already been requested by auditors.
If an entity prefers to utilize Performance Based Maintenance then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
2. Time-Based Protection System Maintenance (TBM) Programs
A. What does this Maintenance Standard say about commissioning? Is it necessary to have
documentation in your maintenance history of the completion of commission testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified on Table 1ain the Tables of PRC-005-2, verification of the
adequacy of initial installation necessitates the performance of testing and inspections that go
well beyond these routine maintenance activities. For example, commission testing might set
baselines for future tests; perform acceptance tests and/or warranty tests; utilize testing methods
that are not generally done routinely like staged-fault-tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation and need not be re-verified
within an ongoing maintenance program. Example – it is not necessary to re-verify correct
terminal strip wiring on an ongoing basis.
PRC-005-2 assumes that thorough commission testing was performed prior to a protection
system being placed in service. PRC-005-2 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
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PRC-005-2 Frequently-Asked Questions
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content
and therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
AnNotwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See next FAQ).
B. How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a facility and its associated
Protection System were placed in service. Alternatively, an entity may choose to use the date
of completion of the commission testing of the Protection System component as the starting
point in determining its first maintenance due dates. Whichever method is chosen, for newly
installed Protection Systems the maintenance program should clearly identify when
maintenance is first due.
It is conceivable that there can be a (substantial) difference in time between the date of testing
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non-compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in-service
dates then the testing date should be followed because it is the degradation of components that
is the concern. While accuracy fluctuations may decrease when components are not energized
there are cases when degradation can take place even though the device is not energized.
Minimizing the time between commissioning tests and in-service dates will help.
C. The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled outage
following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance intervals
were selected with typical plant outages, among other things, in mind.
D. If I am unable to complete the maintenance as required due to a major natural disaster
(hurricane, earthquake, etc), how will this affect my compliance with this standard.
The NERC Sanction Guidelines of the North American Electric Reliability Corporation
effective January 15, 2008 provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.1
E. What if my observed testing results show a high incidence of out-of-tolerance relays, or,
even worse, I am experiencing numerous relay misoperations due to the relays being outof-tolerance?
1 Sanction Guidelines of the North American Electric Reliability Corporation. Effective January 15, 2008.
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PRC-005-2 Frequently-Asked Questions
AnyThe established maximum time intervals are mandatory only as a not-to-exceed limitation.
The establishment of a maximum is measurable. But, any entity can choose to test some or all
of their Protection System components more frequently (or, to express it differently, exceed the
minimum requirements of the Standard). Particularly, if you find that the maximum intervals in
the Standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest. The BES and an entity’s bottom line both suffer.
F. We believe that the 3-month interval between inspections is unneccessary, why can we not
perform these inspections twice per year?
The standard drafting team believes that routine monthly inspections are the norm. To align
routine station inspections with other important inspections the 3-month interval was chosen. In
lieu of station visits many activities can be accomplished with automated monitoring and
alarming.
G. Our maintenance plan calls for us to perform routine protective relay tests every 3 years;
if we are unable to achieve this schedule but we are able to complete the procedures in less
than the Maximum Time Interval then are we in or out of compliance?
You are out of compliance. You must maintain your equipment to your stated intervals within
your maintenance plan. The protective relays (and any Protection System component) cannot
be tested at intervals that are longer than the maximum allowable interval stated in the Tables.
and yet you must conform to your own maintenance plan. Therefore you should design your
maintenance plan such that it is not in conflict with the Minimum Activities and the Maximum
Intervals. You then must maintain your equipment according to your maintenance plan. You
will end up being compliant with both the standard and your own plan.
H. How do I achieve a “grace period” without being out of compliance?
For the purposes of this example, concentrating on just unmonitored protective relays, because
there are more relays out there than anything else – Table 1-1 specifies a maximum time
interval (between the mandated maintenance activities) of 6 calendar years. Your plan must
ensure that your unmonitored relays are tested at least once every 6 calendar years. You could,
within your PSMP, require that your unmonitored relays be tested every 4 calendar years with a
maximum allowable time extension of 18 calendar months. This allows an entity to have
deadlines set for the auto-generation of work orders but still have the flexibility in scheduling
complex work schedules. This also allows for that 18 calendar months to act as a buffer, a grace
period, in the event of unforeseen events. You will note that this example of a maintenance plan
interval has a planned time of 4 years; it also has a built-in time extension allowed within the
PSMP and yet does not exceed the maximum time interval allowed by the standard. So while
there are no time extensions allowed beyond the standard, an entity can still have substantial
flexibility to maintain their Protection System components.
I. If I miss two battery inspections four times out of 100 protection system components on
my transmission system, does that count as 2 percent or 8 percent when counting
Violation Severity Level (VSL) for R4?
The entity failed to complete its scheduled program on two of its one hundred protection
system components which would equate to two percent for application to the VSL Table for
Requirement R4.
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PRC-005-2 Frequently-Asked Questions
3. Performance-Based Protection System Maintenance (PBM) Programs
A. I’m a small entity and cannot aggregate a population of Protection System components to
establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of
individual Protection System components to create a segment that crosses ownership
boundaries. All entities participating in a joint program should have a single documented joint
management process, with consistent Protection System Maintenance Programs (practices,
maintenance intervals and criteria), for which the multiple owners are individually responsible
with respect to the requirements of the Standard. The requirements established for
performance-based maintenance must be met for the overall aggregated program on an ongoing
basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power-plant
vs. substation, and weather conditions.
B. Can an owner go straight to a performance-based maintenance program schedule, if they
have previously gathered records?
Yes. An owner can go to a performance-based maintenance program immediately. The owner
will need to comply with the requirements of a performance-based maintenance program as
listed in the standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they can notcannot prove that they have collected the data as
required for a performance-based maintenance program then they will need to wait until they
can prove compliance.
C. When establishing a performance-based maintenance program, can I use test data from
the device manufacturer, or industry survey results, as results to help establish a basis for
my performance-based intervals?
No. You must use actual in-service test data for the components in the segment.
D. What types of misoperations or events are not considered countable events in the
performance-based Protection System Maintenance (PBM) Program?
Countable events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned.
HumanFor this purpose of tracking hardware issues, human errors resulting in Protection
System Misoperationsmisoperations during system installation or maintenance activities are not
considered countable events. Examples of excluded human errors include relay setting errors,
design errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
misapplication, and components not specified correctly for their installation. Obviously, if one
is setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human-error is not pertinent data might be in the area of testing “86” Lock-Out
Relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move
into a performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial
six-year interval they find zero type “X” failures, but human error led to tripping a BES
element 100 times; they find 100 type “Y” failures and had an additional 100 human-error
caused tripping incidents. In this example the human-error caused misoperations should not be
used to judge the performance of either type of LOR. Analysis of the data might lead “Entity
A” to change time intervals. Type “X” LOR can be placed into extended time interval testing
because of its low failure rate (zero failures) while Type “Y” would have to be tested more
often than every 6 calendar years (100 failures divided by 1000 units exceeds the 4% tolerance
level).
Certain types of Protection System component errors that cause Misoperationsmisoperations
are not considered countable events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
E. What are some examples of methods of correcting segment perfomance for PerformanceBased Maintenance?
There are a number of methods that may be useful for correcting segment performance for malperforming segments in a performance-based maintenance system. Some examples are listed
below.
•
The maximum allowable interval, as established by the performance-based maintenance
system, can be decreased. This may, however, be slow to correct the performance of the
segment.
•
Identifiable sub-groups of components within the established segment, which have been
identified to be the mal-performing portion of the segment, can be broken out as an
independent segment for target action. Each resulting segment must satisfy the minimum
population requirements for a performance-based maintenance program in order to remain
within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
Components within the mal-performing segment can be replaced with other components
(electromechanical distance relays with microprocessor relays, for example) to remove the
mal-performing segment.
F. If I find (and correct) a maintenance-correctable issue as a result of a misoperation
investigation (Re: PRC-004), how does this affect my performance-based maintenance
program?
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC-004 required misoperation investigation/corrective action), the actions performed
can count as a maintenance activity, and “reset the clock” on everything you’ve done. In a
performance-based maintenance program, you also need to record the maintenance-correctable
issue with the relevant component group and use it in the analysis to determine your correct
performance-based maintenance interval for that component group. Note that “resetting the
clock” should not be construed as interfering with an entity’s routine testing schedule because
the “clock-reset” would actually make for a decreased time interval by the time the next routine
test schedule comes around.
For example a relay scheme, consisting of 4 relays, is tested on 1-1-11 and the PSMP has a time
interval of 3 calendar years with an allowable extension of 1 calendar year. The relay would be
due again for routine testing before the end of the year 2015. This mythical relay scheme has a
misoperation on 6-1-12 that points to one of the four relays as bad. Investigation proves a bad
relay and a new one is tested and installed in place of the original. This replacement relay
actually could be retested before the end of the year 2016 (clock-reset) and not be out of
compliance. This requires tracking maintenance by individual relays and is allowed. However,
many companies schedule maintenance in other ways like by substation or by circuit breaker or
by relay scheme. By these methods of tracking maintenance that “replaced relay” will be
retested before the end of the year 2015. This is also acceptable. In no case was a particular
relay tested beyond the PSMP of 4 years max, nor was the 6 year max of the standard exceeded.
The entity can reset the clock if they desire or the entity can continue with original schedules
and, in effect, test even more frequently.
G. Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation from
the factory to the job site, length of time before a charge is put on the battery, the method of
installation, the voltage level and duration of equalize charges, the float voltage level used, and
the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a performance-based Protection System Maintenance
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
(PBM) program. These inherent variances in the aging process of a battery cell make
establishment of a designated segment based on manufacturer and type of battery impossible.
The whole point of PBM is that if all variables are isolated then common aging and
performance criteria would be the same. However, there are too many variables in the electrochemical process to completely isolate all of the performance-changing criteria.
Similarly Functional Entities that want to establish a condition-based maintenance program
using Level 3 the highest levels of monitoring; resulting in the least amount of hands-on
maintenance activity, of the battery used in a station dc supply can not do socannot completely
eliminate some periodic maintenance. Inspection of the battery is required on a Maximum
Maintenance Interval listed in the tables due to the aging processes of station batteries.
However, Level 3higher degrees of monitoring of a battery can eliminate the requirement for
some periodic testing and some inspections (see Level 3 Monitoring Attributes for Component
of table 1cTable 1-4).
H. Please provide an example of the calculations involved in extending maintenance time
intervals using PBM.
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60
. They start out testing all of the relays within the prescribed Table requirements (6 year max)
by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is greater
than the minimum sample size requirement of 30.
For the sake of example only the following will show 6 failures per year, reality may well have
different numbers of failures every year. PBM requires annual assessment of failures found per
units tested.
After the first year of tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure
rate.
This entity is now allowed to extend the maintenance interval if they choose.
The entity chooses to extend the maintenance interval of this population segment out to 10
years.
This represents a rate of 100 units tested per year; entity selects 100 units to be tested in the
following year.
After that year of testing these 100 units the entity again finds 6 failed units. 6/100= 6%
failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate such that the failure rate is found to be less than 4% per
year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 8 years. This
means that they will now test 125 units per year (1000/8). The entity has just two years left to
get the test rate corrected.
After a year they again find 6 failures out of the 125 units tested. 6/125= 5% failures.
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
In response to the 5% failure rate, the entity decreases the testing interval to 7 years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to get
the test rate corrected.
After a year they again find 6 failures out of the 143 units tested. 6/143= 4.2% failures.
(Note that the entity has tried 5 years and they were under the 4% limit and they tried 7 years
and they were over the 4% limit. They must be back at 4% failures or less in the next year so
they might simply elect to go back to 5 years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to 6 years.
This means that they will now test 167 units per year (1000/6).
After a year they again find 6 failures out of the 167 units tested. 6/167= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 6 years or less. Entity chose 6 year interval and effectively
extended their TBM (5 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; this is there to prevent an
entity from “gaming the system”. An entity might arbitrarily extend time intervals from 6 years
to 20 years. In the event that an entity finds a failure rate greater than 4% then the test rate must
be accelerated such that within three years the failure rate must be brought back down to 4% or
less.
Here is a table that demonstrates the values discussed:
Year #
Total
Population
Test
Interval
Units to be
Tested
(P)
(I)
(U= P/I)
# of
Failures
Found
Failure
Rate
Decision
to Change
Interval
Interval
Chosen
(=F/U)
(F)
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
V
Group by Monitoring Level:
1. All Monitoring Levels
A.
Please provide an example of the level 1 monitored (unmonitored) versus other levels of
monitoring available?
A level 1 (Unmonitored)An unmonitored Protection System has no monitoring and alarm
circuits on the Protection System components. A Protection System component that has
monitoring attributes but no alarm output connected is considered to be un-monitored.
A level 2 (Partially) monitored Protection System or an individual monitored component of a
level 2 (Partially) monitored Protection System has monitoring and alarm circuits on the
Protection System components. The alarm circuits must alert, within 24 hours, a 24-hr staffed
operations centerlocation wherein corrective action can be initiated. This location might be,
but not limited to an Operations Center, Dispatch Office, Maintenance Center or even a
portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of level 2 (Partially) monitored and level 1 (unmonitored)
components within a given Protection System ismight be:
◊
◊
◊
◊
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center. (level 2monitored)
Instrumentation transformers, with no monitoring, connected as inputs to that relay. (level
1unmonitored)
A vented lead-acid battery with low voltage alarm and unintentional grounds detection
alarm connected to SCADA. (monitored except for electrolyte level 2)
A circuit breaker with a trip coil, with no monitor circuit. (level 1 and the trip circuit is not
monitored. (unmonitored)
Given the particular components, and conditions, and using the Table 1 (“Maximum
Allowable Testing Intervals and Maintenance Activities”), the particular components have
maximum activity intervals of:
◊
◊
◊
◊
Every 3 calendar months check electrolyte level (cell voltage and unintentional ground
detection is being maintained more frequently by the monitoring system).
Every 18 calendar months check battery bank ohmic values (if performance tests are not
opted), battery float voltage and battery rack integrity.
Every 6 calendar years battery performance test (if ohmic tests are not opted), battery
charger alarms verified and trip test circuit breakers, electro-mechanical lock-out relays
and auxiliary relays.
Every 12 calendar years the microprocessor relay, the instrumentation transformers and
the control circuitry are verified.
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PRC-005-2 Frequently-Asked Questions
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
◊
◊
◊
◊
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
Instrument transformers, with no monitoring, connected as inputs to that relay.
(monitored)
A vented lead-acid battery with low voltage and ground-detection alarms connected to
SCADA. (monitored except for electrolyte level)
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum
testactivity intervals of:
◊
◊
◊
◊
◊
◊
The Every 3 calendar months check electrolyte level (cell voltage and unintentional
ground detection is being maintained more frequently by the monitoring system).
Every 18 calendar months check battery bank ohmic values (if performance tests are not
opted), battery float voltage and battery rack integrity.
Every 6 calendar years microprocessor relay is verified every 12 calendar years, battery
performance test (if ohmic tests are not opted), battery charger alarms verified and trip test
circuit breakers, electro-mechanical lock-out relays and auxiliary relays.
The Every 12 calendar years the instrumentation transformers and the control circuitry are
verified every 12 calendar years.
The battery is verified every 6 calendar years by performing a performance capacity test of
the entire battery bank or by evaluating the measured cell/unit internal ohmic values to
station battery baseline every 18 months.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
Example #23: A combination of level 2 (partially) monitored and level 1 (unmonitored)
components within a given Protection System is:
◊
◊
◊
◊
A microprocessor relay with integral alarm that is not connected to SCADA. (level 1)
Instrument transformers, with no monitoring, connected as inputs to that relay. (level 1)
A vented lead-acid battery with low voltage alarm connected to SCADA. (level 2)
A circuit breaker with a trip coil, with no circuits monitored. (level 1)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components have maximum test
intervals of:
◊
◊
◊
◊
The microprocessor relay is verified every 6 calendar years.
The instrumentation transformers are verified every 12 calendar years.
The battery is verified every 6 calendar years by performing a performance capacity test of
the entire battery bank or by evaluating the measured cell/unit internal ohmic values to
station battery baseline every 18 months.
The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
Example #3: A combination of level 2 (partially) monitored and level 1 (unmonitored)
components within a given Protection System ismight be:
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
◊
◊
◊
◊
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed operations
center. (level 2monitored)
Instrument transformers, with no monitoring, connected as inputs to that relay (level
1unmonitored)
Battery without any alarms connected to SCADA (level 1unmonitored)
Circuit breaker with a trip coil, with no circuits monitored (level 1unmonitored)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”), the particular components shall have
maximum testactivity intervals of:
◊ The Every 3 calendar months check battery bank voltage, check for unintentional grounds
and check electrolyte level.
◊ Every 18 calendar months check battery bank ohmic values (if performance tests are not
opted), battery float voltage and battery rack integrity.
◊ Every 6 calendar years battery performance test (if ohmic tests are not opted), battery
charger alarms verified and trip test circuit breakers, electro-mechanical lock-out relays
and auxiliary relays.
◊ Every 12 calendar years the microprocessor relay is verified every 12 calendar years.
◊ The instrument, the instrumentation transformers and the control circuitry are verified
every 12 calendar years.
◊ The battery is verified every 3 months, every 18 months, plus, depending upon the type of
battery used it may be verified at other maximum test intervals, as well.
◊ The circuit breaker trip circuits and auxiliary relays are tested every 6 calendar years.
B.
What is the intent behind the different levels of monitoring?
The intent behind different levels of monitoring is to allow less frequent manual intervention
when more information is known about the condition of Protection System components.
Condition-Based Maintenance is a valuable asset to improve reliability.
C.
Do all monitoring levels apply to all components in a protection system?
No. For some components in a protection system, certain levels of monitoring will not be
relevant. See table below: For example a battery will always need some kind of inspection.
D.
My microprocessor relays and dc circuit alarms are contained on relay panels in a 24hour attended control room. Does this qualify as an extended time interval conditionbased system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Table 1b or Table 1c.
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PRC-005-2 Frequently-Asked Questions
Monitoring Level Applicability TableTables.
(See related definition and decision tree for various level requirements)
Level 1
(Unmonitored)
Level 2
(Partially
Monitored)
Level 3
(Fully
Monitored)
Protective relays
Y
Y
Y
Instrument transformer Inputs to
Protective Relays
Y
N
Y
Protection System control circuitry
(Other than aux-relays & lock-out
relays)
Y
Y
Y
Aux-relays & lock-out relays
Y
N
N
DC supply (other than station
batteries)
Y
Y
Y
Station batteries
Y
N
N
Y
Y
Y
UVLS and UFLS relays that comprise
a protection scheme distributed over
the power system
Y
Y
Y
SPS, including verification of end-toend performance, or relay sensing
for centralized UFLS or UVLS
systems
Y
Y
Y
Protection Component
Protection system communications
equipment and channels
Y = Monitoring Level Applies
N = Monitoring Level Not Applicable
E.
When documenting the basis for inclusion of components into the appropriate levels of
monitoring as per Requirement R2 of the standard, is it necessary to provide this
documentation via aabout the device by device listing of componentsevery component
and the specific monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
systems are Level 2 - Partiallysupply battery chargers are Monitored by stating the following
within the program description:
“All substation dc systemssupply battery chargers are considered Level 2 - Partially
Monitored and subject to the rows for monitored equipment of Table 1b1-4
requirements as all substation dc systemssupply battery chargers are equipped with dc
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PRC-005-2 Frequently-Asked Questions
voltage alarms and ground detection alarms that are sent to the manned control
center.”
Similarly, it would be acceptable to use a combination of a global statement and a device level
list of exclusions. Example:
“Except as noted below, all substation dc systemssupply battery chargers are
considered Level 2 - Partially Monitored and subject to the rows for monitored
equipment of Table 1b1-4 requirements as all substation dc systemssupply battery
chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center. The dc systemssupply battery chargers of
Substation X, Substation Y, and Substation Z are considered Level 1 - Unmonitored
and subject to the rows for unmonitored equipment in Table 1a1-4 requirements as
they are not equipped with ground detection capability.”
Regardless whether this documentation is provided via a device by device listing of
monitoring attributes, by global statements of the monitoring attributes of an entire population
of component types, or by some combination of these methods, it should be noted that auditors
may request supporting drawings or other documentation necessary to validate the inclusion of
the device(s) within the appropriate level of monitoring. This supporting background
information need not be maintained within the program document structure but should be
retrievable if requested by an auditor.
F.
How do I know what monitoring level I am under? – Include Decision Trees
Decision Trees are provided below for each of the following categories of equipment to assist
in the determination of the level of monitoring.
◊
◊
◊
◊
◊
Protective Relays
Current and Voltage Sensing Devices
Protection System Control Circuitry
Station dc Supply
Protection System Communication Systems
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PRC-005-2 Frequently-Asked Questions
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PRC-005-2 Frequently-Asked Questions
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
CONTROL CIRCUIT
MONITOR LEVEL
DECISION TREE
Start
No
Meets
requirements for
Level 2
Monitoring
Yes
?
Is the following true?
1. Control Circuit whose alarms are
automatically provided daily (or more
frequently) to a location where action
can be taken to initiate resolution for
alarmed failures.
2. Monitoring and alarming of
continuity of trip circuit(s).
Note: Trip coils, auxiliary relays, and
lock-out relays must be electrically
operated at Level 1 interval.
Yes
No
?
Meets
requirements for
Level 3
Monitoring
Is the following true?
1. Every function required for correct operation of
Control Cirucuit is continuously monitored and
verified, and detected maintenance-correctable
issues reported.
2. Verification of the means by which alarms and
monitored values are transmitted to a location
where action can be taken to initiate resolution.
3. Detected maintenance-correctable issues for
Control Circuit are be reported within 1 hour or
less of the maintenance-correctable issue
occurring, to a location where action can be taken
to initiate resolution.
4. Monitoring of the continuity of breaker trip
circuits (with alarming for non-continuity), along
with the presence of tripping voltage supply all the
way from relay terminals (or from inside the relay)
though the trip coil, including any auxiliary
contacts essential to proper Protection System
operation. If a trip circuit comprises multiple
paths, each of the paths must be monitored,
including monitoring of the operating coil circuit(s)
and the tripping circuits of auxiliary tripping relays
and lockout relays.
Level 1 Monitored
Control Circuit
Note: Trip coils, auxiliary relays, and lock-out
relays must be electrically operated at Level 1
interval.
End
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PRC-005-2 Frequently-Asked Questions
DC SUPPLY
MONITOR LEVEL
DECISION TREE
Note: Physical inspection of the battery is
required regardless of level of monitoring used.
Start
No
Yes
?
Meets
requirements for
Level 2 Monitoring
Is the following true?
1. DC Supply whose alarms are automatically
provided daily (or more frequently) to a location
where action can be taken for alarmed failures.
2. Monitoring and alarming for the following
items:
- station dc supply
- unintential dc grounds
- electrolyte level of all cells
- individual battery cell/unit state of charge
- continuity of battery cell-to-cell and terminal
resistance
No
Yes
?
Meets
requirements for
Level 3 Monitoring
Is the following true?
1. Verification of the means by which alarms and
monitored values are transmitted to a location
where action can be taken.
2. Detected maintenance-correctable issues are
reported within 1 hour or less of the
maintenance-correctable issue occurring, to a
location where action can be taken to inititate
resolution of the maintenance correctable issue.
3. Monitoring and alarming the station dc supply
status, including, for station dc supplies that
have as a component a battery, the voltage,
specific gravity, electrolyte level, temperature
and connectivity (cell to cell and terminal
connection resistance) of each cell as well as
the battery system terminal voltage and
electrical continuity of the overall battery system.
4. Monitoring and alarming if the performance
capability of the battery is degraded.
5. Monitoring and alarming the ac powered dc
power supply status including low and high
voltage and charge rate for station dc supplies
that have battery systems.
Level 1 Monitored
DC Supply
End
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PRC-005-2 Frequently-Asked Questions
COMMUNICATION SYSTEM
MONITOR LEVEL
DECISION TREE
Start
No
?
Meets
requirements for
Level 2 Monitoring
Yes
Is the following true?
1. Communication
Equipment whose alarms
are automatically provided
daily (or more frequently)
to a location where action
can be taken to initiate
resolution for alarmed
failures.
2. Monitoring and alarming
of protection
communications system
by mechanisms that check
for presence of the
communications channel.
No
?
Yes
Meets
requirements for
Level 3 Monitoring
Is the following true?
1. Verification of the means by
which alarms and monitored
values are transmitted to a
location where action can be
taken to initiate resolution.
2. Detected maintenancecorrectable issues are reported
within 1 hour or less of the
maintenance-correctable issue
occurring, to a location where
action can be taken to initiate
resolution.
3. Evaluating the performance of
the channel and its interface to
protective relays to determine
the quality of the channel and
alarming if the channel does not
meet performance criteria
Level 1 Monitored
Comm. Equip.
End
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PRC-005-2 Frequently-Asked Questions
2. Level 1 Monitored Protection Systems (Unmonitored Protection Systems )
A.
We have an electromechanical (unmonitored) relay that has a trip output to a lockout
relay (unmonitored) which trips our transformer off-line by tripping the transformer’s
high-side and low-side circuit breakers. What testing must be done for this system?
This system is made up of components that are level 1 (all unmonitored).. Assuming a timebased protection system maintenance program schedule, (as opposed to a performance-based
maintenance program), each component must be maintained per Table 1a – Level 1
Monitoring Maximum Allowable Testing Intervals and Maintenance Activities.the most
frequent hands-on activities listed in the Tables 1-1 through 1-5.
3. Level 2 Monitored Protection Systems (Partially Monitored Protection Systems)
A.
We have a 30 year old oil circuit breaker with a red indicating lamp on the substation
relay panel that is illuminated only if there is continuity through the breaker trip coil.
There is no SCADA monitor or relay monitor of this trip coil. The line protection relay
package that trips this circuit breaker is a microprocessor relay that has an integral
alarm relay that will assert on a number of conditions that includes a loss of power to the
relay. This alarm contact connects to our SCADA system and alerts our 24-hour
operations center of relay trouble when the alarm contact closes. This microprocessor
relay trips the circuit breaker only and does not monitor trip coil continuity or other
things such as trip current. Is this an unmonitored or a partially-monitored system?
How often must I perform maintenance?
The protective relay is a level 2 (partially) monitored component of your protection system
and can be maintained every 12 years or when a maintenance correctable issue arises.
Assuming a time-based protection system maintenance program schedule, this component
must be maintained per Table 1b – Level 2 Monitoring Maximum Allowable Testing Intervals
and Maintenance Activities The control circuitry has no electro-mechanical parts and can be
maintained every 12 years. The trip coil(s) has to be electrically operated at least once every 6
years.
The rest of your protection system contains components that are level 1 (unmonitored) and
must be maintained within at least the maximum verification intervals of Table 1a.
B.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Examples include Two examples would be: using
values gathered via data communications and automatically comparing these values with
values from other sources, andor using groupings of other measurements (such as vector
summation of bus feeder currents) for comparison if calibration requirements assure
acceptable measurement of power system input values. Other. Many other methods are
possible.
C.
For a level 2 monitored Protection System (Partially Monitored Protection System)
pertaining toHow is the performance criteria of Protection System communications
equipment and channels, how is the performance criteria involved in the maintenance
program?
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
TheAn entity determines the acceptable performance criteria for each installation, depending
on the technology implemented. If the communicationcommunications channel performance
of a Protection System varies from the pre-determined performance criteria for that system,
then these results should be investigated and resolved.
D.
My system has alarms that are gathered once daily through an auto-polling system; this
is not really a conventional SCADA system but does it meet the Table 1b1 requirements
for inclusion as Level 2a monitored system?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the maintenance-correctable issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
4. Level 3 Monitored Protection Systems (Fully Monitored Protection Systems)that also monitor
alarm path failures
A.
Why are there activities defined for levels of monitoring a level-3 monitored Protection
System? The component when that level of technology doesmay not seem to exist at this
time to implement this monitoring level.yet be available?
There may actuallyalready be some equipment available that is capable of meeting level-3the
highest levels of monitoring criteria, listed in which case it may be maintained according to
Table 1cthe Tables. However, even if there is no equipment available today that can meet this
level of monitoring; the Standard establishes the necessary requirements for when such
equipment becomes available. By creating a roadmap for development, this provision makes
the Standard technology-neutral. The standard drafting team wants to avoid the need to revise
the Standard in a few years to accommodate technology advances that are certainlymay be
coming to the industry.
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
Ap p e n d ix A — P ro te c tio n S ys te m Ma in te n a n c e
S ta n d a rd Dra ftin g Te a m
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle E. Ashton
Tri-State G&T
Mark Lukas
ComEd
Bob Bentert
Florida Power & Light Company
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
John Ciufo
Hydro One Inc
Mark Peterson
Great River Energy
Sam Francis
Oncor
William Shultz
Southern Company Generation
Carol A Gerou
Midwest Reliability Organization
Leonard Swanson, Jr
National Grid USA
William Shultz
Southern Company Generation
Eric A Udren
Quanta Technology
Russell C Hardison
Tennessee Valley Authority
Philip B Winston
Georgia PowerSouthern Company
Transmission
David Harper
NRG Texas Maintenance Services
John A Zipp
ITC Holdings
Draft 2: April, 2010
PRC-005-2 Frequently-Asked Questions
In d e x
3-month interval, 2425
aggregate, 24, 2526
alarm, 16, 17, 18, 29, 30,
3819, 31, 32, 34
automated monitoring and
alarming, 2425, 26
auto-restoration, 5
auxiliary relay, 11, 12
batteries, 12, 13, 14, 15,
26, 27, 3128, 29
battery, 1011, 12, 13, 14,
15, 26, 2716, 28, 29,
3031
broken, 7
capacity, 14, 15, 29, 30
channel performance, 18,
3819, 34
charger, 12, 13, 14
check-off, 1516
closing circuits, 5
commission, 23, 24
Communication Site
Batteries, 15
current and voltage
measurements, 9
data retention, 2223
DC ground, 1516
documentation, 6, 2122,
23, 31, 3224, 33
documentation method,
1516
electromechanical, 7, 10,
26, 3827, 33
electro-mechanical relays,
6
evidence, 6, 22, 23
fiber optic I/O scheme,
1718
firmware, 5, 2527
frequency-shift, 1617
fully monitored, 16, 21
guard, 16, 17, 18
Level 1, 16, 17, 31, 32, 38
Level 2, 16, 17, 31, 32, 38
Level 3, 16, 17, 27, 31, 39
communications, 7, 11, 16,
17, 18, 31, 3819, 34
communications channel,
17, 18
Communications Site
Batteries, 16, 17
communications-assistedtrip, 11
component, 2, 5, 11, 14,
19, 2215, 20, 23, 2524,
26, 2927, 28, 31, 32,
3833
continuity, 12, 13, 14,
3833
corrective, 2, 5, 266, 27,
28
countable events, 2, 2526,
27
lockout relay, 11, 20,
3821, 33
maintenance correctable
issue, 2, 3834
maintenance plan, 6, 22,
2423, 25
maximum allowable
interval, 24, 2625, 27
microprocessor, 5, 6, 7, 9,
10, 11, 13, 14, 26, 29,
30, 3827, 31, 32, 34
Misoperations, 2, 2527
nickel-cadmium, 14, 15
ohmic, 14, 15, 29, 30
out-of-service, 7
partially monitored, 11,
1617
PBM, 24, 25, 26, 2728, 29
performance-based
maintenance, 25, 26, 27,
28
pilot wire, 1617
PMU, 1920
power-line carrier, 1617
pressure relays, 11, 12
protective relays, 5, 6, 7,
89, 10, 12, 13, 1617, 18,
2021
reclosing relays, 5
Restoration, 56
sample list of devices,
2021
segment, 2, 24, 25, 26, 27,
29
settings, 2, 6, 7, 12, 2223
SPS, 5, 19, 3120
Table 1a, 2, 3, 5, 23, 32,
3833
Table 1b, 5, 11, 17, 32,
3818, 33
Table 1c, 2, 5, 21, 3922,
34
TBM, 2223
trip coil, 10, 11, 29, 30,
3831, 32, 33
trip signal, 11, 1718
trip test, 11
tripping circuits, 1011
UFLS, 18, 19, 3120
unintentional ground, 1516
unmonitored, 16, 2917, 30,
3831, 32, 33, 34
UVLS, 18, 19, 3120
valve-regulated lead-acid,
15
vented lead-acid, 15, 2931
voltage and current
sensing devices, 2, 89,
10
VRLA, 14, 15
Draft 2: April, 2010
Page
PRC-005-2 Frequently-Asked Questions
Draft 2: April, 2010
Page
PRC-005-2
Protection System Maintenance
Draft Supplementary Reference
November 17, 2010
Prepared by the
Protection System Maintenance and Testing Standard Drafting Team
PRC-005-2
Project 2007-17
Draft 3: November 17, 2010
Page 1
Table of Contents
1. Introduction and Summary ..........................................................................................................3
2. Need for Verifying Protection System Performance ...................................................................3
2.1 Existing NERC Standards for Protection System Maintenance and Testing ..........................3
2.2 Proposed Modification to NERC Glossary Definition ............................................................4
2.3 Applicability of New Protection System Maintenance Standards ...........................................4
2.4 Applicable Relays ....................................................................................................................4
3. Relay Product Generations ........................................................................................................5
4. Definitions..................................................................................................................................5
5. Time-Based Maintenance (TBM) Programs ...............................................................................6
Maintenance Practices .....................................................................................................................6
5.1 Extending Time-Based Maintenance .........................................................................................7
6. Condition-Based Maintenance (CBM) Programs ........................................................................8
7. Time-Based versus Condition-Based Maintenance ...................................................................9
8. Maximum Allowable Verification Intervals ..............................................................................9
Maintenance Tests ...........................................................................................................................9
8.1 Table of Maximum Allowable Verification Intervals ...........................................................10
8.2 Retention of Records................................................................................................................12
8.3 Basis for Table 1 Intervals .....................................................................................................12
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays ...................................13
9. Performance-Based Maintenance Process ...............................................................................15
9.1 Minimum Sample Size.............................................................................................................15
10. Overlapping the Verification of Sections of the Protection System ........................................18
11. Monitoring by Analysis of Fault Records ................................................................................18
12. Importance of Relay Settings in Maintenance Programs .........................................................19
13. Self-Monitoring Capabilities and Limitations .........................................................................20
14. Notification of Protection System Failures ..............................................................................20
15. Maintenance Activities ............................................................................................................21
15.1 Protective Relays (Table 1-1) ................................................................................................21
15.3 Control circuitry associated with protective functions (Table 1-5) ......................................22
15.4 Batteries and DC Supplies (Table 1-4) ..................................................................................24
15.5 Associated communications equipment (Table 1-2)..............................................................24
15.6 Alarms (Table2) .....................................................................................................................25
15.7 Examples of Evidence of Compliance ...................................................................................25
16. References ................................................................................................................................27
Figures............................................................................................................................................28
Figure 1: Typical Transmission System ........................................................................................28
Figure 2: Typical Generation System ............................................................................................29
Figure 3: Requirements Flowchart.................................................................................................31
Appendix A ....................................................................................................................................32
Appendix B — Protection System Maintenance Standard Drafting Team ...................................35
Draft 3: November 17, 2010
Page 2
This supplementary reference to PRC-005-2 borrows heavily from the technical reference by the System
Protection and Control Task Force (SPCTF) Protection System Maintenance Technical Reference paper
approved by the Planning Committee in September 2007. Additionally, data available from IEEE, EPRI,
and maintenance programs from various generation and transmission utilities across the NERC
boundaries was utilized by the Protection System Maintenance and Testing Standard Drafting Team
(PSMT SDT) for PRC-005-2 (Project 2007-17) to develop this reference document..
1. Introduction and Summary
NERC currently has four reliability standards that are mandatory and enforceable in the United States and
address various aspects of maintenance and testing of Protection and Control systems. These standards
are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for Protection Systems,
and that these entities must be able to demonstrate they are carrying out such a program, there are no
specifics regarding the technical requirements for Protection System maintenance programs. Furthermore,
FERC Order 693 directed additional modifications respective to Protection System maintenance
programs. This revision of PRC-005-1 combines and replaces PRC-005, PRC-008, PRC-011 and PRC017.
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate their
performance until a fault or other power system problem requires that they operate to protect power
system elements, or even the entire Bulk Electric System (BES). Lacking faults or system problems, the
protection systems may not operate for extended periods. A Misoperation - a false operation of a
protection system or a failure of the protection system to operate, as designed, when needed - can result in
equipment damage, personnel hazards, and wide area disturbances or unnecessary customer outages.
Maintenance or testing programs are used to determine the performance and availability of protection
systems.
Typically, utilities have tested protection systems at fixed time intervals, unless they had some incidental
evidence that a particular protection system was not behaving as expected. Testing practices vary widely
across the industry. Testing has included system functionality, calibration of measuring relays, and
correctness of settings. Typically, a protection system must be visited at its installation site and removed
from service for this testing.
Fundamentally, a reliability standard for Protection System Maintenance and Testing requires the
performance of the maintenance activities that are necessary to detect and correct plausible age and
service related degradation of components such that a properly built and commissioned Protection System
will continue to function as designed over its service life.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset owner
define a testing program. The starting point is the existing Standard PRC-005, briefly restated as follows:
Purpose: To ensure all transmission and generation Protection Systems affecting the reliability of the
Bulk Electric System (BES) are maintained and tested.
Draft 3: November 17, 2010
Page 3
PRC-005-1 is not specific on where the boundaries of the Protection Systems lie. However, the definition
of Protection System in the NERC Glossary of Terms used in Reliability Standards indicates what must
be included as a minimum.
Definition of Protection System (excerpted from the NERC Standards Glossary of Terms):
Protective relays, associated communications systems, voltage and current sensing devices, station
batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
Requirements: The owner shall have a documented maintenance program with test intervals. The owner
must keep records showing that the maintenance was performed at the specified intervals.
2.2 Proposed Modification to NERC Glossary Definition
The Protection Systems Maintenance and Testing Standard Drafting Team (PSM SDT), proposes changes
to the NERC glossary definition of Protection Systems as follows:
Protection System (modification)
o Protective relays which respond to electrical quantities,
o communications systems necessary for correct operation of protective functions,
o voltage and current sensing devices providing inputs to protective relays,
o station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
o control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from the
original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“… and that are applied on, or are designed to provide protection for the BES.”
The drafting team intends that this Standard will not apply to “merely possible” parallel paths, (subtransmission and distribution circuits), but rather the standard applies to any Protection System that is
designed to detect a fault on the BES and take action in response to that fault. The Standard Drafting
Team does not feel that Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the Regional definitions of the
BES.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and voltage
sensing devices, dc control circuitry and associated communications circuits. The relays to which this
standard applies are those relays that use measurements of voltage, current, frequency and/or phase angle
and provide a trip output to trip coils, dc control circuitry or associated communications equipment. This
definition extends to IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or trip-free relay)
as these devices are tripping relays that respond to the trip signal of the protective relay that processed the
signals from the current and voltage sensing devices.
Draft 3: November 17, 2010
Page 4
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration, pressure,
seismic, thermal or gas accumulation) are not included.
3. Relay Product Generations
The likelihood of failure and the ability to observe the operational state of a critical protection system,
both depends on the technological generation of the relays as well as how long they have been in service.
Unlike many other transmission asset groups, protection and control systems have seen dramatic
technological changes spanning several generations. During the past 20 years, major functional advances
are primarily due to the introduction of microprocessor technology for power system devices such as
primary measuring relays, monitoring devices, control systems, and telecommunications equipment.
Modern microprocessor based relays have six significant traits that impact a maintenance strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and some
connected substation inputs and outputs such as trip coil continuity. Most relay users are aware
that these relays have self monitoring, but are not focusing on exactly what internal functions are
actually being monitored. As explained further below, every element critical to the protection
system must be monitored, or else verified periodically.
•
Ability to capture fault records showing how the protection system responded to a fault in its zone
of protection, or to a nearby fault for which it is required not to operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-fault times. The relays can compute values such as MW and MVAR line
flows that are sometimes used for operational purposes such as SCADA.
•
Data communications via ports that provide remote access to all of the results of protection
system monitoring, recording, and measurement.
•
Ability to trip or close circuit breakers and switches through the protection system outputs, on
command from remote data communications messages or from relay front panel button requests.
•
Construction from electronic components some of which have shorter technical life or service life
than electromechanical components of prior protection system generations.
4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Restore — Return malfunctioning components to proper operation.
Draft 3: November 17, 2010
Page 5
5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which protection systems are maintained or verified according
to a time schedule. The scheduled program often calls for technicians to travel to the physical site and
perform a functional test on protection system components. However, some components of a TBM
program may be conducted from a remote location - for example, tripping a circuit breaker by
communicating a trip command to a microprocessor relay to determine if the entire protection system
tripping chain is able to operate the breaker.
Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have been
developed from prior experience or manufacturers’ recommendations. The TBM verification
interval is based on a variety of factors, including experience of the particular asset owner,
collective experiences of several asset owners who are members of a country or regional council,
etc. The maintenance intervals are fixed, and may range in number of months or in years.
TBM can include review of recent power system events near the particular terminal. Operating
records may verify that some portion of the protection system has operated correctly since the last
test occurred. If specific protection scheme components have demonstrated correct performance
within specifications, the maintenance test time clock can be reset for those components.
•
PBM – performance-based maintenance - intervals are established based on analytical or
historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied by
adjustments to maintenance intervals are used to justify continued use of PBM-developed
extended intervals when test failures or in-service failures occur infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from nondisruptive self monitoring of components demonstrate operational status as those components
remain in service. Whatever is verified by CBM does not require manual testing, but taking
advantage of this requires precise technical focus on exactly what parts are included as part of the
self diagnostics.
Microprocessor based protective relays that perform continuous self-monitoring verify correct
operation of most components within the device. Self-monitoring capabilities may include the ac
signal inputs, analog measuring circuits, processors and memory for measurement, protection,
and data communications, trip circuit monitoring, and protection or data communications signals.
For those conditions, failure of a self-monitoring routine generates an alarm and may inhibit
operation to avoid false trips. When internal components, such as critical output relay contacts,
are not equipped with self-monitoring, they can be manually tested. The method of testing may
be local or remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike TBM,
PBM intervals are adjusted based on good or bad experiences. The CBM verification intervals can be
hours or even milliseconds between non-disruptive self monitoring checks within or around components
as they remain in service.
Draft 3: November 17, 2010
Page 6
TBM, PBM, and CBM can be combined for individual components, or within a complete Protection
System. The following diagram illustrates the relationship between various types of maintenance
practices described in this section. In the Venn diagram the overlapping regions show the relationship of
TBM with PBM historical information and the inherent continuous monitoring offered through CBM.
This figure shows:
•
•
•
Region 1: The TBM intervals that are increased based on known reported operational condition of
individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been subject to
TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
5.1 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly established to
assure proper functioning of each component of the protection system, when data on the reliability of the
components is not available other than observations from time-based maintenance. The following factors
may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from relay self
monitoring, for example), the intervals may be extended or manual testing may be eliminated.
This is referred to as condition-based maintenance or CBM. CBM is valid only for precisely the
components subject to monitoring. In the case of microprocessor-based relays, self-monitoring
may not include automated diagnostics of every component within a microprocessor.
•
Previous maintenance history for a group of components of a common type may indicate that the
maintenance intervals can be extended while still achieving the desired level of performance. This
Draft 3: November 17, 2010
Page 7
is referred to as performance-based maintenance or PBM. It is also sometimes referred to as
reliability-centered maintenance or RCM, but PBM is used in this document.
•
Observed proper operation of a component may be regarded as a maintenance verification of the
respective component or element in a microprocessor-based device. For such an observation, the
maintenance interval may be reset only to the degree that can be verified by data available on the
operation. For example, the trip of an electromechanical relay for a fault verifies the trip contact
and trip path, but only through the relays in series that actually operated; one operation of this
relay cannot verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is not unusual
to cause failure of a component by removing it from service and restoring it. The improper application of
test signals may cause failure of a component. For example, in electromechanical overcurrent relays, test
currents have been known to destroy convolution springs.
In addition, maintenance usually takes the component out of service, during which time it is not able to
perform its function. Cutout switch failures, or failure to restore switch position, commonly lead to
protection failures.
6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information available from
modern microprocessor-based relays and other intelligent electronic devices (IEDs) that monitor
protection system elements. These relays and IEDs generate monitoring information during normal
operation, and the information can be assessed at a convenient location remote from the substation. The
information from these relays and IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in relay logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillograph records for
faults and disturbances, metered values, and binary input status reports. Some of these are
available on the relay front panel display, but may be available via data communications
ports. Large files of fault information can only be retrieved via data communications.
These results comprise a mass of data that must be further analyzed for evidence of the
operational condition of the protection system.
Using these two types of information, the user can develop an effective maintenance program carried out
mostly from a central location remote from the substation. This approach offers the following advantages:
1. Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
2. Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some relays will show health problems by
incorrect relaying before being caught in the next test round. The frequent or continuous
nature of CBM makes the effective verification interval far shorter than any required
TBM maximum interval.
Draft 3: November 17, 2010
Page 8
7. Time-Based versus Condition-Based Maintenance
Time-based and condition-based maintenance programs are both acceptable, if implemented according
to technically sound requirements. Practical programs can employ a combination of time-based and
condition-based maintenance. The standard requirements introduce the concept of optionally using
condition monitoring as a documented element of a maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule dated March
16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability Standards for the BulkPower System, directed NERC to submit a modification to PRC-005-1 that includes a requirement that
maintenance and testing of a protection system must be carried out within a maximum allowable interval
that is appropriate to the type of the protection system and its impact on the reliability of the Bulk Power
System. Accordingly, this Supplementary Reference Paper refers to the specific maximum allowable
intervals in PRC-005-2. The defined time limits allow for longer time intervals if the maintained
component is monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay between the
moment of a protection failure and time the protection system owner knows about it, for the monitored
segments of the protection system. In some cases, the verification is practically continuous - the time
interval between verifications is minutes or seconds. Thus, technically sound, condition-based
verification, meets the verification requirements of the FERC order even more effectively than the strictly
time-based tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage of remote
monitoring, data analysis, and control capabilities of modern protection systems to reduce the need for
periodic site visits and invasive testing of components by on-site technicians. This periodic testing must
be conducted within the maximum time intervals specified in Tables 1-1 through Tables 1-5 of PRC-0052.
8. Maximum Allowable Verification Intervals
The Maximum Allowable Testing Intervals and Maintenance Activities show how CBM with newer relay
types can reduce the need for many of the tests and site visits that older protection systems require. As
explained below, there are some sections of the protection system that monitoring or data analysis may
not verify. Verifying these sections of the Protection Systems requires some persistent TBM activity in
the maintenance program. However, some of this TBM can be carried out remotely - for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control capabilities
can be used to verify function of one tripping path and proper trip coil operation, if there has been no fault
or routine operation to demonstrate performance of relay tripping circuits.
Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is operating
correctly after a time period of field installation. These tests may be used to ensure that individual
components are still operating within acceptable performance parameters - this type of test is needed for
components susceptible to degraded or changing characteristics due to aging and wear. Full system
performance tests may be used to confirm that the total protection system functions from measurement of
power system values, to properly identifying fault characteristics, to the operation of the interrupting
devices.
Draft 3: November 17, 2010
Page 9
8.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1-1 through 1-5), in the
standard, specifies maximum allowable verification intervals for various generations of protection
systems and categories of equipment that comprise protection systems. The right column indicates
maintenance activities required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1 shows an
example of telecommunications-assisted line protection system comprising substation equipment at each
terminal and a telecommunications channel for relaying between the two substations. Figure 2 shows a
typical Generation station layout. The various subsystems of a Protection System that need to be verified
are shown. UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated in these
Figures. UFLS, UVLS and SPS all use identical equipment as Protection Systems in the performance of
their functions and therefore have the same maintenance needs.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that most of
the components that can make up a Protection System can also have technological advancements that
place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC-005-2:
• First find the Table associated with your component. The tables are arranged in the order of
mention in the definition of Protection System; Table 1-1 is for protective relays, Table 1-2 is for
the associated communications systems, Table 1-3 is for current and voltage sensing devices,
Table 1-4 is for station dc supply and Table 1-5 is for control circuits. There is an additional table,
Table 2, which brings alarms into the maintenance arena; this was broken out to simplify the
other tables.
•
Next look within that table for your device and its degree of monitoring. The tables have different
hands-on maintenance activities prescribed depending upon the degree to which you monitor your
equipment. Find the maintenance activity that applies to the monitoring level that you have on
your piece of equipment.
•
This Maintenance Activity is the minimum maintenance activity that must be documented.
•
If your PSMP (plan) requires more activities then you must perform and document to this higher
standard.
•
After the maintenance activity is known, check the Maximum Maintenance Interval; this time is
the maximum time allowed between hands-on maintenance activity cycles of this component.
•
If your PSMP (plan) requires activities more often than the Tables maximum then you must
perform and document those activities to this higher standard.
•
Any given component of a Protection System can be determined to have a degree of monitoring
that may be different from another component within that same Protection System. For example,
in a given Protection System it is possible for an entity to have a monitored protective relay and
an unmonitored associated communications system; this combination would require hands-on
maintenance activity on the relay at least once every 12 years and attention paid to the
communications system as often as every 3 months.
•
An entity does not have to utilize the extended time intervals made available by this use of
condition-based monitoring. An easy choice to make is to simply utilize the unmonitored level of
maintenance made available on each of the 5 Tables. While the maintenance activities resulting
from this choice would require more maintenance man-hours, the maintenance requirements may
be simpler to document and the resulting maintenance plans may be easier to create.
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For each Protection System component, Table 1 shows maximum allowable testing intervals for the
various degrees of monitoring. These degrees of monitoring, or levels, range from the legacy unmonitored
through a system that is more comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC-005-2. There may
be any number of reasons that an entity chooses a more stringent plan than the minimums prescribed
within PRC-005-2, most notable of which is an entity using performance based maintenance
methodology. (Another reason for having a more stringent plan than is required could be a regional entity
could have more stringent requirements.) Regardless of the rationale behind an entity’s more stringent
plan, it is incumbent upon them to perform the activities, and perform them at the stated intervals, of the
entity’s PSMP. A quality PSMP will help assure system reliability and adhering to any given PSMP
should be the goal.
Additional Notes for Tables 1-1 through 1-5
1. For electro-mechanical relays, adjustment is required to bring measurement accuracy within the
tolerance needed by the asset owner. Microprocessor-relays with no remote monitoring of alarm
contacts, etc, are un-monitored relays and need to be verified within the Table interval as other
un-monitored relays but may be verified as functional by means other than testing by simulated
inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring calibration, but
acceptable measurement of power system input values must be verified (verification of the
Analog to Digital [A/D] converters) within the Table intervals. The integrity of the digital inputs
and outputs that are used as protective functions must be verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a protection system or
SPS (as opposed to a monitoring task) must be verified as a component in a protection system.
4. In addition to verifying the circuitry that supplies dc to the protection system, the owner must
maintain the station dc supply. The most widespread station dc supply is the station battery and
charger. Unlike most Protection System components physical inspection of station batteries for
signs of component failure, reduced performance, and degradation are required to ensure that the
station battery is reliable enough to deliver dc power when required. IEEE Standards 450, 1188,
and 1106 for Vented Lead-Acid, Valve-Regulated Lead-Acid, and Nickel-Cadmium batteries,
respectively (which are the most commonly used substation batteries on the NERC BES) have
been developed as an important reference source of maintenance recommendations. The
Protection System owner might use the applicable IEEE recommended practice which contains
information and recommendations concerning the maintenance, testing and replacement of its
substation battery. However, the methods prescribed in these IEEE recommendations cannot be
specifically required because they do not apply to all battery applications.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS systems,
and large entities will usually maintain a portion of these systems in any given year.
Additionally, if relatively small quantities of such systems do not perform properly, it will not
affect the integrity of the overall program. Thus these distributed systems have decreased
requirements as compared to other Protection Systems.
6. Voltage & Current Sensing Device circuit input connections to the protection system relays can
be verified by (but not limited to) comparison of measured values on live circuits or by using test
currents and voltages on equipment out of service for maintenance. The verification process can
be automated or manual. The values should be verified to be as expected, (phase value and phase
relationships are both equally important to verify).
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7. Verify the protection system tripping function by performing an operational trip test on all
components contained in the trip circuit. This includes circuit breaker or circuit switcher trip
coils, auxiliary tripping relays (94), lock-out relays (86), and communications-assisted trip
scheme elements. Each control circuit path that carries trip signal must be verified, although each
path must be checked only once. A maintenance program may include performing an overall test
for the entire system at one time, or several split system tests with overlapping trip verification. A
documented real-time trip of any given trip path is acceptable in lieu of a functional trip test.
8. “End-to-end test” as used in this supplementary reference is any testing procedure that creates a
remote input to the local communications-assisted trip scheme. While this can be interpreted as a
GPS-type functional test it is not limited to testing via GPS. Any remote scheme manipulation
that can cause action at the local trip path can be used to functionally-test the dc Control
Circuitry. A documented real-time trip of any given trip path is acceptable in lieu of a functional
trip test. It is possible, with sufficient monitoring, to be able to verify each and every parallel trip
path that participated in any given dc Control Circuit trip. Or, another possible solution is that a
single trip path from a single monitored relay can be verified to be the trip path that successfully
tripped during a real-time operation. The variations are only limited by the degree of engineering
and monitoring that an entity desires to pursue.
9. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus feeder
currents) can be used for comparison if calibration requirements assure acceptable measurement
of power system input values.
10. Notes 1-9 attempt to describe the testing activities they do not represent the only methods to
achieve these activities but rather some possible methods. Technological advances, ingenuity
and/or industry accepted techniques can all be used to satisfy maintenance activity requirements;
the standard is technology and method neutral in most cases.
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three years.
However, with a three year retention cycle, the records of verification for a protection system will
typically be discarded before the next verification, leaving no record of what was done if a misoperation
or failure is to be analyzed.
PRC-005-2 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation
of the two most recent performances of each distinct maintenance activity for the Protection System
components, or to the previous on-site audit date, whichever is longer
This requirement assures that the documentation shows that the interval between maintenance cycles
correctly meets the maintenance interval limits. The requirement is actually alerting the industry to
documentation requirements already implemented by audit teams. Evidence of compliance bookending
the interval shows interval accomplished instead of proving only your planned interval.
8.3 Basis for Table 1 Intervals
SPCTF authors collected all available data from Regional Entities (REs) on time intervals recommended
for maintenance and test programs. The recommendations vary widely in categorization of relays, defined
maintenance actions, and time intervals, precluding development of intervals by averaging. SPCTF also
reviewed the 2005 Report [2] of the IEEE Power System Relaying Committee Working Group I-17
(Transmission Relay System Performance Comparison). Review of the I-17 report shows data from a
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small number of utilities, with no company identification or means of investigating the significance of
particular results.
To develop a solid current base of practice, SPCTF surveyed its members regarding their maintenance
intervals for electromechanical and microprocessor relays, and asked the members to also provide
definitively-known data for other entities. The survey represented 470 GW of peak load, or 64% of the
NERC peak load. Maintenance interval averages were compiled by weighting reported intervals
according to the size (based on peak load) of the reporting utility. Thus, the averages more accurately
represent practices for the large populations of protection systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of 5 years for
electromechanical or solid state relays, and 7 years for un-monitored microprocessor relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond 7 years,
based on favorable experience with the particular products they have installed. To provide a technical
basis for such extension, SPCTF authors developed a recommendation of 10 years using the Markov
modeling approach from [1] as summarized in Section 8.4. The results of this modeling depend on the
completeness of self-testing or monitoring. Accordingly, this extended interval is allowed by Table 1 only
when such relays are monitored as specified in the attributes of monitoring contained in Tables 1-1
through 1-5 and Table 2. Monitoring is capable of reporting protection system health issues that are likely
to affect performance within the 10 year time interval between verifications.
It is important to note that, according to modeling results, protection system availability barely changes as
the maintenance interval is varied below the 10-year mark. Thus, reducing the maintenance interval does
not improve protection system availability. With the assumptions of the model regarding how
maintenance is carried out, reducing the maintenance interval actually degrades protection system
availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level. The industry
has experience with self-monitoring microprocessor relays that leads to the Table 1 value for a monitored
relay as explained in Section 8.3. To develop a basis for the maximum interval for monitored relays in
their Protection System Maintenance – A Technical Reference, the SPCTF used the methodology of
Reference [1], which specifically addresses optimum routine maintenance intervals. The Markov
modeling approach of [1] is judged to be valid for the design and typical failure modes of microprocessor
relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability measures:
• Relay Unavailability - the probability that the relay is out of service due to failure or maintenance
activity while the power system element to be protected is in service.
• Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a fault occurs, leading to failure to operate for the fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test). ST = 0 if
there is no self-monitoring; ST = 1 for full monitoring. Practical ST values are estimated to range from
.75 to .95. The SPCTF simulation runs used constants in the Markov model that were the same as those
used in [1] with the following exceptions:
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal fault clearing time of 10 cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup fault clearing time of 50 cycles)
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Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a protection system)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a protection system repair after failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to these
parameter adjustments.
The resulting curves for Relay Unavailability and Abnormal Unavailability versus maintenance interval
showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years – the curve is flat,
with no significant change in either unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years, much lower than MTBF values
typically published for these relays. Also, the Markov modeling indicates that both the relay
unavailability and abnormal unavailability actually become higher with more frequent testing. This
shows that the time spent on these more frequent tests yields no failure discoveries that approach the
negative impact of removing the relays from service and running the tests.
PSMT SDT further notes that the SPCTF also allowed 25% extensions to the “maximum time intervals”.
With a 5 year time interval established between manual maintenance activities and a 25% time extension
then this equates to a 6.25 year maximum time interval. It is the belief of the PSMT SDT that the SPCTF
understood that 6.25 years was thereby an adequate maximum time interval between manual maintenance
activities. The PSMT SDT has followed the FERC directive for a maximum time interval and has
determined that no extensions will be allowed. Six years has been set for the maximum time interval
between manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval between
maintenance activities. A 10 year interval with a 25% allowed extension equates to a maximum allowed
interval of 12.5 years between manual maintenance activities. The Standard does not allow extensions on
any component of the protection system; thus the maximum allowed interval for these components has
been set to12 years. Twelve years also fits well into the traditional maintenance cycles of both substations
and generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum Maintenance
Interval”. The PSMT SDT deemed it necessary to include the term “Calendar” to facilitate annual
maintenance planning, scheduling and implementation. This need is the result of known occurrences of
system requirements that could cause maintenance schedules to be missed by a few days or weeks. The
PSMT SDT chose the term “Calendar” to preclude the need to have schedules be met to the day. An
electro-mechanical protective relay that is maintained in year #1 need not be revisited until 6 years later
(year #7). For example: a relay was maintained April 10, 2008; maintenance would need to be completed
no later than December 31, 2014.
Section 9 describes a performance-based maintenance process which can be used to justify maintenance
intervals other than those described in Table 1.
Section 10 describes sections of the protection system, and overlapping considerations for full verification
of the protection system by segments. Segments refer to pieces of the protection system, which can range
from a single device to a panel to an entire substation.
Section 11 describes how relay operating records can (but not required to) serve as a basis for verification,
reducing the frequency of manual testing.
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Section 13 describes how a cooperative effort of relay manufacturers and protection system users can
improve the coverage of self-monitoring functions, leading to full monitoring of the bulk of the protection
system, and eventual elimination of manual verification or testing.
9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a performance-based maintenance process may be used to establish
maintenance intervals (PRC-005 Attachment A Criteria for a Performance-Based Protection System
Maintenance Program). A performance-based maintenance process may justify longer maintenance
intervals, or require shorter intervals relative to Table 1. In order to use a performance-based maintenance
process, the documented maintenance program must include records of repairs, adjustments, and
corrections to covered protection systems in order to provide historical justification for intervals other
than those established in Table 1. Furthermore, the asset owner must regularly analyze these records of
corrective actions to develop a ranking of causes. Recurrent problems are to be highlighted, and remedial
action plans are to be documented to mitigate or eliminate recurrent problems.
Utilities with performance-based maintenance track performance of protection systems, demonstrate how
they analyze findings of performance failures and aberrations, and implement continuous improvement
actions. Since no maintenance program can ever guarantee that no malfunction can possibly occur,
documentation of a performance-based maintenance program would serve the utility well in explaining to
regulators and the public a misoperation leading to a major system outage event.
A performance-based maintenance program requires auditing processes like those included in widely used
industrial quality systems (such as ISO 9001-2000, Quality management systems — Requirements; or
applicable parts of the NIST Baldridge National Quality Program). The audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance-based Maintenance (PBM) program the asset owner must first sort the
various Protection System components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM but does not own 60 units to
comprise a population then that asset owner may combine data from other asset owners until the needed
60 units is aggregated. Each population segment must be composed of a grouping of Protection Systems
or components of a consistent design standard or particular model or type from a single manufacturer and
subjected to similar environmental factors. For example: One segment cannot be comprised of both GE &
Westinghouse electro-mechanical lock-out relays; likewise, one segment cannot be comprised of 60 GE
lock-out relays, 30 of which are in a dirty environment and the remaining 30 from a clean environment.
This PBM process cannot be applied to batteries but can be applied to all other components of a
Protection System including (but not limited to) specific battery chargers, instrument transformers, trip
coils and/or control circuitry (etc.).
9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling distribution of the
sample mean can be approximated by a normal probability distribution.” The Central Limit Theorem
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states: “In selecting simple random samples of size n from a population, the sampling distribution of the
sample mean x can be approximated by a normal probability distribution as the sample size becomes
large.” (Essentials of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003)
To use the Central Limit Theorem in statistics, the population size should be large. The references below
are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30), the
central limit theorem enables us to conclude that the sampling distribution of the sample
mean can be approximated by a normal distribution.” (Essentials of Statistics for
Business and Economics, Anderson, Sweeney, Williams, 2003)
“If samples of size n, when n>=30, are drawn from any population with a mean u and a
standard deviation σ, the sampling distribution of sample means approximates a normal
distribution. The greater the sample size, the better the approximation.” (Elementary
Statistics - Picturing the World, Larson, Farber, 2003)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005)
“… the normal is often used as an approximation to the t distribution in a test of a null
hypothesis about the mean of a normally distributed population when the population
variance is estimated from a relatively large sample. A sample size exceeding 30 is often
given as a minimal size in this connection.” (Statistical Analysis for Business Decisions,
Peters, Summers, 1968)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated using the
bound on the Error of Distribution Formula when the expected result is of a “Pass/Fail” format and will
be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
Β = bound on the error of distribution (allowable error)
z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
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z
n = π(1 − π)
Β
2
Minimum Population Size to use Performance-based Program
One entity’s population of components should be large enough to represent a sizeable sample of a
vendor’s overall population of manufactured devices. For this reason the following assumptions are
made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-based Program
The number of components that should be included in a sample size for evaluation of the appropriate
testing interval can be smaller because a lower confidence level is acceptable since the sample testing is
repeated or updated annually. For this reason, the following assumptions are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation mentioned.
Using this and the results of the equation, the following numbers are recommended (and required within
the standard):
Minimum Population Size to use Performance-based Maintenance Program = 60
Minimum Sample Size to evaluate Performance-based Program = 30.
Once the population segment is defined then maintenance must begin within the intervals as outlined for
the device described in the Tables (Table 1-1 through Table 1-5). Time intervals can be lengthened
provided the last year’s worth of components tested (or the last 30 units maintained, whichever is more)
had fewer than 4% countable events. It is notable that 4% is specifically chosen because an entity with a
small population (60 units) would have to adjust its time intervals between maintenance if more than 1
countable event was found to have occurred during the last analysis period. A smaller percentage would
require that entity to adjust the time interval between maintenance activities if even one unit is found out
of tolerance or causes a Misoperation.
The minimum number of units that can be tested in any given year is 5% of the population. Note that this
5% threshold sets a practical limitation on total length of time between intervals at 20 years.
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If at any time the number of countable events equals or exceeds 4% of the last year’s tested components
(or the last 30 units maintained, whichever is more) then the time period between manual maintenance
activities must be decreased. There is a time limit on reaching the decreased time at which the countable
events is less than 4%; this must be attained within three years.
This additional time period of three years to restore segment performance to <4% countable events is
mandated to keep entities from “gaming the PBM system”. It is believed that this requirement provides
the economic disincentives to discourage asset owners from arbitrarily pushing the PBM time intervals
out to up to 20 years without proper statistical data.
10. Overlapping the Verification of Sections of the Protection System
Tables 1-1 through 1-5 require that every protection system component be periodically verified. One
approach is to test the entire protection scheme as a unit, from the secondary windings of voltage and
current sources to breaker tripping. For practical ongoing verification, sections of the protection system
may be tested or monitored individually. The boundaries of the verified sections must overlap to ensure
that there are no gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as appropriate, to
establish and operate a maintenance program. For example, a protection system may be divided into
multiple overlapping sections with a different maintenance methodology for each section:
•
Time-based maintenance with appropriate maximum verification intervals for categories
of equipment as given in the Tables 1-1 through 1-5;
• Full monitoring as described in Tables 1-1 through 1-5;
• A performance-based maintenance program as described in Section 9 above or
Attachment A of the Standard;
• Opportunistic verification using analysis of fault records as described in Section 11
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve fault event records and oscillographic records by data
communications after a fault. They analyze the data closely if there has been an apparent misoperation, as
NERC standards require. Some advanced users have commissioned automatic fault record processing
systems that gather and archive the data. They search for evidence of component failures or setting
problems hidden behind an operation whose overall outcome seems to be correct. The relay data may be
augmented with independently captured digital fault recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for a manual
time-interval based check on protection systems whose operations are analyzed. Even electromechanical
protection systems instrumented with DFR channels may achieve some CBM benefit. The completeness
of the verification then depends on the number and variety of faults in the vicinity of the relay that
produce relay response records, and the specific data captured.
A typical fault record will verify particular parts of certain protection systems in the vicinity of the fault.
For a given protection system installation, it may or may not be possible to gather within a reasonable
amount of time an ensemble of internal and external fault records that completely verify the protection
system.
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For example, fault records may verify that the particular relays that tripped are able to trip via the control
circuit path that was specifically used to clear that fault. A relay or DFR record may indicate correct
operation of the protection communications channel. Furthermore, other nearby protection systems may
verify that they restrain from tripping for a fault just outside their respective zones of protection. The
ensemble of internal fault and nearby external fault event data can verify major portions of the protection
system, and reset the time clock for the Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel with
multiple relays, only the specific relay(s) whose operation can be observed without ambiguity in the
record and the associated wiring paths are verified. Be careful about using fault response data to verify
that settings or calibration are correct. Unless records have been captured for multiple faults close to
either side of a setting boundary, setting or calibration could still be incorrect.
If fault record data is used to show that portions or all of a protection system have been verified to meet
Table 1 requirements, the owner must retain the fault records used, and the maintenance related
conclusions drawn from this data and used to defer Table 1 tests, for at least the retention time interval
given in Section 8.2.
12. Importance of Relay Settings in Maintenance Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to show that
the relays have correct settings and calibration. Microprocessor relays, by contrast, provide the means for
continuously monitoring measurement accuracy. Furthermore, the relay digitizes inputs from one set of
signals to perform all measurement functions in a single self-monitoring microprocessor system. These
relays do not require testing or calibration of each setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older relays. Some
microprocessor relays have hundreds or thousands of settings, many of which are critical to protection
system performance.
Monitoring does not check measuring element settings. Analysis of fault records may or may not reveal
setting problems. To minimize risk of setting errors after commissioning, the user should enforce strict
settings data base management, with reconfirmation (manual or automatic) that the installed settings are
correct whenever maintenance activity might have changed them. For background and guidance, see [5].
Table 1 requires that settings must be verified to be as specified. The reason for this requirement is
simple. With legacy relays (non-microprocessor protective relays) it is necessary to know the value of the
intended setting in order to test, adjust and calibrate the relay. Proving that the relay works per specified
setting was the de facto procedure. However, with the advanced microprocessor relays it is possible to
change relay settings for the purpose of verifying specific functions and then neglect to return the settings
to the specified values. While there is no specific requirement to maintain a settings management process
there remains a need to verify that the settings left in the relay are the intended, specified settings. This
need may manifest itself after any of the following:
•
•
•
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
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13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products for nearly
20 years. Theoretically, any element that is monitored does not need a periodic manual test. A problem
today is that the community of manufacturers and users has not created clear documentation of exactly
what is and is not monitored. Some unmonitored but critical elements are buried in installed systems that
are described as self-monitoring.
Until users are able to document how all parts of a system which are required for the protective functions
are monitored or verified (with help from manufacturers), they must continue with the unmonitored or
partially monitored intervals established in Table 1.
Going forward, manufacturers and users can develop mappings of the monitoring within relays, and
monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of full monitoring, the manufacturers of the microprocessor-based self-monitoring
components in the protection system should publish for the user a document or map that shows:
•
How all internal elements of the product are monitored for any failure that could
impact protection system performance.
•
Which connected circuits are monitored by checks implemented within the product;
how to connect and set the product to assure monitoring of these connected circuits;
and what circuits or potential problems are not monitored.
With this information in hand, the user can document full monitoring for some or all sections by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component and
circuit that is critical to protection is monitored by the microprocessor product(s) or by
other design features.
•
Extending the monitoring to include the alarm transmission facilities through which
failures are reported within a given time frame to allocate where action can be taken to
initiate resolution of the alarm attributed to a maintenance correctable issue, so that
failures of monitoring or alarming systems also lead to alarms and action.
•
Documenting the plans for verification of any unmonitored components according to the
requirements of Table 1.
14. Notification of Protection System Failures
When a failure occurs in a protection system, power system security may be compromised, and
notification of the failure must be conducted in accordance with relevant NERC standard(s). Knowledge
of the failure may impact the system operator’s decisions on acceptable loading conditions.
This formal reporting of the failure and repair status to the system operator by the protection system
owner also encourages the system owner to execute repairs as rapidly as possible. In some cases, a
microprocessor relay or carrier set can be replaced in hours; wiring termination failures may be repaired
in a similar time frame. On the other hand, a component in an electromechanical or early-generation
electronic relay may be difficult to find and may hold up repair for weeks. In some situations, the owner
may have to resort to a temporary protection panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would be that a
BES entity could be prudent in its protective relay maintenance but if its battery maintenance program is
lacking then reliability could still suffer. The NERC glossary outlines a Protection System as containing
specific components. PRC-005-02 requires specific maintenance activities be accomplished within a
specific time interval. As noted previously, higher technology equipment can contain integral monitoring
capability that actually performs maintenance verification activities routinely and often; therefore manual
intervention to perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and voltage sensing
devices and are used to isolate a faulted portion of the BES. Devices that sense thermal, vibration,
seismic, pressure, gas or any other non-electrical inputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor based equipment in the
following ways, the relays should meet the asset owners’ tolerances.
•
•
Non-microprocessor devices must be tested with voltage and/or current applied to the device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test mandated.
o There is no specific documentation mandated.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers. There is
presently a technology available (fiber-optic Hall-effect) that does not utilize conventional transformer
technology; these devices and other technologies that produce quantities that represent the primary values
of voltage and current are considered to be a type of voltage and current sensing devices included in this
standard.
The intent of the maintenance activity is to verify the input to the protective relay from the device that
produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these signals is to
know that the expected output from these components actually reaches the protective relay. Therefore, the
proof of the proper operation of these components also demonstrates the integrity of the wiring (or other
medium used to convey the signal) from the current and voltage sensing device all the way to the
protective relay. The following observations apply.
• There is no specific ratio test, routine test or commissioning test mandated.
• There is no specific documentation mandated.
• It is required that the signal be present at the relay.
• This expectation can be arrived at from any of a number of means; by calculation, by comparison
to other circuits, by commissioning tests, by thorough inspection, or by any means needed to
verify the circuit meets the asset owner’s protection system maintenance program.
• An example of testing might be a saturation test of a CT with the test values applied at the relay
panel; this therefore tests the CT as well as the wiring from the relay all the back to the CT.
• Another possible test is to measure the signal from the voltage and/or current sensing devices,
during load conditions, at the input to the relay.
Draft 3: November 17, 2010
Page 21
•
•
•
•
Another example of testing the various voltage and/or current sensing devices is to query the
microprocessor relay for the real-time loading; this can then be compared to other devices to
verify the quantities applied to this relay. Since the input devices have supplied the proper values
to the protective relay then the verification activity has been satisfied. Thus event reports (and
oscillographs) can be used to verify that the voltage and current sensing devices are performing
satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this should add up to
zero watts and zero vars thus proving the voltage and/or current sensing devices system
throughout the bus.
Another method for proving the voltage and/or current sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
Any other methods that provide documentation that the expected transformer values as applied to
the inputs to the protective relays are acceptable.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit switcher or
any other interrupting device. It includes the wiring from the batteries to the relays. It includes the wiring
(or other signal conveyance) from every trip output to every trip coil. It includes any device needed for
the correct processing of the needed trip signal to the trip coil of the interrupting device; this requirement
is meant to capture inputs and outputs to and from a protective relay that are necessary for the correct
operation of the protective functions. In short, every trip path must be verified and every I/O path must be
verified; the method of verification is optional to the asset owner. An example of testing methods to
accomplish this might be to verify, with a volt-meter, the existence of the proper voltage at the open
contacts, the open circuited input circuit and at the trip coil(s). As every parallel trip path has similar
failure modes, each trip path from relay to trip coil must be verified. Each trip coil must be tested to trip
the circuit breaker (or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete functional test.
If a suitable monitoring system is installed that verifies every parallel trip path then the manualintervention testing of those parallel trip paths can be extended beyond twelve years, however the actual
operation of the circuit breaker must still occur at least once every six years. This 6-year tripping
requirement can be completed as easily as tracking the real-time fault-clearing operations on the circuit
breaker or tracking the trip coil(s) operation(s) during circuit breaker routine maintenance actions
The circuit-interrupting device should not be confused with a motor-operated disconnect. The intent of
this standard is to require maintenance intervals and activities on Protection Systems equipment and not
just all equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground switch as an
interrupting device if this ground switch is utilized in a Protection System and forces a ground fault to
occur that then results in an expected Protection System operation to clear the forced ground fault. The
SDT believes that this is essentially a transferred-tripping device without the use of communications
equipment. If this high-speed ground switch is “…applied on, or designed to provide protection for the
BES…” then this device needs to be treated as any other Protection System component. The control
circuitry would have to be tested within 12 years and any electromechanically operated device will have
to be tested every 6 years. If the spring-operated ground switch can be disconnected from the solenoid
triggering unit then the solenoid triggering unit can easily be tested without the actual closing of the
ground blade.
Circuit breakers that participate in a distributed UFLS or UVLS scheme are excluded from the tripping
requirement, but not from the circuit test requirements; since the circuitry must be tested at least once
every 12 years and the circuit interrupting device need not be tested then this effectively makes this a 12
Draft 3: November 17, 2010
Page 22
year requirement. There are many circuit interrupting devices in the distribution system that will be
operating for any given under-frequency event that requires tripping for that event. A failure in the
tripping-action of a single distributed system circuit breaker will be far less significant than, for example,
any single Transmission Protection System failure such as a failure of a Bus Differential Lock-Out Relay.
While many failures of these distributed system circuit breakers could add up to be significant, it is also
believed that many circuit breakers are operated often on just fault clearing duty and therefore these
circuit breakers are operated at least as frequently as any requirements that appear in this standard.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay (86) that
may exist in any particular trip scheme. If these devices are electro-mechanical components then they
must be trip tested. The PSMT SDT considers these components to share some similarities in failure
modes as electro-mechanical protective relays; as such there is a six year maximum interval between
mandated maintenance tasks unless PBM is applied.
When verifying the operation of the 94 and 86 relays each normally-open contact that closes to pass a trip
signal must be verified as operating correctly. Normally-open contacts that are not used to pass a trip
signal and normally-closed contacts do not have to be verified. Verification of the tripping paths is the
requirement.
New technology is also accommodated here; there are some tripping systems that have replaced the
traditional hard-wired trip circuitry with other methods of trip-signal conveyance such as fiber-optics. It is
the intent of the PSMT SDT to include this, and any other, technology that is used to convey a trip signal
from a protective relay to a circuit breaker (or other interrupting device) within this category of
equipment.
Draft 3: November 17, 2010
Page 23
15.4 Batteries and DC Supplies (Table 1-4)
IEEE guidelines were consulted to arrive at the maintenance activities for batteries. The following
guidelines were used: IEEE 450 (for Vented Lead-Acid batteries), IEEE 1188 (for Valve-Regulated LeadAcid batteries) and IEEE 1106 (for Nickel-Cadmium batteries).
The currently proposed NERC definition of a Protection System is
o Protective relays which respond to electrical quantities,
o communications systems necessary for correct operation of protective functions,
o voltage and current sensing devices providing inputs to protective relays,
o station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
o control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.” The station battery is not the only component
that provides dc power to a Protection System. In the new definition for Protection
System “station batteries” are replaced with “station dc supply” to make the battery
charger and dc producing stored energy devices (that are not a battery) part of the
Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and testing
procedures that allow the owner to choose how to verify that a battery string is free of open circuits. The
term “continuity” was introduced into the standard to allow the owner to choose how to verify continuity
of a battery set by various methods, and not to limit the owner to the two methods recommended in the
IEEE standards. Continuity as used in Table 1-4 of the standard refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative terminal.
Without verifying continuity of a station battery, there is no way to determine that the station battery is
available to supply dc power to the station. An open battery string will be an unavailable power source in
the event of loss of the battery charger.
Batteries cannot be a unique population segment of a Performance-based Maintenance Program (PBM)
because there are too many variables in the electro-chemical process to completely isolate all of the
performance-changing criteria necessary for using PBM on battery systems. However, nothing precludes
the use of a PBM process for any other part of a dc supply besides the batteries themselves.
15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications assisted trip scheme is a vital piece of the trip
circuit. Remote action causing a local trip can be thought of as another parallel trip path to the trip coil
that must be tested.
Besides the trip output and wiring to the trip coil(s) there is also a communications medium that must be
maintained.
Newer technologies now exist that achieve communications-assisted tripping without the conventional
wiring practices of older technology.
For example: older technologies may have included Frequency Shift Key methods. This technology
requires that guard and trip levels be maintained.
The actual tripping path(s) to the trip coil(s) may be tested as a parallel trip path within the dc control
circuitry tests.
Draft 3: November 17, 2010
Page 24
Emerging technologies transfer digital information over a variety of carrier mediums that are then
interpreted locally as trip signals.
The requirements apply to the communicated signal needed for the proper operation of the protective
relay trip logic or scheme. Therefore this standard is applied to equipment used to convey both trip signals
(permissive or direct) and block signals.
It was the intent of this standard to require that a test be made of any communications-assisted trip
scheme regardless of the vintage of the technology. The essential element is that the tripping (or blocking)
occurs locally when the remote action has been asserted; or that the tripping (or blocking) occurs remotely
when the local action is asserted.
Any evidence of operational test or documentation of measurement of signal level, reflected power or
data-error rates can fulfill the requirements.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the control
house to the circuit interrupting device in the yard. This method of tripping the circuit breaker, even
though it might be considered communications, must be maintained per the dc control circuitry
maintenance requirements.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an additional
table added for alarms. This additional table was added for clarity. This enabled the common alarm
attributes to be consolidated into a single spot and thus make it easier to read the Tables 1-1 through 1-5.
The alarms need to arrive at a site wherein a corrective action can be initiated. This could be a control
room, operations center, etc. The alarming mechanism can be a standard alarming system or an autopolling system, the only requirement is that the alarm be brought to the action-site within 24 hours. This
effectively makes manned-stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned-station now makes that monitored point eligible
for monitored status. Obviously, these same rules apply to a non-manned-station, which is that if the
monitored point has an alarm that is auto-reported to the operations center (for example) within 24 hours
then it too is considered monitored.
15.7 Examples of Evidence of Compliance
To comply with the requirements of this Standard an entity will have to document and save evidence. The
evidence can be of many different forms. The Standard Drafting Team recognizes that there are
concurrent evidence requirements of other standards that could, at times fulfill evidence requirements of
this standard.
For example: maintaining evidence for operation of Special Protection Systems could concurrently be
utilized as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus the reporting requirements that one may have to do for the mis-operation of a Special
Protection Scheme under PRC-016 could work for the activity tracking requirements under this PRC-0052.
Another example might be:
Draft 3: November 17, 2010
Page 25
Some entities maintain records of all interruptions. These records can be concurrently utilized, if the
entity desires, as DC Trip Path verifications.
Analysis of Event Recordings can provide details that can eliminate some hands-on maintenance
activities; merely printing out the event report provides limited benefit of verification of specific
maintenance items.
Standardized-forms, hard or soft copy, can be created, filled out and archived. These forms can be of the
entities’ design and can be aimed at answering the specific requirements of the Standard as well as
additional requirements as needed by the entity.
Fill-in blanks, check-boxes, drop-down lists, auto-date formats, etc. can all be used as the primary action
is the maintenance activity time interval; other techniques can be used to verify that the maintenance
activity was performed, such as test reports.
Other evidence of compliance might be, but is not limited to:
Prints, maintenance plans, training materials, policies, procedures, data print-outs or exhibits,
correspondence, reports, data-base records, etc.
There is the legacy method of paper trail for everything, this is acceptable. There are also paperless
systems existing and evolving that are also acceptable.
Proof of compliance should simply be the entities’ records of maintenance completed.
Draft 3: November 17, 2010
Page 26
16. References
NERC/SPCTF/Relay_Maintenance_Tech_Ref_approved_by_PC.pdf
1. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J. Kumm, M.S.
Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power Delivery, Vol. 10,
No. 2, April 1995.
2. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003, 2004
and 2005,” Working Group I17 of Power System Relaying Committee of IEEE Power
Engineering Society, May 2006.
3. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System Relaying
Committee of IEEE Power Engineering Society, September 16, 1999.
4. “Transmission Protective Relay System Performance Measuring Methodology,” Working
Group I3 of Power System Relaying Committee of IEEE Power Engineering Society, January
2002.
5. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3 of
Power System Relaying Committee of IEEE Power Engineering Society, December 2006.
6. “Proposed Statistical Performance Measures for Microprocessor-Based Transmission-Line
Protective Relays, Part I - Explanation of the Statistics, and Part II - Collection and Uses of
Data,” Working Group D5 of Power System Relaying Committee of IEEE Power
Engineering Society, May 1995; Papers 96WM 016-6 PWRD and 96WM 127-1 PWRD,
1996 IEEE Power Engineering Society Winter Meeting.
7. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
8. “Use of Preventative Maintenance and System Performance Data to Optimize Scheduled
Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia Tech Protective
Relay Conference, May 1996.
PSMT SDT References
9. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams, 2003
10. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore, 2005
11. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
Draft 3: November 17, 2010
Page 27
Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
Draft 3: November 17, 2010
Page 28
Figure 2: Typical Generation System
For information on components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
Draft 3: November 17, 2010
Page 29
Figure 1 & 2 Legend – Components of Protection Systems
Number
in
Figure
Component of Protection System
Includes
Excludes
1
Protective relays which respond to
electrical quantities
All protective relays that use current and/or
voltage inputs from current & voltage sensors and
that trip the 86, 94 or trip coil.
Devices that use non-electrical methods of operation
including thermal, pressure, gas accumulation, and
vibration. Any ancillary equipment not specified in
the definition of Protection systems. Control and/or
monitoring equipment that is not a part of the
automatic tripping action of the Protection System
2
Voltage and current sensing devices
providing inputs to protective relays
The signals from the voltage & current sensing
devices to the protective relay input.
Voltage & current sensing devices that are not a part
of the Protection System, including sync-check
systems, metering systems and data acquisition
systems.
3
control circuitry associated with protective
functions
All control wiring (or other medium for conveying
trip signals) associated with the tripping action of
86 devices, 94 devices or trip coils (from all
parallel trip paths). This would include fiber-optic
systems that carry a trip signal as well as hardwired systems that carry trip current.
Closing circuits, SCADA circuits
4
Station dc supply
Batteries and battery chargers and any
control power system which has the
function of supplying power to the
protective relays, associated trip circuits
and trip coils.
Any power supplies that are not used to
power protective relays or their associated
trip circuits and trip coils.
5
Communications systems
necessary for correct operation of
protective functions
Tele-protection equipment used to convey
specific information, in the form of analog
or digital signals, necessary for the correct
operation of protective functions.
Any communications equipment that is not
used to convey information necessary for
the correct operation of protective functions.
(Return)
Draft 3: November 17, 2010
Page 30
Figure 3: Requirements Flowchart
Requirements
Flowchart
Start
PRC-005-2
Note: GO, DP, & TO
may use one or
multiple programs
Each GO, DP, & TO
shall establish a
maintenance
program [R1]
Performance
Based
Time Based
Decide if using Time Based, Condition
Baesd, and/or Performance Based
program
◊
◊
Condition Based
◊
Ensure
components
have necessary
monitoring [R2]
Separate components into
appropriate families of 60 or more
Maintain components for each
segment per Table One until at least
30 components have been tested
Analyze data to determine
appropriate interval for segment(s)
[R3]
Perform maintenance activities from
Table One for each segment with interval
from analysis above and collect data for
future analysis
[R3, R4.4.2]
◊
Maintain components
per Table One
Intervals and
Activities [R4.4.1]
◊
◊
Collect countable events from
maintenance and failures
Analyze data from maintenance of
last 30 components and/or last year
to verify countable events below 4%
Adjust maintenance interval to keep
countable events below 4%
[R3]
Implement corrective
actions as needed [R4]
End
Draft 3: November 17, 2010
Page 31
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in Section 10
of the paper. As an example, Figure A-1 shows protection for a critical transmission line by carrier
blocking directional comparison pilot relaying. The goal is to verify the ability of the entire two-terminal
pilot protection scheme to protect for line faults, and to avoid over-tripping for faults external to the
transmission line zone of protection bounded by the current transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays themselves,
the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of internal
electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report the
state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of other
relays, meters, or DFRs. The other readings may be from redundant relaying or measurement
systems or they may be derived from values in other protection zones. Comparison with other
such readings to within required relaying accuracy verifies Voltage & Current Sensing
Draft 3: November 17, 2010
Page 32
Devices, wiring, and analog signal input processing of the relays. One effective way to do
this is to utilize the relay metered values directly in SCADA, where they can be compared
with other references or state estimator values.
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the protection
system, so each carrier set has a connected or integrated automatic checkback test unit. The
automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation or
noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the protection
system elements that experience tells us are the most prone to fail. But, does this comprise a complete
verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded regions
show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
Draft 3: November 17, 2010
Page 33
2. Within each line relay, all the microprocessors that participate in the trip decision have been
verified by internal monitoring. However, the trip circuit is actually energized by the contacts
of a small telephone-type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a fault.
3. The check-back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying circuit
or the carrier receiver output state. These connections include microprocessor I/O ports,
electronic driver circuits, wiring, and sometimes telephone-type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but this
does not confirm that the state change indication is correct when the breaker or switch opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified maximum time
interval between trip tests. Clearing of naturally-occurring faults are demonstrations of operation that
reset the time interval clock for testing of each breaker tripped in this way. If faults do not occur, manual
tripping of the breaker through the relay trip output via data communications to the relay microprocessor
meets the requirement for periodic testing.
PRC-005 does not address breaker maintenance, and its protection system test requirements can be met by
energizing the trip circuit in a test mode (breaker disconnected) through the relay microprocessor. This
can be done via a front-panel button command to the relay logic, or application of a simulated fault with a
relay test set. However, utilities have found that breakers often show problems during protection system
tests. It is recommended that protection system verification include periodic testing of the actual tripping
of connected circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and that the
other relay demonstrate reception of that blocking carrier. This can be observed from relay or DFR
records during naturally occurring faults, or by a manual test. If the checkback test sequence were
incorporated in the relay logic, the carrier sets and carrier channel are then included in the overlapping
segments monitored by the two relays, and the monitoring gap is completely eliminated.
Draft 3: November 17, 2010
Page 34
Appendix B — Protection System Maintenance Standard
Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Mark Lukas
ComEd
Merle E. Ashton
Tri-State G&T
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
Bob Bentert
Florida Power & Light Company
John Ciufo
Hydro One Inc
Mark Peterson
Great River Energy
Sam Francis
Oncor
Leonard Swanson, Jr
National Grid USA
Carol A Gerou
Midwest Reliability Organization
Eric A Udren
Quanta Technology
William Shultz
Southern Company Generation
Philip B Winston
Southern Company Transmission
Russell C Hardison
Tennessee Valley Authority
John A Zipp
ITC Holdings
David Harper
NRG Texas Maintenance Services
Draft 3: November 17, 2010
Page 35
PRC-005-2
Protection System Maintenance
Draft Supplementary Reference
May 27November 17, 2010
Prepared by the
Protection System Maintenance and Testing Standard Drafting Team
PRC-005-2
Project 2007-17
Table of Contents
1. Introduction and Summary ..........................................................................................................3
2. Need for Verifying Protection System Performance ...................................................................3
2.1 Existing NERC Standards for Protection System Maintenance and Testing ..........................3
2.2 Proposed Modification to NERC Glossary Definition ............................................................4
2.3 Applicability of New Protection System Maintenance Standards ...........................................4
2.4 Applicable Relays ....................................................................................................................4
3. Relay Product Generations ........................................................................................................5
4. Definitions..................................................................................................................................5
5. Time-Based Maintenance (TBM) Programs ...............................................................................6
Maintenance Practices .....................................................................................................................6
5.1 Extending Time-Based Maintenance .........................................................................................8
6. Condition-Based Maintenance (CBM) Programs ........................................................................8
7. Time-Based versus Condition-Based Maintenance ...................................................................9
8. Maximum Allowable Verification Intervals ..............................................................................9
Maintenance Tests .........................................................................................................................10
8.1 Table of Maximum Allowable Verification Intervals ...........................................................10
Level 1 Monitoring (Unmonitored) Table 1a ...........................................8.2 Retention of Records
13
Level 2 Monitoring (Partially Monitored)8.3 Basis for Table 1b1 Intervals ..............................14
Level 3 Monitoring (Fully Monitored) Table 1c8.4 Basis for Extended Maintenance Intervals for Microprocesso
8.2 Retention of Records.......................................... 9. Performance-Based Maintenance Process
16
8.3 Basis for Table 1 Intervals ............................................................... 9.1 Minimum Sample Size
17
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays10. Overlapping the Verification of Sec
9. Performance-Based Maintenance Process ............ 11. Monitoring by Analysis of Fault Records
19
9.1 Minimum Sample Size................. 12. Importance of Relay Settings in Maintenance Programs
20
10. Overlapping the Verification of Sections of the Protection System13. Self-Monitoring Capabilities and Limi
11. Monitoring by Analysis of Fault Records ......... 14. Notification of Protection System Failures
21
12. Importance of Relay Settings in15. Maintenance ProgramsActivities ...................................22
13. Self-Monitoring Capabilities and Limitations .................... 15.1 Protective Relays (Table 1-1)
22
14. Notification of Protection System Failures15.3 Control circuitry associated with protective functions (Table
15. Maintenance Activities ......................................... 15.4 Batteries and DC Supplies (Table 1-4)
25
15.1 Protective Relays ............................15.5 Associated communications equipment (Table 1-2)
25
15.2 Voltage & Current Sensing Devices ...................................................... 15.6 Alarms (Table2)
26
15.3 DC Control Circuitry ........................................... 15.7 Examples of Evidence of Compliance
26
15.4 Batteries and DC Supplies ................................................................................ 16. References
28
15.5 Tele-protection equipment ............................................................................................Figures
29
15.6 Examples of Evidence of Compliance ...................... Figure 1: Typical Transmission System
29
16. References ....................................................................... Figure 2: Typical Generation System
30
Figures.........................................................................................Figure 3: Requirements Flowchart
32
Figure 1: Typical Transmission System ........................................................................ Appendix A
33
Figure 2: Typical Generation SystemAppendix B — Protection System Maintenance Standard Drafting Team
Figure 3: Requirements Flowchart.................................................................................................32
Appendix A ....................................................................................................................................33
Appendix B — Protection System Maintenance Standard Drafting Team ...................................36
Draft 2: April3: November 17, 2010
Page 2
This supplementary reference to PRC-005-2 borrows heavily from the technical reference by the System
Protection and Control Task Force (SPCTF) (Protection System Maintenance Technical Reference paper
approved by the Planning Committee in September 2007).. Additionally, data available from IEEE, EPRI,
and maintenance programs from various generation and transmission utilities across the NERC
boundaries was utilized by the Protection System Maintenance and Testing Standard Drafting Team
(PSMTSDTPSMT SDT) for PRC-005-2 (Project 2007-17) utilized maintenance program data from
various generation and transmission utilities across the NERC boundaries; as well as data from IEEE and
EPRI.to develop this reference document..
1. Introduction and Summary
NERC currently has four reliability standards that are mandatory and enforceable in the United States and
address various aspects of maintenance and testing of Protection and Control systems. These standards
are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for Protection Systems,
and that these entities must be able to demonstrate they are carrying out such a program, there are no
specifics regarding the technical requirements for Protection System maintenance programs. Furthermore,
FERC Order 693 directed additional modifications respective to Protection System maintenance
programs. This revision of PRC-005-1 combines and replaces PRC-005, PRC-008, PRC-011 and PRC017.
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate their
performance until a fault or other power system problem requires that they operate to protect power
system elements, or even the entire Bulk Electric System (BES). Lacking faults or system problems, the
protection systems may not operate for extended periods. A Misoperation - a false operation of a
protection system or a failure of the protection system to operate, as designed, when needed - can result in
equipment damage, personnel hazards, and wide area disturbances or unnecessary customer outages. A
maintenance Maintenance or testing program isprograms are used to determine the performance and
availability of protection systems.
Typically, utilities have tested protection systems at fixed time intervals, unless they had some incidental
evidence that a particular protection system was not behaving as expected. Testing practices vary widely
across the industry. Testing has included system functionality, calibration of measuring relays, and
correctness of settings. Typically, a protection system must be visited at its installation site and removed
from service for this testing.
Fundamentally, a reliability standard for Protection System Maintenance and Testing requires the
performance of the maintenance activities that are necessary to detect and correct plausible age and
service related degradation of components such that a properly built and commissioned Protection System
will continue to function as designed over its service life.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset owner
define a testing program. The starting point is the existing Standard PRC-005, briefly restated as follows:
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Purpose: To ensure all transmission and generation Protection Systems affecting the reliability of the
Bulk Electric System (BES) are maintained and tested.
PRC-005-1 is not specific on where the boundaries of the Protection Systems lie. However, the definition
of Protection System in the NERC Glossary of Terms used in Reliability Standards indicates what must
be included as a minimum.
Definition of Protection System (excerpted from the NERC Standards Glossary of Terms):
Protective relays, associated communicationcommunications systems, voltage and current sensing
devices, station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
Requirements: The owner shall have a documented maintenance program with test intervals. The owner
must keep records showing that the maintenance was performed at the specified intervals.
2.2 Proposed Modification to NERC Glossary Definition
The Protection Systems Maintenance and Testing Standard Drafting Team (PSM SDT), proposes changes
to the NERC glossary definition of Protection Systems as follows:
Protection System (modification)
o - Protective relays, communication which respond to electrical quantities,
o communications systems necessary for correct operation of protective functions,
o voltage and current sensing devices providing inputs to protective relays and associated
circuitry from the voltage and current sensing devices, ,
o station DCdc supply, and control circuitry, associated with protective functions from
the(including station DCbatteries, battery chargers, and non-battery-based dc supply), and
o control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from the
original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“… and that are applied on, or are designed to provide protection for the BES.”
The drafting team intends that this Standard will not apply to “merely possible” parallel paths, (subtransmission and distribution circuits), but rather the standard applies to any Protection System that is
designed to detect a fault on the BES and take action in response to that fault. The Standard Drafting
Team does not feel that Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the Regional definitions of the
BES.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and voltage
sensing devices, dc control circuitry and associated communications circuits. The relays to which this
standard applies are those relays that use measurements of voltage, current, frequency and/or phase angle
and provide a trip output to trip coils, dc control circuitry or associated communications equipment. This
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definition extends to IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or trip-free relay)
as these devices are tripping relays that respond to the trip signal of the protective relay that processed the
signals from the current and voltage sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration, pressure,
seismic, thermal or gas accumulation) are not included.
3. Relay Product Generations
The likelihood of failure and the ability to observe the operational state of a critical protection system,
both depends on the technological generation of the relays as well as how long they have been in service.
Unlike many other transmission asset groups, protection and control systems have seen dramatic
technological changes spanning several generations. During the past 20 years, major functional advances
are primarily due to the introduction of microprocessor technology for power system devices such as
primary measuring relays, monitoring devices, control systems, and telecommunications equipment.
Modern microprocessor based relays have six significant traits that impact a maintenance strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and some
connected substation inputs and outputs such as trip coil continuity. Most relay users are aware
that these relays have self monitoring, but are not focusing on exactly what internal functions are
actually being monitored. As explained further below, every element critical to the protection
system must be monitored, or else verified periodically.
•
Ability to capture fault records showing how the protection system responded to a fault in its zone
of protection, or to a nearby fault for which it is required not to operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-fault times. The relays can compute values such as MW and MVAR line
flows that are sometimes used for operational purposes such as SCADA.
•
Data communications via ports that provide remote access to all of the results of protection
system monitoring, recording, and measurement.
•
Ability to trip or close circuit breakers and switches through the protection system outputs, on
command from remote data communications messages or from relay front panel button requests.
•
Construction from electronic components some of which have shorter technical life or service life
than electromechanical components of prior protection system generations.
4. Definitions
Protection System Maintenance Program (PSMP) –— An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
An ongoing program by which Protection System components are kept in working order and where
malfunction components are restored to working order
•
•
Verification – A means of determiningVerify — Determine that the component is
functioning correctly.
Monitoring – Observation ofMonitor — Observe the routine in-service operation of the
component.
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•
•
Testing – Application ofTest — Apply signals to a component to observe functional
performance or output behavior, or to diagnose problems.
• Inspection – To detectInspect — Detect visible signs of component failure, reduced
performance and degradation.
• Calibration – Adjustment ofCalibrate — Adjust the operating threshold or measurement
accuracy of a measuring element to meet the intended performance requirement.
Upkeep – Routine activities necessary to assure that the component remains in good working
order and implementation of any manufacturer’s hardware and software service advisories which
are relevant to the application of the device.
•
Restoration – The actions to restore proper operation ofRestore — Return
malfunctioning components. to proper operation.
5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which protection systems are maintained or verified according
to a time schedule. The scheduled program often calls for technicians to travel to the physical site and
perform a functional test on protection system components. However, some components of a TBM
program may be conducted from a remote location - for example, tripping a circuit breaker by
communicating a trip command to a microprocessor relay to determine if the entire protection system
tripping chain is able to operate the breaker.
Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have been
developed from prior experience or manufacturers’ recommendations. The TBM verification
interval is based on a variety of factors, including experience of the particular asset owner,
collective experiences of several asset owners who are members of a country or regional council,
etc. The maintenance intervals are fixed, and may range in number of months or in years.
TBM can include review of recent power system events near the particular terminal. Operating
records may verify that some portion of the protection system has operated correctly since the last
test occurred. If specific protection scheme components have demonstrated correct performance
within specifications, the maintenance test time clock iscan be reset for those components.
•
PBM – performance-based maintenance - intervals are established based on analytical or
historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied by
adjustments to maintenance intervals are used to justify continued use of PBM-developed
extended intervals when test failures or in-service failures occur infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from nondisruptive self monitoring of components demonstrate operational status as those components
remain in service. Whatever is verified by CBM does not require manual testing, but taking
advantage of this requires precise technical focus on exactly what parts are included as part of the
self diagnostics.
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Microprocessor based protective relays that perform continuous self-monitoring verify correct
operation of most components within the device. Self-monitoring capabilities may include the ac
signal inputs, analog measuring circuits, processors and memory for measurement, protection,
and data communications, trip circuit monitoring, and protection or data communications signals.
For those conditions, failure of a self-monitoring routine generates an alarm and may inhibit
operation to avoid false trips. When internal components, such as critical output relay contacts,
are not equipped with self-monitoring, they can be manually tested. The method of testing may
be local or remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike TBM,
PBM intervals are adjusted based on good or bad experiences. The CBM verification intervals can be
hours or even milliseconds between non-disruptive self monitoring checks within or around components
as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete Protection
System. The following diagram illustrates the relationship between various types of maintenance
practices described in this section. In the Venn diagram the overlapping regions show the relationship of
TBM with PBM historical information and the inherent continuous monitoring offered through CBM.
This figure shows:
•
•
•
Region 1: The TBM intervals that are increased based on known reported operational condition of
individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been subject to
TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
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5.1 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly established to
assure proper functioning of each component of the protection system, when data on the reliability of the
components is not available other than observations from time-based maintenance. The following factors
may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from relay self
monitoring, for example), the intervals may be extended or manual testing may be eliminated.
This is referred to as condition-based maintenance or CBM. CBM is valid only for precisely the
components subject to monitoring. In the case of microprocessor-based relays, self-monitoring
may not include automated diagnostics of every component within a microprocessor.
•
Previous maintenance history for a group of components of a common type may indicate that the
maintenance intervals can be extended while still achieving the desired level of performance. This
is referred to as performance-based maintenance or PBM. It is also sometimes referred to as
reliability-centered maintenance or RCM, but PBM is used in this document.
•
Observed proper operation of a component may be regarded as a maintenance verification of the
respective component or element in a microprocessor-based device. For such an observation, the
maintenance interval may be reset only to the degree that can be verified by data available on the
operation. For example, the trip of an electromechanical relay for a fault verifies the trip contact
and trip path, but only through the relays in series that actually operated; one operation of this
relay cannot verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is not unusual
to cause failure of a component by removing it from service and restoring it. The improper application of
test signals may cause failure of a component. For example, in electromechanical overcurrent relays, test
currents have been known to destroy convolution springs.
In addition, maintenance usually takes the component out of service, during which time it is not able to
perform its function. Cutout switch failures, or failure to restore switch position, commonly lead to
protection failures.
6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information available from
modern microprocessor-based relays and other intelligent electronic devices (IEDs) that monitor
protection system elements. These relays and IEDs generate monitoring information during normal
operation, and the information can be assessed at a convenient location remote from the substation. The
information from these relays and IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in relay logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillograph records for
faults and disturbances, metered values, and binary input status reports. Some of these are
available on the relay front panel display, but may be available via data communications
ports. Large files of fault information can only be retrieved via data communications.
These results comprise a mass of data that must be further analyzed for evidence of the
operational condition of the protection system.
Using these two types of information, the user can develop an effective maintenance program carried out
mostly from a central location remote from the substation. This approach offers the following advantages:
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1. Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
2. Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some relays will show health problems by
incorrect relaying before being caught in the next test round. The frequent or continuous
nature of CBM makes the effective verification interval far shorter than any required
TBM maximum interval.
7. Time-Based versus Condition-Based Maintenance
Time-based and condition-based maintenance programs are both acceptable, if implemented according
to technically sound requirements. Practical programs can employ a combination of time-based and
condition-based maintenance. The standard requirements introduce the concept of optionally using
condition monitoring as a documented element of a maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule dated March
16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability Standards for the BulkPower System, directed NERC to submit a modification to PRC-005-1 that includes a requirement that
maintenance and testing of a protection system must be carried out within a maximum allowable interval
that is appropriate to the type of the protection system and its impact on the reliability of the Bulk Power
System. Accordingly, this Supplementary Reference Paper refers to the specific maximum allowable
intervals in PRC-005-2. The defined time limits allow for longer time intervals if the maintained
devicecomponent is monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay between the
moment of a protection failure and time the protection system owner knows about it, for the monitored
segments of the protection system. In some cases, the verification is practically continuous - the time
interval between verifications is minutes or seconds. Thus, technically sound, condition-based verification
(as specified in the header and the “Monitoring Attributes” column of Tables 1b and 1c of PRC-005-2),,
meets the verification requirements of the FERC order even more effectively than the strictly time-based
tests of the same system elements as contained in Table 1acomponents.
The result is that:
This NERC standardsstandard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern protection systems to reduce the
need for periodic site visits and invasive testing of components by on-site technicians. This periodic
testing must be conducted within the maximum time intervals specified in Tables 1a, 1b and 1c1-1
through Tables 1-5 of PRC-005-2.
8. Maximum Allowable Verification Intervals
The Maximum Allowable Testing Intervals and Maintenance Activities requirements show how CBM
with newer relay types can reduce the need for many of the tests and site visits that older protection
systems require. As explained below, there are some sections of the protection system that monitoring or
data analysis may not verify. Verifying these sections of the Protection Systems requires some persistent
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TBM activity in the maintenance program. However, some of this TBM can be carried out remotely - for
example, exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if there has
been no fault or routine operation to demonstrate performance of relay tripping circuits.
Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is operating
correctly after a time period of field installation. These tests may be used to ensure that individual
components are still operating within acceptable performance parameters - this type of test is needed for
components susceptible to degraded or changing characteristics due to aging and wear. Full system
performance tests may be used to confirm that the total protection system functions from measurement of
power system values, to properly identifying fault characteristics, to the operation of the interrupting
devices.
8.1 Table of Maximum Allowable Verification Intervals
Table 1, (collectively known as Table 1, individually called out as Tables 1-1 through 1-5), in the
standard, specifies maximum allowable verification intervals for various generations of protection
systems and categories of equipment that comprise protection systems. The right column indicates
maintenance activities required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1 shows an
example of telecommunications-assisted line protection system comprising substation equipment at each
terminal and a telecommunications channel for relaying between the two substations. Figure 2 shows a
typical Generation station layout. The various subsystems of a Protection System that need to be verified
are shown. UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated in these
Figures. UFLS, UVLS and SPS all use identical equipment as Protection Systems in the performance of
their functions and therefore have the same maintenance needs.
While it is easy to associate protective relays to the threemultiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological advancements
that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables (Tables 1a, 1b and 1c collectively Tables) from
PRC-005-2:
• First check the table header description to verify that your equipment meets the monitoring
requirements. If your equipment does not meet the monitoring requirements of Table 1c then
check Table 1b. If your equipment does not meet the requirements of Table 1b then use Table 1a.
•
If you find a piece of equipment that meets the monitoring requirements of Table 1b or 1c then
you can take advantage of the extended time intervals allowed by Table 1b and 1c. Your
maintenance plan must document that this component can be maintained by the requirements of
Table 1b or 1c because it has the necessary attributes required within that Table.
•
Once you determine which table applies to your equipment’s monitoring requirements then check
the Maintenance Activity that is required for that particular component. First find the Table
associated with your component. The tables are arranged in the order of mention in the definition
of Protection System; Table 1-1 is for protective relays, Table 1-2 is for the associated
communications systems, Table 1-3 is for current and voltage sensing devices, Table 1-4 is for
station dc supply and Table 1-5 is for control circuits. There is an additional table, Table 2, which
brings alarms into the maintenance arena; this was broken out to simplify the other tables.
•
Next look within that table for your device and its degree of monitoring. The tables have different
hands-on maintenance activities prescribed depending upon the degree to which you monitor your
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equipment. Find the maintenance activity that applies to the monitoring level that you have on
your piece of equipment.
•
This Maintenance Activity is the minimum maintenance activity that must be documented.
•
If your PSMP (plan) requires more activities then you must perform and document moreto this
higher standard.
•
After the maintenance activity is known, check the Maximum Maintenance Interval; this time is
the maximum time allowed between hands-on maintenance activity cycles of this component.
•
If your PSMP (plan) requires activities more often than the Tables maximum then you must
perform and document those activities more oftento this higher standard.
•
Any given setcomponent of a Protection System equipment can be maintained with any
combination of Tables 1a, 1b and 1c. An entity does not determined to have to stick to Table 1a
just because some of its equipmenta degree of monitoring that may be different from another
component within that same Protection System. For example, in a given Protection System it is
un-possible for an entity to have a monitored protective relay and an unmonitored associated
communications system; this combination would require hands-on maintenance activity on the
relay at least once every 12 years and attention paid to the communications system as often as
every 3 months.
•
An entity does not have to utilize the extended time intervals in Tables 1b or 1cmade available by
this use of condition-based monitoring. An easy choice to make is to simply utilize Table 1a.the
unmonitored level of maintenance made available on each of the 5 Tables. While the maintenance
activities resulting from choosing to use only Table 1athis choice would require more
maintenance man-hours, the maintenance requirements may be simpler to document and the
resulting maintenance plans may be easier to create.
For each Protection System component, Table 1 shows maximum allowable testing intervals for
unmonitored, partially monitored and fully monitored protection systems:the various degrees of
monitoring. These degrees of monitoring, or levels, range from the legacy unmonitored through a system
that is more comprehensively monitored.
Table 1 Maximum Allowable Testing Intervals and Maintenance Activities
Level 1 Monitoring (Unmonitored) Table 1a
This table applies to electromechanical, analog solid state and other un-monitored Protection Systems
components. This table represents the starting point for all required maintenance activities. The object of
this group of requirements is to have specific activities accomplished at maximum set time intervals.
From this group of activities it follows that CBM or PBM can increase the time intervals between the
hands-on maintenance actions.
Level 2 Monitoring (Partially Monitored) Table 1b
This table applies to microprocessor relays and other associated Protection System components whose
self-monitoring alarms are transmitted to a location (at least daily) where action can be taken for alarmed
failures. The attributes of the monitoring system must meet the requirements specified in the header of the
Table 1b. Given these advanced monitoring capabilities, it is known that there are specific and routine
testing functions occurring within the device. Because of this ongoing monitoring hands-on action is
required less often because routine testing is automated. However, there is now an additional task that
must be accomplished during the hands-on process – the monitoring and alarming functions must be
shown to work.
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Level 3 Monitoring (Fully Monitored) Table 1c
This table applies to microprocessor relays and other associated Protection System components in which
every element or function required for correct operation of the Protection System component is monitored
continuously and verified, including verification of the means by which failure alarms or indicators are
transmitted to a location within 1 hour or less of the maintenance-correctable issue occurring. This is the
highest level of monitoring and if it is available then this gives an entity the ability to have continuous
testing of their (Level 3 Monitored) Protection System Component and thus does not have to manually
intervene to accomplish routine testing chores. Level 3 Fully Monitored yields continuous monitoring
advantages but has substantial technical hurdles that must be overcome; namely that monitoring also
verifies the failure of the monitoring and alarming equipment. Without this important ingredient a device
that is thought to be continuously monitored could be in an alarm state without the asset owner being
aware of this alarm state.
It has been noted here that an entity may have a PSMP that is more stringent than PRC-005-2. There may
be any number of reasons that an entity chooses a more stringent plan than the minimums prescribed
within PRC-005-2, most notable of which is an entity using performance based maintenance
methodology. (Another reason for having a more stringent plan than is required could be a regional entity
could have more stringent requirements.) Regardless of the rationale behind an entity’s more stringent
plan, it is incumbent upon them to perform the activities, and perform them at the stated intervals, of the
entity’s PSMP. A quality PSMP will help assure system reliability and adhering to any given PSMP
should be the goal.
Additional Notes for Table 1a, Table 1b, and Table 1cTables 1-1 through 1-5
1. For electro-mechanical relays, adjustment is required to bring measurement accuracy within the
tolerance needed by the asset owner. Microprocessor-relays with no remote monitoring of alarm
contacts, etc, are un-monitored relays and need to be verified within the Table interval as other
un-monitored relays but may be verified as functional by means other than testing by simulated
inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring calibration, but
acceptable measurement of power system input values must be verified (verification of the
Analog to Digital [A/D] converters) within the Table intervals. The integrity of the digital inputs
and outputs that are used as protective functions must be verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a protection system or
SPS (as opposed to a monitoring task) must be verified as a component in a protection system.
4. In addition to verifying the circuitry that supplies dc to the protection system, the owner must
maintain the station dc supply. The most widespread station dc supply is the station battery and
charger. Unlike most Protection System elementscomponents physical inspection of station
batteries for signs of component failure, reduced performance, and degradation are required to
ensure that the station battery is reliable enough to deliver dc power when required. IEEE
Standards 450, 1188, and 1106 for Vented Lead-Acid, Valve-Regulated Lead-Acid, and NickelCadmium batteries, respectively (which are the most commonly used substation batteries on the
NERC BES) have been developed as an important reference source of maintenance
recommendations. The Protection System owner might use the applicable IEEE recommended
practice which contains information and recommendations concerning the maintenance, testing
and replacement of its substation battery. However, the methods prescribed in these IEEE
recommendations cannot be specifically required because they do not apply to all battery
applications.
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5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS systems,
and large entities will usually maintain a portion of these systems in any given year.
Additionally, if relatively small quantities of such systems do not perform properly, it will not
affect the integrity of the overall program. Thus these distributed systems have decreased
requirements as compared to other Protection Systems.
6. Voltage & Current Sensing Device circuit input connections to the protection system relays can
be verified by (but not limited to) comparison of measured values on live circuits or by using test
currents and voltages on equipment out of service for maintenance. The verification process can
be automated or manual. The values should be verified to be as expected, (phase value and phase
relationships are both equally important to verify).
7. Verify the protection system tripping function by performing an operational trip test on all
components contained in the trip circuit. This includes circuit breaker or circuit switcher trip
coils, auxiliary tripping relays (94), lock-out relays (86), and communications-assisted trip
scheme elements. Each control circuit path that carries trip signal must be verified, although each
path must be checked only once. A maintenance program may include performing an overall test
for the entire system at one time, or several split system tests with overlapping trip verification. A
documented real-time trip of any given trip path is acceptable in lieu of a functional trip test.
8. “End-to-end test” as used in this supplementary reference is any testing procedure that creates a
remote input to the local communications-assisted trip scheme. While this can be interpreted as a
GPS-type functional test it is not limited to testing via GPS. Any remote scheme manipulation
that can cause action at the local trip path can be used to functionally-test the dc Control
Circuitry. A documented real-time trip of any given trip path is acceptable in lieu of a functional
trip test. It is possible, with sufficient monitoring, to be able to verify each and every parallel trip
path that participated in any given dc Control Circuit trip. Or, another possible solution is that a
single trip path from a single monitored relay can be verified to be the trip path that successfully
tripped during a real-time operation. The variations are only limited by the degree of engineering
and monitoring that an entity desires to pursue.
9. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus feeder
currents) can be used for comparison if calibration requirements assure acceptable measurement
of power system input values.
10. Notes 1-9 attempt to describe the testing activities they do not represent the only methods to
achieve these activities but rather some possible methods. Technological advances, ingenuity
and/or industry accepted techniques can all be used to satisfy maintenance activity requirements;
the standard is technology and method neutral in most cases.
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three years.
However, with a three year retention cycle, the records of verification for a protection system will
typically be discarded before the next verification, leaving no record of what was done if a
Misoperationmisoperation or failure is to be analyzed.
PRC-005-2 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation
of the two most recent performances of each distinct maintenance activity for the Protection System
components, or to the previous on-site audit date, whichever is longer.
This requirement assures that the documentation shows that the interval between maintenance cycles
correctly meets the maintenance interval limits. The requirement is actually alerting the industry to
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documentation requirements already implemented by audit teams. Evidence of compliance bookending
the interval shows interval accomplished instead of proving only your planned interval.
8.3 Basis for Table 1 Intervals
SPCTF authors collected all available data from Regional Entities (REs) on time intervals recommended
for maintenance and test programs. The recommendations vary widely in categorization of relays, defined
maintenance actions, and time intervals, precluding development of intervals by averaging. SPCTF also
reviewed the 2005 Report [2] of the IEEE Power System Relaying Committee Working Group I-17
(Transmission Relay System Performance Comparison). Review of the I-17 report shows data from a
small number of utilities, with no company identification or means of investigating the significance of
particular results.
To develop a solid current base of practice, SPCTF surveyed its members regarding their maintenance
intervals for electromechanical and microprocessor relays, and asked the members to also provide
definitively-known data for other entities. The survey represented 470 GW of peak load, or 64% of the
NERC peak load. Maintenance interval averages were compiled by weighting reported intervals
according to the size (based on peak load) of the reporting utility. Thus, the averages more accurately
represent practices for the large populations of protection systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of 5 years for
electromechanical or solid state relays, and 7 years for un-monitored microprocessor relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond 7 years,
based on favorable experience with the particular products they have installed. To provide a technical
basis for such extension, SPCTF authors developed a recommendation of 10 years using the Markov
modeling approach from [1] as summarized in Section 8.4. The results of this modeling depend on the
completeness of self-testing or monitoring. Accordingly, this extended interval is allowed by Table 1 only
when such relays are monitored as specified in the headerattributes of monitoring contained in Tables 1-1
through 1-5 and Table 1b2. Monitoring is capable of reporting protection system health issues that are
likely to affect performance within the 10 year time interval between verifications.
It is important to note that, according to modeling results, protection system availability barely changes as
the maintenance interval is varied below the 10-year mark. Thus, reducing the maintenance interval does
not improve protection system availability. With the assumptions of the model regarding how
maintenance is carried out, reducing the maintenance interval actually degrades protection system
availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level. The industry
has experience with self-monitoring microprocessor relays that leads to the Table 1 value for partial
monitoringa monitored relay as explained in Section 8.3. To develop a basis for the maximum interval
for monitored relays in their Protection System Maintenance – A Technical Reference, the SPCTF used
the methodology of Reference [1], which specifically addresses optimum routine maintenance intervals.
The Markov modeling approach of [1] is judged to be valid for the design and typical failure modes of
microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability measures:
• Relay Unavailability - the probability that the relay is out of service due to failure or maintenance
activity while the power system element to be protected is in service.
• Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a fault occurs, leading to failure to operate for the fault.
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The parameter in the Markov model that defines self-monitoring capability is ST (for self test). ST = 0 if
there is no self-monitoring; ST = 1 for full monitoring. Practical ST values are estimated to range from
.75 to .95. The SPCTF simulation runs used constants in the Markov model that were the same as those
used in [1] with the following exceptions:
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal fault clearing time of 10 cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup fault clearing time of 50 cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a protection system)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a protection system repair after failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to these
parameter adjustments.
The resulting curves for Relay Unavailability and Abnormal Unavailability versus maintenance interval
showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years – the curve is flat,
with no significant change in either unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years, much lower than MTBF values
typically published for these relays. Also, the Markov modeling indicates that both the relay
unavailability and abnormal unavailability actually become higher with more frequent testing. This
shows that the time spent on these more frequent tests yields no failure discoveries that approach the
negative impact of removing the relays from service and running the tests.
PSMT SDT further notes that the SPCTF also allowed 25% extensions to the “maximum time intervals”.
With a 5 year time interval established between manual maintenance activities and a 25% time extension
then this equates to a 6.25 year maximum time interval. It is the belief of the PSMT SDT that the SPCTF
understood that 6.25 years was thereby an adequate maximum time interval between manual maintenance
activities. The PSMT SDT has followed the FERC directive for a maximum time interval and has
determined that no extensions will be allowed. Six years has been set for the maximum time interval
between manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval between
maintenance activities. A 10 year interval with a 25% allowed extension equates to a maximum allowed
interval of 12.5 years between manual maintenance activities. The Standard does not allow extensions on
any component of the protection system; thus the maximum allowed interval for these devicescomponents
has been set to12 years. Twelve years also fits well into the traditional maintenance cycles of both
substations and generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum Maintenance
Interval”. The PSMT SDT deemed it necessary to include the term “Calendar” to facilitate annual
maintenance planning, scheduling and implementation. This need is the result of known occurrences of
system requirements that could cause maintenance schedules to be missed by a few days or weeks. The
PSMT SDT chose the term “Calendar” to preclude the need to have schedules be met to the day. An
electro-mechanical protective relay that is maintained in year #1 need not be revisited until 6 years later
(year #7). For example: a relay was maintained April 10, 2008; maintenance would need to be completed
no later than December 31, 2014.
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Section 9 describes a performance-based maintenance process which can be used to justify maintenance
intervals other than those described in Table 1.
Section 10 describes sections of the protection system, and overlapping considerations for full verification
of the protection system by segments. Segments refer to pieces of the protection system, which can range
from a single device to a panel to an entire substation.
Section 11 describes how relay operating records can (but not required to) serve as a basis for verification,
reducing the frequency of manual testing.
Section 13 describes how a cooperative effort of relay manufacturers and protection system users can
improve the coverage of self-monitoring functions, leading to full monitoring of the bulk of the protection
system, and eventual elimination of manual verification or testing.
9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a performance-based maintenance process may be used to establish
maintenance intervals (PRC-005 Attachment A Criteria for a Performance-Based Protection System
Maintenance Program). A performance-based maintenance process may justify longer maintenance
intervals, or require shorter intervals relative to Table 1. In order to use a performance-based maintenance
process, the documented maintenance program must include records of repairs, adjustments, and
corrections to covered protection systems in order to provide historical justification for intervals other
than those established in Table 1. Furthermore, the asset owner must regularly analyze these records of
corrective actions to develop a ranking of causes. Recurrent problems are to be highlighted, and remedial
action plans are to be documented to mitigate or eliminate recurrent problems.
Utilities with performance-based maintenance track performance of protection systems, demonstrate how
they analyze findings of performance failures and aberrations, and implement continuous improvement
actions. Since no maintenance program can ever guarantee that no malfunction can possibly occur,
documentation of a performance-based maintenance program would serve the utility well in explaining to
regulators and the public a Misoperationmisoperation leading to a major system outage event.
A performance-based maintenance program requires auditing processes like those included in widely used
industrial quality systems (such as ISO 9001-2000, Quality management systems — Requirements; or
applicable parts of the NIST Baldridge National Quality Program). The audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance-based Maintenance (PBM) program the asset owner must first sort the
various Protection System components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM but does not own 60 units to
comprise a population then that asset owner may combine data from other asset owners until the needed
60 units is aggregated. Each population segment must be composed of like devicesa grouping of
Protection Systems or components of a consistent design standard or particular model or type from the
samea single manufacturer and subjected to similar environmental factors. For example: One segment
cannot be comprised of both GE & Westinghouse electro-mechanical lock-out relays; likewise, one
segment cannot be comprised of 60 GE lock-out relays, 30 of which are in a dirty environment and the
remaining 30 from a clean environment. This PBM process cannot be applied to batteries but can be
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applied to all other components of a Protection System including (but not limited to) specific battery
chargers, instrument transformers, trip coils and/or control circuitry (etc.).
9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling distribution of the
sample mean can be approximated by a normal probability distribution.” The Central Limit Theorem
states: “In selecting simple random samples of size n from a population, the sampling distribution of the
sample mean x can be approximated by a normal probability distribution as the sample size becomes
large.” (Essentials of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003)
To use the Central Limit Theorem in statistics, the population size should be large. The references below
are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30), the
central limit theorem enables us to conclude that the sampling distribution of the sample
mean can be approximated by a normal distribution.” (Essentials of Statistics for
Business and Economics, Anderson, Sweeney, Williams, 2003)
“If samples of size n, when n>=30, are drawn from any population with a mean u and a
standard deviation σ, the sampling distribution of sample means approximates a normal
distribution. The greater the sample size, the better the approximation.” (Elementary
Statistics - Picturing the World, Larson, Farber, 2003)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005)
“… the normal is often used as an approximation to the t distribution in a test of a null
hypothesis about the mean of a normally distributed population when the population
variance is estimated from a relatively large sample. A sample size exceeding 30 is often
given as a minimal size in this connection.” (Statistical Analysis for Business Decisions,
Peters, Summers, 1968)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated using the
bound on the Error of Distribution Formula when the expected result is of a “Pass/Fail” format and will
be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
Β = bound on the error of distribution (allowable error)
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z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
z
n = π(1 − π)
Β
2
Minimum Population Size to use Performance-based Program
One entity’s population of components should be large enough to represent a sizeable sample of a
vendor’s overall population of manufactured devices. For this reason the following assumptions are
made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-based Program
The number of components that should be included in a sample size for evaluation of the appropriate
testing interval can be smaller because a lower confidence level is acceptable since the sample testing is
repeated or updated annually. For this reason, the following assumptions are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation mentioned.
Using this and the results of the equation, the following numbers are recommended: (and required within
the standard):
Minimum Population Size to use Performance-based Maintenance Program = 60
Minimum Sample Size to evaluate Performance-based Program = 30.
Once the population segment is defined then maintenance must begin within the intervals as outlined for
Level 1 monitoring,the device described in the Tables (Table 1a).1-1 through Table 1-5). Time intervals
can be lengthened provided the last year’s worth of devicescomponents tested (or the last 30 units
maintained, whichever is more) had fewer than 4% countable events. It is notable that 4% is specifically
chosen because an entity with a small population (60 units) would have to adjust its time intervals
between maintenance if more than 1 countable event was found to have occurred during the last analysis
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period. A smaller percentage would require that entity to adjust the time interval between maintenance
activities if even one unit is found out of tolerance or causes a mis-operationMisoperation.
The minimum number of units that can be tested in any given year is 5% of the population. Note that this
5% threshold sets a practical limitation on total length of time between intervals at 20 years.
If at any time the number of countable events equals or exceeds 4% of the last year’s tested-devices
components (or the last 30 units maintained, whichever is more) then the time period between manual
maintenance activities must be decreased. There is a time limit on reaching the decreased time at which
the countable events is less than 4%; this must be attained within three years.
This additional time period of three years to restore segment performance to <4% countable events is
mandated to keep entities from “gaming the PBM system”. It is believed that this requirement provides
the economic disincentives to discourage asset owners from arbitrarily pushing the PBM time intervals
out to up to 20 years without proper statistical data.
10. Overlapping the Verification of Sections of the Protection System
TableTables 1 requires-1 through 1-5 require that every protection system elementcomponent be
periodically verified. One approach is to test the entire protection scheme as a unit, from the secondary
windings of voltage and current sources to breaker tripping. For practical ongoing verification, sections of
the protection system may be tested or monitored individually. The boundaries of the verified sections
must overlap to ensure that there are no gaps in the verification. See Appendix A of this Supplementary
Reference for additional discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as appropriate, to
establish and operate a maintenance program. For example, a protection system may be divided into
multiple overlapping sections with a different maintenance methodology for each section:
•
Time-based maintenance with appropriate maximum verification intervals for categories
of equipment as given in the Unmonitored, Partially Monitored, or Fully Monitored
TablesTables 1-1 through 1-5;
• Full monitoring as described in header of Table 1cTables 1-1 through 1-5;
• A performance-based maintenance program as described in Section 9 above or
Attachment A of the Standard;
• Opportunistic verification using analysis of fault records as described in Section 11
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve fault event records and oscillographic records by data
communications after a fault. They analyze the data closely if there has been an apparent
Misoperationmisoperation, as NERC standards require. Some advanced users have commissioned
automatic fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome seems to be
correct. The relay data may be augmented with independently captured digital fault recorder (DFR) data
retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for a manual
time-interval based check on protection systems whose operations are analyzed. Even electromechanical
protection systems instrumented with DFR channels may achieve some CBM benefit. The completeness
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of the verification then depends on the number and variety of faults in the vicinity of the relay that
produce relay response records, and the specific data captured.
A typical fault record will verify particular parts of certain protection systems in the vicinity of the fault.
For a given protection system installation, it may or may not be possible to gather within a reasonable
amount of time an ensemble of internal and external fault records that completely verify the protection
system.
For example, fault records may verify that the particular relays that tripped are able to trip via the control
circuit path that was specifically used to clear that fault. A relay or DFR record may indicate correct
operation of the protection communications channel. Furthermore, other nearby protection systems may
verify that they restrain from tripping for a fault just outside their respective zones of protection. The
ensemble of internal fault and nearby external fault event data can verify major portions of the protection
system, and reset the time clock for the Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel with
multiple relays, only the specific relay(s) whose operation can be observed without ambiguity in the
record and the associated wiring paths are verified. Be careful about using fault response data to verify
that settings or calibration are correct. Unless records have been captured for multiple faults close to
either side of a setting boundary, setting or calibration could still be incorrect.
If fault record data is used to show that portions or all of a protection system have been verified to meet
Table 1 requirements, the owner must retain the fault records used, and the maintenance related
conclusions drawn from this data and used to defer Table 1 tests, for at least the retention time interval
given in Section 8.2.
12. Importance of Relay Settings in Maintenance Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to show that
the relays have correct settings and calibration. Microprocessor relays, by contrast, provide the means for
continuously monitoring measurement accuracy. Furthermore, the relay digitizes inputs from one set of
signals to perform all measurement functions in a single self-monitoring microprocessor system. These
relays do not require testing or calibration of each setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older relays. Some
microprocessor relays have hundreds or thousands of settings, many of which are critical to protection
system performance.
Monitoring does not check measuring element settings. Analysis of fault records may or may not reveal
setting problems. To minimize risk of setting errors after commissioning, the user should enforce strict
settings data base management, with reconfirmation (manual or automatic) that the installed settings are
correct whenever maintenance activity might have changed them. For background and guidance, see [5].
Table 1 requires that settings must be verified to be as specified. The reason for this requirement is
simple. With legacy relays (non-microprocessor protective relays) it is necessary to know the value of the
intended setting in order to test, adjust and calibrate the relay. Proving that the relay works per specified
setting was the de facto procedure. However, with the advanced microprocessor relays it is possible to
change relay settings for the purpose of verifying specific functions and then neglect to return the settings
to the specified values. While there is no specific requirement to maintain a settings management process
there remains a need to verify that the settings left in the relay are the intended, specified settings. This
need may manifest itself after any of the following:
•
•
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
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•
A relay is upgraded with a new firmware version.
13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products for nearly
20 years. Theoretically, any element that is monitored does not need a periodic manual test. A problem
today is that the community of manufacturers and users has not created clear documentation of exactly
what is and is not monitored. Some unmonitored but critical elements are buried in installed systems that
are described as self-monitoring.
Until users are able to document how all parts of a system which are required for the protective functions
are monitored or verified (with help from manufacturers), they must continue with the unmonitored or
partially monitored intervals established in Table 1.
Going forward, manufacturers and users can develop mappings of the monitoring within relays, and
monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of full monitoring, the manufacturers of the microprocessor-based self-monitoring
components in the protection system should publish for the user a document or map that shows:
•
How all internal elements of the product are monitored for any failure that could
impact protection system performance.
•
Which connected circuits are monitored by checks implemented within the product;
how to connect and set the product to assure monitoring of these connected circuits;
and what circuits or potential problems are not monitored.
With this information in hand, the user can document full monitoring for some or all sections by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component and
circuit that is critical to protection is monitored by the microprocessor product(s) or by
other design features.
•
Extending the monitoring to include the alarm transmission facilities through which
failures are reported within a given time frame to allocate where action can be taken to
initiate resolution of the alarm attributed to a maintenance correctable issue, so that
failures of monitoring or alarming systems also lead to alarms and action.
•
Documenting the plans for verification of any unmonitored elementscomponents
according to the requirements of Table 1.
14. Notification of Protection System Failures
When a failure occurs in a protection system, power system security may be compromised, and
notification of the failure must be conducted in accordance with relevant NERC standard(s). Knowledge
of the failure may impact the system operator’s decisions on acceptable loading conditions.
This formal reporting of the failure and repair status to the system operator by the protection system
owner also encourages the system owner to execute repairs as rapidly as possible. In some cases, a
microprocessor relay or carrier set can be replaced in hours; wiring termination failures may be repaired
in a similar time frame. On the other hand, a component in an electromechanical or early-generation
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electronic relay may be difficult to find and may hold up repair for weeks. In some situations, the owner
may have to resort to a temporary protection panel, or complete panel replacement.
15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would be that a
BES entity could be prudent in its protective relay maintenance but if its battery maintenance program is
lacking then reliability could still suffer. The NERC glossary outlines a Protection System as containing
specific components. PRC-005-02 requires specific maintenance activities be accomplished within a
specific time interval. As noted previously, higher technology equipment can contain integral monitoring
capability that actually performs maintenance verification activities routinely and often; therefore manual
intervention to perform certain activities on these type devicescomponents may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and voltage sensing
devices and are used to isolate a faulted portion of the BES. Devices that sense thermal, vibration,
seismic, pressure, gas or any other non-electrical inputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor based equipment in the
following ways, the relays should meet the asset owners’ tolerances.
•
•
Non-microprocessor devices must be tested with voltage and/or current applied to the device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test mandated.
o There is no specific documentation mandated.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers. There is
presently a technology available (fiber-optic Hall-effect) that does not utilize conventional transformer
technology; these devices and other technologies that produce quantities that represent the primary values
of voltage and current are considered to be a type of voltage and current sensing devices included in this
standard.
The intent of the maintenance activity is to verify the input to the protective relay from the device that
produces the current or voltage signal sample.
There is no specific test mandated for these devicescomponents. The important thing about these signals
is to know that the expected output from these devicescomponents actually reaches the protective relay.
Therefore, the proof of the proper operation of these devicescomponents also demonstrates the integrity
of the wiring (or other medium used to convey the signal) from the current and voltage sensing device all
the way to the protective relay. The following observations apply.
• There is no specific ratio test, routine test or commissioning test mandated.
• There is no specific documentation mandated.
• It is required that the signal be present at the relay.
• This expectation can be arrived at from any of a number of means; by calculation, by comparison
to other circuits, by commissioning tests, by thorough inspection, or by any means needed to
verify the circuit meets the asset owner’s protection system maintenance program.
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•
•
•
•
•
•
An example of testing might be a saturation test of a CT with the test values applied at the relay
panel; this therefore tests the CT as well as the wiring from the relay all the back to the CT.
Another possible test is to measure the signal from the voltage and/or current sensing devices,
during load conditions, at the input to the relay.
Another example of testing the various voltage and/or current sensing devices is to query the
microprocessor relay for the real-time loading; this can then be compared to other devices to
verify the quantities applied to this relay. Since the input devices have supplied the proper values
to the protective relay then the verification activity has been satisfied. Thus event reports (and
oscillographs) can be used to verify that the voltage and current sensing devices are performing
satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this should add up to
zero watts and zero vars thus proving the voltage and/or current sensing devices system
throughout the bus.
Another method for proving the voltage and/or current sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
OtherAny other methods that provide documentation that the expected transformer values as
applied to the inputs to the protective relays are acceptable.
15.3 DC Control Circuitrycircuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit switcher or
any other interrupting device. It includes the wiring from the batteries to the relays. It includes the wiring
(or other signal conveyance) from every trip output to every trip coil. It includes any device needed for
the correct processing of the needed trip signal to the trip coil of the interrupting device. In short, every
trip; this requirement is meant to capture inputs and outputs to and from a protective relay that are
necessary for the correct operation of the protective functions. In short, every trip path must be verified
and every I/O path must be verified; the method of verification is optional to the asset owner. An example
of testing methods to accomplish this might be to verify, with a volt-meter, the existence of the proper
voltage at the open contacts, the open circuited input circuit and at the trip coil(s). As every parallel trip
path has similar failure modes, each trip path from relay to trip coil must be verified. Each trip coil must
be tested to trip the circuit breaker (or other interrupting device) at least once. There is a requirement to
operate the circuit breaker (or other interrupting device) at least once every six years as part of the
complete functional test. If a suitable monitoring system is installed that verifies every parallel trip path
then the manual-intervention testing of those parallel trip paths can be extended tobeyond twelve years,
however the actual operation of the circuit breaker must still occur at least once every six years. This 6year tripping requirement can be completed as easily as tracking the real-time fault-clearing operations on
the circuit breaker. or tracking the trip coil(s) operation(s) during circuit breaker routine maintenance
actions
The circuit-interrupting device should not be confused with a motor-operated disconnect. The intent of
this standard is to require maintenance intervals and activities on Protection Systems equipment and not
just all equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground switch as an
interrupting device if this ground switch is utilized in a Protection System and forces a ground fault to
occur that then results in an expected Protection System operation to clear the forced ground fault. The
SDT believes that this is essentially a transferred-tripping device without the use of communications
equipment. If this high-speed ground switch is “…applied on, or designed to provide protection for the
BES…” then this device needs to be treated as any other Protection System component. The control
circuitry would have to be tested within 12 years and any electromechanically operated device will have
to be tested every 6 years. If the spring-operated ground switch can be disconnected from the solenoid
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triggering unit then the solenoid triggering unit can easily be tested without the actual closing of the
ground blade.
Distribution circuit Circuit breakers that participate in thea distributed UFLS or UVLS scheme are
excluded from the trip-testingtripping requirement, but not from the circuit test requirements; since the
circuitry must be tested at least once every 12 years and the circuit interrupting device need not be tested
then this effectively makes this a 12 year requirement. There are many circuit interrupting devices in the
distribution system that will be operating for any given under-frequency event that requires tripping for
that event. A failure in the tripping-action of a single distributiondistributed system circuit breaker will be
far less significant than, for example, any single Transmission Protection System failure such as a failure
of a Bus Differential Lock-Out Relay. While many failures of these distributiondistributed system circuit
breakers could add up to be significant, it is also believed that distributionmany circuit breakers are
operated often on just fault clearing duty and therefore the distributionthese circuit breakers are operated
at least as frequently as any requirements that might have appearedappear in this standard.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay (86) that
may exist in any givenparticular trip scheme. These If these devices are electro-mechanical
devicescomponents then they must be trip tested. The PSMT SDT considers these devicescomponents to
share some similarities in failure modes as electro-mechanical protective relays; as such there is a six year
maximum interval between mandated maintenance tasks unless PBM is applied.
When verifying the operation of the 94 and 86 relays each normally-open contact that closes to pass a trip
signal must be verified as operating correctly. Normally-open contacts that are not used to pass a trip
signal and normally-closed contacts do not have to be verified. Verification of the tripping paths is the
requirement.
New technology is also accommodated here; there are some tripping systems that have replaced the
traditional hard-wired trip circuitry with other methods of trip-signal conveyance such as fiber-optics. It is
the intent of the PSMT SDT to include this, and any other, technology that is used to convey a trip signal
from a protective relay to a circuit breaker (or other interrupting device) within this category of
equipment.
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15.4 Batteries and DC Supplies (Table 1-4)
IEEE guidelines were consulted to arrive at the maintenance activities for batteries. The following
guidelines were used: IEEE 450 (for Vented Lead-Acid batteries), IEEE 1188 (for Valve-Regulated LeadAcid batteries) and IEEE 1106 (for Nickel-Cadmium batteries).
The presentcurrently proposed NERC definition of a Protection System is “protective
o Protective relays, associated communication which respond to electrical quantities,
o communications systems, necessary for correct operation of protective functions,
o voltage and current sensing devices, providing inputs to protective relays,
o station dc supply associated with protective functions (including station batteries, battery
chargers, and dc non-battery-based dc supply), and
o control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.” The station battery is not the only component
that provides dc power to a Protection System. In the new definition for Protection
System “station batteries” are replaced with “station dc supply” to make the battery
charger and dc producing stored energy devices (that are not a battery) part of the
Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and testing
procedures that allow the owner to choose how to verify that a battery string is free of open circuits. The
term “continuity” was introduced into the standard to allow the owner to choose how to verify continuity
of a battery set by various methods, and not to limit the owner to the two methods recommended in the
IEEE standards. Continuity as used in Table 1-4 of the standard refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative terminal.
Without verifying continuity of a station battery, there is no way to determine that the station battery is
available to supply dc power to the station. An open battery string will be an unavailable power source in
the event of loss of the battery charger.
Batteries cannot be a unique population segment of a Performance-based Maintenance Program (PBM)
because there are too many variables in the electro-chemical process to completely isolate all of the
performance-changing criteria necessary for using PBM on battery systems. However, nothing precludes
the use of a PBM process for any other part of a dc supply besides the batteries themselves.
15.5 Tele-protectionAssociated communications equipment (Table 1-2)
This is also known as associated telecommunications equipment. The equipment used for tripping in a
communications assisted trip scheme is a vital piece of the trip circuit. Remote action causing a local trip
can be thought of as another parallel trip path to the trip coil that must be tested.
Besides the trip output and wiring to the trip coil(s) there is also a communications medium that must be
maintained.
Newer technologies now exist that achieve communications-assisted tripping without the conventional
wiring practices of older technology.
For example: older technologies may have included Frequency Shift Key methods. This technology
requires that guard and trip levels be maintained.
The actual tripping path(s) to the trip coil(s) may be tested as a parallel trip path within the dc control
circuitry tests.
Draft 2: April3: November 17, 2010
Page 25
Emerging technologies transfer digital information over a variety of carrier mediums that are then
interpreted locally as trip signals.
The requirements apply to the communicated signal needed for the proper operation of the protective
relay trip logic or scheme. Therefore this standard is applied to equipment used to convey both trip signals
(permissive or direct) and block signals.
It was the intent of this standard to require that a test be made of any communications-assisted trip
scheme regardless of the vintage of the technology. The essential element is that the tripping (or blocking)
occurs locally when the remote action has been asserted; or that the tripping (or blocking) occurs remotely
when the local action is asserted.
EvidenceAny evidence of operational test or documentation of measurement of signal level, reflected
power or data-error rates is neededcan fulfill the requirements.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the control
house to the circuit interrupting device in the yard. This method of tripping the circuit breaker, even
though it might be considered communications, must be maintained per the dc control circuitry
maintenance requirements.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an additional
table added for alarms. This additional table was added for clarity. This enabled the common alarm
attributes to be consolidated into a single spot and thus make it easier to read the Tables 1-1 through 1-5.
The alarms need to arrive at a site wherein a corrective action can be initiated. This could be a control
room, operations center, etc. The alarming mechanism can be a standard alarming system or an autopolling system, the only requirement is that the alarm be brought to the action-site within 24 hours. This
effectively makes manned-stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned-station now makes that monitored point eligible
for monitored status. Obviously, these same rules apply to a non-manned-station, which is that if the
monitored point has an alarm that is auto-reported to the operations center (for example) within 24 hours
then it too is considered monitored.
15.7 Examples of Evidence of Compliance
To comply with the requirements of this Standard an entity will have to document and save evidence. The
evidence can be of many different forms. The Standard Drafting Team recognizes that there are
concurrent evidence requirements of other standards that could, at times fulfill evidence requirements of
this standard.
For example: maintaining evidence for operation of Special Protection Systems could concurrently be
utilized as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus the reporting requirements that one may have to do for the misoperationmis-operation of
a Special Protection Scheme under PRC-016 could work for the activity tracking requirements under this
PRC-005-2.
Another example might be:
Draft 2: April3: November 17, 2010
Page 26
Some entities maintain records of all interruptions. These records can be concurrently utilized, if the
entity desires, as DC Trip Path verifications.
Analysis of Event Recordings can provide details that can eliminate some hands-on maintenance
activities; however, merely printing out the event report provides limited benefit of verification of specific
maintenance items.
Standardized-forms, hard or soft copy, can be created, filled out and archived. These forms can be of the
entities’ design and can be aimed at answering the specific requirements of the Standard as well as
additional requirements as needed by the entity.
Fill-in blanks, check-boxes, drop-down lists, auto-date formats, etc. can all be used as the primary action
is the maintenance activity; the secondary action is time interval; other techniques can be used to verify
that the maintenance activity was performed, such as test reports.
Other evidence of compliance might be, but is not limited to:
Prints, maintenance plans, training materials, policies, procedures, data print-outs or exhibits,
correspondence, reports, data-base records, etc.
There is the legacy method of paper trail for everything, this is acceptable. There are also paperless
systems existing and evolving that are also acceptable.
Proof of compliance should simply be the entities’ records of maintenance completed.
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Page 27
16. References
NERC/SPCTF/Relay_Maintenance_Tech_Ref_approved_by_PC.pdf
1. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J. Kumm, M.S.
Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power Delivery, Vol. 10,
No. 2, April 1995.
2. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003, 2004
and 2005,” Working Group I17 of Power System Relaying Committee of IEEE Power
Engineering Society, May 2006.
3. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System Relaying
Committee of IEEE Power Engineering Society, September 16, 1999.
4. “Transmission Protective Relay System Performance Measuring Methodology,” Working
Group I3 of Power System Relaying Committee of IEEE Power Engineering Society, January
2002.
5. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3 of
Power System Relaying Committee of IEEE Power Engineering Society, December 2006.
6. “Proposed Statistical Performance Measures for Microprocessor-Based Transmission-Line
Protective Relays, Part I - Explanation of the Statistics, and Part II - Collection and Uses of
Data,” Working Group D5 of Power System Relaying Committee of IEEE Power
Engineering Society, May 1995; Papers 96WM 016-6 PWRD and 96WM 127-1 PWRD,
1996 IEEE Power Engineering Society Winter Meeting.
7. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
8. “Use of Preventative Maintenance and System Performance Data to Optimize Scheduled
Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia Tech Protective
Relay Conference, May 1996.
PSMT SDT References
9. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams, 2003
10. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore, 2005
11. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
Draft 2: April3: November 17, 2010
Page 28
Figures
Figure 1: Typical Transmission System
For information on numbered components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
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Page 29
Figure 2: Typical Generation System
For information on numbered components, see Figure 1 & 2 Legend – Components of Protection Systems
(Return)
Draft 2: April3: November 17, 2010
Page 30
Figure 1 & 2 Legend – Components of Protection Systems
Number
Inin
Figure
Component of Protection System
Includes
Excludes
1
Protective relays which respond to
electrical quantities
All protective relays that use current and/or
voltage inputs from current & voltage sensors and
that trip the 86, 94 or trip coil.
Devices that use non-electrical methods of operation
including thermal, pressure, gas accumulation, and
vibration. Any ancillary equipment not specified in
the definition of Protection systems. Control and/or
monitoring equipment that is not a part of the
automatic tripping action of the Protection System
2
Voltage & Current Sensing Devices and
associated circuitrycurrent sensing devices
providing inputs to protective relays
The signals from the voltage & current sensing
devices for protective relays as well as the wiring
(or other medium) used to convey signal output
from the sensor to the protective relay input.
Voltage & current sensing devices that are not a part
of the Protection System, including sync-check
systems, metering systems and data acquisition
systems.
3
DC Circuitrycontrol circuitry associated
with protective functions
All control wiring (or other medium for conveying
trip signals) associated with the tripping action of
86 devices, 94 devices or trip coils (from all
parallel trip paths). This would include fiber-optic
systems that carry a trip signal as well as hardwired systems that carry trip current.
Closing circuits, SCADA circuits
4
Station dc supply
Batteries and battery chargers and any
control power system which has the
function of supplying power to the
protective relays, associated trip circuits
and trip coils.
Any power supplies that are not used to
power protective relays or their associated
trip circuits and trip coils.
5
Associated communications
systemsCommunications systems
necessary for correct operation of
protective functions
Tele-protection equipment used to convey
remote tripping action to a local trip coil
or blocking signal tospecific information,
in the trip logic (if applicable).form of
analog or digital signals, necessary for the
correct operation of protective functions.
Any communications equipment that is not
used to convey information necessary for
remote tripping action to a local trip coil or
blocking signal to the trip logic (if
applicable).correct operation of protective
functions.
(Return)
Draft 2: April,3: November 17, 2010
Page 31
Figure 3: Requirements Flowchart
Requirements
Flowchart
Start
PRC-005-2
Each GO, DP, & TO
shall establish a
maintenance
program [R1]
Note: GO, DP, & TO
may use one or
multiple programs
Performance
Based
Time Based
Decide if using Time Based, Condition
Baesd, and/or Performance Based
program
◊
◊
Condition Based
◊
Ensure
components
have necessary
monitoring [R2]
Separate components into
appropriate families of 60 or more
Maintain components for each
segment per Table One until at least
30 components have been tested
Analyze data to determine
appropriate interval for segment(s)
[R3]
Perform maintenance activities from
Table One for each segment with interval
from analysis above and collect data for
future analysis
[R3, R4.4.2]
◊
Maintain components
per Table One
Intervals and
Activities [R4.4.1]
◊
◊
Implement corrective
actions as needed [R4]
End
Draft 2: April3: November 17, 2010
Page 32
Collect countable events from
maintenance and failures
Analyze data from maintenance of
last 30 components and/or last year
to verify countable events below 4%
Adjust maintenance interval to keep
countable events below 4%
[R3]
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in Section 10
of the paper. As an example, Figure A-1 shows protection for a critical transmission line by carrier
blocking directional comparison pilot relaying. The goal is to verify the ability of the entire two-terminal
pilot protection scheme to protect for line faults, and to avoid over-tripping for faults external to the
transmission line zone of protection bounded by the current transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays themselves,
the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of internal
electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report the
state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of other
relays, meters, or DFRs. The other readings may be from redundant relaying or measurement
systems or they may be derived from values in other protection zones. Comparison with other
such readings to within required relaying accuracy verifies Voltage & Current Sensing
Draft 2: April3: November 17, 2010
Page 33
Devices, wiring, and analog signal input processing of the relays. One effective way to do
this is to utilize the relay metered values directly in SCADA, where they can be compared
with other references or state estimator values.
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the protection
system, so each carrier set has a connected or integrated automatic checkback test unit. The
automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation or
noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the protection
system elements that experience tells us are the most prone to fail. But, does this comprise a complete
verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded regions
show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
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Page 34
2. Within each line relay, all the microprocessors that participate in the trip decision have been
verified by internal monitoring. However, the trip circuit is actually energized by the contacts
of a small telephone-type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a fault.
3. The check-back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying circuit
or the carrier receiver output state. These connections include microprocessor I/O ports,
electronic driver circuits, wiring, and sometimes telephone-type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but this
does not confirm that the state change indication is correct when the breaker or switch opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified maximum time
interval between trip tests. Clearing of naturally-occurring faults are demonstrations of operation that
reset the time interval clock for testing of each breaker tripped in this way. If faults do not occur, manual
tripping of the breaker through the relay trip output via data communications to the relay microprocessor
meets the requirement for periodic testing.
PRC-005 does not address breaker maintenance, and its protection system test requirements can be met by
energizing the trip circuit in a test mode (breaker disconnected) through the relay microprocessor. This
can be done via a front-panel button command to the relay logic, or application of a simulated fault with a
relay test set. However, utilities have found that breakers often show problems during protection system
tests. It is recommended that protection system verification include periodic testing of the actual tripping
of connected circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and that the
other relay demonstrate reception of that blocking carrier. This can be observed from relay or DFR
records during naturally occurring faults, or by a manual test. If the checkback test sequence were
incorporated in the relay logic, the carrier sets and carrier channel are then included in the overlapping
segments monitored by the two relays, and the monitoring gap is completely eliminated.
Draft 2: April3: November 17, 2010
Page 35
Appendix B — Protection System Maintenance Standard
Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Mark Lukas
ComEd
Merle E. Ashton
Tri-State G&T
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
Bob Bentert
Florida Power & Light Company
John Ciufo
Hydro One Inc
Sam Francis
Oncor
Carol A Gerou
Midwest Reliability Organization
William Shultz
Southern Company Generation
Mark Peterson
Great River Energy
William Shultz
Southern Company Generation
Leonard Swanson, Jr
National Grid USA
Eric A Udren
Quanta Technology
Russell C Hardison
Tennessee Valley Authority
Philip B Winston
Georgia PowerSouthern Company
Transmission
David Harper
NRG Texas Maintenance Services
John A Zipp
ITC Holdings
Draft 2: April3: November 17, 2010
Page 36
Standard PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
A. Introduction
1.
Title:
Transmission and Generation Protection System Maintenance and Testing
2.
Number:
PRC-005-1
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained and tested.
4.
Applicability
4.1. Transmission Owner.
4.2. Generator Owner.
4.3. Distribution Provider that owns a transmission Protection System.
5.
Effective Date:
May 1, 2006
B. Requirements
R1.
R2.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall provide
documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Reliability Organization on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1.
Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained.
C. Measures
M1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System that affects the
reliability of the BES, shall have an associated Protection System maintenance and testing
program as defined in Requirement 1.
M2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System that affects the
reliability of the BES, shall have evidence it provided documentation of its associated
Protection System maintenance and testing program and the implementation of its program as
defined in Requirement 2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization.
Ad o p te d b y Bo a rd o f Tru s te e s : Fe b ru a ry 7, 2006
Effective Date: May 1, 2006
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Standard PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation Protection System,
shall retain evidence of the implementation of its Protection System maintenance and
testing program for three years.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation Protection System,
shall each demonstrate compliance through self-certification or audit (periodic, as part of
targeted monitoring or initiated by complaint or event), as determined by the Compliance
Monitor.
2.
Levels of Non-Compliance
2.1. Level 1: Documentation of the maintenance and testing program provided was
incomplete as required in R1, but records indicate maintenance and testing did occur
within the identified intervals for the portions of the program that were documented.
2.2. Level 2: Documentation of the maintenance and testing program provided was complete
as required in R1, but records indicate that maintenance and testing did not occur within
the defined intervals.
2.3. Level 3: Documentation of the maintenance and testing program provided was
incomplete, and records indicate implementation of the documented portions of the
maintenance and testing program did not occur within the identified intervals.
2.4. Level 4: Documentation of the maintenance and testing program, or its implementation,
was not provided.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
Ad o p te d b y Bo a rd o f Tru s te e s : Fe b ru a ry 7, 2006
Effective Date: May 1, 2006
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S ta n d a rd P RC-008-0 — Un d e rfre q u e n c y Lo a d S h e d d in g Eq u ip m e n t Ma in te n a n c e P ro g ra m s
A. Introduction
1.
Title:
Implementation and Documentation of Underfrequency Load Shedding
Equipment Maintenance Program
2.
Number:
3.
Purpose:
Provide last resort system preservation measures by implementing an Under
Frequency Load Shedding (UFLS) program.
4.
Applicability:
PRC-008-0
4.1. Transmission Owner required by its Regional Reliability Organization to have a UFLS
program
4.2. Distribution Provider required by its Regional Reliability Organization to have a UFLS
program
5.
Effective Date: April 1, 2005
B. Requirements
R1.
The Transmission Owner and Distribution Provider with a UFLS program (as required by its
Regional Reliability Organization) shall have a UFLS equipment maintenance and testing
program in place. This UFLS equipment maintenance and testing program shall include UFLS
equipment identification, the schedule for UFLS equipment testing, and the schedule for UFLS
equipment maintenance.
R2.
The Transmission Owner and Distribution Provider with a UFLS program (as required by its
Regional Reliability Organization) shall implement its UFLS equipment maintenance and
testing program and shall provide UFLS maintenance and testing program results to its
Regional Reliability Organization and NERC on request (within 30 calendar days).
C. Measures
M1. Each Transmission Owner’s and Distribution Provider’s UFLS equipment maintenance and
testing program contains the elements specified in Reliability Standard PRC-007-0_R1.
M2. Each Transmission Owner and Distribution Provider shall have evidence that it provided the
results of its UFLS equipment maintenance and testing program’s implementation to its
Regional Reliability Organization and NERC on request (within 30 calendar days).
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Timeframe
On request (within 30 calendar days).
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
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S ta n d a rd P RC-008-0 — Un d e rfre q u e n c y Lo a d S h e d d in g Eq u ip m e n t Ma in te n a n c e P ro g ra m s
2.
Levels of Non-Compliance
2.1. Level 1: Documentation of the maintenance and testing program was incomplete, but
records indicate implementation was on schedule.
2.2. Level 2: Complete documentation of the maintenance and testing program was provided,
but records indicate that implementation was not on schedule.
2.3. Level 3: Documentation of the maintenance and testing program was incomplete, and
records indicate implementation was not on schedule.
2.4. Level 4: Documentation of the maintenance and testing program, or its implementation
was not provided.
E. Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
2 of 2
S ta n d a rd P RC-011-0 — UVLS S ys te m Ma inte na n c e a n d Te s tin g
A. Introduction
1.
Title:
Undervoltage Load Shedding System Maintenance and Testing
2.
Number:
PRC-011-0
3.
Purpose:
Provide system preservation measures in an attempt to prevent system voltage
collapse or voltage instability by implementing an Undervoltage Load Shedding (UVLS)
program.
4.
Applicability:
4.1. Transmission Owner that owns a UVLS system
4.2. Distribution Provider that owns a UVLS system
5.
Effective Date:
April 1, 2005
B. Requirements
R1.
The Transmission Owner and Distribution Provider that owns a UVLS system shall have a
UVLS equipment maintenance and testing program in place. This program shall include:
R1.1.
The UVLS system identification which shall include but is not limited to:
R1.1.1. Relays.
R1.1.2. Instrument transformers.
R1.1.3. Communications systems, where appropriate.
R1.1.4. Batteries.
R2.
R1.2.
Documentation of maintenance and testing intervals and their basis.
R1.3.
Summary of testing procedure.
R1.4.
Schedule for system testing.
R1.5.
Schedule for system maintenance.
R1.6.
Date last tested/maintained.
The Transmission Owner and Distribution Provider that owns a UVLS system shall provide
documentation of its UVLS equipment maintenance and testing program and the
implementation of that UVLS equipment maintenance and testing program to its Regional
Reliability Organization and NERC on request (within 30 calendar days).
C. Measures
M1. Each Transmission Owner and Distribution Provider that owns a UVLS system shall have
documentation that its UVLS equipment maintenance and testing program conforms with
Reliability Standard PRC-011-0_R1.
M2. Each Transmission Owner and Distribution Provider that owns a UVLS system shall have
evidence it provided documentation of its UVLS equipment maintenance and testing program
and the implementation of that UVLS equipment maintenance and testing program as specified
in Reliability Standard PRC-011-0_R2.
D. Compliance
1.
Compliance Monitoring Process
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
1 of 2
S ta n d a rd P RC-011-0 — UVLS S ys te m Ma inte na n c e a n d Te s tin g
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Timeframe
On request (30 calendar days).
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Documentation of the maintenance and testing program was incomplete, but
records indicate implementation was on schedule.
2.2. Level 2:
Documentation of the maintenance and testing program was incomplete, but
records indicate implementation was on schedule.
2.3. Level 3:
Documentation of the maintenance and testing program was incomplete, and
records indicate implementation was not on schedule.
2.4. Level 4:
Documentation of the maintenance and testing program, or its
implementation, was not provided.
E. Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
2 of 2
S ta n d a rd P RC-017-0 — S p e c ia l P rote c tio n S ys te m Main te n a n c e a n d Te s tin g
A. Introduction
1.
Title:
Special Protection System Maintenance and Testing
2.
Number:
PRC-017-0
3.
Purpose:
To ensure that all Special Protection Systems (SPS) are properly designed, meet
performance requirements, and are coordinated with other protection systems. To ensure that
maintenance and testing programs are developed and misoperations are analyzed and corrected.
4.
Applicability:
4.1. Transmission Owner that owns an SPS
4.2. Generator Owner that owns an SPS
4.3. Distribution Provider that owns an SPS
5.
Effective Date:
April 1, 2005
B. Requirements
R1.
The Transmission Owner, Generator Owner, and Distribution Provider that owns an SPS shall
have a system maintenance and testing program(s) in place. The program(s) shall include:
R1.1.
SPS identification shall include but is not limited to:
R1.1.1. Relays.
R1.1.2. Instrument transformers.
R1.1.3. Communications systems, where appropriate.
R1.1.4. Batteries.
R2.
R1.2.
Documentation of maintenance and testing intervals and their basis.
R1.3.
Summary of testing procedure.
R1.4.
Schedule for system testing.
R1.5.
Schedule for system maintenance.
R1.6.
Date last tested/maintained.
The Transmission Owner, Generator Owner, and Distribution Provider that owns an SPS shall
provide documentation of the program and its implementation to the appropriate Regional
Reliability Organizations and NERC on request (within 30 calendar days).
C. Measures
M1. The Transmission Owner, Generator Owner, and Distribution Provider that owns an SPS shall
have a system maintenance and testing program(s) in place that includes all items in Reliability
Standard PRC-017-0_R1.
M2. The Transmission Owner, Generator Owner, and Distribution Provider that owns an SPS shall
have evidence it provided documentation of the program and its implementation to the
appropriate Regional Reliability Organizations and NERC on request (within 30 calendar
days).
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
1 of 2
S ta n d a rd P RC-017-0 — S p e c ia l P rote c tio n S ys te m Main te n a n c e a n d Te s tin g
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization. Each Region shall report
compliance and violations to NERC via the NERC Compliance Reporting process.
Timeframe:
On request (30 calendar days.)
1.2. Compliance Monitoring Period and Reset Timeframe
Compliance Monitor: Regional Reliability Organization.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Documentation of the maintenance and testing program was incomplete, but
records indicate implementation was on schedule.
2.2. Level 2:
Complete documentation of the maintenance and testing program was
provided, but records indicate that implementation was not on schedule.
2.3. Level 3:
Documentation of the maintenance and testing program was incomplete, and
records indicate implementation was not on schedule.
2.4. Level 4:
Documentation of the maintenance and testing program, or its
implementation, was not provided.
E. Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
2 of 2
Standards Announcement
Existing Ballot Window Re-opened
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-17: Protection System Maintenance and Testing
A successive ballot for the proposed standard, PRC-005-2 — Protection System Maintenance, and a concurrent,
non-binding poll on revised VRFs and VSLs are being reopened until a quorum is reached.
Instructions
For those members who have not cast a ballot during this voting window, your vote is needed to achieve
quorum since the votes and comments from the last ballot will not be carried over. In addition, members of the
ballot pool will need to cast a new opinion on the revised VRFs and VSLs. The drafting team will consider all
comments (those submitted with a comment form, and those submitted with a ballot or with the non-binding
poll) and will determine whether to make additional changes to the standard and its implementation plan.
During the successive ballot window, members of the ballot pool associated with this project may log in and
submit their votes from the following page: https://standards.nerc.net/CurrentBallots.aspx
Documents for this project, including an off-line unofficial copy of the questions listed in the comment forms
are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Note that PRC-005-2 reflects the merging of the following standards into a single standard, making it
impractical to post a “redline” of proposed PRC-005-2 that shows the changes to the last balloted version of the
standard.
• PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
• PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
• PRC-011-0 — UVLS System Maintenance and Testing
• PRC-017-0 — Special Protection System Maintenance and Testing
The last approved versions of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 have been posted on the
project’s Web page for easy reference at:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Next Steps
The drafting team will consider all comments (those submitted with a comment form, and those submitted with
a ballot or with the non-binding poll) and will determine whether to make additional changes to the standard
and its implementation plan.
Project Background
The proposed PRC-005-2 – Protection System Maintenance standard addresses FERC directives from FERC
Order 693, as well as issues identified by stakeholders. In accordance with the FERC directives, this draft
standard establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a conditionbased maintenance program, where the hands-on maintenance intervals are adjusted to reflect the known and
reported condition of the relevant devices. For a performance-based maintenance program, it ascertains where
the hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant devices.
Applicability of Standards in Project
Transmission Owners
Generator Owners
Distribution Providers
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Successive Ballot Window Open
December 10 – December 19, 2010
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-17: Protection System Maintenance and Testing
A successive ballot for the proposed standard, PRC-005-2 — Protection System Maintenance, and a concurrent,
non-binding poll on revised VRFs and VSLs are being conducted through 8:00 pm Eastern on Sunday,
December 19.
Instructions
All members of the ballot pool must cast a new ballot since the votes and comments from the last ballot will not
be carried over. In addition, members of the ballot pool will need to cast a new opinion on the revised VRFs
and VSLs. The drafting team will consider all comments (those submitted with a comment form, and those
submitted with a ballot or with the non-binding poll) and will determine whether to make additional changes to
the standard and its implementation plan.
During the successive ballot window, members of the ballot pool associated with this project may log in and
submit their votes from the following page: https://standards.nerc.net/CurrentBallots.aspx
Documents for this project, including an off-line unofficial copy of the questions listed in the comment forms
are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Note that PRC-005-2 reflects the merging of the following standards into a single standard, making it
impractical to post a “redline” of proposed PRC-005-2 that shows the changes to the last balloted version of the
standard.
• PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
• PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
• PRC-011-0 — UVLS System Maintenance and Testing
• PRC-017-0 — Special Protection System Maintenance and Testing
The last approved versions of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 have been posted on the
project’s Web page for easy reference at:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Next Steps – Successive Ballot and New, Non-binding Poll of VRFs and VSLs
The drafting team will consider all comments (those submitted with a comment form, and those submitted with
a ballot or with the non-binding poll) and will determine whether to make additional changes to the standard
and its implementation plan.
Project Background
The proposed PRC-005-2 – Protection System Maintenance standard addresses FERC directives from FERC
Order 693, as well as issues identified by stakeholders. In accordance with the FERC directives, this draft
standard establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a conditionbased maintenance program, where the hands-on maintenance intervals are adjusted to reflect the known and
reported condition of the relevant devices. For a performance-based maintenance program, it ascertains where
the hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant devices.
Applicability of Standards in Project
Transmission Owners
Generator Owners
Distribution Providers
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate. For more information or assistance, please contact Monica Benson at
[email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Successive Formal Comment Period Open
November 17-December 17, 2010
Now available at: http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-
17.html
Project 2007-17: Protection System Maintenance and Testing
A 30-day formal comment period for the proposed standard, PRC-005-2 — Protection System Maintenance,
and its associated implementation plan and reference documents is now open until 8 p.m. Eastern on
December17, 2010.
Instructions
Please use this electronic form to submit comments on PRC-005-2 and its associated implementation plan and
reference documents. If you experience any difficulties in using the electronic form, please contact Monica
Benson at [email protected].
Documents for this project, including an off-line unofficial copy of the questions listed in the comment forms
are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Note that PRC-005-2 reflects the merging of the following standards into a single standard, making it
impractical to post a “redline” of proposed PRC-005-2 that shows the changes to the last balloted version of the
standard.
• PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
• PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
• PRC-011-0 — UVLS System Maintenance and Testing
• PRC-017-0 — Special Protection System Maintenance and Testing
The last approved versions of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 have been posted on the
project’s web page for easy reference at:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Next Steps – Successive Ballot and New, Non-binding Poll of VRFs and VSLs
During the last 10 days of the 30-day formal comment period, a successive ballot will be conducted for 10 days.
All members of the ballot pool must cast a new ballot since the votes and comments from the last ballot will not
be carried over. In addition, members of the ballot pool will need to cast a new opinion on the revised VRFs and
VSLs. The drafting team will consider all comments (those submitted with a comment form, and those
submitted with a ballot or with the non-binding poll) and will determine whether to make additional changes to
the standard and its implementation plan.
Project Background
The proposed PRC-005-2 – Protection System Maintenance standard addresses FERC directives from FERC
Order 693, as well as issues identified by stakeholders. In accordance with the FERC directives, this draft
standard establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a condition-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect the known and reported
condition of the relevant devices. For a performance-based maintenance program, it ascertains where the
hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant devices.
Applicability of Standards in Project
Transmission Owners
Generator Owners
Distribution Providers
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate. For more information or assistance, please contact Monica Benson at
[email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Successive Ballot Results
Project 2007-17 – Protection System Maintenance and Testing
Now available at: https://standards.nerc.net/Ballots.aspx
Successive Ballot and Non-binding Poll Results for PRC-005-2 – Protection System Maintenance
A successive ballot for the proposed standard, PRC-005-2 — Protection System Maintenance, ended on
December 20, 2010. A non-binding poll of the proposed Violation Risk Factors (VRFs) and Violation Severity
Levels (VSLs) also ended on December 20, 2010. Voting and poll statistics are listed below, and the Ballot
Results Web page provides a link to the detailed results.
Ballot for Standard:
• Quorum: 79.88 %
• Approval: 44.65%
Non-binding Poll for VRFs and VSLs:
• Quorum: 78.06 %
• Supportive Opinion: 52.73%
Next Steps – Successive Ballot and Non-binding Poll of VRFs and VSLs
The drafting team will consider all comments (those submitted with a comment form, and those submitted with
a ballot or with the non-binding poll) and will determine whether to make additional changes to the standard
and its implementation plan.
Project Background
The proposed PRC-005-2 – Protection System Maintenance standard addresses FERC directives from FERC
Order 693, as well as issues identified by stakeholders. In accordance with the FERC directives, this draft
standard establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a conditionbased maintenance program, where the hands-on maintenance intervals are adjusted to reflect the known and
reported condition of the relevant devices. For a performance-based maintenance program, it ascertains where
the hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant devices.
More information can be found on the project page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Ballot Criteria
Approval requires both (1) a quorum, which is established by at least 75% of the members of the ballot pool
submitting either an affirmative vote, a negative vote, or an abstention, and (2) a two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and
negative votes, excluding abstentions and non-responses.
Non-Binding Polls
Non-binding polls of VRFs and VSLs are conducted to provide the drafting team with constructive feedback
on proposed VRFs and VSLs and also to provide information to assist in developing a recommendation for
Board of Trustees approval.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate. For more information or assistance, please contact Monica Benson at
[email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Project 2007-17 Protection System Maintenance and Testing (PRC-005Ballot Name:
2)_sb_in
Password
Ballot Period: 12/10/2010 - 12/20/2010
Log in
Ballot Type: Initial
Register
Total # Votes: 258
Total Ballot Pool: 323
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Quorum: 79.88 % The Quorum has been reached
Weighted Segment
44.65 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
89
9
71
24
68
38
0
11
6
7
323
#
Votes
1
0.2
1
1
1
1
0
0.5
0.3
0.3
6.3
#
Votes
Fraction
30
1
23
9
19
5
0
3
3
3
96
Negative
Fraction
0.429
0.1
0.404
0.409
0.404
0.167
0
0.3
0.3
0.3
2.813
Abstain
No
# Votes Vote
40
1
34
13
28
25
0
2
0
0
143
0.571
0.1
0.596
0.591
0.596
0.833
0
0.2
0
0
3.487
6
2
4
0
5
0
0
1
1
0
19
13
5
10
2
16
8
0
5
2
4
65
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Robert D Smith
John Bussman
Scott Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=59525e0b-1ffa-4078-b13a-43b17ac04f01[1/13/2011 10:51:19 AM]
Ballot
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Comments
View
View
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnesota Power, Inc.
National Grid
Nebraska Public Power District
New York Power Authority
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
John J. Moraski
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Ronald D. Schellberg
Michael Moltane
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
Doug Bantam
Robert Ganley
Martyn Turner
Joe D Petaski
Ernest Hahn
Terry Harbour
Randi Woodward
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
David Thorne
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Chad Bowman
Catherine Koch
Tim Kelley
Robert Kondziolka
https://standards.nerc.net/BallotResults.aspx?BallotGUID=59525e0b-1ffa-4078-b13a-43b17ac04f01[1/13/2011 10:51:19 AM]
Affirmative
Negative
View
Negative
Negative
View
View
Affirmative
Negative
Negative
Negative
View
View
View
Negative
Negative
Affirmative
View
View
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
View
View
View
View
View
Negative
View
Affirmative
Negative
Negative
Negative
Affirmative
View
View
View
Affirmative
Negative
View
Abstain
Negative
Abstain
Negative
Negative
View
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
View
Negative
View
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Santee Cooper
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Arizona Public Service Co.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Leesburg
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V. Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Faramarz Amjadi
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Thomas R. Glock
James V. Petrella
Pat G. Harrington
Rebecca Berdahl
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C. Parent
Steven Grego
https://standards.nerc.net/BallotResults.aspx?BallotGUID=59525e0b-1ffa-4078-b13a-43b17ac04f01[1/13/2011 10:51:19 AM]
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
View
View
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
View
View
View
View
Abstain
Negative
Negative
View
View
Negative
View
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salem Electric
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Tri-State G & T Association, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
Y-W Electric Association, Inc.
AEP Service Corp.
Amerenue
APS
Avista Corp.
Black Hills Corp
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David T. Anderson
Ballard Keith Mutters
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Anthony Schacher
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
David Schiada
Jeff Nelson
Ronald L Donahey
Janelle Marriott
James R. Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
View
View
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
Abstain
Negative
Negative
Negative
Affirmative
Negative
View
View
View
View
View
View
View
Timothy Beyrle
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Christopher Plante
Joseph G. DePoorter
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
John D. Martinsen
Affirmative
View
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
James A Ziebarth
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
George Tatar
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
Affirmative
Negative
Affirmative
View
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View
View
View
View
View
View
View
Negative
Negative
View
Negative
Affirmative
Affirmative
Affirmative
Negative
View
Negative
Abstain
Negative
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Entergy Corporation
FirstEnergy Solutions
Florida Municipal Power Agency
Green Country Energy
Horizon Wind Energy
Indeck Energy Services, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
New Harquahala Generating Co. LLC
New York Power Authority
Northern Indiana Public Service Co.
Otter Tail Power Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Public Utility District No. 1 of Lewis County
Reedy Creek Energy Services
RRI Energy
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Centralia Generation, LLC
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Amir Y Hammad
James B Lewis
Bob Essex
Mike Garton
Robert Smith
Dan Roethemeyer
Stephen Ricker
Negative
Affirmative
Doug Ramey
Affirmative
Kenneth Parker
Stanley M Jaskot
Kenneth Dresner
David Schumann
Greg Froehling
Brent Hebert
Rex A Roehl
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Daniel Duff
Dennis Florom
Charlie Martin
Mike Laney
Mark Aikens
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
David Gordon
Nicholas Q Hayes
Gerald Mannarino
Michael K Wilkerson
Stacie Hebert
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A Heimbach
Wayne Lewis
Jerzy A Slusarz
Steven Grega
Bernie Budnik
Thomas J. Bradish
Bethany Hunter
Glen Reeves
Daniel Baerman
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Richard Jones
Jerry W Johnson
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Joanna Luong-Tran
Barry Ingold
Melissa Kurtz
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
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Negative
Negative
Affirmative
Negative
View
View
View
View
View
View
View
Affirmative
Negative
Affirmative
View
Negative
View
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Negative
View
View
View
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
Entergy Services, Inc.
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Energy
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
OTP Wholesale Marketing
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Ascendant Energy Services, LLC
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
SPS Consulting Group Inc.
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council
Terri F Benoit
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daryn Barker
Brad Jones
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
David Ried
Bruce Glorvigen
Carol Ballantine
John T Sturgeon
James D. Hebson
Hugh A. Owen
Trent Carlson
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
View
View
View
View
View
Affirmative
Negative
Affirmative
View
View
Negative
Negative
View
View
Negative
Negative
View
Affirmative
Negative
Negative
View
Negative
Negative
Affirmative
View
Negative
John Stonebarger
David F. Lemmons
Negative
James A Maenner
Merle Ashton
Negative
Roger C Zaklukiewicz
Affirmative
Kristina M. Loudermilk
Raymond Tran
Jim D. Cyrulewski
Affirmative
Margaret Ryan
Abstain
Peggy Abbadini
Jim R Stanton
Negative
Brian Evans-Mongeon
Affirmative
Terry Volkmann
William Mitchell Chamberlain
Donald E. Nelson
View
View
Affirmative
Diane J. Barney
Jerome Murray
Philip Riley
Ric Campbell
Linda Campbell
Dan R. Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B Edge
Louise McCarren
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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NERC Standards
Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
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Non-binding Poll Results
Non-binding Poll Project 2007-17 Protection System Maintenance - Non-binding Poll
Name: for VRFs and VSLs_nb2 _in
Poll Period: 12/10/2010 - 12/20/2010
Total # Opinions: 274
Total Ballot Pool: 351
78% of those who registered to participate provided an opinion; 53% of
Summary: those who provided an opinion indicated support for the VRFs and VSLs that
were proposed.
Individual Ballot Pool Results
Segment
Organization
Member
Opinions
Affirmative
Comments
1
Allegheny Power
Rodney Phillips
1
Ameren Services
Kirit S. Shah
Negative
View
1
American Electric Power
Paul B. Johnson
Negative
View
1
American Transmission Company,
Jason Shaver
LLC
1
Arizona Public Service Co.
Robert D Smith
Abstain
1
Associated Electric Cooperative,
Inc.
John Bussman
Abstain
1
Avista Corp.
Scott Kinney
1
Baltimore Gas & Electric Company John J. Moraski
1
BC Transmission Corporation
Gordon Rawlings
1
Beaches Energy Services
Joseph S.
Stonecipher
1
Black Hills Corp
Eric Egge
1
Bonneville Power Administration
Donald S. Watkins
1
CenterPoint Energy
Paul Rocha
1
Central Maine Power Company
Brian Conroy
Affirmative
Affirmative
Abstain
View
Affirmative
Abstain
Negative
1
1
City of Vero Beach
Randall McCamish
1
City Utilities of Springfield,
Missouri
Jeff Knottek
Affirmative
1
Clark Public Utilities
Jack Stamper
Affirmative
1
Cleco Power LLC
Danny McDaniel
Negative
1
Colorado Springs Utilities
Paul Morland
Negative
1
Commonwealth Edison Co.
Daniel Brotzman
1
Consolidated Edison Co. of New
York
Christopher L de
Graffenried
Negative
1
Dairyland Power Coop.
Robert W. Roddy
Abstain
1
Dayton Power & Light Co.
Hertzel Shamash
Affirmative
1
Deseret Power
James Tucker
1
Dominion Virginia Power
John K Loftis
Negative
1
Duke Energy Carolina
Douglas E. Hils
Negative
1
East Kentucky Power Coop.
George S. Carruba
Affirmative
1
Empire District Electric Co.
Ralph Frederick
Meyer
Affirmative
1
Entergy Corporation
George R. Bartlett
1
FirstEnergy Energy Delivery
Robert Martinko
Negative
1
Florida Keys Electric Cooperative
Assoc.
Dennis Minton
Negative
1
Gainesville Regional Utilities
Luther E. Fair
Affirmative
1
GDS Associates, Inc.
Claudiu Cadar
Abstain
1
Georgia Transmission Corporation Harold Taylor, II
1
Great River Energy
Gordon Pietsch
1
Hydro One Networks, Inc.
Ajay Garg
1
Idaho Power Company
Ronald D. Schellberg
View
View
Abstain
View
Affirmative
Negative
View
Affirmative
2
1
International Transmission
Company Holdings Corp
Michael Moltane
1
Kansas City Power & Light Co.
Michael Gammon
1
Keys Energy Services
Stan T. Rzad
Negative
1
Lake Worth Utilities
Walt Gill
Negative
View
1
Lakeland Electric
Larry E Watt
Negative
View
1
Lee County Electric Cooperative
John W Delucca
1
Lincoln Electric System
Doug Bantam
Affirmative
1
Long Island Power Authority
Robert Ganley
Negative
1
Lower Colorado River Authority
Martyn Turner
Affirmative
1
Manitoba Hydro
Joe D Petaski
Negative
1
Metropolitan Water District of
Southern California
Ernest Hahn
Abstain
1
MidAmerican Energy Co.
Terry Harbour
1
National Grid
Saurabh Saksena
1
Nebraska Public Power District
Richard L. Koch
1
New York Power Authority
Arnold J. Schuff
1
Northeast Utilities
David H. Boguslawski
1
NorthWestern Energy
John Canavan
Abstain
1
Ohio Valley Electric Corp.
Robert Mattey
Negative
1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
Abstain
1
Omaha Public Power District
Douglas G
Peterchuck
Abstain
1
Oncor Electric Delivery
Michael T. Quinn
1
Orlando Utilities Commission
Brad Chase
1
Otter Tail Power Company
Lawrence R. Larson
1
Pacific Gas and Electric Company
Chifong L. Thomas
Abstain
Affirmative
Abstain
View
Negative
Negative
View
Affirmative
Negative
View
Affirmative
Negative
3
1
PacifiCorp
Mark Sampson
1
PECO Energy
Ronald Schloendorn
1
Platte River Power Authority
John C. Collins
Affirmative
1
Portland General Electric Co.
Frank F. Afranji
Affirmative
1
Potomac Electric Power Co.
David Thorne
Affirmative
1
PowerSouth Energy Cooperative
Larry D. Avery
Negative
1
PPL Electric Utilities Corp.
Brenda L Truhe
Abstain
1
Public Service Company of New
Mexico
Laurie Williams
Abstain
1
Public Service Electric and Gas Co. Kenneth D. Brown
1
Public Utility District No. 1 of
Chelan County
Chad Bowman
1
Puget Sound Energy, Inc.
Catherine Koch
Abstain
1
Sacramento Municipal Utility
District
Tim Kelley
Abstain
1
Salt River Project
Robert Kondziolka
Affirmative
1
Santee Cooper
Terry L. Blackwell
Negative
1
SCE&G
Henry Delk, Jr.
1
Seattle City Light
Pawel Krupa
1
South Texas Electric Cooperative
Richard McLeon
Affirmative
1
Southern California Edison Co.
Dana Cabbell
Affirmative
1
Southern Company Services, Inc.
Horace Stephen
Williamson
1
Southern Illinois Power Coop.
William G. Hutchison
1
Southwest Transmission
Cooperative, Inc.
James L. Jones
Affirmative
1
Southwestern Power
Administration
Gary W Cox
Affirmative
Negative
Abstain
Abstain
Negative
Negative
View
4
1
Sunflower Electric Power
Corporation
Noman Lee Williams
1
Tennessee Valley Authority
Larry Akens
1
Tri-State G & T Association, Inc.
Keith V. Carman
1
Tucson Electric Power Co.
John Tolo
1
United Illuminating Co.
Jonathan Appelbaum
1
Westar Energy
Allen Klassen
1
Western Area Power
Administration
Brandy A Dunn
1
Xcel Energy, Inc.
Gregory L Pieper
2
Alberta Electric System Operator
Jason L. Murray
2
BC Transmission Corporation
Faramarz Amjadi
2
Electric Reliability Council of Texas,
Chuck B Manning
Inc.
2
Independent Electricity System
Operator
Kim Warren
2
ISO New England, Inc.
Kathleen Goodman
2
Midwest ISO, Inc.
Jason L Marshall
2
New York Independent System
Operator
Gregory Campoli
2
PJM Interconnection, L.L.C.
Tom Bowe
Abstain
2
Southwest Power Pool
Charles H Yeung
Abstain
3
Alabama Power Company
Richard J. Mandes
3
Allegheny Power
Bob Reeping
3
Ameren Services
Mark Peters
3
American Electric Power
Raj Rana
3
Arizona Public Service Co.
Thomas R. Glock
3
Atlantic City Electric Company
James V. Petrella
Negative
Abstain
Affirmative
Affirmative
Abstain
Negative
Negative
View
Negative
View
Negative
View
Affirmative
Negative
View
Affirmative
5
3
BC Hydro and Power Authority
Pat G. Harrington
Abstain
3
Blachly-Lane Electric Co-op
Bud Tracy
3
Bonneville Power Administration
Rebecca Berdahl
3
Central Electric Cooperative, Inc.
(Redmond, Oregon)
Dave Markham
Affirmative
3
Central Lincoln PUD
Steve Alexanderson
Affirmative
3
City of Bartow, Florida
Matt Culverhouse
3
City of Clewiston
Lynne Mila
3
City of Farmington
Linda R. Jacobson
3
City of Green Cove Springs
Gregg R Griffin
3
City of Leesburg
Phil Janik
3
Clearwater Power Co.
Dave Hagen
3
Cleco Utility Group
Bryan Y Harper
Negative
3
ComEd
Bruce Krawczyk
Negative
3
Consolidated Edison Co. of New
York
Peter T Yost
3
Consumers Energy
David A. Lapinski
3
Consumers Power Inc.
Roman Gillen
Affirmative
3
Coos-Curry Electric Cooperative,
Inc
Roger Meader
Affirmative
3
Cowlitz County PUD
Russell A Noble
Affirmative
3
Delmarva Power & Light Co.
Michael R. Mayer
Affirmative
3
Detroit Edison Company
Kent Kujala
Affirmative
3
Dominion Resources Services
Michael F Gildea
3
Douglas Electric Cooperative
Dave Sabala
3
Duke Energy Carolina
Henry Ernst-Jr
3
East Kentucky Power Coop.
Sally Witt
Affirmative
Abstain
Abstain
Negative
Affirmative
Negative
View
Affirmative
Abstain
Negative
Negative
View
Affirmative
Negative
Affirmative
6
3
Entergy
Joel T Plessinger
Abstain
3
Fall River Rural Electric
Cooperative
Bryan Case
3
FirstEnergy Solutions
Kevin Querry
Negative
3
Florida Power Corporation
Lee Schuster
Affirmative
3
Gainesville Regional Utilities
Kenneth Simmons
Negative
3
Georgia Power Company
Anthony L Wilson
Negative
3
Georgia System Operations
Corporation
R Scott S. BarfieldMcGinnis
3
Great River Energy
Sam Kokkinen
3
Gulf Power Company
Gwen S Frazier
3
Hydro One Networks, Inc.
Michael D. Penstone
3
JEA
Garry Baker
3
Kansas City Power & Light Co.
Charles Locke
Affirmative
3
Kissimmee Utility Authority
Gregory David
Woessner
Negative
3
Lakeland Electric
Mace Hunter
3
Lane Electric Cooperative, Inc.
Rick Crinklaw
Affirmative
3
Lincoln Electric Cooperative, Inc.
Michael Henry
Affirmative
3
Lincoln Electric System
Bruce Merrill
Affirmative
3
Los Angeles Department of Water
Kenneth Silver
& Power
3
Lost River Electric Cooperative
Richard Reynolds
3
Louisville Gas and Electric Co.
Charles A. Freibert
3
Manitoba Hydro
Greg C. Parent
Negative
3
MEAG Power
Steven Grego
Affirmative
3
MidAmerican Energy Co.
Thomas C. Mielnik
Affirmative
View
View
Affirmative
Negative
View
Abstain
Affirmative
View
Negative
7
3
Mississippi Power
Don Horsley
3
Municipal Electric Authority of
Georgia
Steven M. Jackson
Affirmative
3
Muscatine Power & Water
John S Bos
Affirmative
3
New York Power Authority
Marilyn Brown
Affirmative
3
Niagara Mohawk (National Grid
Company)
Michael Schiavone
Abstain
3
North Carolina Municipal Power
Agency #1
Denise Roeder
Abstain
3
Northern Indiana Public Service
Co.
William SeDoris
3
Northern Lights Inc.
Jon Shelby
3
Ocala Electric Utility
David T. Anderson
3
Okanogan County Electric
Cooperative, Inc.
Ray Ellis
3
Orlando Utilities Commission
Ballard Keith Mutters
3
OTP Wholesale Marketing
Bradley Tollerson
3
PacifiCorp
John Apperson
3
PECO Energy an Exelon Co.
Vincent J. Catania
3
Platte River Power Authority
Terry L Baker
Affirmative
3
Potomac Electric Power Co.
Robert Reuter
Affirmative
3
Progress Energy Carolinas
Sam Waters
Affirmative
3
Public Service Electric and Gas Co. Jeffrey Mueller
Abstain
3
Public Utility District No. 1 of
Chelan County
Abstain
3
Public Utility District No. 2 of Grant
Greg Lange
County
Affirmative
3
Raft River Rural Electric
Cooperative
Affirmative
Kenneth R. Johnson
Heber Carpenter
Negative
View
Negative
Affirmative
Negative
Affirmative
Abstain
8
3
Sacramento Municipal Utility
District
James Leigh-Kendall
3
Salem Electric
Anthony Schacher
3
Salmon River Electric Cooperative Ken Dizes
Affirmative
3
Salt River Project
John T. Underhill
Affirmative
3
San Diego Gas & Electric
Scott Peterson
3
Santee Cooper
Zack Dusenbury
Negative
3
Seattle City Light
Dana Wheelock
Negative
3
South Mississippi Electric Power
Association
Gary Hutson
3
Southern California Edison Co.
David Schiada
3
Springfield Utility Board
Jeff Nelson
3
Tampa Electric Co.
Ronald L Donahey
3
Tri-State G & T Association, Inc.
Janelle Marriott
Affirmative
3
Umatilla Electric Cooperative
Steve Eldrige
Affirmative
3
West Oregon Electric Cooperative,
Marc Farmer
Inc.
3
Wisconsin Electric Power Marketing James R. Keller
Abstain
3
Wisconsin Public Service Corp.
Gregory J Le Grave
Abstain
3
Xcel Energy, Inc.
Michael Ibold
4
Alliant Energy Corp. Services, Inc. Kenneth Goldsmith
4
American Municipal Power - Ohio
4
American Public Power Association Allen Mosher
4
City of Clewiston
4
City of New Smyrna Beach Utilities
Timothy Beyrle
Commission
4
Consumers Energy
Kevin Koloini
Kevin McCarthy
David Frank Ronk
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
View
9
4
Cowlitz County PUD
Rick Syring
Affirmative
4
Detroit Edison Company
Daniel Herring
Affirmative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
View
4
Fort Pierce Utilities Authority
Thomas W. Richards
Negative
View
4
Georgia System Operations
Corporation
Guy Andrews
4
Illinois Municipal Electric Agency
Bob C. Thomas
Abstain
4
Integrys Energy Group, Inc.
Christopher Plante
Abstain
4
Madison Gas and Electric Co.
Joseph G. DePoorter
Abstain
4
Ohio Edison Company
Douglas Hohlbaugh
Negative
4
Old Dominion Electric Coop.
Mark Ringhausen
Affirmative
4
Public Utility District No. 1 of
Douglas County
Henry E. LuBean
Affirmative
4
Public Utility District No. 1 of
Snohomish County
John D. Martinsen
Abstain
4
Sacramento Municipal Utility
District
Mike Ramirez
Abstain
4
Seattle City Light
Hao Li
4
Seminole Electric Cooperative, Inc. Steven R Wallace
4
South Mississippi Electric Power
Association
Steve McElhaney
4
Wisconsin Energy Corp.
Anthony Jankowski
Abstain
4
Y-W Electric Association, Inc.
James A Ziebarth
Abstain
5
AEP Service Corp.
Brock Ondayko
5
Amerenue
Sam Dwyer
Negative
5
APS
Mel Jensen
Abstain
5
Avista Corp.
Edward F. Groce
Affirmative
5
BC Hydro and Power Authority
Clement Ma
Affirmative
Affirmative
View
Negative
Affirmative
10
5
Black Hills Corp
George Tatar
Affirmative
5
Bonneville Power Administration
Francis J. Halpin
5
Chelan County Public Utility
District #1
John Yale
5
City of Grand Island
Jeff Mead
Abstain
5
City of Tallahassee
Alan Gale
Abstain
5
City Water, Light & Power of
Springfield
Karl E. Kohlrus
5
Consolidated Edison Co. of New
York
Wilket (Jack) Ng
Negative
View
5
Constellation Power Source
Generation, Inc.
Amir Y Hammad
Negative
View
5
Consumers Energy
James B Lewis
Negative
View
5
Cowlitz County PUD
Bob Essex
5
Dominion Resources, Inc.
Mike Garton
5
Duke Energy
Robert Smith
5
Dynegy Inc.
Dan Roethemeyer
Affirmative
5
East Kentucky Power Coop.
Stephen Ricker
Affirmative
5
Energy Northwest - Columbia
Generating Station
Doug Ramey
Affirmative
5
Entegra Power Group, LLC
Kenneth Parker
Abstain
5
Entergy Corporation
Stanley M Jaskot
Abstain
5
Exelon Nuclear
Michael Korchynsky
5
ExxonMobil Research and
Engineering
Martin Kaufman
Abstain
5
FirstEnergy Solutions
Kenneth Dresner
Negative
View
5
Florida Municipal Power Agency
David Schumann
Negative
View
5
Great River Energy
Cynthia E Sulzer
Negative
Negative
Affirmative
Negative
View
Negative
11
5
Green Country Energy
Greg Froehling
5
Horizon Wind Energy
Brent Hebert
5
Indeck Energy Services, Inc.
Rex A Roehl
5
JEA
Donald Gilbert
5
Kansas City Power & Light Co.
Scott Heidtbrink
5
Kissimmee Utility Authority
Mike Blough
5
Lakeland Electric
Thomas J Trickey
5
Liberty Electric Power LLC
Daniel Duff
5
Lincoln Electric System
Dennis Florom
5
Louisville Gas and Electric Co.
Charlie Martin
5
Luminant Generation Company LLC Mike Laney
5
Manitoba Hydro
5
Massachusetts Municipal Wholesale
David Gordon
Electric Company
5
New Harquahala Generating Co.
LLC
Nicholas Q Hayes
5
New York Power Authority
Gerald Mannarino
5
Northern Indiana Public Service
Co.
Michael K Wilkerson
5
Otter Tail Power Company
Stacie Hebert
5
Pacific Gas and Electric Company
Richard J. Padilla
5
PacifiCorp
Sandra L. Shaffer
5
Portland General Electric Co.
Gary L Tingley
5
PowerSouth Energy Cooperative
Tim Hattaway
5
PPL Generation LLC
Mark A Heimbach
5
Progress Energy Carolinas
Wayne Lewis
5
PSEG Power LLC
Jerzy A Slusarz
Affirmative
Negative
View
Affirmative
Affirmative
Negative
Affirmative
Negative
View
Mark Aikens
Abstain
Negative
Abstain
Affirmative
Affirmative
Abstain
12
5
Public Utility District No. 1 of Lewis
Steven Grega
County
5
Reedy Creek Energy Services
Bernie Budnik
5
RRI Energy
Thomas J. Bradish
Abstain
5
Sacramento Municipal Utility
District
Bethany Hunter
Abstain
5
Salt River Project
Glen Reeves
5
San Diego Gas & Electric
Daniel Baerman
5
Santee Cooper
Lewis P Pierce
5
Seattle City Light
Michael J. Haynes
5
Seminole Electric Cooperative, Inc. Brenda K. Atkins
5
South Carolina Electric & Gas Co.
Richard Jones
5
South Mississippi Electric Power
Association
Jerry W Johnson
5
Southern Company Generation
William D Shultz
5
SRW Cogeneration Limited
Partnership
Michael Albosta
5
Tampa Electric Co.
RJames Rocha
Affirmative
5
Tenaska, Inc.
Scott M. Helyer
Abstain
5
Tennessee Valley Authority
George T. Ballew
Abstain
5
TransAlta Centralia Generation,
LLC
Joanna Luong-Tran
Abstain
5
Tri-State G & T Association, Inc.
Barry Ingold
Affirmative
5
U.S. Army Corps of Engineers
Melissa Kurtz
Affirmative
5
U.S. Bureau of Reclamation
Martin Bauer P.E.
5
Wisconsin Electric Power Co.
Linda Horn
Abstain
5
Wisconsin Public Service Corp.
Leonard Rentmeester
Abstain
5
Xcel Energy, Inc.
Liam Noailles
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
View
13
6
AEP Marketing
Edward P. Cox
Negative
View
6
Ameren Energy Marketing Co.
Jennifer Richardson
Negative
6
Bonneville Power Administration
Brenda S. Anderson
Abstain
6
Cleco Power LLC
Matthew D Cripps
Negative
6
Consolidated Edison Co. of New
York
Nickesha P Carrol
Negative
6
Constellation Energy Commodities
Brenda Powell
Group
Negative
6
Dominion Resources, Inc.
Louis S Slade
Negative
6
Duke Energy Carolina
Walter Yeager
Negative
6
Entergy Services, Inc.
Terri F Benoit
Abstain
6
Eugene Water & Electric Board
Daniel Mark Bedbury
6
Exelon Power Team
Pulin Shah
Negative
6
FirstEnergy Solutions
Mark S Travaglianti
Negative
View
6
Florida Municipal Power Pool
Thomas E Washburn
Negative
View
6
Florida Power & Light Co.
Silvia P Mitchell
6
Great River Energy
Donna Stephenson
6
Kansas City Power & Light Co.
Thomas Saitta
6
Lakeland Electric
Paul Shipps
6
Lincoln Electric System
Eric Ruskamp
6
Louisville Gas and Electric Co.
Daryn Barker
6
Luminant Energy
Brad Jones
Negative
View
6
Manitoba Hydro
Daniel Prowse
Negative
View
6
New York Power Authority
Thomas
Papadopoulos
6
Northern Indiana Public Service
Co.
Joseph O'Brien
View
View
Affirmative
Negative
View
Affirmative
Negative
14
6
Omaha Public Power District
David Ried
6
OTP Wholesale Marketing
Bruce Glorvigen
6
Platte River Power Authority
Carol Ballantine
Negative
6
Progress Energy
John T Sturgeon
Affirmative
6
PSEG Energy Resources & Trade
LLC
James D. Hebson
Abstain
6
Public Utility District No. 1 of
Chelan County
Hugh A. Owen
Abstain
6
RRI Energy
Trent Carlson
6
Santee Cooper
Suzanne Ritter
Negative
6
Seattle City Light
Dennis Sismaet
Negative
6
Seminole Electric Cooperative, Inc. Trudy S. Novak
6
South Carolina Electric & Gas Co.
Matt H Bullard
6
Tennessee Valley Authority
Marjorie S. Parsons
6
Western Area Power
Administration - UGP Marketing
John Stonebarger
6
Xcel Energy, Inc.
David F. Lemmons
8
Roger C Zaklukiewicz
8
James A Maenner
8
Merle Ashton
8
Kristina M.
Loudermilk
Negative
View
Affirmative
Negative
Affirmative
Negative
8
Ascendant Energy Services, LLC
Raymond Tran
8
JDRJC Associates
Jim D. Cyrulewski
Affirmative
8
Pacific Northwest Generating
Cooperative
Margaret Ryan
Affirmative
8
Power Energy Group LLC
Peggy Abbadini
8
SPS Consulting Group Inc.
Jim R Stanton
Abstain
15
8
Utility Services, Inc.
Brian EvansMongeon
8
Volkmann Consulting, Inc.
Terry Volkmann
9
California Energy Commission
William Mitchell
Chamberlain
9
Commonwealth of Massachusetts
Department of Public Utilities
Donald E. Nelson
9
National Association of Regulatory
Diane J. Barney
Utility Commissioners
9
North Carolina Utilities Commission Kimberly J. Jones
9
Oregon Public Utility Commission
Jerome Murray
9
Public Service Commission of
South Carolina
Philip Riley
Affirmative
9
Utah Public Service Commission
Ric Campbell
Affirmative
10
Florida Reliability Coordinating
Council
Linda Campbell
10
Midwest Reliability Organization
Dan R. Schoenecker
10
New York State Reliability Council
Alan Adamson
Affirmative
10
Northeast Power Coordinating
Council, Inc.
Guy V. Zito
Affirmative
10
ReliabilityFirst Corporation
Jacquie Smith
10
SERC Reliability Corporation
Carter B Edge
Abstain
10
Western Electricity Coordinating
Council
Louise McCarren
Abstain
Abstain
Affirmative
Affirmative
Abstain
16
Individual or group. (44 Responses)
Name (25 Responses)
Organization (25 Responses)
Group Name (19 Responses)
Lead Contact (19 Responses)
Question 1 (40 Responses)
Question 1 Comments (44 Responses)
Question 2 (36 Responses)
Question 2 Comments (44 Responses)
Question 3 (39 Responses)
Question 3 Comments (44 Responses)
Question 4 (39 Responses)
Question 4 Comments (44 Responses)
Question 5 (38 Responses)
Question 5 Comments (44 Responses)
Group
Pepco Holding Inc & Affilates
David K Thorne
Yes
Yes
Yes
Yes
Yes
What "specific statistical data" was used to validate that unmonitored communication systems are 24
times more prone to failure than unmonitored protective relays? Comments were previously
submitted that the 3 month interval for verifying unmonitored communication systems was much too
short. The SDT declined to change the interval and in their response stated: "The 3 month intervals
are for unmonitored equipment and are based on experience of the relaying industry represented by
the SDT, the SPCTF and review of IEEE PSRC work. Relay communications using power line carrier or
leased audio tone circuits are prone to channel failures and are proven to be less reliable than
protective relays." The 3 month interval is very burdensome and our experience does not appear to
justify. A longer interval should be reconsidered.
Group
Pacific Northwest Small Public Power Utility Comment Group
Steve Alexanderson
Yes
Yes
No
Yes
WECC does not use the definition of the BES that NERC supplied to FERC via
http://www.nerc.com/docs/docs/ferc/RM06-16-6-14-07CompFilingPar77ofOrder693FINAL.pdf, so the
answer to III.1.3 (page 19-20) is not accurate.
No
Group
Tennessee Valley Authority
Dave Davidson
Yes
No
There is no allowance for deferral of maintenance because of factors beyond the control of the TO,
GO, or DP. These include the unavailability of customer outages, generation outages, system
configuration, high risk of loss of generation or customer load or impact to power quality. Proposed
Change: Provide a process for acceptable deferral of maintenance activities. Table 1-4 Table 1-4 The
requirement to perform cell internal ohmic resistance measurements every 18 months for vented
lead-acid batteries is excessive. Our normal battery life is 20+ years. A 3-year internal resistance test
frequency is adequate to prove battery integrity. IEEE 1188 recommends verification of internal ohmic
resistance to be on a quarterly bases. It appears other intervals take into account recommended
inspection interval plus some grace period. Proposed Change: Change maintenance interval from 3
months to 6 months. Section: R1.5 This new requirement will require significant documentation with
no known improvement to the reliability of the BES. What data is being used to determine the need
for this requirement? How far does this requirement go? Table 1-4 requires the inspection of “physical
condition of battery rack” What are “identify calibration tolerance or other equivalent parameters” for
this task? You already have verify, test, inspect, and calibrate defined. Leave out R1.5 which requires
more than meeting the definitions.
No
No
Yes
R4 - “Identification of the resolution” and “Initiation of the resolution” are very distinct activities. In
other places in this standard the requirement is for the resolution to be initiated, that is identified in a
corrective maintenance work order, “identification of a resolution” requires technical expertise and
can be difficult to track and might change over time for a particular problem. Proposed Change:
Change “identification” to “initiation” in phrase “including identification of the resolution…”. Overall:
NERC is making significant changes to this sizeable standard and only allowing minimum comment
period. While this is a good standard that has clearly taken many hours to develop, we are primarily
voting “NO” because of the hurried fashion it is being commented, voted, and reviewed.
Individual
Jack Stamper
Clark Public Utilities
No
The SDT has greatly improved the clarity of this document in the areas of relays, communication
systems, voltage and current sensing devices, control circuitry, and alarming paths. The
recommendations on station dc supply are still confusing. First, there are five different attribute
categories for unmonitored dc supply. Are these five categories mutually exclusive? Are we supposed
to follow just the category applicable to the type of battery? Are we supposed to follow the first
category and any of the subsequent four battery type categories as they apply? I suspect some of the
3 month and 18 month items in the first category are considered to be necessary by the SDT
regardless of battery type. The current categorization is confusing. If we are required to perform the
3 month and 18 month activities listed in the first category regardless of battery type AS WELL AS the
other applicable battery type activities, please indicate this in Table 1-4. As a different option, just
eliminate the first category entirely and place the appropriate 3 month and 18 month verification and
inspection requirements in the four battery type specific categories. It may be repetitive but clarity is
paramount in this standard. Second, the FAQ examples seem to indicate that the SDT views the
performance of an internal ohmic battery test or a battery performance test as valid forms for
verifying the individual battery cell states (i.e. state of charge of the individual battery cells/units,
battery continuity, battery terminal connection resistance, and battery internal cell-to-cell or unit-tounit connection resistance). It would be helpful if this were more obviously stated in table 1-4.
Currently it could be interpreted that we need to do all of the individual cell-cell verification in addition
to the ohm test or the full performance test. I don’t believe this is the intent of the SDT (based on the
FAQ examples) but we need to see the intent in Table 1-4. Third, does a monitored dc supply have to
monitor some or all of each of the different line items listed? The FAQ examples indicate that if only
some are monitored, the dc supply can still be treated as monitored as long as the unmonitored items
are verified. This means that for a VLA battery with a low voltage alarm and unintentional ground
alarm, all that is needed is to check electrolyte level every 3 months, check float voltage and battery
rack every 18 months and perform either an internal ohm check at 18 months or a battery
performance test at 6 years. Also battery alarms need to be verified at 6 years. This is not clear in
Table 1-4 and it could be interpreted by some that a monitored station dc supply monitors ALL of the
listed items not just SOME. The FAQs imply that partial monitoring is acceptable but Table 1-4 does
not indicate this very clearly. I do wish to say once again that this proposed standard is much easier
to understand and that with a little more clarification in the dc supply section I would vote in the
affirmative.
Yes
No
Yes
Provide answers to the following questions. Does the completion of a battery ohm test or a battery
performance test satisfy the verification requirements for state of charge of the individual battery
cells/units, battery continuity, battery terminal connection resistance, and battery internal cell-to-cell
or unit-to-unit connection resistance (where available to measure)?
No
Individual
John Bee
Exelon
Yes
• Clarify what kind of testing is required on lockout relays/86 devices. Specifically, whether functional
testing is adequate or if simple calibration, similar to protective relays, is all that is are required. •
Clarify if protective relays that trip equipment (e.g., a condensate pump that would in turn cause a
main generator trip) are also included in the scope of this Standard. • Clarify if relays which result in
generator run back, but do not trip the generator, are included in the scope of this Standard.
Yes
In response to Exelon’s comments provided to drafts 1 and 2 of PRC-005, the SDT did not explain
why a conflict with an existing regulatory requirement is acceptable. The SDT responded that a
conflict does not exist and that the removal of grace periods simply is there to comply with FERC
Order directive 693. This response does not answer or address dual regulation by the NRC and by the
FERC. Specifically, the request has not been adequately considered for an allowance for NRC-licensed
generating units to default to existing Operating License Technical Specification Surveillance
Requirements if there is a maintenance interval that would force shutting down a unit prematurely or
become non-compliant with PRC-005. Therefore, Exelon requests that the SDT communicate with the
NRC and with the FERC to ensure a conflict of dual regulation is not imposed on a nuclear generating
unit without the necessary evaluation. In addition, although Exelon Nuclear agrees with the SDT that
the maximum allowed battery capacity testing intervals of not to exceed 6 calendar years for vented
lead acid or NiCad batteries (not to exceed 3 calendar years for VRLA batteries) could be integrated
within the plant’s routine 18 month to 2 year interval refueling outage schedule, the SDT has not
considered that nuclear refueling outages may be extended past the 18 month to 2 year "normal"
periodicity. There are some unique factors related to nuclear generating units that the SDT has not
taken into consideration in that these units are typically online continuously between refueling
outages without shutting down for any other required maintenance. Historically, generating units
have at times extended planned refueling outage shutdown dates days and even weeks due to
requests from transmission operations, fuel issues and electrical demand. Without the grace period
exclusion currently allowed by existing maintenance programs, a nuclear plant will be forced to either
extend outage duration to include testing on an every other refueling outage (i.e., every four years to
ensure compliance for a typical boiling water reactor) or leave the testing on a six year periodicity
with the vulnerability of a forced shut down simply to perform maintenance to meet the six year
periodicity or a self report of non-compliance. To ensure compliance, the nuclear industry will be
forced to schedule battery testing on a four year periodicity to ensure the six year periodicity is met,
thus imposing a requirement on nuclear generating units that would not apply to other types of
generating units. In addition, Exelon has the following technical comments • Sections 4.2.5.4 and
4.2.5.5 need to clearly state that only protection which affects the BES is within the scope of the PRC005. • There is not enough clarity in the statement “each protection system component type” for one
to stay at the component level vs. dropping to sub-component level. If sub-components reviews are
required, the effort becomes unmanageable. Therefore the Standard should identify calibration
tolerances or other equivalent parameters. Suggest rewording to "each protection system major
component type”
Group
Northeast Power Coordinating Council
Guy Zito
No
The wording “Component Type” is not necessary in each title. Just the equipment category should be
listed--what is now shown as “Component Type - Protective Relay”, should be Protective Relay.
However, Protective Relay is too general a category. Electromechanical relays, solid state relays, and
microprocessor based relays should have their own separate tables. So instead of reading Protective
Relay in the title, it should read Electromechanical Relays, etc. This will lengthen the standard, but
will simplify reading and referring to the tables, and eliminate confusion when looking for information.
The “Note” included in the heading is also not necessary. “Attributes” is also not necessary in the
column heading, “Component” suffices.
No
Because all the requirements deal with protective system maintenance and testing, violations could
directly cause or contribute to bulk electric system instability, etc., the VRFs should all be “High”. The
Time Horizons should all be “Operations Planning” because of the immediacy of a failure to meet the
requirements. For the R1 Lower VSL, include a second part to read: Failed to identify calibration
tolerances or other equivalent parameters for one Protection System component type that establish
acceptable parameters for the conclusion of maintenance activities. For the R1 Moderate VSL, suggest
similar wording as for the Lower VSL but specifying two Protection System component types. For the
R1 High VSL, suggest changing the wording of the 3rd part to be similar to the Lower VSL to match
the requirement and to cater for more than two Protection System component types. For the R3
Severe VSL, in part 3, replace “less” with fewer.
No
Yes
See response to Question 5 below.
Yes
In general, the standard is overly prescriptive and complex. It should not be necessary for a standard
at this level to be as detailed and complex as this standard is. Entities working with manufacturers,
and knowledge gained from experience can develop adequate maintenance and testing programs.
Why are “Relays that respond to non-electrical inputs or impulses (such as, but not limited to,
vibration, pressure, seismic, thermal or gas accumulation)…” not included? The output contacts from
these devices are oftentimes connected in tripping or control circuits to isolate problem equipment.
Due to the critical nature of the trip coil, it must be maintained more frequently if it is not monitored.
Trip coils are also considered in the standard as being part of the control circuitry. Table 1-5 has a
row labeled “Unmonitored Control circuitry associated with protective functions”, which would include
trip coils, has a “Maximum Maintenance Interval” of “12 Calendar Years”. Any control circuit could fail
at any time, but an unmonitored control circuit could fail, and remain undetected for years with the
times specified in the Table (it might only be 6 years if I understand that as being the trip test
interval specified in the table). Regardless, if a breaker is unable to trip because of control circuit
failure, then the system must be operated in real time assuming that that breaker will not trip for a
fault or an event, and backup facilities would be called upon to operate. Thus, for a line fault with a
“stuck” breaker (a breaker unable to trip), instead of one line tripping, you might have many more
lines deloaded or tripped because of a bus having to be cleared because of a breaker failure initiation.
The bulk electric system would have to be operated to handle this contingency. In reference to the
FAQ document, Section 5 on Station dc Supply, Question K, clarification is needed with respect to dc
supplies for communication within the substation. For example, if the communication systems were
run off a separate battery in separate area in a substation, would the standard apply to these
batteries or not? To define terms only as they are used in PRC-005-2 is inviting confusion. Although
they may be unique to PRC-005-2, some or all of them may be used in future standards, some
already may be used in existing standards, and may or may not be deliberately defined. Consistency
must be maintained, not only for administrative purposes, but for effective technical communications
as well. What is the definition of “Maintenance” as used in the table column “Maximum Maintenance
Interval”? Maintenance can range from cleaning a relay cover to a full calibration of a relay. A control
circuit is not a component, it is made up of components. Sub-requirement 1.5 needs to be clarified. It
is not clear what “Identify calibration tolerances or other equivalent parameters…” means, and may
be subject to different interpretations by entities and compliance enforcement personnel. In the
Implementation plan for Requirement R1, recommend changing “six” to fifteen. This change would
restore the 3-month time difference that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require regulatory approval. It will ensure
equity for those entities located in jurisdictions that do not require regulatory approval, as is the case
in Ontario. The ‘box’ for “Monitored Station dc supply…” in Table 1-4 is not clear. It seems to continue
to the next page to a new box. There are multiple activities without clear delineation. Regarding
station service transformers, Item 4.2.5.5 under Applicability should be deleted. The purpose of this
standard is to protect the BES by clearing generator, generator bus faults (or other electrical
anomalies associated with the generator) from the BES. Having this standard apply to generator
station service transformers, that have no direct connection to the BES, does meet this criteria. The
FAQs (III.2.A) discuss how the loss of a station service transformer could cause the loss of a
generating unit, but this is not the purpose of PRC-005. Using this logic than any system or device in
the power plant that could cause a loss of generation should also be included. This is beyond the
scope of the NERC standards. The Drafting Team must respond to the following concerns raised in the
FERC NOPR, Docket No. RM10-5-000, Interpretation of Protection System Reliability Standard,
December 16, 2010) to “prevent a gap in reliability”. • Any component that detects any quantity
needed to take an action, or that initiates any control action (initial tripping, reclosing, lockout, etc.)
affecting the reliability of the Bulk-Power System should be included as a component of a Protection
System, as well as any component or device that is designed to detect defective lines or apparatuses
or other power system conditions of an abnormal or dangerous nature and to initiate appropriate
control circuit actions. • The exclusion of auxiliary relays will result in a gap in the maintenance and
testing of Protection Systems affecting the reliability of the Bulk-Power System. • Excluding the
maintenance and testing of reclosing relays will result in a gap in the maintenance and testing of
relays affecting the reliability of the Bulk-Power System. • Not establishing the specific requirements
relative to the scope and/or methods for a maintenance and testing program for the DC control
circuitry that is necessary to ensure proper operation of the Protection System, including voltage and
continuity.
Individual
Joe Petaski
Manitoba Hydro
No
The maintenance requirements for batteries listed in Table 1-4 do not appear to be consistent with
example 1 in Section V, 1A of the FAQ. Specifically the FAQ does not mention the state of charge of
the individual battery cells/units, the battery continuity, the battery terminal connection resistance,
the battery internal cell-to-cell or unit-to-unit connection resistance, or the cell condition, which are
indicated as 18 month interval tasks in table 1-4.
No
The high VSL for R1 “Failed to include all maintenance activities relevant for the identified monitoring
attributes specified in Tables 1-1 through 1-5” may be interpreted in different ways and should be
further clarified.
No
Yes
As previously stated, the maintenance requirements for batteries listed in Table 1-4 do not appear to
be consistent with example 1 in Section V, 1A of the FAQ. Specifically the FAQ does not mention the
state of charge of the individual battery cells/units, the battery continuity, the battery terminal
connection resistance, the battery internal cell-to-cell or unit-to-unit connection resistance, or the cell
condition which are indicated as 18 month interval tasks in table 1-4.
Yes
1) We disagree with the requirements for battery maintenance outlined in table 1-4. In particular the
requirement for a 3 month check on electrolyte level seems too frequent based on our experience. We
would like to point out that although IEEE std 450 (which seems to be the basis for table 1-4) does
recommend intervals it also states that users should evaluate these recommendations against their
own operating experience. 2) Also, the Implementation Plan is not consistent for areas requiring
regulatory approval and areas requiring regulatory approval. The 6 month time frame proposed for R1
for areas not requiring regulatory approval is not achievable and is not consistent with areas requiring
regulatory approval. To be consistent, the effective date for R1 in jurisdictions where no regulatory
approval is required should be the first day of the first calendar quarter 12 months after BOT
approval.
Group
Platte River Power Authority System Maintenance
Deborah Schaneman
Yes
No
The 5%, 10%, and 15% levels for R2 & R4 exaggerate the severity levels for small companies. A
small DP with only 9 relays in a protection system would only have to be missing 1 record for a
severe VSL.
No
No
Yes
Please clarify what is required by R1.5: Identify calibration tolerances or other equivalent parameters
for each Protection System component type that establish acceptable parameters for the conclusion of
maintenance activities required. Is the intent a brief summary for each component type in the PSMP
that would cover all equipment within that component type, or is it a detailed list of each piece of
equipment within each component type? The inclusion of dated check-off lists in M4 provides much
needed clarity to the list of evidence.
Individual
Dan Roethemeyer
Dynegy Inc.
Yes
No
For R4, the VRF has been changed to high. We question the need to change to high since there are
numerous elements that will still protect the system while repairs are being made.
No
No
Yes
For R1.5, we feel to much is being asked for since this information is not easilly controlled and the
tolerances vary over time.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
Yes
No
Oncor strongly disagrees with the modification to the Violation Severity Levers (VSL) table under the
High VSL column where it states that it is a high VSL for “Failed to establish calibration tolerance or
equivalent parameters to determine if components are within acceptable parameters.” Oncor feels
modifying the standard by adding a requirement that requires a Transmission Owner, Generation
Owner or Distribution Provider to “identify calibration tolerances or other equivalent parameters for
each Protection System component type that establish acceptable parameters for the conclusion of
maintenance activities” is too intrusive and divisive for what it brings to the reliability of the BES. The
requirement (Requirement R1 part 1.5) and its associated High VSL should be removed from PRC005-2.
No
Yes
There is still confusion in Table 1-4 concerning the “Monitored Station dc supply.” The uncertainty is
over whither an Owner must have all seven (7) monitoring activities (Station dc supply voltage, State
of charge of the individual battery cell/units, Battery continuity of station battery, Cell-to-cell and
battery terminal resistance, Electrolyte level of all cells in station battery, Unintentional dc grounds,
and Cell/unit internal ohmic values of station battery) listed in the table or just one of them to take
advantage of forgoing the maximum maintenance interval for an activity and going to the 6 year
maximum maintenance interval to verify that the monitoring device is calibrated. A FAQ concerning
this question would be beneficial to those who are concerned that they must monitor all seven
activities in order to take advantage of condition based maintenance for the station dc supply. Also an
explanation of how each of the 7 monitoring activities relates to a specific station dc supply
maintenance activity might be beneficial.
Yes
Comment A: Oncor believes that Requirement R1 Part 1.5 of this Standard should be removed. It is
too vague, intrusive, and divisive for what it brings to the reliability of the BES. Specifically it burdens
all Transmission Owners, Generation Owners or Distribution Providers with the impossible task of
having to “identify calibration tolerances or other equivalent parameters for each Protection System
component type that establish acceptable parameters for the conclusion of maintenance activities.”
By definition a Protection System component type is “any one of the five specific elements of the
Protection System definition” and “a component is any individual discrete piece of equipment included
in a Protection System, such as a protective relay or current sensing device.” What Requirement R1
part 1.5 with its associated High VSL in the Standard would decree is that all Transmission Owners,
Generation Owners and Distribution Providers who “failed to establish calibration tolerance or
equivalent parameters to determine if every individual discrete piece of equipment in a Protection
System is within acceptable parameters” would be in violation of the Standard – with a High VSL.
Oncor with over 98 years of Protection System maintenance experience feels that most Owners
including itself would be non-compliant with this unclear, meddling and disruptive requirement no
matter how long the implementation plan for the Standard is. Comment B: Oncor believes that in light
of Comment “A” above Requirement R4 Part 4.2 must be modified to remove all references to
Requirement R1 Part 1.5 of the Standard. The new requirement should be modified to read “Either
verify that the components are within acceptable parameters at the conclusion of the maintenance
activities or initiate any necessary activities to correct maintenance correctable issues.” Also in order
to assist both the owners and the compliance authorities who may question how one verifies that the
components are within acceptable parameters the FAQ document should be modified to discuss how
many utilities are doing this with results that indicate either a pass or fail certified by the qualified
persons performing maintenance. Comment C: Oncor feels that the wording “no less frequently than”
found in Requirement R4 Parts 4.1.1 and 4.1.2 should be chanced back to the wording in the previous
version of the Standard “not to exceed.” Comment D: Oncor recommends that in light of Comment
“A” above Measure M1 be modified to remove all reference to Requirement R1 Part 1.5. Comment E:
Oncor, as stated in Comment “B” above, recommends that the FAQ document be modified to provide
more information on what could be used for evidence that the Transmission Owner, Generation Owner
or Distribution Provider has “initiated resolution of identified maintenance correctable issues.” This will
assist both the owners and the compliance authorities in answering the question of what constitutes
proof that a maintenance correctable issue was identified. Comment F: The second and third
paragraphs added under Compliance 1.3 Data Retention provide more information as to what data is
required to be retained. Oncor feels that these two paragraphs will help the compliance authorities,
the Transmission Owners, Generation Owners and Distribution Providers needed guidance of what is
required for data retention.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
Yes
The tables clearly tie to each component type in a Protection System. This is consistent with the
required PSMP format, making it straight forward to incorporate the intervals and to demonstrate
compliance.
Yes
Ingleside Cogeneration, LP, believes that the Section 15.5 of the Supplementary Reference
“Associated communications equipment (Table 1-2)” properly reflects the intent of the validation of
relay-to-relay communications. It states that any “evidence of operational test or documentation of
measurement of signal level, reflected power or data-error rates can fulfill the requirements.”
However, Table 1-2 – which will be the ultimate reference used by audit teams – only clearly allows
for the measurement of channel parameters. Although the newer technology relays provide read-outs
of signal level or data-error rates that do not require intrusive testing, older relays do not. The tools
required to perform such testing are not easily available – and may leave the communications
channel in worse shape after testing than it was prior to testing. We believe that Table 1-2 should be
updated to clearly state that an operational test is sufficient for the testing of relay-to-relay
communication – consistent with the Supplementary Reference.
The latest version of PRC-005-2 includes a new requirement (R1.5) to identify calibration tolerances
or equivalent parameters that must be verified before a maintenance activity is considered complete.
Although we understand the project team’s intent, Ingleside Cogeneration LP is concerned that this
requirement will lead to multiple interpretations of which tolerances or parameters are the most
important. In addition, audit teams may expect to see certain values based upon their own sense of
reliability. This is exactly the ambiguity that PRC-005-2 is trying to eliminate. In addition, calibration
tolerances and reliability parameters may vary by equipment manufacturer or by configuration. It is
not clear that documenting every scenario to demonstrate regulatory compliance is a benefit to BES
reliability.
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
No
IMPA does not agree with the percentage in the VSL table for R4. For smaller entities that have six or
less of any one type of Protection System Component and they fail, for whatever reason (even if it's a
matter of incomplete documentation), to complete scheduled program maintenance on that
component they will be subjected to the severe VSL penalty Matrix. Consideration should be given to
entities having less than say, 100 of a component. There should be some type of tiered sub table
within the VSL matrix for this consideration - registered entities having a certain component in
quantities greater than or equal to 100 and registered entities having quantities of that certain
component of less than 100.
No
No
Yes
Standard PRC-005-2 Draft 3 contains a section of "Definitions of Terms Used in Standard" that
includes newly defined or revised terms uses in this proposed standard. There are a number of
references made to these Terms in the Standard that are not capitalized. IMPA would propose that
anywhere that the terms included in the "Definition of Terms Used" are used in the standard that they
be capitalized. When any word is not capitalized in a standard then the common practice is to use the
Webster Dictionary meaning. IMPA does not know why the SDT is reluctant to put these terms in the
NERC Glossary of Terms, but by putting the terms in the glossary it would eliminate any confusion.
When these terms are capitalized all registered entities will know that these are defined terms and will
be able to consistently apply the definition without confusion. For example: 1.1 Address all Protection
System component types. would become 1.1 Address all Protection System Component Types. If
these terms are not capitalized in the standard (meaning they are not referring to the defined term)
then the meaning of these terms could vary not only from utility to utility but also from Region to
Region.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
Yes
No
No
Individual
Ed Davis
Entergy Services
No
The tables are generally much clearer and the SDT is to be commended on their efforts. However, we
believe the Alarming Point Table needs additional clarification with regard to the Maximum
Maintenance Interval. If an “alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there isn’t necessarily a maximum
interval established as there is for Protection System components. Also, if an entity’s alarm producing
device maintenance is performed in sections and triggered by segment or component maintenance,
there would essentially be multiple maximum intervals for the alarm producing device of that entity.
On that basis, we suggest the interval verbiage be revised to “When alarm producing device or
system is verified, or by sections as per the monitored component/protection system specified
maximum interval as applicable”. Alternately, if the intention is to establish maximum intervals as
simply being no longer than the individual component maintenance intervals as we suggest for
inclusion above, then the verbiage should be revised to “When alarm producing component/protection
system segment is verified”. In either case are we to interpret monitored components with attributes
which allow for no periodic maintenance specified as not requiring periodic alarm verification?
No
R1.5 calls for “identification of calibration tolerances or equivalent parameters…” whereas the
associated VSL references “failure to establish calibration criteria….” and is listed as high. If R1.5 is to
be included in this standard, then we suggest the severity level of a failure to simply “identify” or
document such calibration tolerances would be analogous to the severity level(s) of a “failure to
specify one (or Cthe severity level should be consistent with the other elements of R1. Both cases
appear to be more of a documentation issue as opposed to a failure to implement. Shouldn’t a failure
to implement any necessary calibration tolerance be accounted for in R4?
Yes
R1.5 calls for “identification of calibration tolerances or equivalent parameters for each Protection
System Component Type….”. We believe the Supplementary Reference document should provide
additional information and examples of calibration tolerances or equivalent parameters which would
be expected for the various component types. Especially for any “equivalent” parameters which would
be required for compliance for a component type besides protective relays.
Yes
Section II.2.B references R4.3 which has been revised to R4.2.
Yes
Adding Requirement 1.5 is a significant revision and raises questions as to how broadly an accuracy
or equivalent parameter requirement and associated documentation would need to be addressed by
entities and/or will be measured for compliance. Discussion on this new requirement does not seem to
be addressed anywhere in the FAQ or Supplementary Reference documents. Additionally, to the best
of our knowledge, the need for such a requirement was not brought up as a concern or comment on
the prior draft version of this standard, and in the context of a requirement need, we don’t believe it
has been attributed to or actually poses any significant reliability risk. We do not believe this
requirement is justified.
Individual
Greg Rowland
Duke Energy
Yes
No
• R1.3 appears to be missing from the VSL for R1. • Also, it’s unclear to us what the expectation is for
compliance documentation for “monitoring attributes and related maintenance activities” in R1.4 and
“calibration tolerances or other equivalent parameters” in R1.5. This is fairly straightforward for
relays, but not for other component types. • R4 – More clarity must be provided on the expectation
for compliance documentation. This is a High VRF requirement, and there may only be a small
number of maintenance-correctable items, hence a significant exposure to an extreme penalty.
No
Yes
There are typographical errors on the FAQ Requirements Flowchart (should be R4.1.1 and R4.1.2
instead of R4.4.1 and R4.4.2).
Yes
• We have previously commented that the FAQ and Supplementary Reference documents should be
made part of this standard. If that cannot be done, then more of the information in those documents
needs to be included in the requirements in the standard to provide clarity. Compliance will only be
measured against what is in the standard, and we need more clarity. • R1.4 and R1.5 need more
information to provide clarity for compliance. It’s unclear to us what the expectation is for compliance
documentation for “monitoring attributes and related maintenance activities” in R1.4 and “calibration
tolerances or other equivalent parameters” in R1.5. This is fairly straightforward for relays, but not for
other component types. Either provide clarity or delete these requirements. • R4.2 – it is critical that
more clarity be provided for R1.5 so that we can also understand what the compliance expectation is
for R4.2 • M4 – Need to clarify that these pieces of evidence are all “or”, not “and” (i.e. any of the
listed examples are sufficient for compliance). We reiterate the need for additional clarity on R1.5 and
R4.2 such that compliance can be demonstrated for all component types. • Table 2 – We are fairly
clear on the expectation for relays, but need more clarity on the expectation for other component
types. Also, need to change the phrase “corrective action can be taken” to “corrective action can be
initiated”, consistent with the Supplementary Reference document.
Group
Electric Market Policy
Mike Garton
Yes
Dominion does not feel that clarity has been added to the tables. A numbering structure should be
added to the table for referencing each task prescribed. The tables should more clearly designate and
separate time based versus performance based tasks. Additionally, Table 1-4 contains, in several
places, an activity to “Verify that the station battery can perform as designed by evaluating the
measured cell/unit internal ohmic values to station battery baseline.” This seems to suggest that each
time the batteries are checked, the measured cell/unit internal ohmic value should agree with some
baseline value. This appears to be overly prescriptive as the values reading-to-reading should fall
within the tolerances established per Requirement R1.5, not equal a baseline. The activities for other
component types are not this prescriptive.
No
VSL R3. How do you measure a percentage of countable events over a period of time? How are you to
determine what the total population to be considered? An entity should not be penalized if they are
following their program, correcting issues, and documenting all actions, even if there is a high failure
rate in an instance.
Yes
The document on page 3 states that data available from EPRI (et.al) was utilized by the Standard
Drafting Team; however, there are no references to EPRI documents in Section 16. Suggest including
EPRI references for completeness.
Yes
The FAQ’s do not appear to have kept up with the current draft Standard. For example, Question B
under Section 2 for Protective Relays, refers to the use of the word “Restoration” in the definition of a
Protection System Maintenance Program. The current definition uses the word “Restore.” Additionally,
Answers B, I, and J under Section 2 for Protective Relays each refer to Requirement R4.3, which in
not in the current Standard. Suggest a final edit of the FAQ’s to clean-up these type of issues.
Yes
1. The draft to PRC-005-2 contains defined terms that upon approval will remain with the standard
rather than being moved to the Glossary of Terms. These terms when used in the Requirements are
not designated in any way (e.g., capitalization, bold, etc.) to point the reader back to the in-standard
definition. Need to explicitly state the intent of the SDT to either (1) use the newly defined term
“Protection System (modification)” only in this standard (PRC-005-2) or (2) replace the existing
definition of the existing term in the “Glossary of Terms Used in NERC Reliability Standards” with the
proposed definition for the existing term. 2. The language used in Footnote 1 on Attachment A does
not agree with the definition of Countable events provided elsewhere in the draft standard. Suggest
footnote be removed. 3. Requirement R1.5 uses the phrase “or other equivalent parameters” which is
confusing. Suggest replacing with “or acceptance criteria.” 4. Requirement R1.5 should read as
follows: “Identify calibration program.” The currently proposed language focuses on specific
calibration tolerances and acceptance parameters. These tolerances are developed on a per device,
per location basis and would be captured at a procedural level, not a program level. To add this at a
program level would only complicate the program and would not lend any improvement to the
reliability of the bulk electric system. We recommend maintaining a general calibration requirement,
similar to what is stated above, for an entity to develop their calibration program. 5. Requirement 2
Component should be replaced with Component Type. Creating a program to monitor the equipment
at this level of equipment would not add any value to the bulk electric system as all components
should already be included in component type maintenance tasks. Recommend removing the
definition of Component. 6. The requirement to address “monitoring attributes” in Requirement 2 for
time based maintenance program is unclear, onerous and unnecessary for a reliable protection
system program. 7. Requirement (R4) should identify correctible maintenance issues not the
resolution of these issues. The language in R4.2 should strike correcting maintenance issues related
to R1.5 and instead state: Any maintenance correctible issues found during the maintenance activity
should be identified” 8. Table 1.2 change time frame from 3 months to 3 years.
Individual
Dale Fredrickson
Wisconsin Electric Power Company
Yes
No
Yes
Table 1-4 requires an activity to verify the state of charge of battery cells. There are no possible
options for meeting this requirement listed in the FAQ document. Unlike other terms used in the
standard, this term is not mentioned or defined in the FAQ. To comply with this standard, the SDT
needs to provide more guidance. For example, for VLA batteries the measured specific gravity could
indicate state of charge. For VRLA batteries, it is not as clear how to determine state of charge, but
possibly this can be determined by monitoring the float current.
Individual
Dan Rochester
Independent Electricity System Operator
No
R1 Lower - We suggest including a second part as follows: “Failed to identify calibration tolerances or
other equivalent parameters for one Protection System component type that establish acceptable
parameters for the conclusion of maintenance activities. “ R1 Moderate – We suggest similar to the
Lower VSL but catering for two Protection System component types. R1 High - We suggest changing
the wording of the 3rd part to match the requirement and to cater for more than two Protection
System component types. Editorial Comment to Severe VSL for R3: In part 3, replace “less” with
“fewer”.
No
No
Yes
Requirement R1, Part 1.5 is vague and needs clarification. It is not clear what “Identify calibration
tolerances or other equivalent parameters” means and this may be subject to different interpretations
by entities and compliance enforcement personnel. Additionally, in the Implementation plan for
Requirement R1, we recommend changing “six” to “fifteen” to restore the 3-month time difference
between the durations of the implementation periods for jurisdictions that do and don’t require
regulatory approval, which existed in the previous draft. This change will ensure equity for those
entities located in jurisdictions that do not require regulatory approval as is the case here in Ontario.
More importantly it supports the IESO’s strong belief in the principle that reliability standards should
be implemented in an orderly and coordinated fashion across regions to ensure system reliability is
not compromised.
Individual
Thad Ness
American Electric Power
No
Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12 years for unmonitored control
circuitry, yet other portions of control circuitry have a maximum interval of 6 years. AEP does not
understand the rationale for the difference in intervals, when in most cases, one verifies the other.
Also, unmonitored control circuitry is capitalized in row 4 such that it infers a defined term. In the first
row of table 1-4 on page 16, it is difficult to determine if it is a cell that wraps from the previous page
or is a unique row. This is important because the Maximum Maintenance Intervals are different (i.e.
18 months vs 6 years). It is difficult to determine to which elements the 6 year Maximum
Maintenance Interval applies. AEP suggests repeating the heading “Monitored Station dc supply
(excluding UFLS and UVLS) with: Monitor and alarm for variations from defined levels (See Table 2):”
for the bullet points on this page.
No
The VSL table should be revised to remove the reference to the Standard Requirement 1.5 in the R1
“High” VSL. All four levels of the VSL for R2 make reference to a “condition-based PSMP.” However,
no where in the standard is the term “condition-based” used in reference to defining ones PSMP. The
VSL for R2 should be revised to remove reference to a condition-based PSMP; alternatively the
Standard could be revised to include the term “condition-based” within the Standard Requirements
and Table 1. In multiple instances, Table 1 uses the phrase “No periodic maintenance specified” for
the Maximum Maintenance Interval. Is this intended to imply that a component with the designated
attributes is not required to have any periodic maintenance? If so, the wording should more clearly
state “No periodic maintenance required” or perhaps “Maintain per manufacturers recommendations.”
Failure to clearly state the maintenance requirement for these components leaves room for
interpretation on whether a Registered Entity has a maintenance and testing program for devices
where the Standard has not specified a periodic maintenance interval and the manufacturer states
that no maintenance is required.
Yes
With such a complex standard as this, the FAQ and Supplementary Reference documents do aid the
Protection System owner in demystifying the requirements. But AEP holds strong doubt on how much
weight the documents carry during audits. It would be better to include them as an appendix in the
actual standard, but in a more compact version with the following modifications: Section 5 of the
Supplementary Reference, refers to “condition-based” maintenance programs. However, no where in
the standard is the term “condition-based” used in reference to defining ones PSMP. The
Supplementary Reference should be revised to remove reference to a condition-based PSMP;
alternatively the Standard could be revised to include the term “condition-based” within the Standard
Requirements and Table 1. Section 15.7, page 26, appears to have a typographical error “...can all be
used as the primary action is the maintenance activity...” Figure 2 is difficult to read. The figure is
grainy and the colors representing the groups are similar enough that it is hard to distinguish between
groups.
Yes
With such a complex standard as this, the FAQ and Supplementary Reference documents do aid the
Protection System owner in demystifying the requirements. But AEP holds strong doubt on how much
weight the documents carry during audits. It would be better to include them as an appendix in the
actual standard, but in a more compact version with the following modifications: The section “Terms
Used in PRC-005-2” is blank and should be removed as it adds no value. Section I.1 and Section
IV.3.G reference “condition-based” maintenance programs. However, no where in the standard is the
term “condition-based” used in reference to defining ones PSMP. The FAQ should be revised to
remove reference to a condition-based PSMP; alternatively the Standard could be revised to include
the term “condition-based” within the Standard Requirements and Table 1. The second sentence to
the response in Section I.1 appears to have a typographical error “... an entity needs to and perform
ONLY time-based...”.
Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2 should be removed.
Specifying calibration tolerances for every protection system component type, while a seemingly good
idea, represents a substantial change in the direction of the standard. It would be very onerous for
companies to maintain a list of calibration tolerances for every protection system component type and
show evidence of such at an audit. AEP believes entities need the flexibility to determine what
acceptance criteria is warranted and need discretion to apply real-time engineering/technician
judgment where appropriate. Three different types of maintenance programs (time-based,
performance-based and condition-based) are referenced in the standard or VSLs, yet the time-based
and condition-based programs are neither defined nor described. Certain terms defined within the
definition section (such as Countable Event or Segment) only make sense knowing what those three
programs entail. These programs should be described within the standard itself and not assume a
knowledge of material in the Supplementary Reference or FAQ. “Protective relay” should be a defined
term that lists relay function for applicability. There are numerous ‘relays’ used in protection and
control schemes that could be lumped in and be erroneously included as part of a Protection System.
For example, reclosing or synchronizing relays respond to voltage and hence could be viewed by an
auditor as protective relays, but they in fact perform traditional control functions versus traditional
protective functions. The Data Retention requirement of keeping maintenance records for the two
most recent maintenance performances is a significant hurdle for any owners to abide by during the
initial implementation period. The implementation plan needs to account for this such that Registered
Entities do not have to provide retroactive testing information that was not explicitly required in the
past.
Group
Western Area Power Administration
Brandy A. Dunn
Yes
Yes
No
No
No
Individual
Michael Moltane
ITC
Yes
The following question concerns Table 1-3. Our testing program includes “impedance testing” of the
current transformers (CTs) along with insulation testing of the wiring and CT secondary. Impedance
testing involves impressing an increasing voltage on the secondary of the CT (with primary open
circuited) until 1 (one) ampere flows. This method determines the “knee” of the saturation curve that
is used as a benchmark for comparison to previous testing and other CTs. This procedure has
successfully identified CT problems over the past several decades. We believe this procedure to be
adequate. Does the SDT agree that this method is sufficient to meet the testing requirements of Table
1-3 and that a current comparison is not needed in addition to this testing? Another variation of this is
for voltage device compliance. Table 1-3 indicates that we should verify the correct voltages are
received by the relay. This means that the VT would need to be energized and we would measure the
secondary voltages to compare with others. Power plant relay testing is normally performed during
plant outages when this measurement cannot be done. Some plants do not allow any testing while
the unit is on line. It would seem that the standard would be written to allow some other type of
testing to be performed other than the measurement test. For Table 1-1 Row 1, we believe the intent
is to verify that settings are as specified for non-microprocessor relays and microprocessor relays
alike. If this is the case, consider adding “Verify that settings are as specified” as a bullet under the
headings for non-microprocessor relays and microprocessor relays. Splitting the tables into separate
sections for Protective Relays, Communication Systems, VT and CTs, and Station D.C. Supply helped
the clarity.
Yes
Yes
Auxiliary Relay Testing: We repeat our objection to the 6 year requirement for testing of auxiliary
relays. The STD response to our previous objection was: Please see new Table 1-5. The SDT believes
that mechanical solenoid-operated devices share performance attributes (and failure modes) with
electromechanical relays and need to be tested at similar intervals. Performance-based maintenance
is an option to increase the intervals if the performance of these devices supports those intervals.
Auxiliary relays are, of course, electromechanical relays, but much less complicated than impedance,
differential or even time-overcurrent electromechanical relays. It has been our experience that trip
failures are rare and that our present 10 year control, trip tests, and other related testing are
sufficient in verifying the integrity of the scheme. Section 8.3 of the Supplemental Reference notes
statistical surveys were done to determine the maintenance intervals. Were auxiliary relays included
in these surveys in a such a way to verify that they indeed require a 6 year maintenance interval? We
recommend they be considered part of the control circuitry, with a 12 year test cycle. High Speed
Ground Switch Testing We repeat our recommendation that the standard state that a high speed
ground switch is an interrupting device. We also recommend that testing requirements for High-Speed
ground switches be clearly stated in the standard. Section 15.3 of the Supplemental Reference
contains the following: It is necessary, however, to classify a device that actuates a high-speed autoclosing ground switch as an interrupting device if this ground switch is utilized in a Protection System
and forces a ground fault to occur that then results in an expected Protection System operation to
clear the forced ground fault. The SDT believes that this is essentially a transferred-tripping device
without the use of communications equipment. If this high-speed ground switch is “…applied on, or
designed to provide protection for the BES…” then this device needs to be treated as any other
Protection System component. The control circuitry would have to be tested within 12 years and any
electromechanically operated device will have to be tested every 6 years. If the spring-operated
ground switch can be disconnected from the solenoid triggering unit then the solenoid triggering unit
can easily be tested without the actual closing of the ground blade. We disagree that a high-speed
ground switch can be adequately tested by disconnecting the solenoid triggering unit. The ability of
the trip coil to “operate the circuit breaker” must be verified per Table 1-5 Row 1. The ability of the
“solenoid triggering unit” to operate the ground switch should be required also. A high-speed ground
switch is a unique device. Its maintenance requirements should be specifically included in the
standard itself. Based on Draft 3 of the standard, this is a electromechanically operated device and
would have to be tested every 6 years. A logical location would be in Table 1-5. Is there test data to
support the test method of disconnecting the solenoid triggering unit?
No
Yes
5.1 We would like some further clarification on PRC-005-2 Draft 3, specifically on the statement in
Table 1-4 for unmonitored station DC supply with VLA batteries. In the table it is mentioned that we
are to perform either a capacity test every six years or verify that the station battery can perform as
designed by evaluating the measured cell/unit internal ohmic values to station battery baseline, the
latter statement is a little vague and needs further clarification with regards to the expectations from
the standard. Please describe an acceptable method of establishing a baseline “measured cell/unit
internal ohmic value” We would like to know what exactly is required. We measure the cell internal
ohmic value on an annual basis every 12 months, is that enough? What are the comparison
parameters with regards to battery baseline? At what percent should we look to replace the cell? 5.2
Is a battery system that only supplies the SCADA RTU considered part of the protective system if
alarms for the monitored protective systems utilize that SCADA RTU?
Individual
Kathleen Goodman
ISO New England Inc.
No
The wording “Component Type” is not necessary in each title. Just the equipment category should be
listed--what is now shown as “Component Type - Protective Relay”, should be Protective Relay.
However, Protective Relay is too general a category. Electromechanical relays, solid state relays, and
microprocessor based relays should have their own separate tables. So instead of reading Protective
Relay in the title, it should read Electromechanical Relays, etc. This will lengthen the standard, but
will simplify reading and referring to the tables, and eliminate confusion when looking for information.
The “Note” included in the heading is also not necessary. “Attributes” is also not necessary in the
column heading, “Component” suffices.
No
Because all the requirements deal with protective system maintenance and testing, violations could
directly cause or contribute to bulk electric system instability, etc., the VRFs should all be “High”. The
Time Horizons should all be “Operations Planning” because of the immediacy of a failure to meet the
requirements. For the R1 Lower VSL, include a second part to read: Failed to identify calibration
tolerances or other equivalent parameters for one Protection System component type that establish
acceptable parameters for the conclusion of maintenance activities. For the R1 Moderate VSL, suggest
similar wording as for the Lower VSL but specifying two Protection System component types. For the
R1 High VSL, suggest changing the wording of the 3rd part to be similar to the Lower VSL to match
the requirement and to cater for more than two Protection System component types. For the R3
Severe VSL, in part 3, replace “less” with fewer.
No
Yes
See response to Question 5 below.
In general, the standard is overly prescriptive and complex. It should not be necessary for a standard
at this level to be as detailed and complex as this standard is. Entities working with manufacturers,
and knowledge gained from experience can develop adequate maintenance and testing programs.
Why are “Relays that respond to non-electrical inputs or impulses (such as, but not limited to,
vibration, pressure, seismic, thermal or gas accumulation)…” not included? The output contacts from
these devices are oftentimes connected in tripping or control circuits to isolate problem equipment.
Due to the critical nature of the trip coil, it must be maintained more frequently if it is not monitored.
Trip coils are also considered in the standard as being part of the control circuitry. Table 1-5 has a
row labeled “Unmonitored Control circuitry associated with protective functions”, which would include
trip coils, has a “Maximum Maintenance Interval” of “12 Calendar Years”. Any control circuit could fail
at any time, but an unmonitored control circuit could fail, and remain undetected for years with the
times specified in the Table (it might only be 6 years if I understand that as being the trip test
interval specified in the table). Regardless, if a breaker is unable to trip because of control circuit
failure, then the system must be operated in real time assuming that that breaker will not trip for a
fault or an event, and backup facilities would be called upon to operate. Thus, for a line fault with a
“stuck” breaker (a breaker unable to trip), instead of one line tripping, you might have many more
lines deloaded or tripped because of a bus having to be cleared because of a breaker failure initiation.
The bulk electric system would have to be operated to handle this contingency. In reference to the
FAQ document, Section 5 on Station dc Supply, Question K, clarification is needed with respect to dc
supplies for communication within the substation. For example, if the communication systems were
run off a separate battery in separate area in a substation, would the standard apply to these
batteries or not? To define terms only as they are used in PRC-005-2 is inviting confusion. Although
they may be unique to PRC-005-2, some or all of them may be used in future standards, some
already may be used in existing standards, and may or may not be deliberately defined. Consistency
must be maintained, not only for administrative purposes, but for effective technical communications
as well. What is the definition of “Maintenance” as used in the table column “Maximum Maintenance
Interval”? Maintenance can range from cleaning a relay cover to a full calibration of a relay. A control
circuit is not a component, it is made up of components. Sub-requirement 1.5 needs to be clarified. It
is not clear what “Identify calibration tolerances or other equivalent parameters…” means, and may
be subject to different interpretations by entities and compliance enforcement personnel. In the
Implementation plan for Requirement R1, recommend changing “six” to fifteen. This change would
restore the 3-month time difference that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require regulatory approval. It will ensure
equity for those entities located in jurisdictions that do not require regulatory approval, as is the case
in Ontario. The ‘box’ for “Monitored Station dc supply…” in Table 1-4 is not clear. It seems to continue
to the next page to a new box. There are multiple activities without clear delineation.
Group
TransAlta Centralia Generation Partnership
Joanna Luong-Tran
Yes
No
Please provide acronyms list and its explanations in the standard.
No
No
No
Individual
Rick Koch
Nebraska Public Power District
Yes
No
VRF’s: The definition of a Medium Risk Requirement included on page 8 of the SAR states: "A
requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system." The PSMP
does not "directly" affect the electrical state or the capability of the bulk electric system. A failure of a
Protection System component is required to "directly" affect the BES. Therefore, the PSMP has only
an "indirect" affect on the electrical state or the capability of the BES. Requirements R1 through R3
and their subparts are administrative in nature in that they are comprised entirely of documentation.
Therefore, I recommend changing the Violation Risk Factor of Requirements R1, R2, and R3 to Lower
to be consistent with the Violation Risk Factors defined in the SAR. VSL’s: R2: Tables 1-1 through 1-5
refers to time-based maintenance programs. I recommend changing "condition-based" to "timebased" in all four severity levels. SAR Attachment B - Reliability Standard Review Guidelines states
that violation severity levels should be based on the following equivalent scores: Lower: More than
95% but less than 100% compliant Moderate: More than 85% but less than or equal to 95%
compliant High: More than 70% but less than equal to 85% compliant Severe: 70% or less compliant
I recommend revising the percentages of the violation severity levels to be consistent with the SAR.
R3: The performance-based maintenance program identified in PRC-005 Attachment A provides the
requirements to establish the technical justification for the initial use of a performance-based PSMP
and the requirements to maintain the technical justification for the ongoing use of a performancebased PSMP. However, it appears the VSLs for Requirement R3 only addresses the ongoing use of the
technical justification. I recommend revising the VSLs for R3 to include the initial use of the technical
justification. Item 2) of R3 Severe VSL is a duplicate of Item 2) of R3 Lower VSL. This item is
administrative in nature therefore I recommend deleting Item 2) from R3 Severe VSL. The first and
third bullets of item 4) of R3 Severe VSL are administrative in nature and should be moved to the
Lower VSL R4: SAR Attachment B - Reliability Standard Review Guidelines states that violation
severity levels should be based on the following equivalent scores: Lower: More than 95% but less
than 100% compliant Moderate: More than 85% but less than or equal to 95% compliant High: More
than 70% but less than equal to 85% compliant Severe: 70% or less compliant I recommend revising
the percentages of the violation severity levels to be consistent with the SAR.
Yes
The Supplemental Reference Documents identified are unapproved and in draft form. I believe that
only approved documents should be referenced in the Standard. Therefore, I recommend updating
the Supplemental Reference Documents section with approved versions of the documents.
No
Yes
Definitions: The PSMP definition inappropriately extends the maintenance program to include
corrective maintenance. The first bullet of the Detailed Description section of the SAR specifically
states: "Analysis of correct operations or misoperations may be an integral part of condition-based
maintenance processes, but need not be mandated in a maintenance standard." The comment in the
SAR was directed toward the Purpose of PRC-017 since it is the only one of the applicable PRC
standards that included corrective measures in its Purpose. However, the concept of not including
corrective maintenance in a maintenance standard should apply to all of the applicable PRC
standards. The same statement from the SAR identified above was also included in the NERC SPCTF
Assessment of Standards referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment of
the Standards identified the need to expand the maintenance and testing program to include
corrective maintenance. I recommend deleting the words "and proper operation of malfunctioning
components is restored." from the first sentence of the PSMP definition. I believe that failure to do so
exceeds the scope of the SAR. The definition of a Countable Event should clearly state whether or not
multiple conditions on a single component will count as a single Countable Event or as multiple
Countable Events. For example, a single relay fails its undervoltage setting and its under frequency
setting. Is this one Countable Event or two Countable Events? Applicability Part 4.2.2: The ERO does
not establish underfrequency load-shedding requirements. Those requirements will be established by
Reliability Standard PRC-006-1 when it is approved by FERC. I recommend changing Accountability
Part 4.2.2. to "...installed to provide last resort system preservation measures." (Note this wording is
consistent with the Purpose of PRC-006-0.) Applicability Part 4.2.5.4 and 4.2.5.5: Station Service
transformers provide energy to plant loads and not the BES. If these plant transformers are included,
why not include the rest of the plant systems? I recommend deleting Applicability Part 4.2.5.4 and
4.2.5.5. Requirement R1 Part 1.2: The wording of the first sentence is unclear about what information
is required. For example, I could state in my PSMP that: "All Protection System component types are
addressed through time-based, performance-based, or a combination of these maintenance methods"
and be compliant with the Requirement. I recommend re-wording the first sentence to state: "Identify
which maintenance method is used to address each Protection System component type. Options
include time-based, performance-based (per PRC-005 Attachment A), or a combination of time-based
and performance-based (per PRC-005 Attachment A)." Note that PRC-005 Attachment A does not
address a combination of maintenance methods and therefore the second reference in the first
sentence should be removed if the original wording is retained. Requirement R1 Part 1.4: The column
titles in Tables 1-1 through 1-5 have been revised to “Component Attributes” and “Activities”. I
recommend changing "monitoring attributes" to "component attributes" and "maintenance activities"
to "activities" to be consistent with the Tables. Requirement R1 Part 1.5: Maintenance acceptance
criteria for a given Protection System component type may very depending on the manufacturer,
model, etc.. Including all acceptance criteria in the PSMP document will over-complicate the program
document. I recommend clarifying Part 1.5 to allow the incorporation of device-specific acceptance
criteria in the applicable evidentiary documentation. One possible option is to add a second sentence
as follows: "The calibration tolerances or other equivalent parameters may be included with the
maintenance records." Note that a personal preference would be to use the phrase “acceptance
criteria” instead of “calibration tolerances or other equivalent parameters”. Requirement R4: The
PSMP definition inappropriately extends the maintenance program to include corrective maintenance.
The first bullet of the Detailed Description section of the SAR specifically states: "Analysis of correct
operations or misoperations may be an integral part of condition-based maintenance processes, but
need not be mandated in a maintenance standard." The comment in the SAR was directed toward the
Purpose of PRC-017 since it is the only one of the applicable PRC standards that included corrective
measures in its Purpose. However, the concept of not including corrective maintenance in a
maintenance standard should apply to all of the applicable PRC standards. The same statement from
the SAR identified above was also included in the NERC SPCTF Assessment of Standards referenced in
the SAR. Neither the SAR nor the NERC SPCTF Assessment of the Standards identified the need to
expand the maintenance and testing program to include corrective maintenance. I recommend
deleting the words "including identification of the resolution of all maintenance correctable issues"
from the first sentence of the Requirement. I believe that failure to do so exceeds the scope of the
SAR. Requirement R4 Part 4.2: What is considered sufficient verification of parameters? Does this
require an engineer or technician signature or simply an indication of pass/fail? The PSMP definition
inappropriately extends the maintenance program to include corrective maintenance. The first bullet
of the Detailed Description section of the SAR specifically states: "Analysis of correct operations or
misoperations may be an integral part of condition-based maintenance processes, but need not be
mandated in a maintenance standard." The comment in the SAR was directed toward the Purpose of
PRC-017 since it is the only one of the applicable PRC standards that included corrective measures in
its Purpose. However, the concept of not including corrective maintenance in a maintenance standard
should apply to all of the applicable PRC standards. The same statement from the SAR identified
above was also included in the NERC SPCTF Assessment of Standards referenced in the SAR. Neither
the SAR nor the NERC SPCTF Assessment of the Standards identified the need to expand the
maintenance and testing program to include corrective maintenance. I recommend re-wording
Requirement 4, Part 4.2 to state: "Verify that the components are within the acceptable parameters
established in accordance with Requirement R1, Part 1.5 at the conclusion of the maintenance
activities." I believe that failure to do so exceeds the scope of the SAR. Measurement M2: Can a
single specification document suffice for similar relay types such as one document for SEL relays? For
trip circuit monitoring can a standard document be used for a group of similar schemes ?
Measurement M4: I assume this is not an all inclusive list of potential forms of evidence. Please clarify
what is meant by "such as". Does this mean that: 1) Any one item is sufficient?; 2) Certain
combinations of evidence are necessary? If so, what combinations?; 3) Are other items that are not
identified here acceptable? Measurement M4 repeatedly refers to "dated" evidence. However, current
audit expectations include either performer signatures or initials on the evidence in addition to the
dates. Please revise Measurement M4 to clearly state the expectations regarding performer signatures
or initials on the evidence documents. The PSMP definition inappropriately extends the maintenance
program to include corrective maintenance. The first bullet of the Detailed Description section of the
SAR specifically states: "Analysis of correct operations or misoperations may be an integral part of
condition-based maintenance processes, but need not be mandated in a maintenance standard." The
comment in the SAR was directed toward the Purpose of PRC-017 since it is the only one of the
applicable PRC standards that included corrective measures in its Purpose. However, the concept of
not including corrective maintenance in a maintenance standard should apply to all of the applicable
PRC standards. The same statement from the SAR identified above was also included in the NERC
SPCTF Assessment of Standards referenced in the SAR. Neither the SAR nor the NERC SPCTF
Assessment of the Standards identified the need to expand the maintenance and testing program to
include corrective maintenance. I recommend deleting the words: "and initiated resolution of
identified maintenance correctable issues" from the last sentence of Measurement M4. I believe that
failure to do so exceeds the scope of the SAR. Compliance Part 1.3: Tables 1-1 through 1-5 refers to
time-based maintenance programs. I recommend changing "performance-based" to "time-based" in
the last sentence of the third paragraph. The last paragraph of Part 1.3 of the Compliance Section
states: "The Compliance Enforcement Authority shall keep the last periodic audit report and all
requested and submitted subsequent compliance records." This appears to be a requirement of the
Compliance Enforcement Authority however they are not identified in Section 4 Applicability of the
Standard. It is also in conflict with the SAR Attachment B - Reliability Standard Review Guidelines
which states on page SAR-10: "Do not write any requirements for the Regional Reliability
Organization. Any requirements currently assigned to the RRO should be re-assigned to the applicable
functional entity." I recommend deleting the last paragraph of Part 1.3 of the Compliance Section to
avoid conflict with the SAR. Table 1-1: The Activity of row 1 states: “Verify operation of the relay
inputs and outputs that are essential to …”. Please clarify what is meant by “operation of” the relay
inputs and outputs. What is the criteria to determine if something is “essential”? The first line of row 2
has a double colon. Please delete one of them. For the second bullet of row 2 column 1, please clarify
what is meant by the last part of this sentence "that are also performing self monitoring and
alarming" and how it relates to the voltage and current sampling required. It appears the self
monitoring is required in the first bullet. For the first bullet of row 2 column 3, many relay settings
may not be essential to the protective function of the relay. I recommend revising the first bullet to:
“Settings that are essential to the proper function of the protection system are as specified.” The
format of the Activities column for all three rows are different. Please reformat them to be consistent.
My preference is the second row. Table 1-2: Row 1 Column 2, verifying the functionality of
communications systems on a 3 calendar months basis is excessive and unnecessary. Suggest
changing the Maximum Maintenance Interval to either 6 calendar months or semi-annual. Row 2
Column 1, please provide examples of typical communications systems that fit into this category,
e.g.,Mirror Bit or Guard systems? The words “such as” are used repeatedly. Please clarify what is
meant by "such as". Is this left up to the Utility to define in their PSMP? Table 1-5: The Activity for
row 1 requires verification that each trip coil is able to operate the device. If a control circuitry
contains multiple trip coils, it is not always possible to determine which trip coil energized to trip the
device. I recommend changing "each trip coil" to "at least one trip coil". Please clarify what is meant
by an "Electromechanical trip" device in row 3. Row 3 column 3, does this mean verify the trip contact
on the device operates properly but not verify the trip circuit wiring from this contact to the trip coil
since the trip circuit is tested in the row below? It is difficult to separate the meaning in these two
rows. Row 4 column 3 requires verification of all paths of the control and trip circuits. Please clarify if
this includes the control circuitry of Protection Systems located at the other end of a line if the device
utilizes a remote trip scheme?
Group
Bonneville Power Administration
Denise Koehn
Yes
Yes
Yes
Some of the maintenance tasks need to be defined: - The state of charge of each individual cell may
need to be better defined. There are means to verify the state of charge of the entire bank, but not
each individual cell. - Battery continuity needs to be defined. - There is no mention to what the limits
are for the "other equivalent parameters" when performing maintenance activities, just that they
need to be identified. There are a large number of battery models which creates a large contrast of
parameters, which cannot be grouped together. It is also difficult to get baseline values for older
battery models which could result in moving baselines until they become more accurate as the
database is populated. - If corrective actions are required, is there a maximum allowable duration for
when they need to be resolved? The maximum allowable maintenance for station batteries
(impedance testing and performance/service testing) is too frequent and suggest an extension or
alternative testing methods to stay in compliance. The frequency with which BPA performs the 18
month maintenance tasks as prescribed in the standard are on a 24 month interval along with visual
inspections and voltage measurements monthly. BPA has seen success with this maintenance
program with the ability to identify suspect cells or entire banks with adequate time to perform
corrective actions such as repairs or replacements. BPA also does not perform routine capacity
testing, this is an as required maintenance task to confirm/validate our other test results if needed.
BPA would like to see clarification for these issues before we can fully support this standard.
Individual
Armin Klusman
CenterPoint Energy
Yes
Yes
The need for an FAQ document, in addition to an extensive Supplementary Reference document,
illustrates the complexity and impracticality of the proposed Standard. CenterPoint Energy does not
support the development of an additional type of document, that is, the FAQ document. CenterPoint
Energy recommends eliminating the FAQ document and using only a Supplementary Reference”
document. This would also provide the benefit of not having contradictory information in the two
documents.
Yes
(a) CenterPoint Energy cannot support this proposed Standard. Any standard that requires a 35 page
Supplementary Reference document and a 37 page FAQ – Practical Compliance and Implementation
document, in addition to extensive tables in the Standard, is much too prescriptive and complex to be
practically implemented. (b) CenterPoint Energy is opposed to approving a standard that imposes
unnecessary burden and reliability risk by imposing an overly prescriptive approach that in many
cases would “fix” non-existent problems. To clarify this last point, CenterPoint Energy is not asserting
that maintenance problems do not exist. However, requiring all entities to modify their practices to
conform to the inflexible approach embodied in this proposal, regardless of how existing practices are
working, is not an appropriate solution. Among other things, requiring entities to modify practices
that are working well to conform to the rigid requirements proposed herein carries the downside risk
that the revised practices, made solely to comply with the rigid requirements, degrade reliability
performance. (c) CenterPoint Energy is very concerned that a large increase in the amount of
documentation will be required in order to demonstrate compliance - with no resulting reliability
benefit. CenterPoint Energy believes this Standard could actually result in decreasing system
reliability, as the Standard proposes excessive maintenance requirements. The following is included in
the Supplementary Reference document (page 8): “Excessive maintenance can actually decrease the
reliability of the component or system. It is not unusual to cause failure of a component by removing
it from service and restoring it.” System reliability can be even further reduced by the number of
transmission line and autotransformer outages required to perform maintenance. (d) The following is
included in the FAQ – Practical Compliance and Implementation document: “PRC-005-2 assumes that
thorough commission testing was performed prior to a protection system being placed in service.
PRC-005-2 requires performance of maintenance activities that are deemed necessary to detect and
correct plausible age and service related degradation of components such that a properly built and
commission tested Protection System will continue to function as designed over its service life.”
CenterPoint Energy believes some proposed requirements, such as wire checking a relay panel, do not
conform to this statement. CenterPoint Energy’s experience has been that panel wiring does not
degrade with age and service and that problems with panel wiring, after thorough commissioning, is
not a systemic issue.
Individual
Andrew Pusztai
American Transmission Company
Yes
Yes
No
Yes
FAQ Protective Relays 2.D: The last sentence is not consistent with the discussions at the “March
2010, Standard Drafting Team Meeting, Project 2007-17”. The understanding from that meeting was
that the relay settings would be verified that the “as left” settings were the same as the “as found”
settings and that the intent was not to verify the settings against a Master Record. Therefore the
intent is that the tester will verify that no setting changes were made as part of the testing process.
Please include this clarification with the language in the standard. FAQ Group by Type of Maintenance
Program 2.B: We agree with the use of either the in-service date or the commissioning date to start
the initial due date calculation for maintenance. Please include this clarification with the language in
the standard.
Yes
ATC recognizes the substantial efforts that the SDT has made on PRC-005 and appreciate the SDT’s
modifications to this Standard based on previous comments made. ATC looks forward to continuing to
have a positive influence on this process via the comment process, ballots and interaction with the
SDT. ATC was very close to an affirmative vote on this Standard prior to the unanticipated changes
that appeared in this most recent posting. These changes introduce a significant negative impact from
ATC’s perspective. Therefore, ATC is recommending a negative ballot in the hope that our concerns
regarding R 1.5 and R 4.2 and other clarifications will be included with the standard The two items
within the proposed Standard that we take exception to are not directly related to implementing FERC
Order 693. Rather, it is the overly prescriptive nature with respect to the “how” as outlined in the
proposed Standard that ATC takes exception... To improve and find the proposed Standard
acceptable, ATC would like to see the following modifications: 1. Change the text to require the
actuation of a single trip coil (row 1 of table 1.5). This would satisfy the intent to exercise the
mechanism on a regular schedule, given that the mechanism binding is a much more likely source of
a coil failure. The balance of trip coils could then be tested as part of routine breaker maintenance. 2.
Eliminate the additional requirements introduced by the addition of R1.5 and the associated
modifications to R4.2. The additional documentation required for the range of each element is
typically incorporated into the pass/fail mechanism of the existing test equipment (which is reflective
of the manufacturer recommendations) used to conduct these tests. Therefore, requiring the
assembly of this additional documentation from each entity would: a. Be duplicative and voluminous
as it would require us to track thousands of additional data points due to the variability in element
ranges by relay manufacturer, model number and vintage. b. Not add to the reliability of the system
as this function is already being performed on a collective basis.
Group
Santee Cooper
Terry L. Blackwell
Yes
No
No
No
We do not agree with the addition of Requirements 1.5 and 4.2 without work on or review by the
Power System Maintenance and Testing Drafting Team. While some maintenance activities on some
component types (such as calibration testing of electromechanical relays) translate inherently well
into these requirements,the requirements of tolerances and documentation do not fit as well to all
maintenance activities on other types of equipment considered part of the protective system. These
requirements need to be worked on through the drafting team to make them viable and effective for
all protective system component types.
Individual
Eric Salsbury
Consumers Energy
Yes
Yes
No
No
Yes
1. Table 1-3 states, “are received by the protective relays”. Does this require that the inputs to each
individual relay must be checked, or is it sufficient to verify that acceptable signals are received at the
relay panel, etc? 2. Relative to Table 1-5, the activities will likely require that system components be
removed from service to complete those activities. If the changes to the BES definition (per the FERC
Order) causes system elements such as 138 kV connected distribution transformers to be considered
as BES, these components can not be removed from service for maintenance without outaging
customers. The standard must exempt these components from the activities of Table 1-5 if the
activity would result in deenergizing customers. 3. For the component types addressed in Tables 1-3
and 1-5, the requirements may cause entities to identify components very differently than they are
currently doing, and doing so may take several years to complete. The Implementation Plan for R1
and R4 is too aggressive in that it may not permit entities to complete the identification of discrete
components and the associated maintenance and implement their program as currently proposed. We
propose that the Implementation Plan specifically address the components in Table 1-3 and 1-5 with a
minimum of 3 calendar years for R1 and 12 calendar years after that for R4. 4. As for the interval in
Table 1-4 regarding the battery terminal connection resistance, we believe that an 18-month interval
is excessively frequent for this activity, and suggest that it be moved to the 6-calendar-year interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections every 4-years, rather
than measuring the terminal connection resistance to determine if the connections are sound.
Disregarding the interval, would this activity satisfy the “verify the battery terminal connection
resistance” activity?
Group
NextEra Energy
Silvia Parada Mitchell
Yes
Yes
No
No
Yes
The draft standard is too perscriptive. Requirement R1, Part 1.5 would be overwhelming if approved.
Requirement R1, Part 1.5 should be deleted. Requirement R4, Part 4.2 phrase "established in
accordance with Requirement R1, Part 1.5" should be deleted. The standard without these additional
requirements would be sufficient to establish that the Protection System is maintained and protects
the BES. Table 1-2 Component Type Communications Systems Maximum Maintenance Interval of 3
Calendar Months to verify that the communications system is functional for any unmonitored
communications system is unyielding. Most communication failures are caused by power supply
failures which Next Era does monitor. Based on experience and monitoring of communication power
supplies, 12 calendar months would be adequate. The maximum maintenance interval should be
changed from 3 calendar months to 12 calendar months. Table 1-4, Component Type Station dc
Supply Maximum Maintenance Interval of 3 Calendar Months to inspect electrolyte levels on “Any
unmonitored station dc supply not having the monitoring attributes of a category below. (excluding
UFLS and UVLS)” is too stringent. Verifying battery charger float voltage every 18 calendar months is
sufficient to prevent excessive gassing and water loss of battery cells. The maximum maintenance
interval should be changed from 3 calendar months to 6 calendar months. Table 1-4, Component
Type Station dc Supply Maximum Maintenance Interval of 3 Calendar Months to measure the internal
ohmic values on “Unmonitored Station dc supply with Valve Regulated Lead-Acid (VRLA) batteries
that does not have the monitoring attributes of a category below. (excluding UFLS and UVLS)” is too
stringent. With the standard’s requirement to verify the float voltage every 18 calendar months,
measuring the internal ohmic values every 6 calendar months would be adequate. The maximum
maintenance interval should be changed from 3 calendar months to 6 calendar months.
Individual
Bill Shultz
Southern Company Generation
Yes
Yes
Yes
--- On Page 4, Paragraph 2.2 is no longer proposed – the paragraphs just before 2.2 need to be
revised. --- On Page 12, item 7, the phrase “operational trip test” is not used in the standard. Please
consider using this phrase in the standard. --- On Pages 14-15, several paragraphs describing the
contents of Sections 9, 10, 11, & 13 are given – these appear to be out of place and don’t seem to
belong here (just before “9. Performance-Based Maintenance Process). --- On Page 24, correct the
bulleted Protection System Definition to match the most recent definition. --- On Page 29, please
improve the clarity of Figure 2. --- On Page 31, please revise the flowchart references to R4.4.1 and
R4.4.2. --- Please correct the following formatting: Page 2, Table of Contents; Page 18, the bulleted
item list; Page 23, add a space before the last paragraph.
Yes
--- On Page 3, please revise the flow chart references to R4.4.1 and R4.4.2. Also, add (Attachment A)
to the “Performance Based” label. --- On Page 7, Section I, correct the reference of R4.3 to R4.2.
Also, revise the last paragraph in Section I to the following: The entity should assure that the
component performance is acceptable at the conclusion of the maintenance activities or initiate
resolution of any indentified maintenance correctable issues. --- On Page 7, Section J, correct the
reference of R4.3 to R4.2. --- On Page 10, Section D, a reference is made to “trip test” Table 1.
Should this be Table 1-5? The exact phrase “trip test” is not used in the standard. Should it be? --On Page 10, Section e, the phrase “functional (or operational) trip test” is not used in the standard –
should it be? --- On Page 11, Section 5A, correct the reference of Table 1 to Table 1-4 in the Station
Battery and Emerging Technologies paragraph. --- On Page 12, Section B, correct the reference of
Table 1 to Table 1-4. (2X) --- On Page 13, Section F, correct the reference of Table 1 to Table 1-4.
(1X) --- On Page 14, Section G, correct the reference of Table 1 to Table 1-4. (3X) --- On Page 14,
Section G, change the text “The first maintenance activity” to The capacity testing activity”. --- On
Page 14, Section G, change the text “The second maintenance activity”, to The internal ohmic
measurement activity”. --- On Page 14, Section H, correct the reference of Table 1 to Table 1-4. (1X)
--- On Page 17, Section C, correct the reference of Table 1 to Table 1-5. (1X) --- Please address what
is meant by “Battery terminal connection resistance” on Page 14, Table 1-4 of the standard.
Yes
• Please consider retaining the definitions stated to be moved to the NERC Glossary – they would be
valuable to entities in the standard. • On Page 5, Section 1.2, please consider changing “or a
combination of these maintenance methods (per PRC-005-Attachment A).” to “or a combination of
these two maintenance methods.” • On Page 5, Section 1.5: recommend deleting this section - the
subjectivity of what is an acceptable value for component testing makes this requirement unvaluable. • On Page 5, Section 4.2, it is recommended that the requirement be the following: Either
verify that the component performance is acceptable at the conclusion of the maintenance activities
or initiate resolution of any identified maintenance correctable issue. • On Page 5, Measure M1,
replace 1.5 with 1.4 (after eliminating Requirement 1.5) • On Page 6, Section 1.3, replace the
existing Data Retention text with the following: The TO, GO, and DP shall each retain documentation
for the longer of the these time periods: 1) the two most recent performances of each distinct
maintenance activity for the Protection System component, or (2) all performances of each distinct
maintenance activity for the Protection System component since the previous scheduled audit date.
The Compliance Enforcement Authority shall keep the last periodic audit report and all requested and
submitted subsequent compliance records. • On Page 10, Section F, please correct the revision
information for the documents listed. • On Pages 14 & 15, Table 1-4, move the bottom row to the
next page so that it is easier to see that the maintenance activities are an “either/or” option. • On
Page 17, Table 1-5, it seems that the 12 calendar year interval activities would automatically be
included in the 6 calendar year activity for verifying the electrical operation of electromechanical trip
and auxiliary devices. Is the 12 year requirement superfluous? • On Page 19, Attachment A, it is
recommended to delete the footnote #1 since the definition is given already on Page 2.
Group
NERC Staff
Mallory Huggins
Yes
Yes
In section 2.3, NERC staff recommends noting that the present NERC Glossary definition of Bulk
Electric System will be revised in response to FERC Order No. 743. In Section 2.4, NERC staff
recommends changing the phrase “relays that use measurements of voltage, current, frequency
and/or phase angle” with “protective relays that respond to electrical quantities” for consistency with
recent changes to the proposed definition of Protection System.
Yes
At a minimum, the response to Question II.1.A should be revised to reflect the present revision of
Requirement R1. In the current proposed response to the FAQ, the answer refers to text that was
deleted from Requirement R1 in the current posting of the standard; i.e., this standard covers
protective relays “that use measurements of voltage, current and/or phase angle to determine
anomalies and to trip a portion of the BES.” The removal of this text from Requirement R1 makes it
less clear whether the standard applies to reclosing functions and protective functions used to
supervise automatic or manual closing of a circuit breaker to ensure the voltage magnitude and phase
angle difference are within specified tolerances. The drafting team also should consider whether
additional specificity is required to ensure applicability is clearly defined within the standard. In the
response to Question II.2.H, NERC staff notes that the word “than” should be changed to “then” in
the phrase “If the component no longer performs Protection System functions than...” In the response
to Question II.2.I, NERC staff recommends noting that “When a failure occurs in a protection system,
power system security may be compromised, and notification of the failure must be conducted in
accordance with relevant NERC standard(s).” The recommended text is included in the Supplementary
Reference Document and inclusion in the FAQ response provides consistency and highlights
obligations in other standards necessary for BES reliability. In the response to Question III.1.A, NERC
staff recommends noting that the present NERC Glossary definition of Bulk Electric System will be
revised in response to FERC Order No. 743. In the response to Question III.3.A, NERC staff
recommends a more generic reference to NERC UFLS requirements in place of the reference to PRC007-0, as PRC-007 will be retired pending FERC approval of PRC-006-1. In the response to Question
IV.1.A (third paragraph), NERC staff recommends changing the phrase “that are certainly coming to
the industry” to “may be coming to the industry” for consistency with the change to the response to
Question V.4.A. Both questions appear to address the same or similar concerns.
Yes
Commissioning (Initial) Testing: During development of PRC-005-2, NERC staff has observed a trend
in system disturbances involving Protection System problems that should have been identified and
corrected during commissioning (initial) testing. While NERC staff recognizes that the addition of
commissioning testing may be unrealistic at this stage in the standard drafting process, we want to
emphasize its importance. If the SDT chooses to leave commissioning testing out at this juncture, we
plan to pursue other avenues to ensure its eventual inclusion through a separate standards project.
NERC staff agrees with the SDT’s opinion that without commissioning testing, a registered entity
responsible for compliance with this standard cannot provide proof of its interval testing period as
required by the standard. As soon as the entity puts the protective scheme into service, time “0” for
interval testing begins. The next testing interval would be some specific number of years in the future
from time “0.” An entity’s failure to properly commission new protection system equipment has
caused or exacerbated several recent events, greatly impacting BPS reliability. The following are
examples of errors that were not detected during commissioning. These undetected errors were
observed by NERC staff during event analysis and investigation activities: •Failure to apply correct
relay settings. This has occurred repeatedly and has been due to improper procedures, poor
document control, misapplication or miscalibration of the relay, or a combination of the above.
•Failure to install the proper CT or PT ratio occurred due to poor document control practices and
resulted in an undesired protection system response after the equipment was placed in service.
•Failure to conduct a functional test of new control circuits to the schematic diagram resulted in an
undesired protection system response after equipment was placed in service. •An incorrect CT ratio
was not detected during commissioning, and the equipment was subsequently placed in service.
Because in-service testing was not performed, the error remained undetected until the relay
misoperated during a fault. Many of the above conditions can remain undetected for extended
periods, until they are revealed by a relay misoperation during fault or heavy load conditions. The
affects resulting from these cases could have been prevented with proper commissioning testing. We
believe that by requiring commissioning testing for new protection system equipment, the reliability of
BPS would be improved. --- Requirement 2: In Requirement 2, it is unclear what is meant by “shall
verify those components possess the monitoring attributes identified in Tables 1-1 through 1-5 in its
PSMP” because the use of terms in the Requirement is not consistent with the column headings used
in Tables 1-1 through 1-5. It also is not clear that components need not possess all attributes; rather,
they must possess all attributes consistent with the Maximum Maintenance Interval specified in an
entity’s PSMP. NERC staff recommends revising R2 to provide additional clarity as follows: “Each
Transmission Owner, Generator Owner, and Distribution Provider that uses maintenance intervals for
monitored Protection Systems described in Tables 1-1 through 1-5, shall verify those components
possess the monitoring attributes Component Attributes identified in the first column of Tables 1-1
through 1-5 consistent with the Maximum Maintenance Interval specified in its PSMP.”
Group
FirstEnergy
Sam Ciccone
Yes
While we agree that the clarity of the tables has improved, there are still items that warrant further
clarity. In Table 1-1, references to "Verify acceptable measurement of power system input values" is
made for microprocessor relays on 6 and 12 calendar year intervals. Wouldn't this also be prudent on
non-microprocessor based relays as well on the 6 year interval? Also, in Table 1-3, "Verify that
acceptable measurement of the current and voltage signals are received by the protective relays" is
shown on a 12 calendar year interval. What is the difference between this activity and the similar
activity performed in Table 1-1? In Table 1-4, this table is complex and the detailed maintenance
activities in this particular table is puzzling when compared to the more generic detail in the other
tables within this section. For example, an incorrect operation due to a deteriorated signal from a CT
or VT has a higher probability than a failure of a battery bank to perform when called upon. In Table
1-5, Please provide clarity on the "Unmonitored Control circuitry associated with protective functions"
component attribute. This would most likely be an FAQ item.
No
The VSL for R2 need to be adjusted since "Condition Based Maintenance" has been removed from the
standard.
Yes
1. The discussions surrounding implementing the PSMP on pages 10 and 11 of the clean copy are
troublesome for the following reasons. On Pg. 10, under Sec. 8.1, the 4th bullet item states "If your
PSMP (plan) requires more activities then you must perform and document to this higher standard".
This statement's use of the word "must" implies that an entity will be audited to their documented
maintenance practices, even if those practices exceed the requirements of the PRC-005 standard. The
PRC-005 standard, and any standard, details the minimum requirements that must be met to achieve
a certain reliability goal. For example, if an entity's program states that it will do maintenance on a
relay every 4 years, but the standard only requires maintenance every 6 years, the entity shall be
held compliant to the standard's 6 year interval. If the entity in this example decides that in year 4 it
must delay its maintenance to year six, that should be allowable since the standard PRC-005-2
requires maintenance every 6 years. 2. Since the standard no longer discusses Condition Based
Maintenance, it should be removed from the reference document for consistency.
No
Yes
REQUIREMENTS Requirement R1 – Subpart 1.5 – We do not support this subpart for the following
reasons and offer the following suggestions: To satisfy R1.5, a calibration tolerance or other
equivalent parameter would have to be established for each item included in the definition. Many
devices which may have similar functionality may also have different performance criteria that would
preclude the use of a "one size fits all" calibration tolerance. Many of these criteria are provided by
the manufacturer and often vary by manufacturer for a similar device. It would be very difficult to
specify in your program all of the calibration tolerances or other equivalent parameters associated
with the protection system components Therefore, we suggest the team delete Subpart 1.5 of Req.
R1, and revise Subpart 4.2 of Req. R4 to read: "Initiate resolution of any identified maintenance
correctable issues at the conclusion of maintenance activities for Protection System components."
IMPLEMENTATION PLAN On pg. 2 of the implementation plan, under "Retirement of Existing
Standards", the statement "The existing standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-0170 shall be retired upon regulatory approval of PRC-005-2" is not accurate. Since the new PRC-005-2
standard allows for at least 12 months to become compliant with Requirement R1 – establish a
Protection System Maintenance Program (PSMP) -the existing standards are still effective during this
time. Additionally, we have concerns with the "General Considerations" describing protocols for
compliance audits conducted during the allowed 12 month development period of the PSMP and that
entities could specify for "each component type" whether maintenance of that component is being
performed according to its maintenance program under the "retired" PRC maintenance standards or
the new PRC-005-2 standard. In our view, this creates a level of compliance complexity for both the
Registered Entity and Regional Entity that should be avoided in the transition to PRC-005-2.
FirstEnergy proposes that the Implementation Plan state that the existing standards remain in effect
for one year past applicable approval (NERC Board or Regulatory) and that they are retired coincident
with the one-year transition to Requirement R1 of PRC-005-2 which would establish all Registered
Entities having a new PSMP per the expectations of PRC-005-2. At that time all entities would be
required to be under the new PRC-005-2 standard and begin implementing their PSMP per the
phased-in Implementation Plan for the remaining requirements. To summarize, per our above
discussion we propose the team perform the following: 1. Revise the Implementation Plan section
titled "Retirement of Existing Standards" section to read as follows: "The existing Standards PRC-0051, PRC-008-0, PRC-011-0 and PRC-017-0 shall be retired on the first day of the first calendar quarter
twelve months following applicable regulatory approvals, or in those jurisdictions where no regulatory
approval is required, on the first day of the first calendar quarter 12 months following the Board of
Trustees adoption" 2. Remove the entire "General Considerations" section from the Implementation
Plan. The bulleted item under the section titled "Implementation plan for R1" has a discrepancy in the
time allowed to implement R1 between entities applicable to regulatory approval of the standard
versus those in jurisdictions where no regulatory approval is needed and base their adherence per the
Board of Trustee adoption. Please revise to reflect a 12 month transition period for each.
DEFINITIONS Maintenance Correctable Issue - This is a maintenance standard and this concept gets
into the long term repair activities. Is this really appropriate in this standard? If NERC feels repairing
is critical to BES reliability, then they should probably initiate a standard in that area. Component –
Regarding the phrase "local zone of protection", why is this in quotes? Is there a narrow definition for
this? If so, this term should be defined also. DATA RETENTION SECTION 1.3 Regarding the data
retention for Req. R3 and R4, it is not practical to keep potentially 24 years of data for components
that are maintained every 12 years. We suggest rewording this to "For R3 and R4, Transmission
Owner, Generator Owner, and Distribution Provider shall each keep documentation of the most recent
performances of each distinct maintenance activity for the Protection System components, or to the
previous scheduled audit date, whichever is longer". ATTACHMENT A – FOOTNOTE 1 This footnote
regarding countable events needs to be revised to match the definition of countable events found at
the beginning of the standard.
Individual
Martin Bauer
US Bureau of Reclamation
No Comment
Yes
The tables rely on a reference document which is not a part of the standard and as such may be
altered without due process. Either the relevant text from the reference needs to be inserted into the
standard or the reference itself incorporated into the standard. Specific References such as
Yes
The supplemental reference provides significant clarity to the intent and application of standard;
however, in doing so, it reveals conflicts and ambiguity in the text of the standard. It is suggested
that some of the clarifying language be inserted into the text of the standard.
No Comment
Yes
The concept of including definitions in this standard that are not a part of the Glossary of Terms will
create a conflict with other standards that choose to use the term with a different meaning. This
practice should be disallowed. If a definition is be introduced it should be added to the Glossary of
Terms. This concept was not provided to industry for comment when the modificatios to the Definition
of Protection System was introduced. Additional related to this practice are included later on. The
Term "Protective Relays" is overly broad as it is not limited to those devices which are used to protect
the BES. In the reference provided to the standard, the SDT definied "Protective Relays" as "These
relays are defined as the devices that receive the input signal from the current and voltage sensing
devices and are used to isolate a faulted portion of the BES. " The Definition for "Protective Relays" as
well as the components associated with the them should be associated with the protection of the BES
in the definition. The Section 2.4 of the attached reference and the recent FERC NOPR are in conflict
with the definition of "Protective Relays" which include lockout relays and transfer trip relays "The
relays to which this standard applies are those relays that use measurements of voltage, current,
frequency and/or phase angle and provide a trip output to trip coils, dc control circuitry or associated
communications equipment. This Draft 2: April3: November 17, 2010 Page 5 definition extends to
IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or trip-free relay) as these devices
are tripping relays that respond to the trip signal of the protective relay that processed the signals
from the current and voltage sensing devices." The definition should be revised to relfect that is really
intended. The SDT as created an implied definition by specifically defining DC circuits associated with
the trip function of a "Protective Relay" but failing to specifically define voltage and current sensing
circuits providing inputs to "Protective Relays". The team clearly intended the circuits to be included
but the definition does not since it only refers the the "voltage and current sensing devices". Starting
with the Definitions and continuing through the end of the document, terms that have been defined
are not capitalized. This leaves it ambiguous as to whether the defined term is to be applied or it is a
generic reference. Only defined terms "Protection System Maintenance Program" and "Protection
System" are consistently capitalized. Protection System Maintenance Program (PSMP) definition: The
Restore bullet should be revised to read as follows: "Return malfunctioning components to proper
operation by repair or calibration during performance of the initial on-site activity." Add the following
at the end of the PSMP definition: “NOTE: Repair or replacement of malfunctioning Components that
require follow-up action fall outside of the PSMP, and are considered Maintenance Correctable Issues.”
Protection System (modification) definition: The term "protective functions" that is used herein should
be changed to "protective relay functions" or what is meant by the phrase should become a defined
term, as it is being used as if it is a well known well defined, and agreed upon term. The first bullet
text should be revised to read as follows: "Protective relays that monitor BES electrical quantities and
respond when those quantities exceed established parameters," the last two bullets should be
reversed in order and modified to read as follows: • control circuitry associated with protective relay
functions through the trip coil(s) of the circuit breakers or other interrupting devices, and • station dc
supply (including station batteries, battery chargers, and non-battery-based dc supply) associated
with the preceding four bullets. Statement between the Protection System (modification) definition
and the Maintenance Correctable Issue definition; Is this a NERC accepted practice? There does not
appear to be a location in the standard for defining terms. Having terms that are not contained in the
"Glossary of Terms used in NERC Reliability Standards," and are outside of the terms of the
standards, and yet are necessary to understand the terms of the Requirements is not acceptable.
They would become similar to the reference documents, and could be changed without notice.
Maintenance Correctable Issue definition: The last sentence should be modified to read as follows:
"Therefore this issue requires follow-up corrective action which is outside the scope of the Protection
System Maintenance Program and the Standard PRC-005-2 defined Maximum Maintenance Intervals."
The definition could also be easily clarified to read "Maintenance Correctable Issue – Failure of a
component to operate within design parameters such that it cannot be restored to functional order by
repair or calibration; therefore requires replacement." This ensures that any action to restore the
equipment, short of replacement, is still considered maintenance. Otherwise ambiguity is introduced
as what "maintenance" is. Countable Event definition: An explanation should be made that this is a
part of the technical justification for the ongoing use of a performance-based Protection System
Maintenance Program for PRC-005. Insert the phrase "Standard PRC-005-2" before the term "Tables
1-1…" 4. Applicability: 4.2. Facilities: 4.2.5.4 and 4.2.5.5: Delete these two parts of the applicability.
Station service transformer protection systems are not designed to provide protection for the BES.
Per PRC-005-2 Protection System Maintenance Draft Supplementary Reference, Nov. 17 2010,
Section 2.3 - Applicability of New Protection System Maintenance Standards: “The BES purpose is to
transfer bulk power. The applicability language has been changed from the original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…” To the present language: “… and that
are applied on, or are designed to provide protection for the BES.” The drafting team intends that this
Standard will not apply to “merely possible” parallel paths, (sub-transmission and distribution
circuits), but rather the standard applies to any Protection System that is designed to detect a fault
on the BES and take action in response to that fault.” Station Service transformer protection is
designed to detect a fault on equipment internal to a powerplant and not directly related to the BES.
In addition, many Station Service protection ensures fail over to a second source in case of a
problem. Thus station service transformer protection system is a powerplant reliability issue and not a
BES reliability issue. As such station service transformer protection should not be included in PRC 005
2. In addition, the SDT appears to have targeted generation station service without regard to
transmission systems. If generating station service transformers are that important, then why are
substation/switchyard station service transformers not also important? B. Requirements Should the
sub requirements have the "R" prefix? R4. Change the phrase "… PSMP, including identification of the
resolution of all …" to read "…PSMP including identification, but not the resolution, of all …". General
comment PRC005-2 is very specific in listing the maximum maintenance interval but is still very
vague in listing the specific components to test. Suggest adding the following to the standard. A
sample list of devices or systems that must be verified in a generator to meet the requirements of
this Maintenance Standard: Examples of typical devices and relay systems that respond to electrical
quantities and may directly trip the generator, or trip through a lockout relay may include but are not
necessarily limited to: • Fault protective functions, including distance functions, voltage-restrained
overcurrent functions, or voltage-controlled overcurrent functions • Loss-of-field relays • Volts-perhertz relays • Negative sequence overcurrent relays • Over voltage and under voltage protection
relays • Stator-ground relays • Communications-based protection systems such as transfer-trip
systems • Generator differential relays • Reverse power relays • Frequency relays • Out-of-step
relays • Inadvertent energization protection • Breaker failure protection • lockout or tripping relays
For generator step up transformers, operation of any the following associated protective relays
frequently would result in a trip of the generating unit and, as such, would be included in the
program: • Transformer differential relays • Neutral overcurrent relay • Phase overcurrent relays In
the Lower, Moderate and Severe VSL descriptions, in addition to not being capitalized, the defined
term Maintenance Correctable Issues should not be hyphenated. In Attachment A Section 2 Page 51
should be modified as follows: 2. Maintain the components in each segment according to the timebased maximum allowable intervals established in Tables 1-1 through 1-5 until results of maintenance
activities for the segment are available for a minimum of either 30 individual components of the
segment or a significant statistical population of the individual components of a segment." Without
the modifiction the requirement unfairly target smaller entities. This will allow smaller entities to
determine adjust its time based intervals if its experience with an appropriate number components
supports it. In Attachment A Section 5 Page 51 should be modified as follows: 5. Determine the
maximum allowable maintenance interval for each segment such that the segment experiences
countable events on no more than 4% of the components within the segment, for the greater of
either the last 30 components maintained or a significant statistical population of the individual
components of a segment maintained in the previous year. Without the modifiction the requirement
unfairly target smaller entities. This will allow smaller entities to determine adjust its time based
intervals if its experience with an appropriate number components supports it. In Attachment A
Section 5 Page 52 should be modified as follows: 5. Using the prior year’s data, determine the
maximum allowable maintenance interval for each segment such that the segment experiences
countable events on no more than 4% of the components within the segment, for the greater of
either the last 30 components maintained or a significant statistical population of the individual
components of a segment components maintained in the previous year. Without the modifiction the
requirement unfairly target smaller entities. This will allow smaller entities to determine adjust its
time based intervals if its experience with an appropriate number components supports it.
Group
City of Austin DBA Austin Energy
Reza Ebrahimian
Yes
The Requirement R1.5. is vague and the intent is not well understood. We recommend it be rewritten
to clarify the intent. In the Requirement R2. the phrase “… shall verify those components possess the
monitoring attributes …” is too vague and not easily understandable. We recommend this requirement
be rewritten.
Individual
Kenneth A. Goldsmith
Alliant Energy
Yes
Yes
No
No
Yes
In the Purpose statement delete “affecting” and replace it with “protecting”. The purpose of the
standard deals with systems that protect the BES. In sections R1 and R4.2.1 delete “applied on” as
unneeded and potentially confusing. The goal is to cover Protection Systems designed to protect the
BES. Alliant Energy believes that Article 1.4 needs to be deleted from the standard. It is redundant
and serves no purpose. Alliant Energy believes that Article 1.5 needs to be deleted from the standard.
There is a major concern on what an “acceptable parameter” is and how it would be interpreted by
the Regional Entities. Section 4.2 Applicable Facilities: We are concerned with this paragraph being
interpreted differently by the various regions and thereby causing a large increase in scope for
Distribution Provider protection systems beyond the reach of UFLS or UVLS. 4.2.1 Protection Systems
applied on, or designed to provide protection for, the BES. The description is vague and open for
different interpretations for what is “applied on” or “designed to provide protection”. According to the
November 17, 2010 Draft Supplementary Reference page 4, the Standard will not apply to subtransmission and distribution circuits, but will apply to any Protection System that is designed to
detect a fault on the BES and take action in response to the fault. The Standard Drafting Team does
not feel that Protection Systems designed to protect distribution substation equipment are included in
the scope of this standard; however, this will be impacted by the Regional Entity interpretations of
‘protecting” the BES. Most distribution protection systems will not react to a fault on the BES, but are
caught up in the interpretation due to tripping a breaker(s) on the BES. We request clarification that
the examples listed below do not constitute components of a BES Protection System: 1. Older
distribution substations that lack a transformer high side interrupting device and therefore trip a
transmission breaker or a portion of the transmission system or bus, or 2. Newer distribution
substations that contain a transformer high side interrupting device but also incorporate breaker
failure protection that will trip a transmission breaker or a portion of the transmission system or bus.
Since distribution provider systems are typically radial and do not contain the level of redundancy of
transmission or generation protection systems, it is not cheap, safe, maintaining BES reliability, or
easy to coordinate companies to test these protection systems to the level of PRC-005-2 draft
recommendations. Section F Supplemental Reference Documents: The references listed in this section
refer to 2009 dates and do not match with the 2010 reference documents supplied for comment.
Table 1-4 Component Type Station dc Supply: • “Any dc supply for a UFLS or UVLS system” - This
should not have the same testing interval as control circuits, but should have a maximum
maintenance period as other dc supplies do. • Replace the words “perform as designed” on page 14 of
Table 1-4 with “operate within defined tolerances.” Table 1-5 Component Type Control Circuitry: •
This table allows for unmonitored trip coils for UFLS or UVLS breakers to have “no periodic
maintenance”. The PRC-005-2 Supplemental Frequently Asked Question #7B and #7C give excellent
reasoning for not requiring maintenance on the trip coil component due to the larger number of
failures that would be required to have any substantial impact to the BES as well as the statement
that distribution breakers are operated often on just fault clearing duty already. We believe that the
unmonitored control circuitry has the same level of minimal BES impact and is also being tested each
time the distribution breaker undergoes fault clearing duty. With this logic, we do not see why there
would be different maintenance requirements for these two components. • Alliant Energy is concerned
that the addition of mandatory 86 and 94 auxiliary lockout relays (Electromechanical trip or Auxiliary
devices) will force entire bus outages that will compromise the BES reliability more by forcing utilities
across the US to unnecessarily take multiple non-faulted BES elements out of service. Such testing is
also likely to introduce human error that will cause outages such as items outlined in the NERC
lessons learned” and therefore such testing will result in more outages than actual failures. An
equivalent non-destructive test needs to be identified to allow entities to sufficiently trace and test
trip paths without taking multiple substation line outages to physically test a lockout or breaker failure
scheme.
Group
PacifiCorp
Sandra Shaffer
Yes
Yes
Group
Florida Municipal Power Agency
Frank Gaffney
Yes
No
The VRF of R1 should be Low since the attached tables are essentially the PSMP.
Yes
Yes
Yes
UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC-008/011 as
being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other protection system
components, e.g., communications (probably not applicable), voltage and current sensing devices
(e.g., instrument transformers), Station DC supply, control circuitry. What's key about this is that
these components are all part of distribution system protection, so, these activities would not be
covered by other BES protection system maintenance and testing. I'm sure we are testing batteries
and the like, but, we are probably not testing battery chargers and control circuitry, and, in many
cases distribution circuits are such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation Protection Systems
which are needed to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will not be noticeable to the
event. It does make sense to test the relays themselves in part to ensure that the regio0nsl UFLS
program is being met, but, to test the other protection system components is not worthwhile. Note
that DC Supplies and most of the control circuitry of distribution lines are "tested" frequently by
distribution circuits clearing faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this version is better than prior
versions because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry. Applicability, 4.2.1, should reflect the Y&W
and Tri-State interpretation (Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a BES Facility and that trips a
BES Facility" Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the definition of
Protection System (recently approved) does not clearly exclude "non-electrical" protection, the
Applicability section should. For instance, a vibration monitor, steam pressure, etc. protection of
generators, sudden pressure protection of transformers, etc. should not be included in the standard.
An alternative is to change the definition of Protection System to make sure it only includes electrical
Table 1-4 requires a comparison of measured battery internal ohmic value to battery baseline. Battery
manufacturers typically do not provide this value and one manufacturer states that the baseline test
are to be performed after the battery has been in regular float service for 90 days. It is unclear how
to comply with the requirement for the initial 90 days. Additionally, we would recommend that this
requirement be modified to permit an entity to establish a “baseline” value based on statistical
analysis of multiple test results specific to a given battery manufacturer/model. Several commenters
previously expressed their concerns with performing capacity tests. While this may just be an entity’s
preference, allowing an entity to establish a baseline at some point beyond the initial installation
period would give entities the option of using the internal resistance test in lieu of a capacity test.
Small entities with only one or two BES substations may not have enough components to take
advantage of the expanded maintenance intervals afforded by a performance-based maintenance
program. Aggregating these components across different entities doesn’t seem too logical considering
the variations at the sub-component level (wire gauge, installation conditions, etc.) Trip circuits are
interconnected to perform various functions. Testing a trip path may involve disabling other features
(i.e. breaker failure or reclosing) not directly a part of the test being performed. Temporary
modifications made for testing introduce a chance to accidentally leave functions disabled, contacts
shorted, jumpers lifted, etc. after testing has been completed. Trip coils and cable runs from panels to
breaker can be made to meet the requirements for monitored components. The only portions of the
circuitry where this may not be the case is in the inter- and intra-panel wiring. Because such portions
of the circuitry have no moving parts and are located inside a control house, the exposure is
negligible and should not be covered by the requirements. Entities will be at increased compliance risk
as they struggle to properly document the testing of all parallel tripping paths. The interconnected
nature of tripping circuits will make it difficult to count the number of circuits consistently for the
purpose of calculating a VSL.
Individual
Martyn Turner
LCRA Transmission Services Corporation
No
It would help to add a column to the left labeled Category. I.E. a relay could be classified under
Category 1 attributes unmonitored or Cat 2, Cat 3. Table 1-4, Station DC is very difficult to follow.
Yes
Yes
Well written and helpful document. In Section 8.1, the document states that if your PSMP requires
activities more often than the Tables maximum, then you must perform to that higher standard.
While it is understandable that an entity may desire to maintain their PRS at a higher level, they
should not be fined or penalized for achieving less than their standard but within the intervals stated
in the Tables. This point should be clarified, preferably within the standard itself.
Yes
No
Group
PSEG Companies ("Public Service Enterprise Group Companies")
Kenneth D. Brown
Yes
No comment
Yes
Figure 2 “typical generation system” shows a typical auxiliary medium voltage bus, in addition to the
color coded elements suggest that a very distinct line of demarcation (dark dotted line) be added to
the figure that defines the elements associated with the MV bus protection served by the station Aux
Transformer and unit aux transformer are not part of the BES- PSMP PRC5 requirements. Also see
comment 5 below; we suggest that the station service transformer must be connected to BES for
inclusion in standard requirements. Suggest adding an explanation note to figure 2 to clarify this.
Yes
Suggest that the section 5 – station DC supply have some specific examples added that would be
acceptable methods for verifying the “state of charge” as required by standard table 1-4.
Yes
The facilities listed in 4.2.5.5 include protection systems for “system connected” station service
transformers associated with generators that are part of the BES. If a station service transformer is
connected to a non BES bus then it would still fall under the PRC5 applicability requirements as
written. The FAQs discuss relays associated with station auxiliary loads as not included in the program
requirements. The non BES connected transformers should be included in that same category of
equipment. From the FAQ’s - “Relays which trip breakers serving station auxiliary loads such as
pumps, fans, or fuel handling equipment, etc., need not be included in the program even if the loss of
the those loads could result in a trip of the generating unit. Furthermore, relays which provide
protection to secondary unit substation (SUS) or low switchgear transformers and relays protecting
other downstream plant electrical distribution system components are not included in the scope of
this program even if a trip of these devices might eventually result in a trip of the generating unit.”
Suggest the following added details be considered to be consistent with intent of BES connected
facilities. Revise Description 4.2.5.5 as follows: “Protection systems for BES system connected station
service transformers connected for generators that are part of the BES”. With respect to DC supply
systems (batteries, chargers),the implementation plan is too aggressive. Some battery checks will
have to be done on a 3 month interval, and entities will be required to be compliant with this new
frequency in 1 Calendar year. This timeframe is unreasonable and needs to be pushed back to at least
2 years. PSEG is also asking for clarification to the supplemental reference document: On page 4,
section 2.3 it states that the standard is designed to ONLY include “relays that detect a fault on the
BES and take action in response to that fault”. If PSEG is interpreting this correctly, this is a massive
shift from the existing PRC-005-1 standard. The existing PRC-005-1 includes all distribution relays
that trip a BES breaker to be part of the scope. In this revision, PRC-005-2 would exclude those
distribution relays if they are designed to act for faults on the distribution system. PSEG would fully
support this interpretation. PSEG would like this clarified and confirmed. This is very important.
Group
Southern Company Transmission
JT Wood
Yes
The Standard Drafting Team should be commended for making the tables much easier to understand
No
We disagree with the inclusion of the VSLs, VRFs, and time Horizons associated with the new
Requirements 1.5 and 4.2
Yes
Page 11 and 12, (Additional Notes for Table 1-1 through 1-5) Comment ->> The standard does not
reference these notes. Should these notes be referenced and included in the Standard? Page 12,
Additional Notes for Table 1, item #7 (“performing an operational trip test”) Comment ->> Standard
does not state that an operational/full functional test is required. Please clarify. Page 22, 15.3,
Control Circuitry Functions, paragraph 1 (“verify, with a volt-meter, the existence of proper voltage at
the open contacts”) Comment ->> The example of measuring the proper voltage with a volt-meter at
the open contacts to verify the circuit indicates that the 12-year “full functional” trip test of control
circuits is not required. Please clarify. Page 22, 15.3, Control Circuitry Functions, paragraph 3 (“UVLS
or UFLS scheme are excluded from the tripping requirement, but not from the circuit test
requirements”) Comment ->> This indicates to me that measuring the proper voltage with a voltmeter at the open contacts will verify the circuit. Please confirm. Please clarify – If a suitable
monitoring system is installed that verifies every parallel trip path then the manual-intervention
testing of those parallel trip paths can be “extended beyond 12 years”. Standard indicates that no
periodic maintenance is required. Consider changing “extended beyond 12 years” to “eliminated”.
Page 23, 15.3, Control Circuitry Functions, paragraph 5 (“When verifying the operation of the 94 and
86 relays each normally-open contact that closes to pass a trip signal must be verified as operating
correctly.”) Comment ->> This indicates that we must verify that trip and auxiliary device contacts
change state. Please confirm. The standard does not state that the contacts must be verified to
change states. If this is required, please add to the standard.
Yes
Page 7, L. (“verify operation of the relay inputs …”) Comment ->> Clarification needed. Standard
states that each input should be “picked up” or “turned on and off”. Do you have to change states of
the input contact(s) or can you just jumper positive to the input(s) to verify that the microprocessor
relay verifies this change of state? Page 10, 4.E (“What does functional (or operational) trip test
include?”) Comment ->> The words “functional (or operational) trip test” are not in the Standard. Is
this required? If so, please clarify this in Standard. If not, please remove. (Reference comment
regarding “verify all paths of the control and trip circuits” on page 17 of standard.) Page 18, 7.
(Distributed UVLS and UFLS system.) and Page 19 8. (Centralized UVLS and UFLS system.) Comment
->> Standard does not specify “distributed” or “centralized” UVLS and UFLS systems. Please consider
combining section 7 & 8, omitting items 7.C., 8.E., and omitting “distributed” and “centralized”
references on pages 18 and 19.
Yes
Page 5, 4.2. (“or initiate resolution”) Comment ->> Standard does not specify to “follow through” to
completion. Is record of completion required? Page 5, 1.5. (1.5. Identify calibration tolerances or
other equivalent parameters for each Protection System component type that establish acceptable
parameters for the conclusion of maintenance activities.) Comment ->> This is too vague, broad,
general and all encompassing. For example, what is the calibration tolerance for “control circuitry”
which is made up of many things such as wiring, auxiliary relays, trip coils, etc. We currently have
calibration tolerances on electromechanical relays but not on all components of a protection system
(communications systems, voltage and current sensing devices, station dc supply, control circuitry).
To try to identify calibration tolerances or other equivalent parameters for each of these components
would be extremely difficult and time consuming. Clarification is needed on what components or parts
of components require calibration tolerances. Another option is to remove this requirement. Page 5,
4.5. (4.2. Either verify that the components are within the acceptable parameters established in
accordance with Requirement R1, Part 1.5 at the conclusion of the maintenance activities, or initiate
resolution of any identified maintenance correctable issues.) Comment ->> See comments above on
1.5. Clarification is needed on what is required to verify that the components are within acceptable
parameters. We feel it should be adequate to provide a simple way to verify this requirement such as
to include this in our maintenance procedure (equipment is to be left within tolerance), provide closed
work order, show “checked” check box, provide a simple statement that this was completed, or etc.
We feel that having to provide detailed data such as “as found” / “as left” values is too complicated
and time consuming. Please clarify or consider removing this requirement. Page 6, M.4. (“and
initiated resolution”) Comment ->> Standard does not specify to “follow through” to completion. Is
record of completion required? Page 10, F.1 (July 2009) & F.2 (DRAFT 1.0 - June 2009) Comment >> Need new dates and draft number. Page 11 (For microprocessor relays, verify operation of the
relay inputs and outputs that are essential …) Comment ->> Does this require changing the state of
the input contacts or can you just jumper voltage to the inputs and verify that the microprocessor
relays acknowledged the change? Page 17 (“Verify electrical operation(1)of EM trip and auxiliary
devices(2).”) Comment ->> (1) Is it required to verify that trip and auxiliary device contacts change
state? If so, please state as a requirement. (2) We recommend that this requirement only includes EM
aux LO / tripping relays that trip interrupting devices directly. Other EM aux relays such as BFI aux.
relays should be excluded. Please state this clearly in the Standard. Note that these aux relays such
as BFI aux relays are included in the “unmonitored control circuitry associated with protective
functions” requirement and will be verified on a 12 year interval. (3) Please consider including an
elementary diagram to show what is included. Page 17 (Verify all paths of the control and trip
circuits.) Comment ->> Clarification needed. Is it required to perform a full functional test, i.e. trip
breakers? Or is reading DC across trip contacts all that is required? Page 14 (Table 1.4) Change the
maintenance interval for unmonitored station dc supply from “3 Calendar Months” to “4 times
Annually”. This facilitate compliance to the standard by creating completion milestones for batteries at
the end of each quarter of the year. Page 15 (Table 1.4 The standard requires the establishment of a
battery baseline for cell/unit internal ohmic values and the comparison of impedance readings every
18 calendar months to that baseline. Due to the lack of original impedance readings at the time of
installation of the battery. Since in many cases no such data is available; it needs to be made clear
that establishing a baseline from , from manufacturer’s data, the most recent impedance test, or the
first impedance test completed after the adoption of the new standard is acceptable
Individual
Terry Harbour
MidAmerican Energy
Yes
Yes
Yes
The Supplementary Reference should have clear disclaimers indicating that nothing in the reference is
mandatory and enforceable.
Yes
The Frequently Asked Questions should have clear disclaimers indicating that nothing in the reference
is mandatory and enforceable.
Yes
MidAmerican remains concerned that including requirements for testing of electromechanical trip or
auxiliary devices (Table 1-5 Row 3) will in some cases require entire bus outages that will
compromise the BES reliability due to the need for entities across the US to take multiple BES
elements out of service during the testing. If this requirement is retained additional time should be
included in the implementation plan to allow for system modifications, such as the installation of relay
test switches, to potentially allow for this testing while minimizing testing outages. Clarify that in the
definition of Component Type that Transmission Owners are allowed the latitude to designate their
own definitions for each of the Component Types, not just control circuits. In the implementation
schedule time periods are provided within which compliance deadlines and percentages of compliance
are given. The following clarifications are recommended: 1. In calculating percentage of compliance
for purposes of demonstrating progress on the implementation plan the percentages are calculated
based on the total population of the protection system components that an entity has that fit the
component category and allowable interval. 2. To obtain compliance with the percentage completion
requirements of the implementation schedule an entity needs to have completed at least one
prescribed maintenance activity of that component type and interval. In the purpose statement delete
“affecting” and replace it with “protecting”. The purpose of the standard deals with systems that
protect the BES. In sections R1 and R4.2.1 delete “applied on or” as unneeded and potentially
confusing. The goal is to cover protection systems designed to protect. Clarify the meaning of “state
of charge” on page 14 in Table 1-4. In Table 1-4 Component Type Station dc Supply, “Any dc supply
for a UFLS or UVLS system” should have the same maximum maintenance period as other dc
supplies. Table 1-5 Component Type Control Circuitry, the table allows for unmonitored trip coils for
UFLS or UVLS breakers to have “no periodic maintenance”. The PRC-005-2 Supplemental Frequently
Asked Question #7B and #7C give excellent reasoning for not requiring maintenance on the trip coil
component due to the larger number of failures that would be required to have any substantial impact
to the BES as well as the statement that distribution breakers are operated often on just fault clearing
duty already. We believe that the unmonitored control circuitry has the same level of minimal BES
impact and is also being tested each time the distribution breaker undergoes fault clearing duty. With
this logic, we do not see why there would be different maintenance requirements for these two
components.
Individual
Kirit Shah
Ameren
Yes
No
(1)The Lower VSL for all Requirements should begin above 1% of the components. For example for
R4: “Entity has failed to complete scheduled program on 1% to 5% of total Protection System
components.” PRC-005-2 unrealistically mandates perfection without providing technical justification.
A basic premise of engineering is to allow for reasonable tolerances, even Six Sigma allows for
defects. Requiring perfection may well harm reliability in that valuable resources will be distracted
from other duties.
No
No
This document is helpful.
Yes
(1)We believe that R1.5 and R4.2 “Calibration tolerances or other equivalent parameters”
requirements should be removed. Neither the Supplement nor the FAQ address the expectation for
them. While we agree that tolerances are needed and used, they need not be specified as part of this
standard. (2) The Data retention is too onerous (a) For those components with numerous cycles
between on-site audits, retaining and providing evidence of the two most recent distinct maintenance
performances and the date of the others should be sufficient. Additionally, we are subject to selfcertification, spot audits and/or inquiries at any time between on-site audits as well. (b) For those
components with cycles exceeding on-site audit interval, retaining and providing evidence of the most
recent distinct maintenance performance and the date of the preceding one should be sufficient.
Auditors will have reviewed the preceding maintenance record. Retaining these additional records
consumes resources with no reliability gain. (3) Definition of the BES perimeter should be included in
accordance with Project 2009-17 Interpretation. (a)Facilities Section 4.2.1 “or designed to provide
protection for the BES” needs to be clarified so that it incorporates the latest Project 2009-17
interpretation. The industry has deliberated and reached a conclusion that provides a meaningful and
appropriate border for the transmission Protection System; this needs to be acknowledged in PRC005-2 and carried forward. (4)System-cnnected station service transformers (4.2.5.5)should be
ommited, because (a) Generating Plant system-connected Station Service transformers should not be
included as a Facility because they are serving load. Omit 4.2.5.5 from the standard. There is no
difference between a station service transformer and a transformer serving load on the distribution
system. This has no impact on the BES, which is defined as the system greater than 100 kV. (b)
system-connected station service transformers in the same table as well as from table-to-table can be
overwhelming. This would help keep Regional Entities and System Owners from making errors. (5)
Retention of maintenance records for replaced equipment should be ommitted. FAQ II 2B final
sentence states that documentation for replaced equipment must be retained to prove the interval of
its maintenance. We disagree with this because the replaced equipment is gone and has no impact on
BES reliability; and such retention clutters the data base and could cause confusion. For example, it
could result in saving lead acid battery load test data beyond the life of its replacement. (6) Battery
inspection every 4 months is sufficient. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for
an interval that might extend past three calendar months due to storms and outages must set a
target interval of two months thereby increasing the number of inspections each year by half again.
This is unnecessarily frequent. We suggest changing the maximum interval for battery inspections to
4 calendar months. For consistency, we also suggest that all intervals expressed as 3 calendar
months be changed to 4 calendar months. (7) PSMP Implement Date should commence at the
beginning of a Calendar year. This is the most practical way to transition assets from our existing
PRC-005-1 plans. (8) Please clarify the meaning of “state of charge” for batteries. Does this mean
specific gravity testing or what? (9) Please clarify that instrument transformer itself is excluded.
Please clarify that the instrument transformer itself is excluded. The standard indicates that only
voltage and current signals need to be verified in Table 1-3, but the recently approved Protection
System definition wording can be mis-interpreted to mean they are included. FAQ 11.3.A is helpful.
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
Yes
Yes
No
No
Yes
In the Purpose statement delete “affecting” and replace it with “protecting”. The purpose of the
standard deals with systems that protect the BES. In sections R1 and R4.2.1 delete “applied on” as
unneeded and potentially confusing. The goal is to cover Protection Systems designed to protect the
BES. The NSRS believes that Article 1.4 needs to be deleted from the standard. It is redundant and
serves not purpose. The NSRS believes that Article 1.5 needs to be deleted from the standard. There
is a major concern on what an “acceptable parameter” is and how it would be interpreted by the
Regional Entities. The NSRS believes that Article 4.2 needs to be deleted from the standard. There is
no need for this article if Article 1.5 is deleted. Section 4.2 Applicable Facilities: We are concerned
with this paragraph being interpreted differently by the various regions and thereby causing a large
increase in scope for Distribution Provider protection systems beyond the reach of UFLS or UVLS.
4.2.1 Protection Systems applied on, or designed to provide protection for, the BES. The description is
vague and open for different interpretations for what is “applied on” or “designed to provide
protection”. According to the November 17, 2010 Draft Supplementary Reference page 4, the
Standard will not apply to sub-transmission and distribution circuits, but will apply to any Protection
System that is designed to detect a fault on the BES and take action in response to the fault. The
Standard Drafting Team does not feel that Protection Systems designed to protect distribution
substation equipment are included in the scope of this standard; however, this will be impacted by
the Regional Entity interpretations of ‘protecting” the BES. Most distribution protection systems will
not react to a fault on the BES, but are caught up in the interpretation due to tripping a breaker(s) on
the BES. Section F Supplemental Reference Documents: The references listed in this section refer to
2009 dates and do not match with the 2010 reference documents supplied for comment. Table 1-4
Component Type Station dc Supply: • “Any dc supply for a UFLS or UVLS system” - This should not
tied to the same testing interval as control circuits. The dc supply system is significantly different
from control circuits and should have a maximum maintenance period as other dc supplies do. •
Replace the words “perform as designed” on page 14 of Table 1-4 with “operate within defined
tolerances.” Table 1-5 Component Type Control Circuitry: • This table allows for unmonitored trip
coils for UFLS or UVLS breakers to have “no periodic maintenance”. “Unmonitored control circuitry
associated with protective functions” should also have an exclusion for UFLS and UVLS circuitry that
would allow for “no periodic maintenance”. • There is a concern that requiring the electrical testing
and maintenance of Electromechanical trip or Auxiliary devices will force entire bus outages to be
scheduled, which will compromise the BES reliability more by forcing utilities across the US to
unnecessarily take multiple non-faulted BES elements out of service. Such testing is also likely to
introduce human error that will cause outages such as items outlined in the NERC lessons learned”
and therefore such testing will result in more outages than actual failures.
Consideration of Comments on Initial Ballot — Protection System Maintenance and Testing (Project 2007-17)
Date of Initial Ballot: December 10 – 20, 2010
Summary Consideration: Many commenters opposed R1 part 1.5 and the associated text, and the SDT responded by removing this text.
Most of these comments were duplicates of those submitted in response to the formal comment period; the SDT responses are
duplicated as well. Please see the Summary Consideration for each of the posted questions within the Consideration of Comments.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Gerry
1
Adamski, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
Voter
Rodney
Phillips
Entity
Segment
1
Vote
Comment
Allegheny Power applauds the hard work that the Standards Draft Team has
exhibited in producing a clear and enforceable standard that will increase the
reliability of the Bulk Electric System. However, the addition of requirement 1.5 is
such a significant change in scope from the last draft that a further review of the
potential impact and any implementation concerns is required by AP and the
industry in general before we can consider voting in-favor of this standard.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Kirit S. Shah
Ameren
1
Negative
(1)We believe that R1.5 and R4.2 “Calibration tolerances or other equivalent
Services
parameters” requirements should be removed. Neither the Supplement nor the
FAQ address the expectation for them. While we agree that tolerances are needed
and used, they need not be specified as part of this standard. (2)
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Paul B.
American
1
Negative
Restructured Tables:
Johnson
Electric Power
1) Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12 years
for unmonitored control circuitry, yet other portions of control circuitry have a
maximum interval of 6 years. AEP does not understand the rationale for the
difference in intervals, when in most cases, one verifies the other. Also,
unmonitored control circuitry is capitalized in row 4 such that it infers a
defined term.
2) In the first row of table 1-4 on page 16, it is difficult to determine if it is a cell
that wraps from the previous page or is a unique row. This is important
1
Allegheny
Power
Negative
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Voter
Entity
Segment
Vote
Comment
because the Maximum Maintenance Intervals are different (i.e. 18 months vs
6 years). It is difficult to determine to which elements the 6 year Maximum
Maintenance Interval applies. AEP suggests repeating the heading “Monitored
Station dc supply (excluding UFLS and UVLS) with: Monitor and alarm for
variations from defined levels (See Table 2):” for the bullet points on this
page.
VSLs, VRFs and Time Horizons:
3) The VSL table should be revised to remove the reference to the Standard
Requirement 1.5 in the R1 “High” VSL.
4) All four levels of the VSL for R2 make reference to a “condition-based PSMP.”
However, nowhere in the standard is the term “condition-based” used in
reference to defining ones PSMP. The VSL for R2 should be revised to remove
reference to a condition-based PSMP; alternatively the Standard could be
revised to include the term “condition-based” within the Standard
Requirements and Table 1.
5) In multiple instances, Table 1 uses the phrase “No periodic maintenance
specified” for the Maximum Maintenance Interval. Is this intended to imply
that a component with the designated attributes is not required to have any
periodic maintenance? If so, the wording should more clearly state “No
periodic maintenance required” or perhaps “Maintain per manufacturers
recommendations.” Failure to clearly state the maintenance requirement for
these components leaves room for interpretation on whether a Registered
Entity has a maintenance and testing program for devices where the Standard
has not specified a periodic maintenance interval and the manufacturer states
that no maintenance is required.
FAQ and Supplementary Reference:
6) With such a complex standard as this, the FAQ and Supplementary Reference
documents do aid the Protection System owner in demystifying the
requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a) Section 5 of the Supplementary Reference, refers to “condition-based”
maintenance programs. However, nowhere in the standard is the term
“condition-based” used in reference to defining ones PSMP. The
Supplementary Reference should be revised to remove reference to a
condition-based PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard Requirements and
Table 1.
2
Voter
Entity
Segment
Vote
Comment
b) Section 15.7, page 26, appears to have a typographical error “...can all be
used as the primary action is the maintenance activity...”
c) Figure 2 is difficult to read. The figure is grainy and the colors representing
the groups are similar enough that it is hard to distinguish between
groups.
7) “Frequently-Asked Questions”: With such a complex standard as this, the FAQ
and Supplementary Reference documents do aid the Protection System owner
in demystifying the requirements. But AEP holds strong doubt on how much
weight the documents carry during audits. It would be better to include them
as an appendix in the actual standard, but in a more compact version with the
following modifications:
a) The section “Terms Used in PRC-005-2” is blank and should be removed as
it adds no value.
b) Section I.1 and Section IV.3.G reference “condition-based” maintenance
programs. However, nowhere in the standard is the term “conditionbased” used in reference to defining ones PSMP. The FAQ should be
revised to remove reference to a condition-based PSMP; alternatively the
Standard could be revised to include the term “condition-based” within the
Standard Requirements and Table 1.
c) The second sentence to the response in Section I.1 appears to have a
typographical error “... an entity needs to and perform ONLY timebased...”.
8) General:
a) Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2
should be removed. Specifying calibration tolerances for every protection
system component type, while a seemingly good idea, represents a
substantial change in the direction of the standard. It would be very
onerous for companies to maintain a list of calibration tolerances for every
protection system component type and show evidence of such at an audit.
AEP believes entities need the flexibility to determine what acceptance
criteria is warranted and need discretion to apply real-time
engineering/technician judgment where appropriate.
b) Three different types of maintenance programs (time-based, performancebased and condition-based) are referenced in the standard or VSLs, yet
the time-based and condition-based programs are neither defined nor
described. Certain terms defined within the definition section (such as
Countable Event or Segment) only make sense knowing what those three
programs entail. These programs should be described within the standard
itself and not assume a knowledge of material in the Supplementary
3
Voter
Entity
Segment
Vote
Response: Thank you for your comments.
Comment
Reference or FAQ.
c) “Protective relay” should be a defined term that lists relay function for
applicability. There are numerous ‘relays’ used in protection and control
schemes that could be lumped in and be erroneously included as part of a
Protection System. For example, reclosing or synchronizing relays respond
to voltage and hence could be viewed by an auditor as protective relays,
but they in fact perform traditional control functions versus traditional
protective functions.
1. The 6-year activities are all related to components with “moving parts”, and the 12-year activities are related to the other
portions of the control circuitry. The capitalized term has been corrected.
2. Table 1-4 has been modified in consideration of your comments.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised.
4. The SDT concluded that Requirement R2 is redundant with R1, Part 1.4, and has deleted R2 (together with the associated
Measure and VSL).
5. If the indicated monitoring attributes are present, no “hands-on” periodic maintenance is required, as the monitoring of the
component is providing a continuing indication of its functionality.
6. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part
of the standard.
A. The Supplemental Reference Document discusses condition-based maintenance in a conceptual manner, as a
generally-recognized term. The SDT did make some changes within the Supplemental Reference document to
clarify the manner in which condition-based maintenance is discussed.
B. This clause has been corrected.
C. A higher-quality version of Figure 2 has been substituted.
7. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part
of the standard.
a) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
b) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
c) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
4
Voter
Entity
Segment
Vote
Comment
Document as appropriate. The SDT considered your comments during this activity.
8. A) The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated
VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
B) The term, “condition-based” has been removed from the draft standard. The other terms are used, but are clear in the
context in which they are used.
C) “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition
with PRC-005. Further, the applicability of generically-described protective relays is defined by the Applicability clause of
PRC-005-2.
Jason Shaver
American
Transmission
Company, LLC
1
Negative
ATC recognizes the substantial efforts that the SDT has made on PRC-005 and
appreciate the SDT’s modifications to this Standard based on previous comments
made. ATC looks forward to continuing to have a positive influence on this process
via the comment process, ballots and interaction with the SDT. ATC was very
close to an affirmative vote on this Standard prior to the unanticipated changes
that appeared in this most recent posting. These changes introduce a significant
negative impact from ATC’s perspective. Therefore, ATC is recommending a
negative ballot in the hope that our concerns regarding R 1.5 and R 4.2 and other
clarifications will be included with the standard.
1. Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part
1.5 and the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not
necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address various related concerns
noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document,
Section 8 for a discussion of this.
John
Bussman
Associated
Electric
Cooperative,
Inc.
1
Negative
AECI want to thanks the team for the efforts being put forth by the drafting team.
The table is much easier to follow and less confusing. AECI is voting negative
because of the battery inspection intervals.
1. We have commented before about the 3 months being excessive and
think it should be annually. However, with that being stated if you are
going to use three months as the interval then that means inspections will
have to be scheduled every 2 months to ensure the inspections happen
every 3 months. Therefore AECI request that the battery inspection
schedule be extended to every 4 months and then entities can schedule
inspections to be performed every 3 months to ensure that the inspections
are completed every 4 months.
5
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2. The same comment applies the the unmonitored communication circuits.
Change the time interval to 4 months. Then scheduling can be every 3
months instead of every 2 months.
3. When you go to Table 1-4 there is confusion with the the DC for a UFLS
or UVLS system. For the interval it states "When control circuits are
verified" Then I go to Table 1-5 the second line that discusses trip coils for
UFLS and UVLS the interval states "No periodic maintenance specified" Is
this what was intended?
Response: Thank you for your comments.
1. The SDT believes that the 3-month interval is proper.
2. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
3. The SDT intends that tripping of the interrupting device for UFLS/UVLS is not required, but that the other portions of the dc
control circuitry still shall be maintained. See Section 15.3 of the Supplementary Reference Document
Joseph S.
Beaches
1
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
Stonecipher
Energy
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new PRCServices
005 sweeps in other protection system components, e.g., communications
(probably not applicable), voltage and current sensing devices (e.g., instrument
transformers), Station DC supply, control circuitry. What we see as a problem is
that these components are all part of distribution system protection, so, these
activities would not be covered by other BES protection system maintenance and
testing. I'm sure we are testing batteries and the like, but, in many cases
distribution circuits are such that it is very difficult, if not impossible, to test
control circuitry to the trip coil of the breaker without causing an outage of the
customers on that distribution circuit. There is no real reliability need for this
either. Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will not be
noticeable to the event. It does make sense to test the relays themselves, in part,
to ensure that the regionsl UFLS program is being met; but, to test the other
protection system components is not worthwhile. Note that DC Supplies and most
of the control circuitry of distribution line breakers are "tested" frequently by
distribution circuits clearing faults such as animals, vegetation blow-ins, lightning,
etc., on distribution circuits, reducing the value of testing to just about nill.
However, this version is better than prior versions because it essentially requires
the entity to determine it's own period of maintenance and testing for UFLS/UVLS
for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project
2009-17) of "transmission Protection System" and should state: "Protection
Systems applied on, or designed to provide protection for a BES Facility and that
6
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trips a BES Facility."
3. Applicability, 4.2. - does not reflect the interpretation of Project 2009-10 that
excludes non-electrical protection (e.g., sudden pressure relays) and auxiliary
relays. Because the definition of Protection System (recently approved) does not
clearly exclude "non-electrical" protection,the Applicability section should. For
instance,, a vibration monitor, steam pressure, etc. protection of generators,
sudden pressure protection of transformers, etc. should not be included in the
standard. An alternative is to change the definition of Protection System to make
sure it only includes electrical.
Response: Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat
constrained relative to similar activities for Protection Systems in general. Regardless, without proper functioning of
these component types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability,
particularly during the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry,
Table 1-5 specifically excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within
PRC-005-2. However, the SDT has made changes to Applicability 4.2.1. in consideration of your comment.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
Donald S.
Watkins
Bonneville
1
Negative
Please see BPA's formal comments submitted on 12/16/10. Our concerns have not
Power
been adequately addressed.
Administration
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
Paul Rocha
CenterPoint
Energy
1
Negative
1) CenterPoint Energy cannot support this proposed Standard. Any standard that
requires a 35 page Supplementary Reference document and a 37 page FAQ Practical Compliance and Implementation document is much too prescriptive
and complex.
2) CenterPoint Energy is very concerned that a large increase in the amount of
documentation will be required in order to demonstrate compliance - with no
resulting reliability benefit. CenterPoint Energy believes this Standard could
actually result in decreasing system reliability, as the Standard proposes
excessive maintenance requirements. The following is included in the
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Comment
Supplementary Reference document (page 8): “Excessive maintenance can
actually decrease the reliability of the component or system. It is not unusual
to cause failure of a component by removing it from service and restoring it.”
System reliability can be even further reduced by the number of transmission
line and autotransformer outages required to perform maintenance.
3) In addition, the following is included in the FAQ - Practical Compliance and
Implementation document: “PRC-005-2 assumes that thorough commission
testing was performed prior to a protection system being placed in service.
PRC-005-2 requires performance of maintenance activities that are deemed
necessary to detect and correct plausible age and service related degradation
of components such that a properly built and commission tested Protection
System will continue to function as designed over its service life.” CenterPoint
Energy believes some proposed requirements, such as wire checking a relay
panel, do not conform to this statement. CenterPoint Energy’s experience has
been that panel wiring does not degrade with age and service and that
problems with panel wiring, after thorough commissioning, is not a systemic
issue.
Response: Thank you for your comments.
1. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate.
2. FERC Order 693 directed that NERC establish maximum maintenance intervals. The documentation required should not
expand dramatically from the documentation currently required to demonstrate compliance. An entity may minimize hands-on
maintenance by utilizing monitoring to extend the intervals.
3. The standard does not require “wire-checking,” but instead generically specifies “verification” – however an entity chooses to
do so.
Jack Stamper
Clark Public
Utilities
1
Negative
My no vote reflects my concern regarding the testing of Station DC Supply (Table
1-4) and Alarming Paths (Table 2). The SDT has provided much clarity to this
standard in the testing requirements for relays, communication systems, voltage
and current sensing devices, and control circuitry.
1. Table 1-4 is still confusing. There are five separate categories of unmonitored
Station DC Supply testing requirements. It is unclear whether these categories
are to be combined or if they are mutually exclusive. The first category applies
to “Any unmonitored station dc supply not having the monitoring attributes of
a category below” and appears to be a set of inspection and verification
8
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requirements that are generally applicable to all unmonitored Station DC
Supplies. The next four categories are applicable to Station DC Supply with
specified types of batteries. If a station has unmonitored vented lead-acid
batteries, are the batteries ONLY subject to the testing requirements for VLA
batteries? OR would these batteries ALSO be subject to the requirements of
the first category?
It appears that the intent is for all Station DC Supply not having any
monitoring attributes to be tested and maintained in accordance with the first
category as well as the second through fifth category that is applicable. If this
is the case, the SDT should consider revising the Component Attributes in
Table 1-4 for the first category of Unmonitored Station DC Supplies to the
following: Any unmonitored station dc supply not having the monitoring
attributes of a category below. (excluding UFLS and UVLS). Station DC Supply
devices applicable under these Table 1-4 general requirements will have
additional testing requirements as described below for non-battery systems,
VRLA battery systems, VLA battery systems, and Ni-Cad battery systems.
2. Do monitored batteries need to have all of the monitoring attributes listed or
does having some of the monitoring attributes qualify a device as "Monitored?"
The frequently asked questions examples on pages 30 - 32 seem to indicate
that if only some of the items are monitored, the Station DC Supply is
considered “Monitored” as long as other items are tested or verified.
If this is the case, the SDT should consider revising the Component Attributes
in Table 1-4 for the first category of Monitored Station DC Supplies to the
following: Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2): o Station
dc supply voltage (voltage of battery charger) o State of charge of the
individual battery cell/units o Battery continuity of station battery o Cell-tocell (if available) and battery terminal resistance. Monitored Station dc supply
will have one or more of the above listed conditions monitored or alarmed with
the remainder of the conditions subject to inspection and verification activities.
3. In Table 2, the first Component Attribute for Alarm Paths contains the
requirement that “Alarms are automatically reported within 24 hours of
DETECTION to a location where corrective action can be taken.” I believe the
term “automatically” should be removed. This term implies an automated
process without human intervention. However, many facilities (i.e. generator
9
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Comment
protection devices or manned substations) have protective devices that while
not being subject to continuous monitoring, are visually inspected in daily or
twice daily inspections. If protection devices have internal self-diagnostics that
provide an alarm (i.e. failure indication on faceplate, relay interrogation, or
LED failure indicator) and these devices are inspected one or more times per
day, failures or malfunctions would be reported within the 24 hour DETECTION
time. This appears to be within the intent of the standard which is to make
sure that failed protective devices do not remain in failure longer than 24
hours without notification to a location where corrective action can be taken.
Response: Thank you for your comments.
1. Table 1-4 has been modified in consideration of your comments.
2. Table 1-4 has been modified in consideration of your comments, and has been revised to remove “state of charge”.
3. “Automatically” has been removed from Table 2 in consideration of your comment.
Danny
Cleco Power
1
Negative
Cleco applies its’ UFLS on the distribution grid with each UF relay individually
McDaniel
LLC
tripping a relatively low value of load thru breakers and reclosers. Since our
program is implemented via a large number of individual components, breakers,
reclosers, and individual batteries, the failure of any one component will have a
minimal impact on the effectiveness of the overall UFLS program within our
region. Therefore, the verification of sensing devices, dc supply voltages, and the
paths of the control circuit and trip circuits on the UFLS systems implemented on
the distribution grid is unnecessary.
Response: Thank you for your comments. The SDT disagrees; the sensing devices, control circuitry and dc supply related to UFLS
has an effect on the performance of the UFLS. The SDT has, however, respected the overall impact on the control circuitry of
individual UFLS on BES reliability by requiring that UFLS be subjected to a subset of the overall sensing devices, control circuitry
and dc supply maintenance activities.
Paul Morland Colorado
1
Negative
CSU offers the following comments:
Springs
1. The document refers to the "BES" or "Bulk Electrical System" yet we have been
Utilities
unable to get a clear definition as to what that is.
2. 1.5 Because some calibration tolerances, such as communications schemes,
change with the weather conditions, establishing tolerances could be difficult if
the weather conditions are not factored into the tables.
3. 4.2.5.4 There needs to be a clear definition for “Station Service Transformers”.
4. The reference to testing tolerances implies that test equipment must be
calibrated to some standard, which this document does not discuss, and leaves
a very wide interpretation for what this standard is, or the required calibration
is required.
5. Table 1-3 Voltage and current devices may be connected to a meter and
compared to a reference source to verify proper operation of the CT or PT.
This seems to be at error in thinking that only microprocessor relays can be
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used to verify CT or PT’s. Also in many PT’s there is more than one winding
and tap, or which this standard seems to imply that only one needs to be
monitored to verify the correct function of all of the windings and taps. If I
were to follow this logic, I only need to monitor one winding of a dual core CT.
Response: Thank you for your comments.
1. Bulk Electric System is defined by NERC, and further defined by the Regional Entities. Please refer to these definitions.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. Station Service transformer provide power to the auxiliary busses of generating plants. Some alternative names for these
devices are “unit auxiliary transformers”, “station auxiliary transformers”, The SDT believes that these devices are
commonly understood throughout industry and therefore require no definition.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
5. Table 1-3 does not prescribe how the voltage and current sensing device inputs to the protective relays shall be verified, just
that they be verified according to the established intervals. Please see Section 15.2 of the Supplementary Reference
Document for a discussion on this topic.
Christopher L
de
Graffenried
Consolidated
Edison Co. of
New York
1
Negative
PRC-005 Initial Ballot Comments:
1. The Tables - The wording “Component Type” is not necessary in each
title. Just the equipment category should be listed--what is now shown as
“Component Type - Protective Relay”, should be Protective Relay.
However, Protective Relay is too general a category. Electromechanical
relays, solid state relays, and microprocessor based relays should have
their own separate tables. So instead of reading Protective Relay in the
title, it should read Electromechanical Relays, etc. This will lengthen the
standard, but will simplify reading and referring to the tables, and
eliminate confusion when looking for information. The “Note” included in
the heading is also not necessary. “Attributes” is also not necessary in the
column heading, “Component” suffices.
2. Other Comments - In general, the standard is overly prescriptive and
complex. It should not be necessary for a standard at this level to be as
detailed and complex as this standard is. Entities working with
manufacturers, and knowledge gained from experience can develop
adequate maintenance and testing programs.
3. Why are “Relays that respond to non-electrical inputs or impulses (such
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4.
5.
6.
7.
8.
9.
as, but not limited to, vibration, pressure, seismic, thermal or gas
accumulation)...” not included? The output contacts from these devices
are oftentimes connected in tripping or control circuits to isolate problem
equipment.
Due to the critical nature of the trip coil, it must be maintained more
frequently if it is not monitored. Trip coils are also considered in the
standard as being part of the control circuitry. Table 1-5 has a row labeled
“Unmonitored Control circuitry associated with protective functions”,
which would include trip coils, has a “Maximum Maintenance Interval” of
“12 Calendar Years”. Any control circuit could fail at any time, but an
unmonitored control circuit could fail, and remain undetected for years
with the times specified in the Table (it might only be 6 years if I
understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure,
then the system must be operated in real time assuming that that breaker
will not trip for a fault or an event, and backup facilities would be called
upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker
unable to trip), instead of one line tripping, you might have many more
lines deloaded or tripped because of a bus having to be cleared because
of a breaker failure initiation. The bulk electric system would have to be
operated to handle this contingency.
In reference to the FAQ document, Section 5 on Station dc Supply,
Question K, clarification is needed with respect to dc supplies for
communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation,
would the standard apply to these batteries or not?
To define terms only as they are used in PRC-005-2 is inviting confusion.
Although they may be unique to PRC-005-2, some or all of them may be
used in future standards, some already may be used in existing standards,
and may or may not be deliberately defined. Consistency must be
maintained, not only for administrative purposes, but for effective
technical communications as well.
What is the definition of “Maintenance” as used in the table column
“Maximum Maintenance Interval”? Maintenance can range from cleaning a
relay cover to a full calibration of a relay.
A control circuit is not a component, it is made up of components.
Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify
calibration tolerances or other equivalent parameters...” means, and may
be subject to different interpretations by entities and compliance
12
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enforcement personnel.
10. In the Implementation plan for Requirement R1, recommend changing
“six” to fifteen. This change would restore the 3-month time difference
that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require
regulatory approval. It will ensure equity for those entities located in
jurisdictions that do not require regulatory approval, as is the case in
Ontario.
11. The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It
seems to continue to the next page to a new box. There are multiple
activities without clear delineation.
12. Regarding station service transformers, Item 4.2.5.5 under Applicability
should be deleted. The purpose of this standard is to protect the BES by
clearing generator, generator bus faults (or other electrical anomalies
associated with the generator) from the BES. Having this standard apply
to generator station service transformers, that have no direct connection
to the BES, does meet this criteria. The FAQs (III.2.A) discuss how the
loss of a station service transformer could cause the loss of a generating
unit, but this is not the purpose of PRC-005. Using this logic than any
system or device in the power plant that could cause a loss of generation
should also be included. This is beyond the scope of the NERC standards.
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that
minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent maintenance, a
performance-based program in accordance with Requirement R3 and Attachment A is an option.
3. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection
System definition. Also, there is currently no technical basis for the maintenance of the devices which respond to non-electrical
quantities on which to base mandatory standards related either to activities or intervals. Absent such a technical basis, we are
currently unable to establish mandatory requirements, but may do so in the future if such a technical basis becomes available.
4. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year interval.
You can maintain these devices more frequently if you desire.
5. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the communications
system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The specific station dc
supply requirements (Table 1-4) do not apply to the dc supply associated only with communications systems. The SDT decided to
13
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eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate.
The SDT considered your comments during this activity.
6. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms,
either now or in the future, may not be consistent with the terms used here. They are defined only for clarify within this standard.
The SDT will confirm with NERC staff that this approach is acceptable.
7. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are specified in
the Activities column. The term is capitalized in the column title in conformance with normal editorial practice as a title, rather
than as a definition.
8. For purposes of this standard, the control circuit IS defined as one component type..
9. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed
within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4
has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Please see Supplementary Reference Document, Section 8 for a discussion of this.
10. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making it
consistent with the remainder of the Implementation Plan.
11. Table 1-4 has been further modified for clarity.
12. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
Robert W.
Roddy
Dairyland
Power Coop.
1
Negative
In Table 1-5 it is unclear which devices the Maximum Maintenance Intervals would
be held to, such as trip coils of circuit breakers and coils of electromechanical trip
or auxiliary relays whose continuity and energization are monitored and alarmed.
Response: Thank you for your comments. Trip coils of circuit breakers have a 6-year interval for physical operation. Coils of
lockout and auxiliary relays also have a 6-year interval for physical operation. Control circuitry whose continuity and energization or
ability to operate are monitored and alarmed require no hands-on maintenance.
John K Loftis
Dominion
Virginia Power
1
Negative
Dominion is opposed to this version because Requirement R1.5 is overly
prescriptive, requiring an extraordinary level of documentation, with little
anticipated improvement in reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
14
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George R.
Bartlett
Entergy
Corporation
Segment
1
Vote
Negative
Comment
The restructured tables are generally much clearer and the SDT is to be
commended on their efforts.
1. However, we believe the Alarming Point Table needs additional
clarification with regard to the Maximum Maintenance Interval. If an
“alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there
isn’t necessarily a maximum interval established as there is for Protection
System components. Also, if an entity’s alarm producing device
maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum
intervals for the alarm producing device of that entity. On that basis, we
suggest the interval verbiage be revised to “When alarm producing device
or system is verified, or by sections as per the monitored
component/protection system specified maximum interval as applicable”.
Alternately, if the intention is to establish maximum intervals as simply
being no longer than the individual component maintenance intervals as
we suggest for inclusion above, then the verbiage should be revised to
“When alarm producing component/protection system segment is
verified”. In either case, are we to interpret monitored components with
attributes which allow for no periodic maintenance specified as not
requiring periodic alarm verification?
2. R1.5 calls for “identification of calibration tolerances or equivalent
parameters...” whereas the associated VSL references “failure to establish
calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply
“identify” or document such calibration tolerances would be analogous to
the severity level(s) of a “failure to specify one" or the severity level
should be consistent with the other elements of R1. Both cases appear to
be more of a documentation issue as opposed to a failure to implement.
Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4? R1.5 calls for “identification of calibration tolerances
or equivalent parameters for each Protection System Component Type....”.
We believe the Supplementary Reference document should provide
additional information and examples of calibration tolerances or equivalent
parameters which would be expected for the various component types.
Especially for any “equivalent” parameters which would be required for
compliance for a component type besides protective relays. Adding
Requirement 1.5 is a significant revision and raises questions as to how
broadly an accuracy or equivalent parameter requirement and associated
15
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documentation would need to be addressed by entities and/or will be
measured for compliance. Discussion on this new requirement does not
seem to be addressed anywhere in the FAQ or Supplementary Reference
documents. Additionally, to the best of our knowledge, the need for such
a requirement was not brought up as a concern or comment on the prior
draft version of this standard, and in the context of a requirement need,
we don’t believe it has been attributed to or actually poses any significant
reliability risk. We do not believe this requirement is justified.
Response: Thank you for your comments.
1. The Maximum Maintenance Interval column entry in Table 2 has been revised to state, “When alarm producing Protection
System component is verified” to clarify this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Robert
FirstEnergy
1
Negative
Please see FirstEnergy's comments submitted separately through the comment
Martinko
Energy
period posting.
Delivery
Response: Thank you for your comments.
Please see our responses to your comments from the formal comment period.
Gordon
Pietsch
Great River
Energy
1
Negative
1. We believe that requiring an entity to identify calibration tolerances in
their PSMP does not add a material benefit and does not contribute to
increased reliability. In addition we believe that R1.5 should be rewritten
to state that a Relay test report should show when a Relay fell out of
tolerance. R4.2 should be rewritten to state that if a test report does show
that a Relay was out of tolerance it should be required to show that
resolution was initiated.
2. The Activities section of Table 1.3 should be revised to include that the
signals do not have to come from energized voltage or current sensing
devices. The current or voltage signals can come from a test set. Note: It
may be difficult to energize CTs or VTs for large capacitor banks, reactors,
or generating units.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
16
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Comment
2. Table 1-3 has been modified in consideration of your comments.
Ajay Garg
Hydro One
Networks,
Inc.
1
Negative
Hydro One is casting a negative vote with the following comments:
1. The added requirement R1, Part 1.5 is vague and needs clarification. It is not
clear what “Identify calibration tolerances or other equivalent parameters”
means and as written will be subject to different interpretations by entities and
compliance enforcement personnel. The addition of this new part of
Requirement R1 that requires the Owners to “identify calibration tolerances or
other equivalent parameters for each Protection System component type” is
onerous and contributes little to the reliability of the BES.
2. Changes introduced to the Implementation Plan since the last posting are not
consistent with respect to jurisdictions where no regulatory approval is
required. The previously posted implementation for Requirement R1 required
entities to be 100% compliant on the first day of the first calendar quarter
three months following applicable regulatory approvals, or in those
jurisdictions where no regulatory approval is required, on the first day of the
first calendar quarter six months following Board of Trustees adoption. The
amended implementation plan changed the three-month time to twelve
months in jurisdictions with regulatory approval required but left the same sixmonth time for the others. For consistency, the six months timeframe should
be changed to fifteen months.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making
it consistent with the remainder of the Implementation Plan.
Michael
Moltane
International
Transmission
Company
Holdings Corp
1
Negative
1. ITC votes "Negative" for the following reasons: Our negative ballot is
based on our objection to the 6 year test interval for auxiliary relays. We
believe our present maintenance period for auxiliary relays of 10 years is
adequate.
2. We also object to the requirement to verify acceptable levels of current
values are received by the protective relays. We believe our present
current transformer testing practice adequately insures acceptable levels
of current are received by the relays and have requested that this
procedure be approved. Detailed comments are included with our
17
Voter
Entity
Segment
Vote
Comment
responses to the 5 questions in the Comment Form associated with this
proposed Standard revision.
Response: Thank you for your comments.
1. The SDT believes that the appropriate interval for devices such as aux or lockout relays remains at 6 years, as these devices
contain “moving parts” which must be periodically exercised to remain reliable.
2.
Please see our response in the Comment Form.
Stan T. Rzad
Keys Energy
Services
1
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuity, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
that distribution circuit. There is no real reliability need for this either.
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regio0nsl UFLS program is being
met, but, to test the other protection system components is not
worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing
faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this
version is better than prior versions because it essentially requires the
entity to determine it's own period of maintenance and testing for
UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
18
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical
4. The VRF of R1 should be Low since the attached tables are essentially the
PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to 4.2.1 in consideration of your comment.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the establishment of an
entity’s individual PSMP.
Walt Gill
Lake Worth
1
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
Utilities
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuity, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
19
Voter
Entity
Segment
Vote
Comment
2.
3.
4.
5.
that distribution circuit. There is no real reliability need for this either.
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regionsl UFLS program is being met,
but, to test the other protection system components is not worthwhile.
Note that DC Supplies and most of the control circuitry of distribution lines
are "tested" frequently by distribution circuits clearing faults such as
animals, vegetation blow-ins, lightning, etc., on distribution circuits,
reducing the value of testing to just about null. However, this version is
better than prior versions because it essentially requires the entity to
determine it's own period of maintenance and testing for UFLS/UVLS for
DC Supply and control circuitry.
Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical
The VRF of R1 should be Low since the attached tables are essentially the
PSMP.
Table 1-4 requires a comparison of measured battery internal ohmic value
to battery baseline. Since battery manufacturers do not provide this value,
it is unclear what the “baseline” values ought to be if an entity recently
began performing this test (assuming it’s several years after the
commissioning of the battery.) Would it be acceptable for an entity to
establish baseline values based on statistical analysis of multiple test
results specific to a given battery manufacturer and design? o Small
entities with only one or two BES substations may not have enough
components to take advantage of the expanded maintenance intervals
afforded by a performance-based maintenance program. Aggregating
20
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
these components across different entities doesn’t seem too logical
considering the variations at the sub-component level (wire gauge,
installation conditions, etc.)
6. Trip circuits are interconnected to perform various functions. Testing a trip
path may involve disabling other features (i.e. breaker failure or reclosing)
not directly a part of the test being performed. Temporary modifications
made for testing introduce a chance to unknowingly leave functions
disabled, contacts shorted, jumpers lifted, etc. after testing has been
completed. Trip coils and cable runs from panels to breaker can be made
to meet the requirements for monitored components. The only portions of
the circuitry where this may not be the case is in the inter and intra-panel
wiring. Because such portions of the circuitry have no moving parts and
are located inside a control house, the exposure is negligible and should
not be covered by the requirements. Entities will be at increased
compliance risk as they struggle to properly document the testing of all
parallel tripping paths.
1.For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component types,
UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during the stressed
system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and
UVLS from maintenance activities related to the interrupting device trip coil.
2.This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration to your comment.
3.The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As for
auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the degree
that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and are being
added to PRC-005-2 to resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the establishment of an
entity’s individual PSMP.
5. Typical baseline values for various types of lead-acid batteries can be obtained from the test equipment manufacturer, perhaps
the battery vendor, and perhaps other sources for batteries that are already in service. For new batteries, the initial battery
baseline ohmic values should be measured upon installation and used for trending.
6. The requirement relative to control circuitry does not explicitly require trip or functional testing of the entire path; it requires that
entities verify all paths without specifying the method of doing so. Please see Section 15.5 of the Supplementary Reference
Document for detailed discussion.
21
Voter
Larry E Watt
Entity
Lakeland
Electric
Segment
1
Vote
Negative
Comment
The major reasons are that:
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuity, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
that distribution circuit. There is no real reliability need for this either.
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regio0nsl UFLS program is being
met, but, to test the other protection system components is not
worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing
faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this
version is better than prior versions because it essentially requires the
entity to determine it's own period of maintenance and testing for
UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
22
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
electrical
4. the VRF of R1 should be Low since the attached tables are essentially the
PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comment.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the establishment of an
entity’s individual PSMP.
Joe D Petaski Manitoba
1
Negative
1. Implementation Plan (Timeline) for R1: In areas not requiring regulatory
Hydro
approval, the 6 month time frame proposed for R1 is not achievable and is
not consistent with areas requiring regulatory approval. To be consistent,
the effective date for R1 in jurisdictions where no regulatory approval is
required should be the first day of the first calendar quarter 12 months
after BOT approval.
2. VSLs: The high VSL for R1 “Failed to include all maintenance activities
relevant for the identified monitoring attributes specified in Tables 1-1
through 1-5” may be interpreted in different ways and should be further
clarified.
3. Table 1-4: The requirements for batteries listed in Table 1-4 do not
appear to be consistent with the comments in the FAQ Section (V 1A
Example 1). Please see comments submitted during formal comment
period for further detail.
4. Table 1-4: The requirement for a 3 month check on electrolyte level
seems too frequent based on our experience. We would like to point out
that although IEEE std 450 (which seems to be the basis for table 1-4)
does recommend intervals it also states that users should evaluate these
recommendations against their own operating experience.
23
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments.
1. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making
it consistent with the remainder of the Implementation Plan.
2. The SDT does not understand your concern; further details are needed.
3. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
4. The SDT believes that the 3-month interval specified in the Standard is appropriate.
Terry
MidAmerican
1
Negative
MidAmerican remains concerned that including requirements for testing of
Harbour
Energy Co.
electromechanical trip or auxiliary devices (Table 1-5 Row 3) will in some cases
require entire bus outages that will compromise the BES reliability due to the need
for entities across the US to take multiple BES elements out of service during the
testing. If this requirement is retained additional time should be included in the
implementation plan to allow for system modifications, such as the installation of
relay test switches, to potentially allow for this testing while minimizing testing
outages.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Saurabh
National Grid
1
Negative
National Grid believes that this new Requirement as written subjects the
Saksena
Transmission Owner, Generation Owner or Distribution Provider to vague
interpretations of what the requirement means by compliance officials. The
addition of the new part of Requirement R1 that requires the Owners to “identify
calibration tolerances or other equivalent parameters for each Protection System
component type” is too intrusive and divisive for what it brings to the reliability of
the BES.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Richard L.
Nebraska
1
Negative
1. The PSMP definition inappropriately extends the maintenance program to
Koch
Public Power
include corrective maintenance. The first bullet of the Detailed Description
District
section of the SAR specifically states: "Analysis of correct operations or
misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard." The
comment in the SAR was directed toward the Purpose of PRC-017 since it
is the only one of the applicable PRC standards that included corrective
measures in its Purpose. However, the concept of not including corrective
maintenance in a maintenance standard should apply to all of the
24
Voter
Entity
Segment
Vote
Comment
2.
3.
4.
5.
applicable PRC standards. The same statement from the SAR identified
above was also included in the NERC SPCTF Assessment of Standards
referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment
of the Standards identified the need to expand the maintenance and
testing program to include corrective maintenance. I recommend deleting
the words "and proper operation of malfunctioning components is
restored." from the first sentence of the PSMP definition. I believe that
failure to do so exceeds the scope of the SAR.
Applicability Part 4.2.2: The ERO does not establish underfrequency loadshedding requirements. Those requirements will be established by
Reliability Standard PRC-006-1 when it is approved by FERC. I recommend
changing Accountability Part 4.2.2. to "...installed to provide last resort
system preservation measures." (Note this wording is consistent with the
Purpose of PRC-006-0.)
Applicability Part 4.2.5.4 and 4.2.5.5: Station Service transformers provide
energy to plant loads and not the BES. If these plant transformers are
included, why not include the rest of the plant systems? I recommend
deleting Applicability Part 4.2.5.4 and 4.2.5.5.
Requirement R4: The PSMP definition inappropriately extends the
maintenance program to include corrective maintenance. The first bullet
of the Detailed Description section of the SAR specifically states: "Analysis
of correct operations or misoperations may be an integral part of
condition-based maintenance processes, but need not be mandated in a
maintenance standard." The comment in the SAR was directed toward the
Purpose of PRC-017 since it is the only one of the applicable PRC
standards that included corrective measures in its Purpose. However, the
concept of not including corrective maintenance in a maintenance
standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC
SPCTF Assessment of Standards referenced in the SAR. Neither the SAR
nor the NERC SPCTF Assessment of the Standards identified the need to
expand the maintenance and testing program to include corrective
maintenance. I recommend deleting the words "including identification of
the resolution of all maintenance correctable issues" from the first
sentence of the Requirement. I believe that failure to do so exceeds the
scope of the SAR.
Requirement R4 Part 4.2: The PSMP definition inappropriately extends the
maintenance program to include corrective maintenance. The first bullet
of the Detailed Description section of the SAR specifically states: "Analysis
25
Voter
Entity
Segment
Vote
Comment
of correct operations or misoperations may be an integral part of
condition-based maintenance processes, but need not be mandated in a
maintenance standard." The comment in the SAR was directed toward the
Purpose of PRC-017 since it is the only one of the applicable PRC
standards that included corrective measures in its Purpose. However, the
concept of not including corrective maintenance in a maintenance
standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC
SPCTF Assessment of Standards referenced in the SAR. Neither the SAR
nor the NERC SPCTF Assessment of the Standards identified the need to
expand the maintenance and testing program to include corrective
maintenance. I recommend re-wording Requirement 4, Part 4.2 to state:
"Verify that the components are within the acceptable parameters
established in accordance with Requirement R1, Part 1.5 at the conclusion
of the maintenance activities." I believe that failure to do so exceeds the
scope of the SAR.
6. Measurement M4: The PSMP definition inappropriately extends the
maintenance program to include corrective maintenance. The first bullet
of the Detailed Description section of the SAR specifically states: "Analysis
of correct operations or misoperations may be an integral part of
condition-based maintenance processes, but need not be mandated in a
maintenance standard." The comment in the SAR was directed toward the
Purpose of PRC-017 since it is the only one of the applicable PRC
standards that included corrective measures in its Purpose. However, the
concept of not including corrective maintenance in a maintenance
standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC
SPCTF Assessment of Standards referenced in the SAR. Neither the SAR
nor the NERC SPCTF Assessment of the Standards identified the need to
expand the maintenance and testing program to include corrective
maintenance. I recommend deleting the words: "and initiated resolution of
identified maintenance correctable issues" from the last sentence of
Measurement M4. I believe that failure to do so exceeds the scope of the
SAR.
Response: Thank you for your comments.
1. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues
(discovered during maintenance activities) is included. The SDT considers this inclusion to be appropriate and necessary as
part of the maintenance program.
26
Voter
Entity
Segment
Vote
Comment
2. Under frequency load shedding requirements, whether established by regional Entities (current practice) or by EC, are ERO
requirements.
3. Clause 4.2.5.5 has been removed. Generator-connected station service transformers are essential to the continuing operation
of the generation plant; therefore, protection on these system components is included within PRC-005-2 if the generation
plant is a BES facility.
4. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues
(discovered during maintenance activities) in included. The SDT considers the inclusion to be appropriate and necessary as
part of the maintenance program.
5. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
6. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues
(discovered during maintenance activities) in included. The SDT considers the inclusion to be appropriate and necessary as
part of the maintenance program.
David H.
Northeast
1
Negative
1) Requirement 1.5 states “Identify calibration tolerances or other equivalent
Boguslawski
Utilities
parameters for each Protection System component type that establish acceptable
parameters for the conclusion of maintenance activities”. This requirement is too
vague and requires that the owner develop his own acceptable calibration
tolerances for “each” protection system component type. The Owners internally
generated calibration tolerances would then be subjected to the personal
interpretation of what this requirement means by compliance officials and
auditors. The confusion and divisiveness that this requirement will create far
outweigh its potential benefits.
2) Due to the critical nature of the trip coil, it should be maintained more
frequently if it is not monitored. Hence, it would be prudent to increase the test
frequency of unmonitored trip coil so that it is more frequent than monitored trip
coil.
3) In reference to the FAQ document, Section 5 on Station dc Supply, Question K,
clarification is needed with respect to dc supplies for communication within the
substation. For example, if the communication systems were run off a separate
battery in separate area in a substation, would the standard apply to these
batteries or not?
4) In section D.1.3., the statement regarding data retention for R2 needs to be
reworded. The words “performance based maintenance program” should be
changed to “time based maintenance program”, since R2 refers to a time based
maintenance program.
27
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year
interval. You can maintain these devices more frequently if you desire.
3. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the
communications system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The
specific station dc supply requirements (Table 1-4) do not apply to the dc supply associated only with communications
systems. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the
Supplementary Reference Document. Your comments have been considered within that activity.
4. The SDT concluded that R2 is redundant with R1, Part 1.4, and has deleted R2 (together with the associated Measure and VSL),
and data retention that reflects the previous R2.
Douglas G
Omaha Public 1
Negative
The three newly added requirements not approved by the drafting team are
Peterchuck
Power District
confusing.
1. OPPD believes that Article 1.4 needs to be deleted from the standard. It is
redundant and serves no purpose.
2. OPPD believes that Article 1.5 needs to be deleted from the standard.
There is a major concern on what an “acceptable parameter” is and how it
would be interpreted by the Regional Entities.
3. OPPD believes that Article 4.2 needs to be deleted from the standard.
There is no need for this article if Article 1.5 is deleted.
Response: Thank you for your comments.
1. The SDT disagrees; Requirement R1, Part 1.4 supports Requirement R1, Part 1.2, and seems necessary to assure that entities
have appropriately applied the longer intervals associated with monitored components. However, in consideration to your
comment the SDT has revised R1.4 and has also removed R2 because of redundancy to Requirement R1, Part 1.4.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
3. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this..
Chifong L.
Pacific Gas
1
Negative
1. PG&E submits a Negative vote on Draft 3 of PRC-005-2 due to the
Thomas
and Electric
addition of Requirement R1, Part 1.5. We do not agree with the addition
Company
of Requirement R1, Part 1.5 to the standard, which requires the Owners
to "identify calibration tolerances or other equivalent parameters for each
Protection System component type". We feel this is too prescriptive and
does not belong in the PSMP which should remain at a higher level of
detail. This new requirement, as written, can subject the Transmission
Owner, Generation Owner or Distribution Provider to vague interpretations
28
Voter
Entity
Segment
Vote
Comment
of what the requirement means by compliance officials. Additionally, the
new requirement could require documenting thousands of calibration
tolerances or other equivalent parameters for companies such as PG&E
that use many different types of relays. This level of detail does not
belong in the PSMP and would make it nearly impossible to manage.
Rather, the calibration tolerances used to test the protection system
components should reside in the Transmission Owner, Generation Owner
and Distribution Provider's test procedure documents, test macros, or
relay instruction manuals. PG&E also has comments on the
Implementation Plan document.
2. PG&E does not agree with the time frames listed for implementation of
Requirements R1, R2, R3 and R4, as explained below:
a. Implementation plan for Requirement R1: Time was extended
from three months to twelve months following regulatory approval
which we agree with. For those jurisdictions where no regulatory
approval is required it would seem that the time frame should also
be extended to at least twelve months following NERC Board
approval. However, it is still listed as six months following NERC
Board approval.
b. Implementation plan for Requirements R2, R3 and R4: For
Protection System Components with maximum allowable intervals
less than 1 year, it does not make sense to require 100%
compliance after twelve months following regulatory approval,
when this is the same time frame for compliance with
Requirement R1 for establishment of the new PSMP. The
implementation time window for Requirements R2, R3 and R4
should follow the implementation of Requirement R1 which
establishes the new PSMP. So the dates listed for 100%
compliance with Requirements R2, R3 and R4 should all be
pushed out by 12 months each.
c. Following is a summary time line for suggested implementation
requirements. o Months 1-12 Establish PSMP per R1
i. Month 12+ Begin performing maintenance under new
PSMP
ii. Month 24 100% compliance date for R2, R3, R4, for
components with max allowable intervals less than 1 year.
iii. 3 Calendar Years 100% compliance date for R2, R3, R4,
for components with max allowable intervals 1 year or
more, but 2 years or less.
29
Voter
Entity
Segment
Vote
Comment
iv. 3 Calendar Years 30% compliance date for R2, R3, R4, for
components with max allowable intervals of 6 years.
v. 5 Calendar Years 60% compliance date for R2, R3, R4,
for components with max allowable intervals of 6 years.
vi. 7 Calendar Years 100% compliance date for R2, R3, R4,
for components with max allowable intervals of 6 years.
3. Overall the updated standard is a huge improvement over Draft 2 in terms
of structure of the tables and presentation, which simplifies the standard
quite a bit. PG&E would have been in support of Draft 3 if the requirement
R1.5 had not been added.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed
within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4
has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. The Implementation Plan for R1 has been changed from six months to twelve months, and the Implementation Plan for Protection
System Components with maximum allowable intervals less than 1 year has been changed from 12 months to 15 months in
consideration of your comment. The Implementation Plan for R4 has been revised to add one year to all established dates.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed
within the PSMP definition and that Requirement R1, Part 1.5 is not necessary. Therefore, it has been removed. The associated
VSL has also been revised.
Brenda L
PPL Electric
1
Negative
PPL Electric Utilities (“PPL EU”) appreciate the hard work and efforts of the
Truhe
Utilities Corp.
Standards Drafting Team in reaching this point in the standards development
process. The basis for the negative vote is the addition of Requirement R1.5
(calibration tolerances) and R4.2 to the standard. This requirement will provide
the opportunity for auditors to decide if the testing criteria for whether a relay
passes a test or not is acceptable. PPL EU recommends that Requirement R1.5 be
deleted from the standard.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Kenneth D.
Public Service 1
Negative
The PSEG Companies do not agree with the Facilities as currently described in
Brown
Electric and
section 4.2.5.5. Please refer to detailed comments provided in the formal
Gas Co.
Comment Form.
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
30
Voter
Pawel Krupa
Entity
Seattle City
Light
Segment
1
Vote
Negative
Comment
Comment: The proposed Standard PRC-005-2 is an improvement over the
previous draft in that it provides more consistency in maintenance and testing
duration internals.
Notwithstanding, two issues are of concern to Seattle City Light such that it is
compelled to vote no:
1) the establishment of bookends for standard verification and
2) the implementation timelines for entities with systems where electromechanical relays still compose a significant number of components in their
protection systems.
1. Bookends: Proposed Standard PRC-005-2 specifies long inspection and
maintenance intervals, up to 12 years, which correspondingly exacerbates the socalled “bookend” issue. To demonstrate that interval-based requirements have
been met, two dates are needed - bookends. Evidencing an initial date can be
problematic for cases where the initial date would occur prior to the effective date
of a standard. NERC has provided no guidance on this issue, and the Regions
approach it differently. Some, such as Texas Regional Entity, require initial dates
beginning on or after the effective date of a Standard. Compliance with intervals is
assessed only once two dates are available that occur on or after a standard took
effect. Other regions, such as Western Electricity Coordinating Council (WECC),
require that entities evidence an initial date prior to the effective date of a
standard. For WECC, compliance with intervals is assessed as soon as a standard
takes effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal. Proposed
Standard PRC-005-2 will be another such standard. Indeed this Standard will
involve by far the largest number of bookends of any NERC standard - many
thousands for a typical entity. Furthermore, the long inspection and maintenance
intervals introduced in the draft will require entities in WECC, for instance, to
evidence initial bookend dates prior to the date original PRC-005-1 took effect. For
the 12-year intervals for CTs and VTs in proposed Standard PRC-005-2, many
initial dates will occur prior to the 2005 Federal Power Act that authorized
Mandatory Reliability Standards and even reach back before the 2003 blackout
that catalyzed the effort to pass the Federal Power Act. As a result, many entities
in WECC maybe at risk of being found in violation of proposed Standard PRC-0052 immediately upon its implementation. Seattle City Light requests that NERC
address the bookends issue, either within proposed Standard PRC-005-2 or in a
31
Voter
Entity
Segment
Vote
Comment
separate, concurrent document.
2. Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with legacy
systems. In example, auxiliary relay and trip coil testing may be essential to prove
the correct operation of complex, multi-function digital protection systems.
However, for legacy systems with single-function electro-mechanical components,
the considerable documentation and operational testing needed to implement and
track such testing is not necessarily proportional to the relative risk posed by the
equipment to the bulk electric system. Performance testing of electro-mechanical
systems, particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause far
more problems on restoration-to-service than they will locate and correct. As such,
to assist entities in their implementation efforts, we believe provision of
alternatives are necessary, such as additional implementation time through
phasing and/or through technical feasability exceptions.
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18 Evidence”.
2. Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic. FERC Order 693
directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is a portion
thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has developed those
requirements in a fashion that affords entities with the opportunity to best meet those requirements.
Horace
Southern
1
Negative
Reference the new Requirements R.1.5 and R.4.2 which are new to this posting:
Stephen
Company
R.1.5 requires the Owners to “identify calibration tolerances or other equivalent
Williamson
Services, Inc.
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES. The entire SDT needs to
thoroughly discuss these new requirements and modify or delete them. Note: We
have also made various requests for clarification to the FAQ and Supplemental
Reference document in our Response to Comments which we are not including
here.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
32
Voter
Entity
Segment
Vote
Larry Akens
Tennessee
Valley
Authority
1
Negative
Brandy A
Dunn
Western Area
Power
Administration
1
Negative
Comment
NERC is making significant changes to this sizeable standard and only allowing
minimum comment period. While this is a good standard that has clearly taken
many hours to develop, we are primarily voting “NO” because of the hurried
fashion it is being commented, voted, and reviewed.
Response: Thank you for your comments. Because of the urgent priority placed on this Standard by NERC, this Standard was
posted for a 30-day formal comment period with a concurrent 10-day ballot period at the conclusion of that comment period, even
though the Standard Development Process allows for a maximum 45-day formal comment period.
1) Western disagrees with the requirement R1, Part 1.5 that requires identifying
"calibration tolerances or equivalent parameters for each Protection System
component~" This requirement will add a burdensome, manual documentation of
thousands of tolerances and parameters that are now part of multiple automated
software programs and routines. These programs were purchased and developed
over numerous years of testing experience by Western and testing equipment
manufacturers. The fact that these tolerance and parameters are automated to
Pass/Fail program notifications, gives our Maintenance Divisions repeatable testing
programs that are not dependent on personnel interpretations. Extracting all these
tolerances and parameters from these programs provides no benefit for our PSMP.
2) Western disagrees with the wording of the R4.2 requirement referencing the
Part 1.5 of R1. The requirements of R4 are that you are to perform the
appropriate maintenance activity and the associated testing. The fact that the
testing was done and the equipment passed the testing meets the compliance for
R4. If the equipment fails the testing, it then becomes a maintenance correctable
issue, that requires adjustment or replacing, with further testing until the
equipment passes the required testing. Documenting thousands of tolerances and
parameters, for possibly thousands of components, serves no useful purpose for
our PSMP or compliance documentation.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Gregory L
Xcel Energy,
1
Negative
“We feel that several improvements were made since the last draft. However, we
Pieper
Inc.
feel that some gaps exist that should be addressed before moving this project
forward. We have detailed our issues in our formal comments.”
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
33
Voter
Kim Warren
Entity
Independent
Electricity
System
Operator
Segment
2
Vote
Negative
Comment
1. Requirement R1, Part 1.5 is vague and needs clarification. It is not clear
what “Identify calibration tolerances or other equivalent parameters”
means and this may be subject to different interpretations by entities and
compliance enforcement personnel.
2. Additionally, in the Implementation plan for Requirement R1, we
recommend changing “six” to “fifteen” to restore the 3-month time
difference between the durations of the implementation periods for
jurisdictions that do and don’t require regulatory approval, which existed
in the previous draft. This change will ensure equity for those entities
located in jurisdictions that do not require regulatory approval as is the
case here in Ontario. More importantly it supports the IESO’s strong belief
in the principle that reliability standards should be implemented in an
orderly and coordinated fashion across regions to ensure system reliability
is not compromised.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making
it consistent with the remainder of the Implementation Plan
Richard J.
Alabama
3
Negative
Reference the new Requirements R.1.5 and R.4.2 which are new to this posting:
Mandes
Power
R.1.5 requires the Owners to “identify calibration tolerances or other equivalent
Company
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES. The entire SDT needs to
thoroughly discuss these new requirements and modify or delete them. Note: We
have also made various requests for clarification to the FAQ and Supplemental
Reference document in our Response to Comments which we are not including
here.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Bob Reeping Allegheny
3
Negative
Allegheny Power applauds the hard work that the Standards Draft Team has
Power
exhibited in producing a clear and enforceable standard that will increase the
reliability of the Bulk Electric System. However, the addition of requirement 1.5 is
such a significant change in scope from the last draft that a further review of the
potential impact and any implementation concerns is required by AP and the
industry in general before we can consider voting in-favor of this standard.
34
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Raj Rana
American
3
Negative
Restructured Tables:
Electric Power
1. Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12
years for unmonitored control circuitry, yet other portions of control
circuitry have a maximum interval of 6 years. AEP does not understand
the rationale for the difference in intervals, when in most cases, one
verifies the other. Also, unmonitored control circuitry is capitalized in row
4 such that it infers a defined term.
2. In the first row of table 1-4 on page 16, it is difficult to determine if it is a
cell that wraps from the previous page or is a unique row. This is
important because the Maximum Maintenance Intervals are different (i.e.
18 months vs 6 years). It is difficult to determine to which elements the 6
year Maximum Maintenance Interval applies. AEP suggests repeating the
heading “Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2):” for
the bullet points on this page.
VSLs, VRFs and Time Horizons:
3. The VSL table should be revised to remove the reference to the Standard
Requirement 1.5 in the R1 “High” VSL.
4. All four levels of the VSL for R2 make reference to a “condition-based
PSMP.” However, nowhere in the standard is the term “condition-based”
used in reference to defining ones PSMP. The VSL for R2 should be
revised to remove reference to a condition-based PSMP; alternatively the
Standard could be revised to include the term “condition-based” within the
Standard Requirements and Table 1.
5. In multiple instances, Table 1 uses the phrase “No periodic maintenance
specified” for the Maximum Maintenance Interval. Is this intended to imply
that a component with the designated attributes is not required to have
any periodic maintenance? If so, the wording should more clearly state
“No periodic maintenance required” or perhaps “Maintain per
manufacturers recommendations.” Failure to clearly state the maintenance
requirement for these components leaves room for interpretation on
whether a Registered Entity has a maintenance and testing program for
devices where the Standard has not specified a periodic maintenance
interval and the manufacturer states that no maintenance is required.
FAQ and Supplementary Reference:
35
Voter
Entity
Segment
Vote
Comment
6. With such a complex standard as this, the FAQ and Supplementary
Reference documents do aid the Protection System owner in demystifying
the requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a. Section 5 of the Supplementary Reference, refers to “conditionbased” maintenance programs. However, nowhere in the standard
is the term “condition-based” used in reference to defining ones
PSMP. The Supplementary Reference should be revised to remove
reference to a condition-based PSMP; alternatively the Standard
could be revised to include the term “condition-based” within the
Standard Requirements and Table 1.
b. Section 15.7, page 26, appears to have a typographical error
“...can all be used as the primary action is the maintenance
activity...”
c. Figure 2 is difficult to read. The figure is grainy and the colors
representing the groups are similar enough that it is hard to
distinguish between groups.
“Frequently-Asked Questions”:
7. With such a complex standard as this, the FAQ and Supplementary
Reference documents do aid the Protection System owner in demystifying
the requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a. The section “Terms Used in PRC-005-2” is blank and should be
removed as it adds no value.
b. Section I.1 and Section IV.3.G reference “condition-based”
maintenance programs. However, nowhere in the standard is the
term “condition-based” used in reference to defining ones PSMP.
The FAQ should be revised to remove reference to a conditionbased PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard
Requirements and Table 1.
c. The second sentence to the response in Section I.1 appears to
have a typographical error “... an entity needs to and perform
ONLY time-based...”.
General:
36
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
8. Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2
should be removed. Specifying calibration tolerances for every protection
system component type, while a seemingly good idea, represents a
substantial change in the direction of the standard. It would be very
onerous for companies to maintain a list of calibration tolerances for every
protection system component type and show evidence of such at an audit.
AEP believes entities need the flexibility to determine what acceptance
criteria is warranted and need discretion to apply real-time
engineering/technician judgment where appropriate.
9. Three different types of maintenance programs (time-based,
performance-based and condition-based) are referenced in the standard
or VSLs, yet the time-based and condition-based programs are neither
defined nor described. Certain terms defined within the definition section
(such as Countable Event or Segment) only make sense knowing what
those three programs entail. These programs should be described within
the standard itself and not assume a knowledge of material in the
Supplementary Reference or FAQ.
10. “Protective relay” should be a defined term that lists relay function for
applicability. There are numerous ‘relays’ used in protection and control
schemes that could be lumped in and be erroneously included as part of a
Protection System. For example, reclosing or synchronizing relays respond
to voltage and hence could be viewed by an auditor as protective relays,
but they in fact perform traditional control functions versus traditional
protective functions.
11. The Data Retention requirement of keeping maintenance records for the
two most recent maintenance performances is a significant hurdle for any
owners to abide by during the initial implementation period. The
implementation plan needs to account for this such that Registered
Entities do not have to provide retroactive testing information that was
not explicitly required in the past.
1. The 6-year activities are all related to components with “moving parts”, and the 12-year activities are related to the other
portions of the control circuitry. The capitalized term has been corrected and additional changes have been made.
2. Table 1-4 has been modified in consideration of your comments.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
The associated VSL has also been revised.
37
Voter
Entity
Segment
Vote
Comment
4. The SDT concluded that Requirement R2 is redundant to Requirement R1, Part 1.4 and has deleted Requirement R2 (together
with the Measures and & VSL).
5. If the indicated monitoring attributes are present, no “hands-on” periodic maintenance is required, as the monitoring of the
component is providing a continuing indication of its functionality.
6. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part
of the standard.
D. The Supplementary Reference Document discusses condition-based maintenance in a conceptual manner, as a
generally-recognized term. The SDT did make some changes within the Supplementary Reference document to
clarify the manner in which condition-based maintenance is discussed. The SDT decided to eliminate the FAQ
document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The
SDT considered your comments during this activity.
E. This clause has been corrected.
7. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part
of the standard.
b) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
c) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
d) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
8. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
9. The term, “condition-based” has been removed from the draft standard. The other terms are used, but are clear in the context
in which they are used.
10. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition with
PRC-005. Further, the applicability of generically-described protective relays is defined by the Applicability clause of PRC005-2.
11. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need
the data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that entities
have been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has
specified the data retention in the posted standard to establish this level of documentation. This seems to be consistent with
the current practices of several Regional Entities.
38
Voter
Entity
Segment
Vote
Comment
Rebecca
Berdahl
Bonneville
3
Negative
Please refer to BPA's submitted comments on 12/16/10.
Power
Administration
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
Steve
Alexanderson
Central
Lincoln PUD
3
Affirmative
WECC does not use the definition of the BES that NERC supplied to FERC via
http://www.nerc.com/docs/docs/ferc/RM06-16-6-1407CompFilingPar77ofOrder693FINAL.pdf, so the answer to FAQ III.1.3 (page 1920) is not accurate.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into
the Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Gregg R
Griffin
City of Green
Cove Springs
3
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuitry, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
that distribution circuit. There is no real reliability need for this either.
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regio0nsl UFLS program is being
met, but, to test the other protection system components is not
worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing
faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this
version is better than prior versions because it essentially requires the
entity to determine it's own period of maintenance and testing for
UFLS/UVLS for DC Supply and control circuitry.
39
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical
4. the VRF of R1 should be Low since the attached tables are essentially the
PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comments.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the establishment of an
entity’s individual PSMP.
Bruce
ComEd
3
Negative
The addition of the requirement R1.5 and associated wording has resulted in
Krawczyk
Exelon to vote No on the standard. While Exelon does specify Protection System
tolerances and parameters in many maintenance documents; attempting to
establish documented requirements for each component type is not practical.
Additionally, this can leave much to the discretion of an auditor as to how in-depth
tolerances need to be. There are many equipment and applications variations,
many of which can utilize generic values while others require very specific value
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ranges. There are many instances where a very specific component tolerance is
required for one application, but the same component doesn’t require a tolerance
in a different application. This could lead to entities having to justify why one
application with a common component requires a narrow range versus the same
component in another application can use a generic value or no tolerance. The
last part of the requirement is also not clear. If a parameter is established, the
R1.5 requirement is inferring component must meet an acceptable parameter to
conclude the maintenance activity. There are many instances when a component
is found out of a tolerance, but the level does not require immediate action and
can even be scheduled for remediation at the next maintenance cycle. The
wording in R1.5 appears to conflict with the R4.2 which indicates maintenance
activities can be conclude as long as corrective maintenance is initiated as a result
of identifying the condition.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Peter T Yost
Consolidated
3
Negative
The Tables Edison Co. of
1. The wording “Component Type” is not necessary in each title. Just the
New York
equipment category should be listed--what is now shown as “Component
Type - Protective Relay”, should be Protective Relay. However, Protective
Relay is too general a category. Electromechanical relays, solid state
relays, and microprocessor based relays should have their own separate
tables. So instead of reading Protective Relay in the title, it should read
Electromechanical Relays, etc. This will lengthen the standard, but will
simplify reading and referring to the tables, and eliminate confusion when
looking for information.
2. The “Note” included in the heading is also not necessary.
“Attributes” is also not necessary in the column heading, “Component”
suffices.
Other Comments –
3. In general, the standard is overly prescriptive and complex. It should not
be necessary for a standard at this level to be as detailed and complex as
this standard is. Entities working with manufacturers, and knowledge
gained from experience can develop adequate maintenance and testing
programs.
4. Why are “Relays that respond to non-electrical inputs or impulses (such
as, but not limited to, vibration, pressure, seismic, thermal or gas
accumulation)...” not included? The output contacts from these devices
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5.
6.
7.
8.
9.
10.
11.
are oftentimes connected in tripping or control circuits to isolate problem
equipment.
Due to the critical nature of the trip coil, it must be maintained more
frequently if it is not monitored. Trip coils are also considered in the
standard as being part of the control circuitry. Table 1-5 has a row labeled
“Unmonitored Control circuitry associated with protective functions”,
which would include trip coils, has a “Maximum Maintenance Interval” of
“12 Calendar Years”. Any control circuit could fail at any time, but an
unmonitored control circuit could fail, and remain undetected for years
with the times specified in the Table (it might only be 6 years if I
understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure,
then the system must be operated in real time assuming that that breaker
will not trip for a fault or an event, and backup facilities would be called
upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker
unable to trip), instead of one line tripping, you might have many more
lines deloaded or tripped because of a bus having to be cleared because
of a breaker failure initiation. The bulk electric system would have to be
operated to handle this contingency.
In reference to the FAQ document, Section 5 on Station dc Supply,
Question K, clarification is needed with respect to dc supplies for
communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation,
would the standard apply to these batteries or not?
To define terms only as they are used in PRC-005-2 is inviting confusion.
Although they may be unique to PRC-005-2, some or all of them may be
used in future standards, some already may be used in existing standards,
and may or may not be deliberately defined. Consistency must be
maintained, not only for administrative purposes, but for effective
technical communications as well.
What is the definition of “Maintenance” as used in the table column
“Maximum Maintenance Interval”? Maintenance can range from cleaning a
relay cover to a full calibration of a relay.
A control circuit is not a component, it is made up of components.
Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify
calibration tolerances or other equivalent parameters...” means, and may
be subject to different interpretations by entities and compliance
enforcement personnel.
In the Implementation plan for Requirement R1, recommend changing
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“six” to fifteen. This change would restore the 3-month time difference
that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require
regulatory approval. It will ensure equity for those entities located in
jurisdictions that do not require regulatory approval, as is the case in
Ontario.
12. The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It
seems to continue to the next page to a new box. There are multiple
activities without clear delineation.
13. Regarding station service transformers, Item 4.2.5.5 under Applicability
should be deleted. The purpose of this standard is to protect the BES by
clearing generator, generator bus faults (or other electrical anomalies
associated with the generator) from the BES. Having this standard apply
to generator station service transformers, that have no direct connection
to the BES, does meet this criteria. The FAQs (III.2.A) discuss how the
loss of a station service transformer could cause the loss of a generating
unit, but this is not the purpose of PRC-005. Using this logic than any
system or device in the power plant that could cause a loss of generation
should also be included. This is beyond the scope of the NERC standards.
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. The SDT believes that the table headings are appropriate as reflected in the draft standard.
3. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies
that minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent
maintenance, a performance-based program in accordance with R3 and Attachment A is an option.
4. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection
System definition. Also, there is currently no technical basis for the maintenance of the devices which respond to nonelectrical quantities on which to base mandatory standards related either to activities or intervals. Absent such a technical
basis, we are currently unable to establish mandatory requirements, but may do so in the future if such a technical basis
becomes available.
5. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year
interval. You can maintain these devices more frequently if you desire
6. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the
communications system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The
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specific station dc supply requirements (Table 1-4) do not apply to the dc supply associated only with communications
systems. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
7. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms,
either now or in the future, may not be consistent with the terms used here. They are defined only for clarify within this
standard.
8. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are
specified in the Activities column. The term is capitalized in the column title in conformance with normal editorial practice as
a title, rather than as a definition.
9. For purposes of this standard, the control circuit IS defined as one component type.
10. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
11. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for R1, making it consistent
with the remainder of the Implementation Plan.
12. Table 1-4 has been further modified for clarity.
13. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
David A.
Consumers
3
Negative
We have the following comment on the revisions, specifically sub-requirement
Lapinski
Energy
R1.12a, which states, "Set the maximum torque angle (MTA) to 90 degrees or the
highest supported by the manufacturer.". We have no issue with this requirement
on transmission lines that are 200 kV or greater. However, we do have a concern
with applying requirement R1.12a on lower voltage lines now that the
Transmission Relay Loadability Standard is being revised to included selected
equipment 200 kV and below. The positive-sequence line angle on lower voltage
lines, such as 69 kV or 46 kV, is significantly lower than 90 degrees. The positivesequence line angle for 3/0 ACSR, for example, is only 55 degrees. Setting a 90
degree MTA on these lines would require a much larger reach setting to provide
adequate line protection. In some cases, especially for lines with long spurs and
poor line conductor, the increased reach setting may actually provide less
loadability than a reach setting based on an MTA set at the positive-sequence line
angle. A 90 degree MTA also dramatically reduces the resistive fault coverage for
these lines. For these reasons, we would propose a modification to sub-
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requirement R1.12a as follows: Set the maximum torque angle (MTA) to 90
degrees or the highest supported by the manufacturer on 200 kV or greater
transmission lines. Set the maximum torque angle (MTA) to the positive-sequence
line angle on transmission lines less than 200 kV.
Response: Thank you for your comments. This comment appears to apply to PRC-023-2 (Project 2010-17), which is a separate
activity, and is not apparently relevant to PRC-005-2.
Michael F
Dominion
3
Negative
Dominion is opposed to this version because Requirement R1.5 is overly
Gildea
Resources
prescriptive, requiring an extraordinary level of documentation, with little
Services
anticipated improvement in reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Henry Ernst- Duke Energy
3
Negative
1. R1.4 and R1.5 need more information to provide clarity for compliance. It’s
Jr
Carolina
unclear to us what the expectation is for compliance documentation for
“monitoring attributes and related maintenance activities” in R1.4 and
“calibration tolerances or other equivalent parameters” in R1.5. This is fairly
straightforward for relays, but not for other component types. Either provide
clarity or delete these requirements.
2. R4.2 - it is critical that more clarity be provided for R1.5 so that we can also
understand what the compliance expectation is for R4.2
3. M4 - Need to clarify that these pieces of evidence are all “or”, not “and” (i.e.
any of the listed examples are sufficient for compliance). We reiterate the
need for additional clarity on R1.5 and R4.2 such that compliance can be
demonstrated for all component types.
4. Table 2 - We are fairly clear on the expectation for relays, but need more
clarity on the expectation for other component types. Also, need to change
the phrase “corrective action can be taken” to “corrective action can be
initiated”, consistent with the Supplementary Reference document.
5. VSL for R1 - Sub-requirement R1.3 appears to be missing.
6. Also, it’s unclear to us what the expectation is for compliance documentation
for “monitoring attributes and related maintenance activities” in R1.4 and
“calibration tolerances or other equivalent parameters” in R1.5. This is fairly
straightforward for relays, but not for other component types.
7. VSL for R4 - More clarity must be provided on the expectation for compliance
documentation. This is a High VRF requirement, and there may only be a
small number of maintenance-correctable items, hence a significant exposure
to an extreme penalty.
8. There are typographical errors on the FAQ Requirements Flowchart (should
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be R4.1.1 and R4.1.2 instead of R4.4.1 and R4.4.2).
9. We have previously commented that the FAQ and Supplementary Reference
documents should be made part of this standard. If that cannot be done,
then more of the information in those documents needs to be included in the
requirements in the standard to provide clarity. Compliance will only be
measured against what is in the standard, and we need more clarity.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
2. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. The SDT has provided examples of the sort of evidence that may serve to demonstrate compliance. The degree to which any
single evidence type is sufficient is dependent on the completeness of the evidence itself. The Measure has been modified to
clarify this point.
4. Table 2 has been modified to be clearer. “Taken” has been replaced with “Initiation” in consideration of your comment.
5. The High VSL for Requirement R1 has been revised in consideration of your comment.
6. The issues of “monitoring attributes” are discussed within Section 15.7 of the Supplementary Reference Document. As for
Requirement R1, Part 1.5, the SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the
associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore,
it has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within
comments. The associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a
discussion of this.
7. Examples of compliance documentation are included within Measure M4 and discussed within various clauses of the FAQ and
within Section 15.7 of the Supplementary Reference Document.
8. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
9. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT believes the entities should be able to implement the standard without the Supplementary
Reference. However, the SDT is also convinced that many entities may find the supporting discussion rationale etc useful
particularly to assist them in implementing the standard in an efficient manner.
46
Voter
Joel T
Plessinger
Entity
Entergy
Segment
3
Vote
Negative
Comment
The restructured tables are generally much clearer and the SDT is to be
commended on their efforts.
1. However, we believe the Alarming Point Table needs additional
clarification with regard to the Maximum Maintenance Interval. If an
“alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there
isn’t necessarily a maximum interval established as there is for Protection
System components. Also, if an entity’s alarm producing device
maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum
intervals for the alarm producing device of that entity. On that basis, we
suggest the interval verbiage be revised to “When alarm producing device
or system is verified, or by sections as per the monitored
component/protection system specified maximum interval as applicable”.
Alternately, if the intention is to establish maximum intervals as simply
being no longer than the individual component maintenance intervals as
we suggest for inclusion above, then the verbiage should be revised to
“When alarm producing component/protection system segment is
verified”. In either case are we to interpret monitored components with
attributes which allow for no periodic maintenance specified as not
requiring periodic alarm verification?
2. R1.5 calls for “identification of calibration tolerances or equivalent
parameters...” whereas the associated VSL references “failure to establish
calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply
“identify” or document such calibration tolerances would be analogous to
the severity level(s) of a “failure to specify one (or the severity level
should be consistent with the other elements of R1. Both cases appear to
be more of a documentation issue as opposed to a failure to implement.
Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4? R1.5 calls for “identification of calibration tolerances
or equivalent parameters for each Protection System Component Type....”.
3. We believe the Supplementary Reference document should provide
additional information and examples of calibration tolerances or equivalent
parameters which would be expected for the various component types.
Especially for any “equivalent” parameters which would be required for
compliance for a component type besides protective relays. Adding
Requirement 1.5 is a significant revision and raises questions as to how
broadly an accuracy or equivalent parameter requirement and associated
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documentation would need to be addressed by entities and/or will be
measured for compliance. Discussion on this new requirement does not
seem to be addressed anywhere in the FAQ or Supplementary Reference
documents. Additionally, to the best of our knowledge, the need for such
a requirement was not brought up as a concern or comment on the prior
draft version of this standard, and in the context of a requirement need,
we don’t believe it has been attributed to or actually poses any significant
reliability risk. We do not believe this requirement is justified.
Response: Thank you for your comments.
1. The Maximum Maintenance Interval column entry in Table 2 has been revised to state, “When alarm producing Protection
System component is verified” to clarify this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Kevin Querry FirstEnergy
3
Negative
Please see FirstEnergy's comments submitted separately through the comment
Solutions
period posting.
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
Lee Schuster
Florida Power
Corporation
3
Negative
Implementation Plan for PRC-005-2
1. Since R2, R3, and R4 requirements would be performed after
establishment of the program documentation, an additional year should
be added to all implementation dates for Requirements R2, R3, and R4 as
shown below:
• Maintenance on components with intervals less than one year must be
completed within two years after applicable regulatory approval
(within one year of completion of R1 Program Documentation).
• Maintenance on components with intervals between one year and two
years must be completed within three years after applicable
regulatory approval (within two years of completion of R1 Program
Documentation).
• Maintenance on components with intervals of six years must be
completed within three-, five-, and seven-year milestones after
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Response: Thank you for your comments.
Vote
Comment
applicable regulatory approval (within two, four, and six years of
completion of R1 Program Documentation).
• Maintenance on components with intervals of twelve years must be
completed within five-, nine-, and thirteen-year milestones after
applicable regulatory approval (within four, eight, and twelve years of
completion of R1 Program Documentation).
Standard PRC-005-02 1.
2. Table 1-2: Rows 1 and 2 require different intervals for the activity “Verify
essential signals to and from Protection System components.” Unless
these inputs and outputs are monitored for Row 2, it would seem that
they should be performed at the same interval for both Rows 1 and 2.
Therefore, EITHER:
• Row 1 should be broken into the following three activities:
• 3 months - Verify communications system is functional
• 6 years - Verify channel meets performance criteria
• 12 years - Verify essential signals to and from other Protection
System components OR:
• Row 2 should be broken into the following two activities:
• 12 years - Verify channel meets performance criteria
•
6 years - Verify essential signals to and from other Protection
System components
3. Table 1-4: Only Row 1 addresses dc supplies associated with UFLS or
UVLS systems. All other rows state that UFLS or UVLS systems are
excluded. What is required to “Verify dc supply voltage” for the
UFLS/UVLS systems? Does it require that the overall station battery
voltage be checked or just the dc voltage available to the UFLS/UVLS
circuit of interest? If a voltage measurement is taken at the UFLS/UVLS
circuit (e.g., in distribution breaker cabinet), can the batteries/chargers at
these facilities be excluded from the PRC-005-2 scope as long as they do
not also supply transmission-related protection?
4. PRC-005-2 FAQ’s Document Section V.1.A, Example #2: The instrument
transformer should be classified as “unmonitored” not “monitored.”
1. The Implementation Plan for Requirement R1 has been changed from 12 months to 15 months in consideration of your
comment. The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
2. The first and second rows differ in that the first row is for unmonitored communications systems, and the second row is
for monitored communications systems. The activities in both rows are appropriate and correct.
3. Table 1-4 has been completely re-structured. For station dc supply for only UFLS/UVLS, the only activity is to verify the dc
49
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voltage.
4. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
Anthony L
Wilson
Georgia
Power
Company
3
Negative
Reference the new Requirements R.1.5 and R.4.2 which are new to this posting:
R.1.5 requires the Owners to “identify calibration tolerances or other equivalent
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES. The entire SDT needs to
thoroughly discuss these new requirements and modify or delete them.
Note: We have also made various requests for clarification to the FAQ and
Supplemental Reference document in our Response to Comments which we are
not including here.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Michael D.
Hydro One
3
Negative
1. The added requirement R1, Part 1.5 is vague and needs clarification. It is not
Penstone
Networks,
clear what “Identify calibration tolerances or other equivalent parameters” means
Inc.
and as written will be subject to different interpretations by entities and
compliance enforcement personnel. The addition of this new part of Requirement
R1 that requires the Owners to “identify calibration tolerances or other equivalent
parameters for each Protection System component type” is onerous and
contributes little to the reliability of the BES.
2. Changes introduced to the Implementation Plan since the last posting are not
consistent with respect to jurisdictions where no regulatory approval is required.
The previously posted implementation for Requirement R1 required entities to be
100% compliant on the first day of the first calendar quarter three months
following applicable regulatory approvals, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter six
months following Board of Trustees adoption. The amended implementation plan
changed the three-month time to twelve months in jurisdictions with regulatory
approval required but left the same six-month time for the others. For consistency,
the six months timeframe should be changed to fifteen months.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated
VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
50
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2. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1,
making it consistent with the remainder of the Implementation Plan.
Garry Baker
JEA
3
Negative
JEA will be voting no on PRC-005-2 because of the following:
1. In Table 1-1 for electromechanical trip or auxiliary devices requires verification
of operation as opposed to verify ability to operate that was specified on trip coils.
I believe it should be ability to operate in each case.
2. Between Table 1-1 and Tables 1-5 essentially would require full functional test
of each station every 12 years.
Response: Thank you for your comments.
1. The distinction in Table 1-5 is correct and as intended by the SDT.
2. A full functional test is one means of completing the required activities, but other methods are also acceptable. See Sections 8
and 15.3 of the Supplementary Reference Document for additional discussion.
Mace Hunter Lakeland
3
Negative
1. Table 1-4 requires a comparison of measured battery internal ohmic
Electric
value to battery baseline. Since battery manufacturers do not provide
this value, it is unclear what the “baseline” values ought to be if an entity
recently began performing this test (assuming it’s several years after the
commissioning of the battery.) Would it be acceptable for an entity to
establish baseline values based on statistical analysis of multiple test
results specific to a given battery manufacturer and design?
2. Lakeland feels that the SDT should have taken into consideration
numerous comments previously made regarding general concerns with
testing Control Circuitry in energized substations. We agree that this can
negatively impact reliability and would like to emphasize the following:
• Small entities with only one or two BES substations may not have enough
components to take advantage of the expanded maintenance intervals
afforded by a performance-based maintenance program. Aggregating
these components across different entities doesn’t seem too logical
considering the variations at the sub-component level (wire gauge,
installation conditions, etc.)
• Trip circuits are interconnected to perform various functions. Testing a trip
path may involve disabling other features (i.e. breaker failure or reclosing)
not directly a part of the test being performed. Temporary modifications
made for testing introduce a chance to unknowingly leave functions
disabled, contacts shorted, jumpers lifted, etc. after testing has been
completed. Trip coils and cable runs from panels to breaker can be made
to meet the requirements for monitored components. The only portions of
the circuitry where this may not be the case is in the inter and intra-panel
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Response: Thank you for your comments.
Vote
Comment
wiring. Because such portions of the circuitry have no moving parts and
are located inside a control house, the exposure is negligible and should
not be covered by the requirements. Entities will be at increased
compliance risk as they struggle to properly document the testing of all
parallel tripping paths.
3. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
4. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative
is to change the definition of Protection System to make sure it only
includes electrical
5. the VRF of R1 should be Low since the attached tables are essentially the
PSMP.
1. Typical baseline values for various types of lead-acid batteries can be obtained from the test equipment manufacturer,
perhaps the battery vendor, and perhaps other sources for batteries that are already in service. For new batteries, the
initial battery baseline ohmic values should be measured upon installation and used for trending.
2. A) Entities are not required to use performance-based maintenance programs. Requirement R3 and Attachment A are
provided for the use of entities that can (and desire to) avail themselves of this approach.
B) The requirement relative to control circuitry does not explicitly require trip or functional testing of the entire path; it
requires that entities verify all paths without specifying the method of doing so. Please see Section 15.5 of the
Supplementary Reference Document for detailed discussion.
3. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within
PRC-005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comments.
4. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
52
Voter
Entity
Segment
Vote
Comment
5. The SDT disagrees; the Tables establish the intervals and activities, and R1 addresses the establishment of an entities’
individual PSMP.
Bruce Merrill
Lincoln
Electric
System
3
Affirmative
While the proposed draft of the standard is acceptable as currently written, LES
would like the drafting team to consider the following comments.
(1) Table 1-1 should state “Test and calibrate (if necessary)” in the first section
under activities. If a relay passes the test, there is no need to calibrate it.
Therefore, not all relays will require calibration.
(2) Please explain the drafting team’s reason for not checking the trip coils of
breakers in the UFLS/UVLS schemes but ensuring that all others are operated
every six years. It would appear that they can all be lumped into the same group
one way or another.
(3) In regards to Specific Gravity Testing, many people do not perform the
specific gravity test routinely if they perform the individual cell internal ohmic test
routinely. LES asks the drafting team to consider allowing the internal cell ohmic
test as a substitute for the specific gravity test.
Response: Thank you for your comments.
1. Table 1-1 has been modified as you suggest.
2. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the
Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system
elements.
3. Table 1-4 does not specify specific gravity testing.
Charles A.
Louisville Gas 3
Negative
LG&E and KU Energy LLC appreciate the hard work and efforts of the Standards
Freibert
and Electric
Drafting Team in reaching this point in the standards development process. The
Co.
basis for the negative vote is the addition of Requirement R1.5 (calibration
tolerances) and R4.2 to the standard. This requirement will provide the
opportunity for auditors to decide if the testing criteria for whether a relay passes
a test or not is acceptable. LG&E and KU Energy recommend that Requirement
R1.5 be deleted from the standard.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Greg C.
Manitoba
3
Negative
1. -Implementation Plan (Timeline) for R1: In areas not requiring regulatory
Parent
Hydro
approval, the 6 month time frame proposed for R1 is not achievable and is not
consistent with areas requiring regulatory approval. To be consistent, the
effective date for R1 in jurisdictions where no regulatory approval is required
should be the first day of the first calendar quarter 12 months after BOT
approval.
53
Voter
Entity
Segment
Vote
Comment
2. - VSLs: The high VSL for R1 “Failed to include all maintenance activities
relevant for the identified monitoring attributes specified in Tables 1-1 through
1-5” may be interpreted in different ways and should be further clarified.
3. -Table 1-4: The requirements for batteries listed in Table 1-4 do not appear to
be consistent with the comments in the FAQ Section (V 1A Example 1). Please
see comments submitted during the formal comment period for further detail.
4. -Table 1-4: The requirement for a 3 month check on electrolyte level seems
too frequent based on our experience. We would like to point out that
although IEEE std 450 (which seems to be the basis for table 1-4) does
recommend intervals it also states that users should evaluate these
recommendations against their own operating experience.
Response: Thank you for your comments.
1. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making
it consistent with the remainder of the Implementation Plan.
2. The SDT does not understand your concern; further details are needed.
3. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
4. The SDT believes that the 3-month interval specified in the Standard is appropriate.
Don Horsley
Mississippi
3
Negative
Reference the new Requirements R.1.5 and R.4.2 which are new to this posting:
Power
R.1.5 requires the Owners to “identify calibration tolerances or other equivalent
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES. The entire SDT needs to
thoroughly discuss these new requirements and modify or delete them.
Note: We have also made various requests for clarification to the FAQ and
Supplemental Reference document in our Response to Comments which we are
not including here.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Michael
Niagara
3
Negative
This new Requirement as written subjects the Transmission Owner, Generation
Schiavone
Mohawk
Owner or Distribution Provider to vague interpretations of what the requirement
(National Grid
means by compliance officials. The addition of the new part of Requirement R1
Company)
that requires the Owners to “identify calibration tolerances or other equivalent
parameters for each Protection System component type” is too intrusive and
divisive for what it brings to the reliability of the BES.
54
Voter
Entity
Segment
Vote
Comment
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Sam Waters
Progress
3
Negative
4.
Implementation Plan for PRC-005-2 Since R2, R3, and R4 requirements
Energy
would be performed after establishment of the program documentation, an
Carolinas
additional year should be added to all implementation dates for
Requirements R2, R3, and R4 as shown below:
• Maintenance on components with intervals less than one year must be
completed within two years after applicable regulatory approval (within
one year of completion of R1 Program Documentation).
• Maintenance on components with intervals between one year and two
years must be completed within three years after applicable regulatory
approval (within two years of completion of R1 Program Documentation).
•
Maintenance on components with intervals of six years must be
completed within three-, five-, and seven-year milestones after applicable
regulatory approval (within two, four, and six years of completion of R1
Program Documentation). o Maintenance on components with intervals
of twelve years must be completed within five-, nine-, and thirteen-year
milestones after applicable regulatory approval (within four, eight, and
twelve years of completion of R1 Program Documentation). Standard PRC005-02 1.
5.
Table 1-2:
1. Rows 1 and 2 require different intervals for the activity “Verify essential
signals to and from Protection System components.” Unless these inputs
and outputs are monitored for Row 2, it would seem that they should be
performed at the same interval for both Rows 1 and 2. Therefore,
EITHER:
• Row 1 should be broken into the following three activities:
• 3 months - Verify communications system is functional
•
6 years - Verify channel meets performance criteria
• 12 years - Verify essential signals to and from other
Protection System components OR:
•
Row 2 should be broken into the following two activities:
• 12 years - Verify channel meets performance criteria
•
6 years - Verify essential signals to and from other
Protection System components.
6.
Table 1-4: Only Row 1 addresses dc supplies associated with UFLS or UVLS
systems. All other rows state that UFLS or UVLS systems are excluded. What
55
Voter
Entity
Segment
Vote
Comment
7.
is required to “Verify dc supply voltage” for the UFLS/UVLS systems? Does it
require that the overall station battery voltage be checked or just the dc
voltage available to the UFLS/UVLS circuit of interest? If a voltage
measurement is taken at the UFLS/UVLS circuit (e.g., in distribution breaker
cabinet), can the batteries/chargers at these facilities be excluded from the
PRC-005-2 scope as long as they do not also supply transmission-related
protection?
PRC-005-2 FAQ’s Document Section V.1.A, Example #2: The instrument
transformer should be classified as “unmonitored” not “monitored.”
Response: Thank you for your comments.
4. The Implementation Plan for Requirement R1 has been changed from 12 months to 15 months in consideration of your
comment. The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
5. The first and second rows differ in that the first row is for unmonitored communications systems, and the second row is for
monitored communications systems. The activities in both rows are appropriate and correct.
6. Table 1-4 has been completely re-structured. For station dc supply for only UFLS/UVLS, the only activity is to verify the dc
voltage.
7. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
Jeffrey
Public Service 3
Negative
The PSEG Companies do not agree with the Facilities as currently described in
Mueller
Electric and
section 4.2.5.5. Please refer to detailed comments provided in our formal
Gas Co.
Comment Form.
Response: Thank you for your comments. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the
Applicability of the standard.
Anthony
Schacher
Salem Electric
3
Negative
Battery testing methodologies are too specific and don't allow for different
substation battery configurations.
Response: Thank you for your comments. The SDT disagrees; the requirements within Table 1-4 establish the minimum
maintenance activities required to assure that station dc supply of various technologies and configurations will perform as intended
without unnecessarily prescribing specific methodologies.
Dana
Wheelock
Seattle City
Light
3
Negative
Comment: The proposed Standard PRC-005-2 is an improvement over the
previous draft in that it provides more consistency in maintenance and testing
duration internals.
Notwithstanding, two issues are of concern to Seattle City Light such that it is
compelled to vote no:
1)
the establishment of bookends for standard verification and 2) the
implementation timelines for entities with systems where electro-mechanical
56
Voter
Entity
Segment
Vote
Comment
2)
relays still compose a significant number of components in their protection
systems. Bookends: Proposed Standard PRC-005-2 specifies long inspection
and maintenance intervals, up to 12 years, which correspondingly
exacerbates the so-called “bookend” issue. To demonstrate that intervalbased requirements have been met, two dates are needed - bookends.
Evidencing an initial date can be problematic for cases where the initial date
would occur prior to the effective date of a standard. NERC has provided no
guidance on this issue, and the Regions approach it differently. Some, such
as Texas Regional Entity, require initial dates beginning on or after the
effective date of a Standard. Compliance with intervals is assessed only once
two dates are available that occur on or after a standard took effect. Other
regions, such as Western Electricity Coordinating Council (WECC), require
that entities evidence an initial date prior to the effective date of a standard.
For WECC, compliance with intervals is assessed as soon as a standard takes
effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal.
Proposed Standard PRC-005-2 will be another such standard. Indeed this
Standard will involve by far the largest number of bookends of any NERC
standard - many thousands for a typical entity. Furthermore, the long
inspection and maintenance intervals introduced in the draft will require
entities in WECC, for instance, to evidence initial bookend dates prior to the
date original PRC-005-1 took effect. For the 12-year intervals for CTs and
VTs in proposed Standard PRC-005-2, many initial dates will occur prior to
the 2005 Federal Power Act that authorized Mandatory Reliability Standards
and even reach back before the 2003 blackout that catalyzed the effort to
pass the Federal Power Act. As a result, many entities in WECC maybe at
risk of being found in violation of proposed Standard PRC-005-2 immediately
upon its implementation. Seattle City Light requests that NERC address the
bookends issue, either within proposed Standard PRC-005-2 or in a separate,
concurrent document.
Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with
legacy systems. In example, auxiliary relay and trip coil testing may be
essential to prove the correct operation of complex, multi-function digital
protection systems. However, for legacy systems with single-function
57
Voter
Entity
Segment
Vote
Comment
electro-mechanical components, the considerable documentation and
operational testing needed to implement and track such testing is not
necessarily proportional to the relative risk posed by the equipment to the
bulk electric system. Performance testing of electro-mechanical systems,
particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause
far more problems on restoration-to-service than they will locate and correct.
As such, to assist entities in their implementation efforts, we believe
provision of alternatives are necessary, such as additional implementation
time through phasing and/or through technical feasibility exceptions.
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18 Evidence”.
Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic.
2. FERC Order 693 directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is a
portion thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has developed
those requirements in a fashion that affords entities with the opportunity to best meet those requirements.
James R.
Wisconsin
3
Negative
Q4: Table 1-4 requires an activity to verify the state of charge of battery cells.
Keller
Electric Power
There are no possible options for meeting this requirement listed in the FAQ
Marketing
document. Unlike other terms used in the standard, this term is not mentioned or
defined in the FAQ. To comply with this standard, the SDT needs to provide more
guidance. For example, for VLA batteries the measured specific gravity could
indicate state of charge. For VRLA batteries, it is not as clear how to determine
state of charge, but possibly this can be determined by monitoring the float
current.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into
the Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has
been revised to remove “state of charge” from the activities.
Michael Ibold
Xcel Energy,
Inc.
3
Negative
See comments under the Transmission segment.
Response: Thank you for your comments. Please see our responses to your comments from the Transmission segment.
Kenneth
Goldsmith
Alliant Energy
Corp.
Services, Inc.
4
Negative
We are concerned with this paragraph being interpreted differently by the various
regions and thereby causing a large increase in scope for Distribution Provider
protection systems beyond the reach of UFLS or UVLS.
i. Protection Systems applied on, or designed to provide protection for, the BES.
The description is vague and open for different interpretations for what is “applied
58
Voter
Entity
Segment
Vote
Comment
on” or “designed to provide protection”.
According to the November 17, 2010 Draft Supplementary Reference page 4, the
Standard will not apply to sub-transmission and distribution circuits, but will apply
to any Protection System that is designed to detect a fault on the BES and take
action in response to the fault. The Standard Drafting Team does not feel that
Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the
Regional Entity interpretations of ‘protecting” the BES. Most distribution protection
systems will not react to a fault on the BES, but are caught up in the
interpretation due to tripping a breaker(s) on the BES.
Response: Thank you for your comments. Applicability 4.2.1 has been revised to remove “applied on”. The SDT believes that this
addresses your concern. Applicability 4.2.2 and 4.2.3, respectively, address UFLS and UVLS specifically, and are not related to 4.2.1.
The Supplementary Reference Documentation has been revised to clarify.
David Frank
Ronk
Consumers
Energy
4
Negative
1. Table 1-3 states, “are received by the protective relays”. Does this require that
the inputs to each individual relay must be checked, or is it sufficient to verify that
acceptable signals are received at the relay panel, etc?
2. Relative to Table 1-5, the activities will likely require that system components
be removed from service to complete those activities. If the changes to the BES
definition (per the FERC Order) causes system elements such as 138 kV connected
distribution transformers to be considered as BES, these components can not be
removed from service for maintenance without outaging customers. The standard
must exempt these components from the activities of Table 1-5 if the activity
would result in deenergizing customers.
3. For the component types addressed in Tables 1-3 and 1-5, the requirements
may cause entities to identify components very differently than they are currently
doing, and doing so may take several years to complete. The Implementation
Plan for R1 and R4 is too aggressive in that it may not permit entities to complete
the identification of discrete components and the associated maintenance and
implement their program as currently proposed. We propose that the
Implementation Plan specifically address the components in Table 1-3 and 1-5
with a minimum of 3 calendar years for R1 and 12 calendar years after that for
R4.
4. As for the interval in Table 1-4 regarding the battery terminal connection
resistance, we believe that an 18-month interval is excessively frequent for this
59
Voter
Entity
Segment
Vote
Comment
activity, and suggest that it be moved to the 6-calendar-year interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections
every 4-years, rather than measuring the terminal connection resistance to
determine if the connections are sound. Disregarding the interval, would this
activity satisfy the “verify the battery terminal connection resistance” activity?
Response: Thank you for your comments.
1. The SDT intends that the voltage and current signals properly reach each individual relay, but there may be several methods of
accomplishing this activity.
2. This concern seems more properly to be one to be addressed during the activities to develop the new BES definition, rather than
within PRC-005-2.
3. The Implementation Plan for Requirement R1 has been modified from “six” months to “twelve” months. The standard has also
been modified (Requirement R1, Part 1.1) to not specifically require identification of all Individual Protection System components.
The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
4. IEEE 450, 1188, and 1106 all recommend this activity at a 12-month interval. Please see Clause 15.4.1 of the Supplementary
Reference Document for a discussion of this activity.
5. Re-torqueing the battery terminals would not meeting this requirement.
Frank
Gaffney
Florida
Municipal
Power Agency
4
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new
PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution
system protection, so, these activities would not be covered by other BES
protection system maintenance and testing. I'm sure we are testing
batteries and the like, but, we are probably not testing battery chargers and
control circuity, and, in many cases distribution circuits are such that it is
very difficult, if not impossible, to test control circuitry to the trip coil of the
breaker without causing an outage of the customers on that distribution
circuit. There is no real reliability need for this either. Unlike Transmission
and Generation Protection Systems which are needed to clear a fault and
may only have one or two back-up systems, there are thousands and
thousands of UFLS relays and if one fails to operate, it will not be noticeable
to the event. It does make sense to test the relays themselves in part to
60
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
ensure that the regionsl UFLS program is being met, but, to test the other
protection system components is not worthwhile. Note that DC Supplies and
most of the control circuitry of distribution lines are "tested" frequently by
distribution circuits clearing faults such as animals, vegetation blow-ins,
lightning, etc., on distribution circuits, reducing the value of testing to just
about null. However, this version is better than prior versions because it
essentially requires the entity to determine it's own period of maintenance
and testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a BES
Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical the VRF of R1 should be Low since the attached tables are
essentially the PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during the
stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comments.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
61
Voter
Thomas W.
Richards
Entity
Fort Pierce
Utilities
Authority
Segment
4
Vote
Negative
Comment
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new
PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution
system protection, so, these activities would not be covered by other BES
protection system maintenance and testing. I'm sure we are testing batteries
and the like, but, we are probably not testing battery chargers and control
circuitry, and, in many cases distribution circuits are such that it is very
difficult, if not impossible, to test control circuitry to the trip coil of the
breaker without causing an outage of the customers on that distribution
circuit. There is no real reliability need for this either. Unlike Transmission
and Generation Protection Systems which are needed to clear a fault and
may only have one or two back-up systems, there are thousands and
thousands of UFLS relays and if one fails to operate, it will not be noticeable
to the event. It does make sense to test the relays themselves in part to
ensure that the regio0nsl UFLS program is being met, but, to test the other
protection system components is not worthwhile. Note that DC Supplies and
most of the control circuitry of distribution lines are "tested" frequently by
distribution circuits clearing faults such as animals, vegetation blow-ins,
lightning, etc., on distribution circuits, reducing the value of testing to just
about null. However, this version is better than prior versions because it
essentially requires the entity to determine it's own period of maintenance
and testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a BES
Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 2009-10 that
excludes non-electrical protection (e.g., sudden pressure relays) and auxiliary
relays. Because the definition of Protection System (recently approved) does
not clearly exclude "non-electrical" protection, the Applicability section
should. For instance, a vibration monitor, steam pressure, etc. protection of
generators, sudden pressure protection of transformers, etc. should not be
included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical
4. Table 1-4 requires a comparison of measured battery internal ohmic value to
battery baseline. Battery manufacturers typically do not provide this value
62
Voter
Entity
Segment
Response: Thank you for your comments.
Vote
Comment
and one manufacturer states that the baseline test are to be performed after
the battery has been in regular float service for 90 days. It is unclear how to
comply with the requirement for the initial 90 days. Additionally, we would
recommend that this requirement be modified to permit an entity to establish
a “baseline” value based on statistical analysis of multiple test results specific
to a given battery manufacturer/model. Several commenters previously
expressed their concerns with performing capacity tests. While this may just
be an entity’s preference, allowing an entity to establish a baseline at some
point beyond the initial installation period would give entities the option of
using the internal resistance test in lieu of a capacity test.
5. Small entities with only one or two BES substations may not have enough
components to take advantage of the expanded maintenance intervals
afforded by a performance-based maintenance program. Aggregating these
components across different entities doesn’t seem too logical considering the
variations at the sub-component level (wire gauge, installation conditions,
etc.)
6. Trip circuits are interconnected to perform various functions. Testing a trip
path may involve disabling other features (i.e. breaker failure or reclosing)
not directly a part of the test being performed. Temporary modifications
made for testing introduce a chance to accidentally leave functions disabled,
contacts shorted, jumpers lifted, etc. after testing has been completed. Trip
coils and cable runs from panels to breaker can be made to meet the
requirements for monitored components. The only portions of the circuitry
where this may not be the case is in the inter- and intra-panel wiring.
Because such portions of the circuitry have no moving parts and are located
inside a control house, the exposure is negligible and should not be covered
by the requirements. Entities will be at increased compliance risk as they
struggle to properly document the testing of all parallel tripping paths. The
interconnected nature of tripping circuits will make it difficult to count the
number of circuits consistently for the purpose of calculating a VSL.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during the
stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1 in consideration of your comments.
63
Voter
Entity
Segment
Vote
Comment
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
4. Typical baseline values for various types of lead-acid batteries can be obtained from the test equipment manufacturer, perhaps
the battery vendor, and perhaps other sources for batteries that are already in service. For new batteries, the initial battery
baseline ohmic values should be measured upon installation and used for trending.
5. Entities are not required to use performance-based maintenance programs. Requirement R3 and Attachment A are provided
for the use of entities that can (and desire to) avail themselves of this approach.
6. The requirement relative to control circuitry does not explicitly require trip or functional testing of the entire path; it requires that
entities verify all paths without specifying the method of doing so. Please see Section 15.5 of the Supplementary Reference
Document for detailed discussion.
Bob C.
Illinois
4
Negative
It is IMEA's understanding from interaction with other entities that Draft 3
provides significant improvement, but that key concerns raised by many entities
Thomas
Municipal
Electric
on Draft 2 were not addressed. IMEA supports comments submitted by Florida
Agency
Municipal Power Agency.
Response: Thank you for your comments. Please see our responses to your comments submitted during the Formal Comment
period..
Christopher
Plante
Integrys
Energy
Group, Inc.
4
Negative
Reason for No Vote:
1. Implementation plan is too aggressive given the drastic changes from
PRC-005-1 to PRC-005-2
2. The drastic changes don’t appear to provide an incremental increase in
the reliability of the BES
3. We support the MRO NSRS comments
Response: Thank you for your comments.
1. The SDT has carefully considered the changes that entities will be expected to make to their program in response to PRC-005-2
and provided an Implementation Plan that should be sufficient and provided a phase-in approach to permit entities to
systemically implement the revised standard. The Implementation Plan for Requirement R4 has been revised to add one year to
all established dates.
2. FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
maintenance activities. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion
that benefits reliability and that may be consistently monitored for compliance.
3. Please see our responses to MRO’s NSRS comments on the Standard Comments.
Joseph G.
Madison Gas
4
Negative
The SDT has made great improvements with this Standard but please consider the
DePoorter
and Electric
following items.
Co.
1. Replace "affecting" with "protecting" in the purpose statement.
64
Voter
Entity
Segment
Vote
Comment
2. 4.2.1 under Facilities, The description is vague and open for different
interpretations for what is “applied on” or “designed to provide protection”.
According to the November 17, 2010 Draft Supplementary Reference page 4, the
Standard will not apply to sub-transmission and distribution circuits, but will apply
to any Protection System that is designed to detect a fault on the BES and take
action in response to the fault. The Standard Drafting Team does not feel that
Protection Systems designed to protect distribution substation equipment are
included in the scope of this standard; however, this will be impacted by the
Regional Entity interpretations of ‘protecting” the BES. Most distribution protection
systems will not react to a fault on the BES, but are caught up in the
interpretation due to tripping a breaker(s) on the BES. Clarification is needed by
the SDT that this does not include distribution assets (notwithstanding UFLS and
UVLS).
3. Upon review, R1.4, R1.5, and R4.2 were added since the last posting. These
are not needed and must of been added to the Standard from an outside sorce.
The SDT was on the proper track to finalize this Standard. These requirements
need to be left to the individual entities to determine the depth and breath of thier
PMSP.
Response: Thank you for your comments.
1. The “Purpose” is defined by the SAR.
2. Applicability 4.2.1 has been revised to remove “applied on”. The SDT believes that this addresses your concern. Applicability
4.2.2 and 4.2.3, respectively, address UFLS and UVLS specifically, and are not related to Applicability 4.2.1. The
Supplementary Reference Documentation has been revised to clarify.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Douglas
Ohio Edison
4
Negative
Please see FirstEnergy's comments submitted separately through the comment
Hohlbaugh
Company
period posting.
Response: Thank you for your comments. Please see our responses to your comments submitted during the Formal Comment
period.
John D.
Martinsen
Public Utility
District No. 1
of Snohomish
4
Affirmative
The overly prescriptive nature of the PRC-005-2 provides greater implementation
clarity. However it may be too onerous for Local Network that have demonstrated
through studies that delayed clearing (that could be attributed to protection
65
Voter
Entity
Segment
Vote
County
Comment
system maintenance and testing) events do not create reliability or cascading
concerns.
Response: Thank you for your comments. PRC-005-2 is applicable to Protection Systems that are designed to provide protection for
BES elements, and uses the Compliance Registry to determine applicable entities. Contributions of BES elements to cascading, etc,
are immaterial in this Applicability.
Hao Li
Seattle City
Light
4
Negative
Comment: The proposed Standard PRC-005-2 is an improvement over the
previous draft in that it provides more consistency in maintenance and testing
duration internals. Notwithstanding, two issues are of concern to Seattle City Light
such that it is compelled to vote no:
1) the establishment of bookends for standard verification and 2) the
implementation timelines for entities with systems where electro-mechanical
relays still compose a significant number of components in their protection
systems. Bookends: Proposed Standard PRC-005-2 specifies long inspection
and maintenance intervals, up to 12 years, which correspondingly
exacerbates the so-called “bookend” issue. To demonstrate that intervalbased requirements have been met, two dates are needed - bookends.
Evidencing an initial date can be problematic for cases where the initial date
would occur prior to the effective date of a standard. NERC has provided no
guidance on this issue, and the Regions approach it differently. Some, such
as Texas Regional Entity, require initial dates beginning on or after the
effective date of a Standard. Compliance with intervals is assessed only once
two dates are available that occur on or after a standard took effect. Other
regions, such as Western Electricity Coordinating Council (WECC), require
that entities evidence an initial date prior to the effective date of a standard.
For WECC, compliance with intervals is assessed as soon as a standard takes
effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal.
Proposed Standard PRC-005-2 will be another such standard. Indeed this
Standard will involve by far the largest number of bookends of any NERC
standard - many thousands for a typical entity. Furthermore, the long
inspection and maintenance intervals introduced in the draft will require
entities in WECC, for instance, to evidence initial bookend dates prior to the
date original PRC-005-1 took effect. For the 12-year intervals for CTs and
VTs in proposed Standard PRC-005-2, many initial dates will occur prior to
the 2005 Federal Power Act that authorized Mandatory Reliability Standards
and even reach back before the 2003 blackout that catalyzed the effort to
pass the Federal Power Act. As a result, many entities in WECC maybe at
66
Voter
Entity
Segment
Vote
Comment
risk of being found in violation of proposed Standard PRC-005-2 immediately
upon its implementation. Seattle City Light requests that NERC address the
bookends issue, either within proposed Standard PRC-005-2 or in a separate,
concurrent document.
2) Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with
legacy systems. In example, auxiliary relay and trip coil testing may be
essential to prove the correct operation of complex, multi-function digital
protection systems. However, for legacy systems with single-function
electro-mechanical components, the considerable documentation and
operational testing needed to implement and track such testing is not
necessarily proportional to the relative risk posed by the equipment to the
bulk electric system. Performance testing of electro-mechanical systems,
particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause
far more problems on restoration-to-service than they will locate and correct.
As such, to assist entities in their implementation efforts, we believe
provision of alternatives are necessary, such as additional implementation
time through phasing and/or through technical feasibility exceptions.
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18 Evidence”.
Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic.
2. FERC Order 693 directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is
a portion thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has developed
those requirements in a fashion that affords entities with the opportunity to best meet those requirements.
James A
Y-W Electric
4
Negative
Y-WEA appreciates the significant amount of work that the SDT has put into this
Ziebarth
Association,
revision of the standard. It is clear that the SDT is making a sincere effort to
Inc.
address comments and concerns from previous revisions of this standard, and that
is a good thing.
While Y-WEA thanks the SDT for the straightforward honesty of disagreeing with
our previous comments on the battery testing interval of 3 months for VRLA
batteries, we still feel that this mandatory maximum testing interval is
unreasonably short, based on IEEE 1188-2005.
67
Voter
Entity
Segment
Vote
Comment
The recommended testing intervals contained in that IEEE standard should be
targeted as reasonable testing intervals, with some degree of leeway allowed
before any mandatory maximum interval is defined. A mandatory maximum
interval of four calendar months would be much more appropriate here. This
would allow a reasonable testing and maintenance program to define a standard
testing interval of three months (in line with the IEEE standard) and still be able to
allow a one month buffer or grace period to account for unexpected delays in
testing due to extreme storms or other unanticipated heavy workloads. With the
draft standard as written, a company must use an unreasonably short preferred
maintenance interval if any grace period is to be built in and still remain under the
mandatory maximum interval of the NERC standard. In particular, this could have
a substantial impact on small companies that are distributed over a large area but
have limited resources to deal with such stringent testing requirements. Because
this standard will ultimately have to comply with the Regulatory Flexibility Act, it
would be worthwhile for the SDT to consider the potential impacts of essentially
forcing entities into much more stringent testing programs than recommended by
current technically-derived and peer reviewed and approved standards such as
IEEE 1188-2005.
Other than that, Y-WEA sincerely appreciates the clarity that has been added to
this standard over that contained in previous versions of the testing and
maintenance standards. This will give registered entities much more guidance as
to what NERC's and the regional entities' expectations are when it comes to
protection system testing and maintenance programs.
Response: Thank you for your comments. The SDT has revised the 3-month interval specified for VRLA batteries for some activities
to 6 months.
Francis J.
Halpin
Bonneville
5
Negative
Please see BPA's comments submitted seperately
Power
Administration
Response: Thank you for your comments. Please see our responses to your comments submitted during the Formal Comment
period.
Wilket (Jack) Consolidated
5
Negative
The Tables –
Ng
Edison Co. of
1. The wording “Component Type” is not necessary in each title. Just the
New York
equipment category should be listed--what is now shown as “Component
Type - Protective Relay”, should be Protective Relay. However, Protective
Relay is too general a category. Electromechanical relays, solid state
relays, and microprocessor based relays should have their own separate
tables. So instead of reading Protective Relay in the title, it should read
68
Voter
Entity
Segment
Vote
Comment
2.
3.
4.
5.
6.
Electromechanical Relays, etc. This will lengthen the standard, but will
simplify reading and referring to the tables, and eliminate confusion when
looking for information.
The “Note” included in the heading is also not necessary. “Attributes” is
also not necessary in the column heading, “Component” suffices. Other
Comments - In general, the standard is overly prescriptive and complex. It
should not be necessary for a standard at this level to be as detailed and
complex as this standard is. Entities working with manufacturers, and
knowledge gained from experience can develop adequate maintenance
and testing programs.
Why are “Relays that respond to non-electrical inputs or impulses (such
as, but not limited to, vibration, pressure, seismic, thermal or gas
accumulation)...” not included? The output contacts from these devices
are oftentimes connected in tripping or control circuits to isolate problem
equipment.
Due to the critical nature of the trip coil, it must be maintained more
frequently if it is not monitored. Trip coils are also considered in the
standard as being part of the control circuitry. Table 1-5 has a row labeled
“Unmonitored Control circuitry associated with protective functions”,
which would include trip coils, has a “Maximum Maintenance Interval” of
“12 Calendar Years”. Any control circuit could fail at any time, but an
unmonitored control circuit could fail, and remain undetected for years
with the times specified in the Table (it might only be 6 years if I
understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure,
then the system must be operated in real time assuming that that breaker
will not trip for a fault or an event, and backup facilities would be called
upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker
unable to trip), instead of one line tripping, you might have many more
lines deloaded or tripped because of a bus having to be cleared because
of a breaker failure initiation. The bulk electric system would have to be
operated to handle this contingency.
In reference to the FAQ document, Section 5 on Station dc Supply,
Question K, clarification is needed with respect to dc supplies for
communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation,
would the standard apply to these batteries or not?
To define terms only as they are used in PRC-005-2 is inviting confusion.
Although they may be unique to PRC-005-2, some or all of them may be
69
Voter
Entity
Segment
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Comment
7.
8.
9.
10.
11.
12.
used in future standards, some already may be used in existing standards,
and may or may not be deliberately defined. Consistency must be
maintained, not only for administrative purposes, but for effective
technical communications as well.
What is the definition of “Maintenance” as used in the table column
“Maximum Maintenance Interval”? Maintenance can range from cleaning a
relay cover to a full calibration of a relay.
A control circuit is not a component, it is made up of components.
Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify
calibration tolerances or other equivalent parameters...” means, and may
be subject to different interpretations by entities and compliance
enforcement personnel.
In the Implementation plan for Requirement R1, recommend changing
“six” to fifteen. This change would restore the 3-month time difference
that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require
regulatory approval. It will ensure equity for those entities located in
jurisdictions that do not require regulatory approval, as is the case in
Ontario.
The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It
seems to continue to the next page to a new box. There are multiple
activities without clear delineation.
Regarding station service transformers, Item 4.2.5.5 under Applicability
should be deleted. The purpose of this standard is to protect the BES by
clearing generator, generator bus faults (or other electrical anomalies
associated with the generator) from the BES. Having this standard apply
to generator station service transformers, that have no direct connection
to the BES, does meet this criteria. The FAQs (III.2.A) discuss how the
loss of a station service transformer could cause the loss of a generating
unit, but this is not the purpose of PRC-005. Using this logic than any
system or device in the power plant that could cause a loss of generation
should also be included. This is beyond the scope of the NERC standards.
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that
minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent maintenance,
a performance-based program in accordance with R3 and Attachment A is an option.
70
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Comment
3. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection
System definition. Also, there is currently no technical basis for the maintenance of the devices which respond to non-electrical
quantities on which to base mandatory standards related either to activities or intervals. Absent such a technical basis, we are
currently unable to establish mandatory requirements, but may do so in the future if such a technical basis becomes available.
4. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year interval.
You can maintain these devices more frequently if you desire.
5. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the communications
system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The specific station dc
supply requirements (Table 1-4) do not apply to the dc supply associated only with communications systems. The SDT has
decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference
document. Your comments have been considered within that activity.
6. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms,
either now or in the future, may not be consistent with the terms used here. They are defined only for clarify within this standard.
7. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are specified
in the Activities column. The term is capitalized in the column title in conformance with normal editorial practice as a title, rather
than as a definition.
8. For purposes of this standard, the control circuit is defined as one component type.
9. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed
within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4
has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been
revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
10. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1,making it
consistent with the remainder of the Implementation Plan.
11. Table 1-4 has been further modified for clarity.
12. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
Amir Y
Constellation
5
Negative
Constellation Power Generation is voting against this standard for the following
Hammad
Power Source
reasons:
Generation,
1. The applicability has included more generation protective components.
Inc.
The current PRC-005 guidance states that only Station Service
transformers for plants 75 MVA and up should be included. The proposed
71
Voter
Entity
Segment
Vote
Comment
2.
3.
4.
5.
standard includes all station service transformers, regardless of plant size
or connection (via generator or system). Constellation Power Generation
does not see the reliability benefits of this increased scope.
R1.4 states that all monitoring attributes of all components must be listed
and identified. For most generation facilities, it is more efficient to
calibrate/check the entire protective system while the plant is in an
outage, regardless of a component’s monitoring capabilities. This
requirement would require those facilities to maintain a list of attributes
that won’t ever be used, and would not alter their testing frequency. What
if an entity were found non-compliant in the situation that was just
described? It does not affect the reliability of the BES and therefore R1.4
should be removed.
M1 doesn’t include a measure for R1.4. It just implies that a facility must
maintain a list.
The battery listing in the attached table is still too prescriptive. If
unmonitored, there should be a quarterly and yearly check, which is
implied, but it is then broken out by battery type to be more prescriptive.
PTs and CTs are mentioned, but it seems as though the drafting team
wants a facility to only test the outputs to ensure they are working
properly. To clarify this, Constellation Power Generation suggests
rewording the testing verbiage for PTs and CTs.
Response:
1. Section 4.2.5 of “Applicability” specifies that only Generation Facilities that are part of the BES are included.
2. The SDT disagrees; Requirement R1, Part 1.4 supports Requirement R1, Part 1.2, and seems necessary to assure that entities have
appropriately applied the longer intervals associated with monitored components. However, in consideration to your comment the
SDT has revised Requirement R1, Part 1.4 and has also removed Requirement R2 because of redundancy to Requirement R1, Part
1.4.
3. Measure M1 has been revised in consideration of your comment.
4. The activities for different battery types are addressed separately because the relevant activities differ.
5. The SDT intends that the instrument transformer and associated circuitry be verified to be functional, but believes that customary
apparatus maintenance (dielectric, infrared, etc) are not relevant to PRC-005-2.
James B
Consumers
5
Negative
1. Table 1-3 states, “are received by the protective relays”. Does this require that
Lewis
Energy
the inputs to each individual relay must be checked, or is it sufficient to verify that
acceptable signals are received at the relay panel, etc?
2. Relative to Table 1-5, the activities will likely require that system components
be removed from service to complete those activities. If the changes to the BES
definition (per the FERC Order) causes system elements such as 138 kV connected
distribution transformers to be considered as BES, these components can not be
removed from service for maintenance without tripping customers. The standard
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Segment
Response: Thank you for your comments.
Vote
Comment
must exempt these components from the activities of Table 1-5 if the activity
would result in deenergizing customers.
3. For the component types addressed in Tables 1-3 and 1-5, the requirements
may cause entities to identify components very differently than they are currently
doing, and doing so may take several years to complete. The Implementation Plan
for R1 and R4 is too aggressive in that it may not permit entities to complete the
identification of discrete components and the associated maintenance and
implement their program as currently proposed. We propose that the
Implementation Plan specifically address the components in Table 1-3 and 1-5
with a minimum of 3 calendar years for R1 and 12 calendar years after that for
R4.
4. As for the interval in Table 1-4 regarding the battery terminal connection
resistance, we believe that an 18-month interval is excessively frequent for this
activity, and suggest that it be moved to the 6-calendar-year interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections
every 4-years, rather than measuring the terminal connection resistance to
determine if the connections are sound. Disregarding the interval, would this
activity satisfy the “verify the battery terminal connection resistance” activity?
1. The SDT intends that the voltage and current signals properly reach each individual relay, but there may be several methods
of accomplishing this activity.
2. This concern seems more properly to be one to be addressed during the activities to develop the new BES definition, rather
than within PRC-005-2.
3. The Implementation Plan for Requirement R1 has been modified from 6 months to 12 months. The Standard has also been
modified (Requirement R1, Part 1.1) to not specifically require identification of all individual Protection System components.
The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
4. IEEE 450, 1188, 1106 all recommend this activity at a 12-month interval. Please see Clause 15.4.1 of the Supplementary
Reference Document for a discussion of this activity.
5. Re-torqueing the battery terminals would not meet this requirement.
Mike Garton
Dominion
5
Negative
Dominion is opposed to this version because Requirement R1.5 is overly
Resources,
prescriptive, requiring an extraordinary level of documentation, with little
Inc.
anticipated improvement in reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
73
Voter
Entity
Stanley M
Jaskot
Entergy
Corporation
Segment
5
Vote
Negative
Comment
The restructured tables are generally much clearer and the SDT is to be
commended on their efforts.
1. However, we believe the Alarming Point Table needs additional
clarification with regard to the Maximum Maintenance Interval. If an
“alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there
isn’t necessarily a maximum interval established as there is for Protection
System components. Also, if an entity’s alarm producing device
maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum
intervals for the alarm producing device of that entity. On that basis, we
suggest the interval verbiage be revised to “When alarm producing device
or system is verified, or by sections as per the monitored
component/protection system specified maximum interval as applicable”.
Alternately, if the intention is to establish maximum intervals as simply
being no longer than the individual component maintenance intervals as
we suggest for inclusion above, then the verbiage should be revised to
“When alarm producing component/protection system segment is
verified”. In either case are we to interpret monitored components with
attributes which allow for no periodic maintenance specified as not
requiring periodic alarm verification?
2. R1.5 calls for “identification of calibration tolerances or equivalent
parameters...” whereas the associated VSL references “failure to establish
calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply
“identify” or document such calibration tolerances would be analogous to
the severity level(s) of a “failure to specify one (or the severity level
should be consistent with the other elements of R1. Both cases appear to
be more of a documentation issue as opposed to a failure to implement.
Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4?
3. R1.5 calls for “identification of calibration tolerances or equivalent
parameters for each Protection System Component Type....”. We believe
the Supplementary Reference document should provide additional
information and examples of calibration tolerances or equivalent
parameters which would be expected for the various component types.
Especially for any “equivalent” parameters which would be required for
compliance for a component type besides protective relays. Adding
Requirement 1.5 is a significant revision and raises questions as to how
74
Voter
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Comment
broadly an accuracy or equivalent parameter requirement and associated
documentation would need to be addressed by entities and/or will be
measured for compliance. Discussion on this new requirement does not
seem to be addressed anywhere in the FAQ or Supplementary Reference
documents. Additionally, to the best of our knowledge, the need for such
a requirement was not brought up as a concern or comment on the prior
draft version of this standard, and in the context of a requirement need,
we don’t believe it has been attributed to or actually poses any significant
reliability risk. We do not believe this requirement is justified.
Response: Thank you for your comments.
1. The Maximum Maintenance Interval column entry in Table 2 has been revised to state, “When alarm producing Protection
System component is verified” to clarify this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Kenneth
FirstEnergy
5
Negative
Please see FirstEnergy's comments submitted separately through the comment
Dresner
Solutions
period posting
Response: Thank you for your comments. Please see our responses to your comments submitted during the formal comment
period.
David
Schumann
Florida
Municipal
Power Agency
5
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The
new PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control
circuitry. What's key about this is that these components are all part of
distribution system protection, so, these activities would not be covered
by other BES protection system maintenance and testing. I'm sure we are
testing batteries and the like, but, we are probably not testing battery
chargers and control circuity, and, in many cases distribution circuits are
such that it is very difficult, if not impossible, to test control circuitry to
the trip coil of the breaker without causing an outage of the customers on
that distribution circuit. There is no real reliability need for this either.
75
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Segment
Response: Thank you for your comments.
Vote
Comment
Unlike Transmission and Generation Protection Systems which are needed
to clear a fault and may only have one or two back-up systems, there are
thousands and thousands of UFLS relays and if one fails to operate, it will
not be noticeable to the event. It does make sense to test the relays
themselves in part to ensure that the regio0nsl UFLS program is being
met, but, to test the other protection system components is not
worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing
faults such as animals, vegetation blow-ins, lightning, etc., on distribution
circuits, reducing the value of testing to just about null. However, this
version is better than prior versions because it essentially requires the
entity to determine it's own period of maintenance and testing for
UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a
BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10
that excludes non-electrical protection (e.g., sudden pressure relays) and
auxiliary relays. Because the definition of Protection System (recently
approved) does not clearly exclude "non-electrical" protection,the
Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of
transformers, etc. should not be included in the standard. An alternative is
to change the definition of Protection System to make sure it only includes
electrical the VRF of R1 should be Low since the attached tables are
essentially the PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made modifications to Applicability 4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees
and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As
for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are included to the
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degree that an entity’s Protection System control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
Rex A Roehl
Indeck Energy
Services, Inc.
5
Negative
The level of detail for every conceivable component of every conceivable
protective system does not relate to improving reliability. For some protective
systems on some equipment, following these requirements, which is undoubtedly
already done, will result in good reliability, but probably not improve reliability.
Applying those same requirements to the thousands, if not millions, of other
protective systems with generate significant costs, generate significant numbers of
violations and not have any significant impact on reliability. The costs of this type
of program cannot be justified unless there is an NRC mandate or a pass through
to ratepayers. Most of the industry will take the cost of this program directly from
the bottom line. For minimal reliability improvement, that is not appropriate under
the FPA Section 215.
Response: Thank you for your comments. FERC Order 693 and the approved SAR assign the SDT to develop a standard with
maximum allowable intervals and minimum maintenance activities. The intervals and activities specified are believed by the SDT to
be technically effective, in a fashion that benefits reliability and that may be consistently monitored for compliance.
Dennis
Florom
Lincoln
Electric
System
5
Affirmative
While the proposed draft of the standard is acceptable as currently written, LES
would like the drafting team to consider the following comments.
(1) Table 1-1 should state “Test and calibrate (if necessary)” in the first section
under activities. If a relay passes the test, there is no need to calibrate it.
Therefore, not all relays will require calibration.
(2) Please explain the drafting team’s reason for not checking the trip coils of
breakers in the UFLS/UVLS schemes but ensuring that all others are operated
every six years. It would appear that they can all be lumped into the same group
one way or another.
(3) In regards to Specific Gravity Testing, many people do not perform the specific
gravity test routinely if they perform the individual cell internal ohmic test
routinely. LES asks the drafting team to consider allowing the internal cell ohmic
test as a substitute for the specific gravity test.
Response: Thank you for your comments.
1. Table 1-1 has been modified as you suggest.
2. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the
Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system
elements.
3. Table 1-4 does not specify specific gravity testing.
Mike Laney
Luminant
5
Negative
Luminant commends the PRC-005-2 Standard Drafting Team for its quality efforts
Generation
in producing this version of the Standard however; Luminant must cast a negative
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ballot vote for this present version of the Standard. The negative vote against the
present version of PRC-005-2 is solely based on the addition of Requirement R1
Part 1.5 with its associated reference to it in Requirement R4 Part 4.2 and the VSL
table.
It is Luminant’s opinion that this new Requirement as written subjects all
Transmission Owners, Generation Owners and Distribution Providers to vague
interpretations of a requirement that cannot be complied with because it is
impossible for any of them to draft the necessary documentation to be compliant
with the Standard. As stated in the High VSL associated with Part 1.5 of
Requirement R1 all owners will fail “to establish calibration tolerance or equivalent
parameters to determine if every individual discrete piece of equipment in a
Protection System is within acceptable parameters.”
It is Luminant’s opinion that the measurement of acceptable performance during
maintenance and testing activities can be accomplished with a Pass/Fail type of
documentation on a test form. No company can effectively establish calibration
tolerance parameters for an entire “component type” of the Protection System.
Doing so could be detrimental to the reliability of the grid. Parameters are
dependent on the location, application and situation specific to each Protection
System device.
The inclusion of Part 1.5 of Requirement R1 is a significant addition to the
standard, and by NERC Rules of Procedure requires the input and consideration of
the full Standard Drafting Team.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Wayne Lewis Progress
5
Negative
1. Implementation Plan for PRC-005-2 Since R2, R3, and R4 requirements
Energy
would be performed after establishment of the program documentation,
Carolinas
an additional year should be added to all implementation dates for
Requirements R2, R3, and R4 as shown below:
• Maintenance on components with intervals less than one year must be
completed within two years after applicable regulatory approval
(within one year of completion of R1 Program Documentation).
•
Maintenance on components with intervals between one year and
two years must be completed within three years after applicable
regulatory approval (within two years of completion of R1 Program
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Documentation).
• Maintenance on components with intervals of six years must be
completed within three-, five-, and seven-year milestones after
applicable regulatory approval (within two, four, and six years of
completion of R1 Program Documentation).
•
Maintenance on components with intervals of twelve years must be
completed within five-, nine-, and thirteen-year milestones after
applicable regulatory approval (within four, eight, and twelve years of
completion of R1 Program Documentation).
2. Standard PRC-005-02 1. Table 1-2: Rows 1 and 2 require different
intervals for the activity “Verify essential signals to and from Protection
System components.” Unless these inputs and outputs are monitored for
Row 2, it would seem that they should be performed at the same interval
for both Rows 1 and 2. Therefore, EITHER:
1. Row 1 should be broken into the following three activities:
• 3 months - Verify communications system is functional
• 6 years - Verify channel meets performance criteria
• 12 years - Verify essential signals to and from other Protection
System components OR:
2. Row 2 should be broken into the following two activities:
1. 12 years - Verify channel meets performance criteria
2. 6 years - Verify essential signals to and from other Protection System
components 2.
3. Table 1-4: Only Row 1 addresses dc supplies associated with UFLS or
UVLS systems. All other rows state that UFLS or UVLS systems are
excluded. What is required to “Verify dc supply voltage” for the
UFLS/UVLS systems? Does it require that the overall station battery
voltage be checked or just the dc voltage available to the UFLS/UVLS
circuit of interest? If a voltage measurement is taken at the UFLS/UVLS
circuit (e.g., in distribution breaker cabinet), can the batteries/chargers at
these facilities be excluded from the PRC-005-2 scope as long as they do
not also supply transmission-related protection?
4. PRC-005-2 FAQ’s Document Section V.1.A, Example #2: The instrument
transformer should be classified as “unmonitored” not “monitored.”
Response: Thank you for your comments.
1. The Implementation Plan for Requirement R1 has been changed from 12 months to 15 months in consideration of your
comment. The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
2. The first and second rows differ in that the first row is for unmonitored communications systems, and the second row is for
monitored communications systems. The activities in both rows are appropriate and correct.
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3. Table 1-4 has been completely re-structured. For station dc supply for only UFLS/UVLS, the only activity is to verify the dc
voltage.
4. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
Jerzy A
PSEG Power
5
Negative
The PSEG Companies do not agree with the Facilities as currently described in
Slusarz
LLC
section 4.2.5.5. Please refer to detailed comments provided in the formal
Comment Form.
Response: Thank you for your comments. Please see our response to your detailed comments from the formal comment period.
Steven
Grega
Public Utility
District No. 1
of Lewis
County
5
Negative
Do not like the word "all" in the proposed standard. Does all components mean
each piece of wire is included? Engineers are conservative in their protection
system designs and have redundant relays and protection paths. Even with half
the relays out of service, protection is normally retained. Would want to have 80%
a compliance level with a year to test & maintenance any component testing
founded to be non-compliant. This proposed standard will ensure many more
violations.
Response: Thank you for your comments. The approved PRC-005-1 already requires that entities have a program to maintain their
Protection System and implement that program. This already implies, “all”, therefore PRC-005-2 should not have the impact
suggested by your comment.
Michael J.
Haynes
Seattle City
Light
5
Negative
The proposed Standard PRC-005-2 is an improvement over the previous draft in
that it provides more consistency in maintenance and testing duration internals.
Notwithstanding, two issues are of concern to Seattle City Light such that it is
compelled to vote no:
1.
the establishment of bookends for standard verification and 2) the
implementation timelines for entities with systems where electro-mechanical
relays still compose a significant number of components in their protection
systems. Bookends: Proposed Standard PRC-005-2 specifies long inspection
and maintenance intervals, up to 12 years, which correspondingly
exacerbates the so-called “bookend” issue. To demonstrate that intervalbased requirements have been met, two dates are needed - bookends.
Evidencing an initial date can be problematic for cases where the initial date
would occur prior to the effective date of a standard. NERC has provided no
guidance on this issue, and the Regions approach it differently. Some, such
as Texas Regional Entity, require initial dates beginning on or after the
effective date of a Standard. Compliance with intervals is assessed only once
two dates are available that occur on or after a standard took effect. Other
regions, such as Western Electricity Coordinating Council (WECC), require
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2.
that entities evidence an initial date prior to the effective date of a standard.
For WECC, compliance with intervals is assessed as soon as a standard takes
effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal.
Proposed Standard PRC-005-2 will be another such standard. Indeed this
Standard will involve by far the largest number of bookends of any NERC
standard - many thousands for a typical entity. Furthermore, the long
inspection and maintenance intervals introduced in the draft will require
entities in WECC, for instance, to evidence initial bookend dates prior to the
date original PRC-005-1 took effect. For the 12-year intervals for CTs and
VTs in proposed Standard PRC-005-2, many initial dates will occur prior to
the 2005 Federal Power Act that authorized Mandatory Reliability Standards
and even reach back before the 2003 blackout that catalyzed the effort to
pass the Federal Power Act. As a result, many entities in WECC maybe at
risk of being found in violation of proposed Standard PRC-005-2 immediately
upon its implementation. Seattle City Light requests that NERC address the
bookends issue, either within proposed Standard PRC-005-2 or in a separate,
concurrent document.
Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with
legacy systems. In example, auxilary relay and trip coil testing may be
essential to prove the correct operation of complex, multi-function digital
protection systems. However, for legacy systems with single-function
electro-mechnical compenents, the considerable documentation and
operational testing needed to implement and track such testing is not
necessarily proporational to the relative risk posed by the equipment to the
bulk electric system. Performance testing of electro-mechanical systems,
particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause
far more problems on restoration-to-service than they will locate and correct.
As such, to assist entities in their implementation efforts, we believe
provision of alternatives are necessary, such as additional implementation
time through phasing and/or through technical feasability exceptions.
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Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18
Evidence”.
2. Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic. FERC Order
693 directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is a
portion thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has
developed those requirements in a fashion that affords entities with the opportunity to best meet those requirements.
William D
Southern
5
Negative
Please see comments submitted via the electronic comment form.
Shultz
Company
Generation
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
George T.
Ballew
Tennessee
Valley
Authority
5
Negative
Project 2007-17 Protection System Maintenance for Standard PRC-005-2 Draft NERC is recommending significant changes to this sizeable standard and only
allowing minimum comment period. While this is a good standard that has clearly
taken many hours to develop, we are primarily voting NO because of the hurried
fashion it is being commented, voted, and reviewed. Official comments to the
document were entered on the NERC Portal.
Response: Thank you for your comments. Please see our responses to your comments from the formal comment period.
Melissa Kurtz
U.S. Army
Corps of
Engineers
5
Negative
Paragraph 4.2.5.4 - The standard should be changed to require station service
transformers only if they will cause a loss of the generator tied to the BES. Also
recommend a definition of station service - we have station service that if lost
would not negatively effect the BES.
Response: Thank you for your comments. Clause 4.2.5.5 has been removed. Generator-connected station service transformers are
essential to the continuing operation of the generation plant; therefore, protection on these system components is included within
PRC-005-2 if the generation plant is a BES facility.
Martin Bauer
P.E.
U.S. Bureau
of
Reclamation
5
Negative
1. The tables rely on a reference document which is not a part of the standard
and as such may be altered without due process. Either the relevant text from
the reference needs to be inserted into the standard or the reference itself
incorporated into the standard.
2. The supplemental reference provides significant clarity to the intent of
standard; however, in doing so, it reveals conflicts and ambiguity in the text of
the standard. It is suggested that some of the clarifying language be inserted
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into the text of the standard.
3. The concept of including definitions in this standard that are not a part of the
Glossary of Terms will create a conflict with other standards that choose to use
the term with a different meaning. This practice should be disallowed. If a
definition is be introduced it should be added to the Glossary of Terms. This
concept was not provided to industry for comment when the modifications to
the Definition of Protection System was introduced. Additional related to this
practice are included later on.
4. The Term "Protective Relays" is overly broad as it is not limited to those
devices which are used to protect the BES. In the reference provided to the
standard, the SDT defined "Protective Relays" as "These relays are defined as
the devices that receive the input signal from the current and voltage sensing
devices and are used to isolate a faulted portion of the BES. " The Definition
for "Protective Relays' as well as the components associated with the them
should be associated with the protection of the BES in the definition.
5. The Section 2.4 of the attached reference and the recent FERC NOPR are in
conflict with the definition of "Protective Relays" which include lockout relays
and transfer trip relays "The relays to which this standard applies are those
relays that use measurements of voltage, current, frequency and/or phase
angle and provide a trip output to trip coils, dc control circuitry or associated
communications equipment.
6. This Draft 2: April3: November 17, 2010 Page 5 definition extends to IEEE
device # 86 (lockout relay) and IEEE device # 94 (tripping or trip-free relay) as
these devices are tripping relays that respond to the trip signal of the
protective relay that processed the signals from the current and voltage
sensing devices." The definition should be revised to reflect that is really
intended. The SDT as created an implied definition by specifically defining DC
circuits associated with the trip function of a "Protective Relay" but failing to
specifically define voltage and current sensing circuits providing inputs to
"Protective Relays". The team clearly intended the circuits to be included but
the definition does not since it only refers the the "voltage and current sensing
devices".
7. Starting with the Definitions and continuing through the end of the document,
terms that have been defined are not capitalized. This leaves it ambiguous as
to whether the defined term is to be applied or it is a generic reference. Only
defined terms "Protection System Maintenance Program" and "Protection
System" are consistently capitalized.
8. Protection System Maintenance Program (PSMP) definition: The Restore bullet
should be revised to read as follows: "Return malfunctioning components to
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proper operation by repair or calibration during performance of the initial onsite activity." Add the following at the end of the PSMP definition: “NOTE:
Repair or replacement of malfunctioning Components that require follow-up
action fall outside of the PSMP, and are considered Maintenance Correctable
Issues.”
9. Protection System (modification) definition: The term "protective functions"
that is used herein should be changed to "protective relay functions" or what is
meant by the phrase should become a defined term, as it is being used as if it
is a well known well defined, and agreed upon term.
a. The first bullet text should be revised to read as follows: "Protective relays
that monitor BES electrical quantities and respond when those quantities
exceed established parameters," the last two bullets should be reversed in
order and modified to read as follows: o control circuitry associated with
protective relay functions through the trip coil(s) of the circuit breakers or
other interrupting devices, and o station dc supply (including station
batteries, battery chargers, and non-battery-based dc supply) associated
with the preceding four bullets.
10. Statement between the Protection System (modification) definition and the
Maintenance Correctable Issue definition; Is this a NERC accepted practice?
There does not appear to be a location in the standard for defining terms.
Having terms that are not contained in the "Glossary of Terms used in NERC
Reliability Standards," and are outside of the terms of the standards, and yet
are necessary to understand the terms of the Requirements is not acceptable.
They would become similar to the reference documents, and could be changed
without notice.
11. Maintenance Correctable Issue definition: The last sentence should be
modified to read as follows: "Therefore this issue requires follow-up corrective
action which is outside the scope of the Protection System Maintenance
Program and the Standard PRC-005-2 defined Maximum Maintenance
Intervals." The definition could also be easily clarified to read "Maintenance
Correctable Issue - Failure of a component to operate within design
parameters such that it cannot be restored to functional order by repair or
calibration; therefore requires replacement." This ensures that any action to
restore the equipment, short of replacement, is still considered maintenance.
Otherwise ambiguity is introduced as what "maintenance" is.
12. Countable Event definition: An explanation should be made that this is a part
of the technical justification for the ongoing use of a performance-based
Protection System Maintenance Program for PRC-005.
13. Insert the phrase "Standard PRC-005-2" before the term "Tables 1-1..."
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14. Applicability: 4.2. Facilities: 4.2.5.4 and 4.2.5.5: Delete these two parts of
the applicability. Station service transformer protection systems are not
designed to provide protection for the BES. Per PRC-005-2 Protection System
Maintenance Draft Supplementary Reference, Nov. 17 2010, Section 2.3 Applicability of New Protection System Maintenance Standards: “The BES
purpose is to transfer bulk power. The applicability language has been changed
from the original PRC-005: “...affecting the reliability of the Bulk Electric
System (BES)...” To the present language: “... and that are applied on, or are
designed to provide protection for the BES.” The drafting team intends that
this Standard will not apply to “merely possible” parallel paths, (subtransmission and distribution circuits), but rather the standard applies to any
Protection System that is designed to detect a fault on the BES and take action
in response to that fault.” Station Service transformer protection is designed to
detect a fault on equipment internal to a powerplant and not directly related to
the BES. In addition, many Station Service protection ensures fail over to a
second source in case of a problem. Thus station service transformer
protection system is a powerplant reliability issue and not a BES reliability
issue. As such station service transformer protection should not be included in
PRC 005 2. In addition, the SDT appears to have targeted generation station
service without regard to transmission systems. If generating station service
transformers are that important, then why are substation/switchyard station
service transformers not also important?
15. Requirements Should the sub requirements have the "R" prefix?
16. R4. Change the phrase "... PSMP, including identification of the resolution of
all ..." to read "...PSMP including identification, but not the resolution, of all
...".
17. General comment PRC005-2 is very specific in listing the
Response: Thank you for your comments.
1. The Tables do not provide a reference to either the Supplementary Reference Document or the FAQ. An entity must comply with
the standard when approved. The reference documents provide additional explanation, discussion, and rationale, but are not
part of the mandatory standard. Since the reference documents are developed in accordance with the standard and will be
posted with the standard, the NERC Standard Development Procedure does require that they undergo industry review before
being initially posted, and upon any revision.
2. The clarifying language is exactly that – clarifying language, and is not essential to application of the Standard. He NERC
Standards Development Procedure establishes that the standard shall not include explanatory text.
3. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms,
may change them in a fashion inconsistent with the intended usage within PRC-005-2.
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4. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition with
PRC-005. Further, the applicability of generically-described protective relays is defined by the Applicability clause of PRC-0052.
5. The issues raised by the FERC NOPR will be addressed as part of the response to the NOPR (and, ultimately, the Order). The
extension of auxiliary and lockout relays is not part of the protective relay (addressed within Table 1-1), but instead as part of the
control circuitry (Table 1-5).
6. The extension of auxiliary and lockout relays is not part of the protective relay (addressed within Table 1-1), but instead as part of
the control circuitry (Table 1-5).
7. Definition from the NERC Glossary of Terms (or those intended for the Glossary) are consistently capitalized (Protection System
and Protection System Maintenance Program fall within this category). As for terms defined only for use within this standard,
these terms are NOT capitalized, since they are not in the Glossary of Terms.
8. The “restore” portion of PSMP specifically addresses returning malfunctioning components to your proper operation. The
requirements regarding maintenance correctable issues are further addressed within that definition (for use only within PRC-0052).
9. The SDT is currently not planning on further modifying the most recent NERC BOT-approved definition of Protection System.
10. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms,
may change them in a fashion inconsistent with the intended usage within PRC-005-2.
11. Identifying problems, but not fixing them, does not constitute an effective program. In deference to the time that may be
necessary to repair / replace defective components, the SDT has decided to require only initiation of resolution of maintenance
correctable issues, not to demonstration completion of them.
12. Since this term is used only in Attachment A, it seems unnecessary to provide the explanation requested.
13. The SDT has elected not to change the reference to the Tables throughout the Standard.
14. Thank you for your comments. Clause 4.2.5.5 has been removed. Generator-connected station service transformers are essential
to the continuing operation of the generation plant; therefore, protection on these system components is included within PRC005-2 if the generation plant is a BES facility.
15. The current style guide for NERC Standards does not preface the Parts with an “R”.
16. Identifying problems, but not fixing them, does not constitute an effective program. In deference to the time that may be
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necessary to repair / replace defective components, the SDT has decided to require only initiation of resolution of maintenance
correctable issues, not to demonstration completion of them.
17. It appears the remainder of your comment was truncated and cannot be ascertained.
Linda Horn
Wisconsin
Electric Power
Co.
5
Negative
Q4: Table 1-4 requires an activity to verify the state of charge of battery cells.
There are no possible options for meeting this requirement listed in the FAQ
document. Unlike other terms used in the standard, this term is not mentioned or
defined in the FAQ. To comply with this standard, the SDT needs to provide more
guidance. For example, for VLA batteries the measured specific gravity could
indicate state of charge. For VRLA batteries, it is not as clear how to determine
state of charge, but possibly this can be determined by monitoring the float
current.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into
the Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been
revised to remove “state of charge” from the activities.
Leonard
Rentmeester
Wisconsin
Public Service
Corp.
5
Negative
1. Implementation plan is too aggressive given the drastic changes from PRC005-1 to PRC-005-2
2. The drastic changes don’t appear to provide an incremental increase in the
reliability of the BES
3. We support the MRO NSRS comments
Response: Thank you for your comments.
1. The SDT has carefully considered the changes that entities will be expected to make to their program in response to PRC-005-2
and provided an Implementation Plan that should be sufficient and provided a phase-in approach to permit entities to
systemically implement the revised standard. The Implementation Plan for Requirement R4 has been revised to add one year to
all established dates.
2. FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals and minimum
maintenance activities. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that
benefits reliability and that may be consistently monitored for compliance.
3. Please see our responses to MRO’s NSRS formal comments in the Consideration of Comments document.
Liam Noailles Xcel Energy,
5
Negative
We feel that several improvements were made since the last draft. However, we
Inc.
feel that some gaps exist that should be addressed before moving this project
forward. We have detailed our issues in our formal comments
Response: Thank you for your comments. Please see our response to your formal comments.
Edward P.
Cox
AEP
Marketing
6
Negative
Restructured Tables:
1. Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12 years
for unmonitored control circuitry, yet other portions of control circuitry have a
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maximum interval of 6 years. AEP does not understand the rationale for the
difference in intervals, when in most cases, one verifies the other. Also,
unmonitored control circuitry is capitalized in row 4 such that it infers a
defined term.
2. In the first row of table 1-4 on page 16, it is difficult to determine if it is a cell
that wraps from the previous page or is a unique row. This is important
because the Maximum Maintenance Intervals are different (i.e. 18 months vs
6 years). It is difficult to determine to which elements the 6 year Maximum
Maintenance Interval applies. AEP suggests repeating the heading “Monitored
Station dc supply (excluding UFLS and UVLS) with: Monitor and alarm for
variations from defined levels (See Table 2):” for the bullet points on this
page.
VSLs, VRFs and Time Horizons:
3. The VSL table should be revised to remove the reference to the Standard
Requirement 1.5 in the R1 “High” VSL.
4. All four levels of the VSL for R2 make reference to a “condition-based PSMP.”
However, nowhere in the standard is the term “condition-based” used in
reference to defining ones PSMP. The VSL for R2 should be revised to remove
reference to a condition-based PSMP; alternatively the Standard could be
revised to include the term “condition-based” within the Standard
Requirements and Table 1.
5. In multiple instances, Table 1 uses the phrase “No periodic maintenance
specified” for the Maximum Maintenance Interval. Is this intended to imply
that a component with the designated attributes is not required to have any
periodic maintenance? If so, the wording should more clearly state “No
periodic maintenance required” or perhaps “Maintain per manufacturers
recommendations.” Failure to clearly state the maintenance requirement for
these components leaves room for interpretation on whether a Registered
Entity has a maintenance and testing program for devices where the Standard
has not specified a periodic maintenance interval and the manufacturer states
that no maintenance is required.
FAQ and Supplementary Reference:
6. With such a complex standard as this, the FAQ and Supplementary Reference
documents do aid the Protection System owner in demystifying the
requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a. Section 5 of the Supplementary Reference, refers to “condition-based”
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Comment
maintenance programs. However, nowhere in the standard is the term
“condition-based” used in reference to defining ones PSMP. The
Supplementary Reference should be revised to remove reference to a
condition-based PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard Requirements
and Table 1.
b. Section 15.7, page 26, appears to have a typographical error “...can
all be used as the primary action is the maintenance activity...”
c. Figure 2 is difficult to read. The figure is grainy and the colors
representing the groups are similar enough that it is hard to
distinguish between groups.
“Frequently-Asked Questions”:
7. With such a complex standard as this, the FAQ and Supplementary Reference
documents do aid the Protection System owner in demystifying the
requirements. But AEP holds strong doubt on how much weight the
documents carry during audits. It would be better to include them as an
appendix in the actual standard, but in a more compact version with the
following modifications:
a. The section “Terms Used in PRC-005-2” is blank and should be
removed as it adds no value. Section I.1 and Section IV.3.G reference
“condition-based” maintenance programs. However, nowhere in the
standard is the term “condition-based” used in reference to defining
ones PSMP.
b. The FAQ should be revised to remove reference to a condition-based
PSMP; alternatively the Standard could be revised to include the term
“condition-based” within the Standard Requirements and Table 1.
c. The second sentence to the response in Section I.1 appears to have a
typographical error “... an entity needs to and perform ONLY timebased...”.
General:
8. Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2
should be removed. Specifying calibration tolerances for every protection
system component type, while a seemingly good idea, represents a substantial
change in the direction of the standard. It would be very onerous for
companies to maintain a list of calibration tolerances for every protection
system component type and show evidence of such at an audit. AEP believes
entities need the flexibility to determine what acceptance criteria is warranted
and need discretion to apply real-time engineering/technician judgment where
appropriate.
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Response: Thank you for your comments.
Vote
Comment
9. Three different types of maintenance programs (time-based, performancebased and condition-based) are referenced in the standard or VSLs, yet the
time-based and condition-based programs are neither defined nor described.
Certain terms defined within the definition section (such as Countable Event or
Segment) only make sense knowing what those three programs entail. These
programs should be described within the standard itself and not assume a
knowledge of material in the Supplementary Reference or FAQ.
10. “Protective relay” should be a defined term that lists relay function for
applicability. There are numerous ‘relays’ used in protection and control
schemes that could be lumped in and be erroneously included as part of a
Protection System. For example, reclosing or synchronizing relays respond to
voltage and hence could be viewed by an auditor as protective relays, but
they in fact perform traditional control functions versus traditional protective
functions.
11. The Data Retention requirement of keeping maintenance records for the two
most recent maintenance performances is a significant hurdle for any owners
to abide by during the initial implementation period. The implementation plan
needs to account for this such that Registered Entities do not have to provide
retroactive testing information that was not explicitly required in the past.
1. The 6-year activities are all related to components with “moving parts”, and the 12-year activities are related to the other
portions of the control circuitry. The capitalized term has been corrected.
2. Table 1-4 has been modified in consideration of your comments.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
The associated VSL has also been revised.
4. The SDT concluded that Requirement R2 is redundant to Requirement R1, Part 1.4 and has deleted Requirement R2 (together
with the Measures and & VSL).
5. If the indicated monitoring attributes are present, no “hands-on” periodic maintenance is required, as the monitoring of the
component is providing a continuing indication of its functionality.
6. The discussion within the Supplementary Reference Document and FAQ are informative, not normative, and thus do not
belong as part of the standard.
a) The Supplementary Reference Document discusses condition-based maintenance in a conceptual manner, as a
generally-recognized term. The SDT did make some changes within the Supplementary Reference document to
clarify the manner in which condition-based maintenance is discussed.
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b) This clause has been corrected.
c) A higher-quality version of Figure 2 has been substituted.
7. The discussion within the Supplementary Reference Document and FAQ are informative, not normative, and thus do not
belong as part of the standard.
a) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
b) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
c) The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
8. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
9. The term, “condition-based” has been removed from the draft standard. The other terms are used, but are clear in the context
in which they are used.
10. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition with
PRC-005. Further, the applicability of generically-described protective relays is defined by the Applicability clause of PRC005-2.
11. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the
data of the most recent performance of the maintenance, as well as the data of the preceding one to validate that entities have
been in compliance since the last audit (or currently, since the beginning of mandatory compliance). The SDT has specified
the data retention in the posted standard to establish this level of documentation. This seems to be consistent with the current
practices of several Regional Entities.
Brenda S.
Bonneville
6
Negative
Refer to BPA comments
Anderson
Power
Administration
Response: Thank you for your comments. Please see our response to the BPA comments.
Matthew D
Cripps
Cleco Power
LLC
6
Negative
Cleco applies its’ UFLS on the distribution grid with each UF relay individually
tripping a relatively low value of load thru breakers and reclosers. Since our
program is implemented via a large number of individual components, breakers,
reclosers, and individual batteries, the failure of any one component will have a
minimal impact on the effectiveness of the overall UFLS program within our
region. Therefore, the verification of sensing devices, dc supply voltages, and the
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paths of the control circuit and trip circuits on the UFLS systems implemented on
the distribution grid is unnecessary.
Response: Thank you for your comments. The SDT disagrees; the sensing devices, control circuitry and dc supply related to UFLS
has an effect on the performance of the UFLS. The SDT has, however, respected the overall impact on the control circuitry of
individual UFLS on BES reliability by requiring that UFLS be subjected to a subset of the overall sensing devices, control circuitry
and dc supply maintenance activities.
Nickesha P
Consolidated
6
Negative
The Tables
Carrol
Edison Co. of
1. The wording “Component Type” is not necessary in each title. Just the
New York
equipment category should be listed--what is now shown as “Component Type
- Protective Relay”, should be Protective Relay. However, Protective Relay is
too general a category. Electromechanical relays, solid state relays, and
microprocessor based relays should have their own separate tables. So
instead of reading Protective Relay in the title, it should read
Electromechanical Relays, etc. This will lengthen the standard, but will simplify
reading and referring to the tables, and eliminate confusion when looking for
information. The “Note” included in the heading is also not necessary.
2. “Attributes” is also not necessary in the column heading, “Component”
suffices.
Other Comments –
3. In general, the standard is overly prescriptive and complex. It should not be
necessary for a standard at this level to be as detailed and complex as this
standard is. Entities working with manufacturers, and knowledge gained from
experience can develop adequate maintenance and testing programs.
4. Why are “Relays that respond to non-electrical inputs or impulses (such as,
but not limited to, vibration, pressure, seismic, thermal or gas
accumulation)...” not included? The output contacts from these devices are
oftentimes connected in tripping or control circuits to isolate problem
equipment.
5. Due to the critical nature of the trip coil, it must be maintained more
frequently if it is not monitored. Trip coils are also considered in the standard
as being part of the control circuitry. Table 1-5 has a row labeled
“Unmonitored Control circuitry associated with protective functions”, which
would include trip coils, has a “Maximum Maintenance Interval” of “12
Calendar Years”. Any control circuit could fail at any time, but an unmonitored
control circuit could fail, and remain undetected for years with the times
specified in the Table (it might only be 6 years if I understand that as being
the trip test interval specified in the table). Regardless, if a breaker is unable
to trip because of control circuit failure, then the system must be operated in
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6.
7.
8.
9.
10.
11.
12.
13.
real time assuming that that breaker will not trip for a fault or an event, and
backup facilities would be called upon to operate. Thus, for a line fault with a
“stuck” breaker (a breaker unable to trip), instead of one line tripping, you
might have many more lines deloaded or tripped because of a bus having to
be cleared because of a breaker failure initiation. The bulk electric system
would have to be operated to handle this contingency.
In reference to the FAQ document, Section 5 on Station dc Supply, Question
K, clarification is needed with respect to dc supplies for communication within
the substation. For example, if the communication systems were run off a
separate battery in separate area in a substation, would the standard apply to
these batteries or not?
To define terms only as they are used in PRC-005-2 is inviting confusion.
Although they may be unique to PRC-005-2, some or all of them may be used
in future standards, some already may be used in existing standards, and may
or may not be deliberately defined. Consistency must be maintained, not only
for administrative purposes, but for effective technical communications as
well.
What is the definition of “Maintenance” as used in the table column “Maximum
Maintenance Interval”? Maintenance can range from cleaning a relay cover to
a full calibration of a relay.
A control circuit is not a component, it is made up of components.
Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify
calibration tolerances or other equivalent parameters...” means, and may be
subject to different interpretations by entities and compliance enforcement
personnel.
In the Implementation plan for Requirement R1, recommend changing “six” to
fifteen. This change would restore the 3-month time difference that existed in
the previous draft, between the durations of the implementation periods for
jurisdictions that do and do not require regulatory approval. It will ensure
equity for those entities located in jurisdictions that do not require regulatory
approval, as is the case in Ontario.
The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It
seems to continue to the next page to a new box. There are multiple activities
without clear delineation. Regarding station service transformers,
Item 4.2.5.5 under Applicability should be deleted. The purpose of this
standard is to protect the BES by clearing generator, generator bus faults (or
other electrical anomalies associated with the generator) from the BES.
Having this standard apply to generator station service transformers, that
have no direct connection to the BES, does meet this criteria. The FAQs
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(III.2.A) discuss how the loss of a station service transformer could cause the
loss of a generating unit, but this is not the purpose of PRC-005. Using this
logic than any system or device in the power plant that could cause a loss of
generation should also be included. This is beyond the scope of the NERC
standards.
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. Please see the SDT’s response to ISO New England Inc. in the formal Standard Comments
3. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies
that minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent
maintenance, a performance-based program in accordance with R3 and Attachment A is an option.
4. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection
System definition. Also, there is currently no technical basis for the maintenance of the devices which respond to nonelectrical quantities on which to base mandatory standards related either to activities or intervals. Absent such a technical
basis, we are currently unable to establish mandatory requirements, but may do so in the future if such a technical basis
becomes available.
5. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year
interval. You can maintain these devices more frequently if you desire
6. With respect to dc supply associated only with communication systems, we prescribe, within Table 1-2, that the
communications system must be verified as functional every 3 months, unless the functionality is verified by monitoring. The
specific station dc supply requirements (Table 1-4) do not apply to the dc supply associated only with communications
systems. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
7. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms,
either now or in the future, may not be consistent with the terms used here. They are defined only for clarify within this
standard. The SDT will confirm with NERC staff that this approach is acceptable.
8. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are
specified in the Activities column. The term is capitalized in the column title in conformance with normal editorial practice as
a title, rather than as a definition.
9. For purposes of this standard, the control circuit is defined as one component type.
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10. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
11. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1,
making it consistent with the remainder of the Implementation Plan Please see the SDT’s response to NPPC in the formal
Standard Comments.
12. Table 1-4 has been further modified for clarity.
13. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
Brenda
Constellation
6
Negative
1. The applicability has included more generation protective components. The
Powell
Energy
current PRC-005 guidance states that only Station Service transformers for
Commodities
plants 75 MVA and up should be included. The proposed standard includes all
Group
station service transformers, regardless of plant size or connection (via
generator or system). Constellation Energy Commodities Group does not see
the reliability benefits of this increased scope.
2. R1.4 states that all monitoring attributes of all components must be listed and
identified. For most generation facilities, it is more efficient to calibrate/check
the entire protective system while the plant is in an outage, regardless of a
component’s monitoring capabilities. This requirement would require those
facilities to maintain a list of attributes that won’t ever be used, and would not
alter their testing frequency. What if an entity were found non-compliant in
the situation that was just described? It does not affect the reliability of the
BES and therefore R1.4 should be removed.
3. M1 doesn’t include a measure for R1.4. It just implies that a facility must
maintain a list.
4. The battery listing in the attached table is still too prescriptive. If
unmonitored, there should be a quarterly and yearly check, which is implied,
but it is then broken out by battery type to be more prescriptive.
5. PTs and CTs are mentioned, but it seems as though the drafting team wants a
facility to only test the outputs to ensure they are working properly. To clarify
this, Constellation Energy Commodities Group suggests rewording the testing
verbiage for PTs and CTs.
Response: Thank you for your comments.
1. Section 4.2.5 of “Applicability” specifies that only Generation Facilities that are part of the BES are included.
2. The SDT disagrees; Requirement R1, Part 1.4 supports Requirement R1, Part 1.2, and seems necessary to assure that entities have
appropriately applied the longer intervals associated with monitored components. However, in consideration to your comment the
95
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Comment
SDT has revised Requirement R1, Part 1.4 and has also removed Requirement R2 because of redundancy to Requirement R1, Part
1.4.
3. Measure M1 has been revised in consideration of your comment.
4. The activities for different battery types are addressed separately because the relevant activities differ.
5. The SDT intends that the instrument transformer and associated circuitry be verified to be functional, but believes that customary
apparatus maintenance (dielectric, infrared, etc) are not relevant to PRC-005-2.
Louis S Slade Dominion
6
Negative
Dominion is opposed to this version because Requirement R1.5 is overly
Resources,
prescriptive, requiring an extraordinary level of documentation, with little
Inc.
anticipated improvement in reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Terri F
Entergy
6
Negative
The restructured tables are generally much clearer and the SDT is to be
Benoit
Services, Inc.
commended on their efforts.
1. However, we believe the Alarming Point Table needs additional
clarification with regard to the Maximum Maintenance Interval. If an
“alarm producing device” is considered to be a device such as an SCADA
RTU, individual entity intervals for such a device would differ, and there
isn’t necessarily a maximum interval established as there is for Protection
System components. Also, if an entity’s alarm producing device
maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum
intervals for the alarm producing device of that entity. On that basis, we
suggest the interval verbiage be revised to “When alarm producing device
or system is verified, or by sections as per the monitored
component/protection system specified maximum interval as applicable”.
Alternately, if the intention is to establish maximum intervals as simply
being no longer than the individual component maintenance intervals as
we suggest for inclusion above, then the verbiage should be revised to
“When alarm producing component/protection system segment is
verified”. In either case are we to interpret monitored components with
attributes which allow for no periodic maintenance specified as not
requiring periodic alarm verification?
2. R1.5 calls for “identification of calibration tolerances or equivalent
parameters...” whereas the associated VSL references “failure to establish
calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply
“identify” or document such calibration tolerances would be analogous to
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Comment
the severity level(s) of a “failure to specify one (or Cthe severity level
should be consistent with the other elements of R1. Both cases appear to
be more of a documentation issue as opposed to a failure to implement.
Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4? R1.5 calls for “identification of calibration tolerances
or equivalent parameters for each Protection System Component Type....”.
We believe the Supplementary Reference document should provide
additional information and examples of calibration tolerances or equivalent
parameters which would be expected for the various component types.
Especially for any “equivalent” parameters which would be required for
compliance for a component type besides protective relays. Adding
Requirement 1.5 is a significant revision and raises questions as to how
broadly an accuracy or equivalent parameter requirement and associated
documentation would need to be addressed by entities and/or will be
measured for compliance. Discussion on this new requirement does not
seem to be addressed anywhere in the FAQ or Supplementary Reference
documents. Additionally, to the best of our knowledge, the need for such
a requirement was not brought up as a concern or comment on the prior
draft version of this standard, and in the context of a requirement need,
we don’t believe it has been attributed to or actually poses any significant
reliability risk. We do not believe this requirement is justified.
Response: Thank you for your comments.
1. The Maximum Maintenance Interval column entry in Table 2 has been revised to state, “When alarm producing Protection
System component is verified” to clarify this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL
has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Mark S
FirstEnergy
6
Negative
Please see FirstEnergy's comments submitted separately through the comment
Travaglianti
Solutions
period posting.
Response: Thank you for your comments. Please see our response to your comments submitted separately through the formal
comment period.
Richard L.
Montgomery
Florida
Municipal
Power Agency
6
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new
PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control circuitry.
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Response: Thank you for your comments.
Vote
Comment
What's key about this is that these components are all part of distribution
system protection, so, these activities would not be covered by other BES
protection system maintenance and testing. I'm sure we are testing batteries
and the like, but, we are probably not testing battery chargers and control
circuity, and, in many cases distribution circuits are such that it is very
difficult, if not impossible, to test control circuitry to the trip coil of the breaker
without causing an outage of the customers on that distribution circuit. There
is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one
or two back-up systems, there are thousands and thousands of UFLS relays
and if one fails to operate, it will not be noticeable to the event. It does make
sense to test the relays themselves in part to ensure that the regio0nsl UFLS
program is being met, but, to test the other protection system components is
not worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits,
reducing the value of testing to just about null. However, this version is better
than prior versions because it essentially requires the entity to determine it's
own period of maintenance and testing for UFLS/UVLS for DC Supply and
control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation
(Project 2009-17) of "transmission Protection System" and should state:
"Protection Systems applied on, or designed to provide protection for a BES
Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that
excludes non-electrical protection (e.g., sudden pressure relays) and auxiliary
relays. Because the definition of Protection System (recently approved) does
not clearly exclude "non-electrical" protection, the Applicability section should.
For instance,, a vibration monitor, steam pressure, etc. protection of
generators, sudden pressure protection of transformers, etc. should not be
included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical the VRF of R1 should
be Low since the attached tables are essentially the PSMP.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
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Comment
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
Thomas E
Washburn
Florida
Municipal
Power Pool
6
Negative
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we
interpreted PRC-008/011 as being only the UFLS/UVLS equipment. The new
PRC-005 sweeps in other protection system components, e.g.,
communications (probably not applicable), voltage and current sensing
devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution
system protection, so, these activities would not be covered by other BES
protection system maintenance and testing. I'm sure we are testing batteries
and the like, but, we are probably not testing battery chargers and control
circuity, and, in many cases distribution circuits are such that it is very
difficult, if not impossible, to test control circuitry to the trip coil of the breaker
without causing an outage of the customers on that distribution circuit. There
is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one
or two back-up systems, there are thousands and thousands of UFLS relays
and if one fails to operate, it will not be noticeable to the event. It does make
sense to test the relays themselves in part to ensure that the regio0nsl UFLS
program is being met, but, to test the other protection system components is
not worthwhile. Note that DC Supplies and most of the control circuitry of
distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits,
reducing the value of testing to just about null. However, this version is better
than prior versions because it essentially requires the entity to determine it's
own period of maintenance and testing for UFLS/UVLS for DC Supply and
control circuitry.
2. Applicability, should reflect the Y&W and Tri-State interpretation (Project
2009-17) of "transmission Protection System" and should state: "Protection
Systems applied on, or designed to provide protection for a BES Facility and
that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that
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Comment
excludes non-electrical protection (e.g., sudden pressure relays) and auxiliary
relays. Because the definition of Protection System (recently approved) does
not clearly exclude "non-electrical" protection,the Applicability section should.
For instance,, a vibration monitor, steam pressure, etc. protection of
generators, sudden pressure protection of transformers, etc. should not be
included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical the VRF of R1 should
be Low since the attached tables are essentially the PSMP.
Response: Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained
relative to similar activities for Protection Systems in general. Regardless, without proper functioning of these component
types, UFLS and UVLS will not respond as expected, and will therefore degrade BES system reliability, particularly during
the stressed system conditions for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5 specifically
excludes UFLS and UVLS from maintenance activities related to the interrupting device trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC005-2. However, the SDT has made changes to Applicability 4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of
Trustees and will soon be filed with FERC for approval, clearly includes only protective relays that respond to electrical
quantities. As for auxiliary relays, the interpretation to which you refer states that they are not explicitly included, but are
included to the degree that an entity’s Protection System control circuitry addresses them(which has been identified as a
reliability gap), and are being added to PRC-005-2 to resolve the gap.
Silvia P
Mitchell
Florida Power
& Light Co.
6
Negative
This draft standard is too perscriptive.
1. Requirement R1, Part 1.5 would be overwhelming if approved. Requirement
R1, Part 1.5 should be deleted.
2. Requirement R4, Part 4.2 phrase "established in accordance with Requirement
R1, Part 1.5" should be deleted. The standard without these additional
requirements would be sufficient to establish that the Protection System is
maintained and protects the BES.
3. Table 1-2 Component Type Communications Systems Maximum Maintenance
Interval of 3 Calendar Months to verify that the communications system is
functional for any unmonitored communications system is unyielding. Most
communication failures are caused by power supply failures which Next Era
does monitor. Based on experience and monitoring of communication power
supplies, 12 calendar months would be adequate. The maximum maintenance
interval should be changed from 3 calendar months to 12 calendar months.
4. Table 1-4, Component Type Station dc Supply Maximum Maintenance Interval
of 3 Calendar Months to inspect electrolyte levels on “Any unmonitored station
100
Voter
Entity
Segment
Vote
Comment
dc supply not having the monitoring attributes of a category below. (Excluding
UFLS and UVLS)” is too stringent. Verifying battery charger float voltage every
18 calendar months is sufficient to prevent excessive gassing and water loss
of battery cells. The maximum maintenance interval should be changed from
3 calendar months to 6 calendar months.
5. Table 1-4, Component Type Station dc Supply Maximum Maintenance Interval
of 3 Calendar Months to measure the internal ohmic values on “Unmonitored
Station dc supply with Valve Regulated Lead-Acid (VRLA) batteries that does
not have the monitoring attributes of a category below. (excluding UFLS and
UVLS)” is too stringent. With the standard’s requirement to verify the float
voltage every 18 calendar months, measuring the internal ohmic values every
6 calendar months would be adequate. The maximum maintenance interval
should be changed from 3 calendar months to 6 calendar months.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are
addressed within the PSMP definition and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
2. Requirement R4 has also been re-drafted to address various related concerns noted within comments. Please see
Supplementary Reference Document, Section 8 for a discussion of this. The associated VSL has also been revised.
3. The activity to which you refer is an inspection-based activity based on overall functionality, and addresses functionality of
various communications technologies. If an entity monitors the power supply (as suggested), doing so addresses one
portion of the functionality, but does not address channel integrity, etc.
4. The SDT disagrees, and believes that the specified activities, at the specified intervals, are appropriate.
5. The standard has been revised as you suggested.
Paul Shipps
Lakeland
6
Negative
Small entities with only one or two BES substations may not have enough
Electric
components to take advantage of the expanded maintenance intervals afforded by
a performance-based maintenance program. Aggregating these components
across different entities doesn’t seem too logical considering the variations at the
sub-component level (wire gauge, installation conditions, etc.)
Response: Thank you for your comments. Entities are not required to use performance-based maintenance programs. Requirement
R3 and Attachment A are provided for the use of entities that can (and desire to) avail themselves of this approach.
Eric
Ruskamp
Lincoln
Electric
System
6
Affirmative
While the proposed draft of the standard is acceptable as currently written, LES
would like the drafting team to consider the following comments.
(1) Table 1-1 should state “Test and calibrate (if necessary)” in the first section
under activities. If a relay passes the test, there is no need to calibrate it.
101
Voter
Entity
Segment
Vote
Comment
Therefore, not all relays will require calibration.
(2) Please explain the drafting team’s reason for not checking the trip coils of
breakers in the UFLS/UVLS schemes but ensuring that all others are operated
every six years. It would appear that they can all be lumped into the same group
one way or another.
(3) In regards to Specific Gravity Testing, many people do not perform the specific
gravity test routinely if they perform the individual cell internal ohmic test
routinely. LES asks the drafting team to consider allowing the internal cell ohmic
test as a substitute for the specific gravity test.
Response: Thank you for your comments.
1. Table 1-1 has been modified as you suggest.
2. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed within the
Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping distribution system
elements.
3. Table 1-4 does not specify specific gravity testing.
Brad Jones
Luminant
Energy
6
Negative
Luminant commends the PRC-005-2 Standard Drafting Team for its quality efforts
in producing this version of the Standard however; Luminant must cast a negative
ballot vote for this present version of the Standard. The negative vote against the
present version of PRC-005-2 is solely based on the addition of Requirement R1
Part 1.5 with its associated reference to it in Requirement R4 Part 4.2 and the VSL
table.
It is Luminant’s opinion that this new Requirement as written subjects all
Transmission Owners, Generation Owners and Distribution Providers to vague
interpretations of a requirement that cannot be complied with because it is
impossible for any of them to draft the necessary documentation to be compliant
with the Standard. As stated in the High VSL associated with Part 1.5 of
Requirement R1 all owners will fail “to establish calibration tolerance or equivalent
parameters to determine if every individual discrete piece of equipment in a
Protection System is within acceptable parameters.”
It is Luminant’s opinion that the measurement of acceptable performance during
maintenance and testing activities can be accomplished with a Pass/Fail type of
documentation on a test form. No company can effectively establish calibration
tolerance parameters for an entire “component type” of the Protection System.
Doing so could be detrimental to the reliability of the grid. Parameters are
dependent on the location, application and situation specific to each Protection
System device.
102
Voter
Entity
Segment
Vote
Comment
The inclusion of Part 1.5 of Requirement R1 is a significant addition to the
standard, and by NERC Rules of Procedure requires the input and consideration of
the full Standard Drafting Team.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it
has been removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The
associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
Daniel
Prowse
Manitoba
Hydro
6
Negative
1. Implementation Plan (Timeline) for R1: In areas not requiring regulatory
approval, the 6 month time frame proposed for R1 is not achievable and is not
consistent with areas requiring regulatory approval. To be consistent, the
effective date for R1 in jurisdictions where no regulatory approval is required
should be the first day of the first calendar quarter 12 months after BOT
approval.
2. VSLs: The high VSL for R1 “Failed to include all maintenance activities relevant
for the identified monitoring attributes specified in Tables 1-1 through 1-5”
may be interpreted in different ways and should be further clarified.
3. Table 1-4: The requirements for batteries listed in Table 1-4 do not appear to
be consistent with the comments in the FAQ Section (V 1A Example 1). Please
see comments submitted during the formal comment period for further detail.
4. Table 1-4: The requirement for a 3 month check on electrolyte level seems
too frequent based on our experience. We would like to point out that
although IEEE std 450 (which seems to be the basis for table 1-4) does
recommend intervals it also states that users should evaluate these
recommendations against their own operating experience.
Response: Thank you for your comments.
1. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for R1, making it consistent
with the remainder of the Implementation Plan.
2. The SDT does not understand your concern; further details are needed.
3. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference
Document as appropriate. The SDT considered your comments during this activity.
4. The SDT believes that the 3-month interval specified in the Standard is appropriate.
Joseph
Northern
6
Negative
We disagree with the practice of performing calibration checks on non
O'Brien
Indiana Public
microprocessor relays every 6 years.
Service Co.
Response: Thank you for your comments. The SDT considers it important that calibration checks be performed on non
microprocessor relays no less frequently than every 6 years.
103
Voter
Entity
Segment
Vote
Comment
James D.
Hebson
PSEG Energy
6
Negative
The PSEG Companies do not agree with the Facilities as currently described in
Resources &
section 4.2.5.5. Please refer to detailed comments provided in the formal
Trade LLC
Comment Form.
Response: Thank you for your comments. Please see our response to your comments from the formal comment period.
Dennis
Sismaet
Seattle City
Light
6
Negative
The proposed Standard PRC-005-2 is an improvement over the previous draft in
that it provides more consistency in maintenance and testing duration internals.
Notwithstanding, two issues are of concern to Seattle City Light such that it is
compelled to vote no:
1) the establishment of bookends for standard verification and
2) the implementation timelines for entities with systems where electromechanical relays still compose a significant number of components in their
protection systems.
1. Bookends: Proposed Standard PRC-005-2 specifies long inspection and
maintenance intervals, up to 12 years, which correspondingly exacerbates the socalled “bookend” issue. To demonstrate that interval-based requirements have
been met, two dates are needed - bookends. Evidencing an initial date can be
problematic for cases where the initial date would occur prior to the effective date
of a standard. NERC has provided no guidance on this issue, and the Regions
approach it differently. Some, such as Texas Regional Entity, require initial dates
beginning on or after the effective date of a Standard. Compliance with intervals is
assessed only once two dates are available that occur on or after a standard took
effect. Other regions, such as Western Electricity Coordinating Council (WECC),
require that entities evidence an initial date prior to the effective date of a
standard. For WECC, compliance with intervals is assessed as soon as a standard
takes effect. Such variation makes application of standards involving bookends
uncertain, arbitrary, capricious, and in the case of WECC, possibly illegal. Proposed
Standard PRC-005-2 will be another such standard. Indeed this Standard will
involve by far the largest number of bookends of any NERC standard - many
thousands for a typical entity. Furthermore, the long inspection and maintenance
intervals introduced in the draft will require entities in WECC, for instance, to
evidence initial bookend dates prior to the date original PRC-005-1 took effect. For
the 12-year intervals for CTs and VTs in proposed Standard PRC-005-2, many
initial dates will occur prior to the 2005 Federal Power Act that authorized
Mandatory Reliability Standards and even reach back before the 2003 blackout
that catalyzed the effort to pass the Federal Power Act. As a result, many entities
104
Voter
Entity
Segment
Vote
Comment
in WECC maybe at risk of being found in violation of proposed Standard PRC-0052 immediately upon its implementation. Seattle City Light requests that NERC
address the bookends issue, either within proposed Standard PRC-005-2 or in a
separate, concurrent document.
2. Legacy Systems: Many entities still have legacy protection systems that rely
upon electro-mechanical relays. Effective testing approaches differ between
electro-mechanical and digital relay systems. Thus, although the proposed
standard rightly looks to the future of digital relays by specifying testing and
maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with legacy
systems. In example, auxilary relay and trip coil testing may be essential to prove
the correct operation of complex, multi-function digital protection systems.
However, for legacy systems with single-function electro-mechanical components,
the considerable documentation and operational testing needed to implement and
track such testing is not necessarily proportional to the relative risk posed by the
equipment to the bulk electric system. Performance testing of electro-mechanical
systems, particularly regarding control circuits, will require extensive disconnection
and reconnection of portions of the circuits. Such activities will likely cause far
more problems on restoration-to-service than they will locate and correct. As such,
to assist entities in their implementation efforts, we believe provision of
alternatives are necessary, such as additional implementation time through
phasing and/or through technical feasibility exceptions.
Response: Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008 “PRC-005 R2 Pre-June 18 Evidence”.
2. Please see Sections 8 and 15.3 of the Supplementary Reference Document for a discussion on this topic. FERC Order 693
directs that NERC establish requirements for the maintenance of the Protection System and control circuitry is a portion
thereof. Therefore, requirements for the maintenance of the control circuitry are necessary and the SDT has developed those
requirements in a fashion that affords entities with the opportunity to best meet those requirements.
David F.
Xcel Energy,
6
Negative
We feel that several improvements were made since the last draft. However, we
Lemmons
Inc.
feel that some gaps exist that should be addressed before moving this project
forward. We have detailed our issues in our formal comments.
Response: Thank you for your comments. Please see our responses to your formal comments.
Jim R
Stanton
SPS
Consulting
Group Inc.
8
Negative
1. The standard as written is wildly prescriptive and violates the concept of "what
and not how." The standard and its Tables seek to prescribe in detail
maintenance and testing processes which should be left up to the owners and
operators of the protection systems.
105
Voter
Entity
Segment
Vote
Comment
2. References to Tables 1-5 should be deleted from the standard itself and
moved to a reference section.
Response: Thank you for your comments.
1. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently
monitored for compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that
minimum activities also need to be prescribed. If an entities’ experience is that components require less-frequent maintenance, a
performance-based program in accordance with Requirement R3 and Attachment A is an option.
2. Tables 1-1 through 1-5 are considered by the SDT to be an integral part of the requirements of the standard and thus belong
within the Standard.
Louise
Western
10
Affirmative Our affirmative vote reflects our belief that the proposed PRC-005-2 is an overall
McCarren
Electricity
improvement to the four standards that it would replace. We also believe that it is
appropriate to address maintenance and testing of all protection systems in one
Coordinating
standard rather than in four individual standards.
Council
Response: Thank you for your comments and support.
END OF REPORT
106
Consideration of Comments on Non-binding Poll of VRFs and VSLs
associated with PRC-005-2 – Protection System Maintenance
(Project 2007-17)
The Project 2007-17 Drafting Team thanks all commenters who submitted comments on the
non-binding poll of VRFs and VSLs associated with the proposed revisions to PRC-005-2.
The standard and associated VRFs and VSLs were posted for a 30-day public comment
period from November 17, 2010 through December 17, 2010, with a 10-day ballot
beginning on December 10, 2010 through December 21, 2010. The stakeholders were
asked to provide feedback on the VRFs and VSLs. There were 28 sets of comments,
including comments from more than 46 different people from approximately 26 companies
representing 6 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_200717.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition,
there is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
2
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
1
Ameren Services
Kirit S. Shah
The Lower VSL for all Requirements should begin above 1% of the components. For example for
R4: “Entity has failed to complete scheduled program on 1% to 5% of total Protection System
components.” PRC-005-2 unrealistically mandates perfection without providing technical
justification. A basic premise of engineering is to allow for reasonable tolerances, even Six Sigma
allows for defects. Requiring perfection may well harm reliability in that valuable resources will be
distracted from other duties.
Thank you for your comments. The NERC criteria for VSLs do not currently permit them to
allow some level of non-performance without being in violation.
1,3,6
American Electric Power, AEP Marketing
Paul B. Johnson, Raj Rana, Edward P. Cox
1. The VSL table should be revised to remove the reference to the Standard Requirement 1.5
in the R1 “High” VSL.
2. All four levels of the VSL for R2 make reference to a “condition-based PSMP.” However,
nowhere in the standard is the term “condition-based” used in reference to defining ones
PSMP. The VSL for R2 should be revised to remove reference to a condition-based PSMP;
alternatively the Standard could be revised to include the term “condition-based” within the
Standard Requirements and Table 1.
3. In multiple instances, Table 1 uses the phrase “No periodic maintenance specified” for the
Maximum Maintenance Interval. Is this intended to imply that a component with the
designated attributes is not required to have any periodic maintenance? If so, the wording
should more clearly state “No periodic maintenance required” or perhaps “Maintain per
manufacturers recommendations.” Failure to clearly state the maintenance requirement for
these components leaves room for interpretation on whether a Registered Entity has
maintenance and testing program for devices where the Standard has not specified a
periodic maintenance interval and the manufacturer states that no maintenance is required.
4. Three different types of maintenance programs (time-based, performance-based and
condition-based) are referenced in the standard or VSLs, yet the time-based and conditionbased programs are neither defined nor described. Certain terms defined within the
definition section (such as Countable Event or Segment) only make sense knowing what
3
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
those three programs entail. These programs should be described within the standard itself
and not assume knowledge of material in the Supplementary Reference or FAQ.
Response
Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5
and the associated changes are addressed within the PSMP definition, and that
Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted
within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
2. The SDT concluded that Requirement R2 is redundant with Requirement R1, Part 1.4,
and has deleted Requirement R2 (together with the associated Measure and VSL).
3. If the indicated monitoring attributes are present, no “hands-on” periodic
maintenance is required, as the monitoring of the component is providing a
continuing indication of its functionality.
4. The term, “condition-based” has been removed from the draft standard. The other
terms are used, but are clear in the context in which they are used.
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
1
Beaches Energy Services
Joseph S. Stonecipher
The VRF of R1 should be Low since the attached tables are essentially the PSMP.
Thank you for your comments. The SDT disagrees; the Tables establish the intervals and
activities, and Requirement R1 addresses the establishment of an entity’s individual PSMP.
3
City of Green Cove Springs
Gregg R Griffin
4
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
1. Small entities with only one or two BES substations may not have enough components to
take advantage of the expanded maintenance intervals afforded by a performance-based
maintenance program. Aggregating these components across different entities doesn’t seem
too logical considering the variations at the sub-component level (wire gauge, installation
conditions, etc.)
2. Trip circuits are interconnected to perform various functions. Testing a trip path may
involve disabling other features (i.e. breaker failure or reclosing) not directly a part of the
test being performed. Temporary modifications made for testing introduce a chance to
unknowingly leave functions disabled, contacts shorted, jumpers lifted, etc. after testing has
been completed. Trip coils and cable runs from panels to breaker can be made to meet the
requirements for monitored components. The only portions of the circuitry where this may
not be the case is in the inter and intra-panel wiring. Because such portions of the circuitry
have no moving parts and are located inside a control house, the exposure is negligible and
should not be covered by the requirements. Entities will be at increased compliance risk as
they struggle to properly document the testing of all parallel tripping paths.
3. Table 1-4 requires a comparison of measured battery internal ohmic value to battery
baseline. Since battery manufacturers do not provide this value, it is unclear what the
“baseline” values ought to be if an entity recently began performing this test (assuming it’s
several years after the commissioning of the battery.) Would it be acceptable for an entity
to establish baseline values based on statistical analysis of multiple test results specific to a
given battery manufacturer and design?
4. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC008/011 as being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other
protection system components, e.g., communications (probably not applicable), voltage and
current sensing devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution system
protection, so, these activities would not be covered by other BES protection system
maintenance and testing. I'm sure we are testing batteries and the like, but, we are
probably not testing battery chargers and control circuitry, and, in many cases distribution
circuits are such that it is very difficult, if not impossible, to test control circuitry to the trip
coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one or two backup systems, there are thousands and thousands of UFLS relays and if one fails to operate, it
will not be noticeable to the event. It does make sense to test the relays themselves in part
to ensure that the regio0nsl UFLS program is being met, but, to test the other protection
system components is not worthwhile. Note that DC Supplies and most of the control
5
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
circuitry of distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits, reducing the
value of testing to just about null. However, this version is better than prior versions
because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry.
5. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of
"transmission Protection System" and should state: "Protection Systems applied on, or
designed to provide protection for a BES Facility and that trips a BES Facility"
6. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the
definition of Protection System (recently approved) does not clearly exclude "non-electrical"
protection, the Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of transformers, etc.
should not be included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical the VRF of R1 should be Low since
the attached tables are essentially the PSMP.
Thank you for your comments.
1. Entities are not required to use performance-based maintenance programs.
Requirement R3 and Attachment A are provided for the use of entities that can (and
desire to) avail themselves of this approach.
2. The requirement relative to control circuitry does not explicitly require trip or functional
testing of the entire path; it requires that entities verify all paths without specifying the
method of doing so. Please see Section 15.5 of the Supplementary Reference Document
for a detailed discussion.
3. Typical baseline values for various types of lead-acid batteries can be obtained from the
test equipment manufacturer, the battery vendor, and perhaps other sources for
batteries that are already in service. For new batteries, the initial battery baseline ohmic
values should be measured upon installation and used for trending.
4. For UFLS and UVLS, the maintenance activities related to station dc supply and control
circuitry are somewhat constrained relative to similar activities for Protection Systems in
general. Regardless, without proper functioning of these component types, UFLS and
UVLS will not respond as expected, and will therefore degrade BES system reliability,
particularly during the stressed system conditions for which UFLS and UVLS are
installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and UVLS
from maintenance activities relate to the interrupting device trip coil.
5. This interpretation is not yet approved. When this interpretation is approved, the SDT will
6
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
incorporate it within PRC-005-2. However, the SDT has made changes to Applicability
4.2.1.
6. The recently-balloted revision of the definition of Protection System, which has been
approved by the NERC Board of Trustees and will soon be filed with FERC for approval,
clearly includes only protective relays that respond to electrical quantities. As for auxiliary
relays, the interpretation to which you refer states that they are not explicitly included, but
are included to the degree that an entity’s Protection System control circuitry addresses
them (which has been identified as a reliability gap), and are being added to PRC-005-2 to
resolve the gap.
Segment
Organization
Member
Comment
Response
1, 5, 6
Consolidated Edison Co. of New York
Christopher L de Graffenried, Wilket (Jack) Ng, Nickesha P Carrol
VSL/VRF Ballot Comments: The Modified VSL’s and VRF’s –
1. Because all the requirements deal with protective system maintenance and testing,
violations could directly cause or contribute to bulk electric system instability, etc., the VRFs
should all be “High”.
2. The Time Horizons should all be “Operations Planning” because of the immediacy of a
failure to meet the requirements.
3. For the R1 Lower VSL, include a second part to read: Failed to identify calibration tolerances
or other equivalent parameters for one Protection System component type that establish
acceptable parameters for the conclusion of maintenance activities.
4. For the R1 Moderate VSL, suggest similar wording as for the Lower VSL but specifying two
Protection System component types.
5. For the R1 High VSL, suggest changing the wording of the 3rd part to be similar to the
Lower VSL to match the requirement and to cater for more than two Protection System
component types.
6. For the R3 Severe VSL, in part 3, replace “less” with fewer.
Thank you for your comments.
1. Consideration of the VRFs, in association with the VRF Guidelines, yields the VRFs as
established within the draft Standard.
2. The SDT has reviewed the time horizons, and believes that Requirement R1 is
properly assigned a Long-Term Planning time horizon, as the activities to develop a
program and to determine the monitoring attributes of components are performed
within the related time period. The SDT concluded that Requirement R2 is redundant
to Requirement R1 and has deleted Requirement R2 (together with the Measure and
7
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
VSL).
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5
and the associated changes are addressed within the PSMP definition, and that
Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The
associated VSL has also been revised.
4. Requirement R1 ‘Moderate’ appears to be similar to Requirement R1 ‘Lower’ as you
suggest.
5. The SDT believes that, if more than two Protection System component types are not
addressed, the ‘Severe’ VSL is appropriate.
6. The SDT believes that your suggestion is similar to the existing text, and declines to
modify the standard.
Segment
Organization
Member
Comment
Response
Segment
Organization
Member
Comment
5
Constellation Power Source Generation, Inc.
Amir Y Hammad
The VRFs and VSLs still do not take into account smaller generation facilities that do not have as
many protection system components as other facilities. They are penalized much more heavily.
Thank you for your comments. The percentage levels within Requirement R4 are consistent
with many other NERC Standards, and are also consistent with the guidance within the NERC
VSL Guidelines.
4
Consumers Energy
David Frank Ronk
1. Table 1-3 states, “are received by the protective relays”. Does this require that the inputs to each
individual relay must be checked, or is it sufficient to verify that acceptable signals are received at
the relay panel, etc?
2. Relative to Table 1-5, the activities will likely require that system components be removed from
service to complete those activities. If the changes to the BES definition (per the FERC Order)
causes system elements such as 138 kV connected distribution transformers to be considered as
BES, these components can not be removed from service for maintenance without outaging
customers. The standard must exempt these components from the activities of Table 1-5 if the
activity would result in deenergizing customers.
3. For the component types addressed in Tables 1-3 and 1-5, the requirements may cause entities
to identify components very differently than they are currently doing, and doing so may take several
years to complete. The Implementation Plan for R1 and R4 is too aggressive in that it may not
8
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
permit entities to complete the identification of discrete components and the associated
maintenance and implement their program as currently proposed. We propose that the
Implementation Plan specifically address the components in Table 1-3 and 1-5 with a minimum of 3
calendar years for R1 and 12 calendar years after that for R4.
4. As for the interval in Table 1-4 regarding the battery terminal connection resistance, we believe
that an 18-month interval is excessively frequent for this activity, and suggest that it be moved to
the 6-calendar-year interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections every 4-years, rather
than measuring the terminal connection resistance to determine if the connections are sound.
Disregarding the interval, would this activity satisfy the “verify the battery terminal connection
resistance” activity?
Response
Thank you for your comments.
1. The SDT intends that the voltage and current signals properly reach each individual
relay, but there may be several methods of accomplishing this activity.
2. This concern seems more properly to be one to be addressed during the activities to
develop the new BES definition, rather than within PRC-005-2
3. The Implementation Plan for Requirement R1 has been modified from 6 months to 12
months. The Standard has also been modified (Requirement R1, Part 1.1) to not
specifically require identification of all individual Protection System components. The
Implementation Plan for Requirement R4 has been revised to add one year to all
established dates.
4. IEEE 450, 1188, 1106 all recommend this activity at a 12-month interval. Please see
Section 15.4.1 of the Supplementary Reference Document for a discussion of this
activity.
5. Re-torqueing the battery terminals would not meet this requirement.
Segment
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Member
Comment
Response
Segment
5
Consumers Energy
James B Lewis
The issues raised in our comments to the proposed Standard need to be addressed.
Thank you for your comments. Please see our response to your comments which were
submitted during the formal comment period.
1, 3, 5, 6
9
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
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Comment
Dominion
John K Loftis, Michael F Gildea, Mike Garton, Louis S Slade
VSL R3. How do you measure a percentage of countable events over a period of time? How are you
to determine what the total population to be considered? An entity should not be penalized if they
are following their program, correcting issues, and documenting all actions, even if there is a high
failure rate in an instance.
Thank you for your comments. Attachment A, to which Requirement R3 refers, specifies that
countable events are assessed on the basis of “for the greater of either the last 30
components maintained or all components maintained in the previous year.”
1, 3, 4, 5, 6
FirstEnergy Energy Delivery, FirstEnergy Solutions, Ohio Edison Company
Robert Martinko, Kevin Querry, Kenneth Dresner, Mark S Travaglianti
Please see FirstEnergy's comments submitted separately through the comment period posting.
Thank you for your comments. Please see our response to your comments which were
submitted during the formal comment period.
4, 5
Florida Municipal Power Agency
Frank Gaffney, David Schumann
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC008/011 as being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other
protection system components, e.g., communications (probably not applicable), voltage and
current sensing devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution system
protection, so, these activities would not be covered by other BES protection system
maintenance and testing. I'm sure we are testing batteries and the like, but, we are
probably not testing battery chargers and control circuity, and, in many cases distribution
circuits are such that it is very difficult, if not impossible, to test control circuitry to the trip
coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one or two backup systems, there are thousands and thousands of UFLS relays and if one fails to operate, it
will not be noticeable to the event. It does make sense to test the relays themselves in part
to ensure that the regio0nsl UFLS program is being met, but, to test the other protection
system components is not worthwhile. Note that DC Supplies and most of the control
10
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
circuitry of distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits, reducing the
value of testing to just about null. However, this version is better than prior versions
because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of
"transmission Protection System" and should state: "Protection Systems applied on, or
designed to provide protection for a BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the
definition of Protection System (recently approved) does not clearly exclude "non-electrical"
protection,the Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of transformers, etc.
should not be included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical the VRF of R1 should be Low since
the attached tables are essentially the PSMP.
Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and
control circuitry are somewhat constrained relative to similar activities for
Protection Systems in general. Regardless, without proper functioning of these
component types, UFLS and UVLS will not respond as expected, and will therefore
degrade BES system reliability, particularly during the stressed system conditions
for which UFLS and UVLS are installed. Relative to control circuitry, Table 1-5
specifically excludes UFLS and UVLS from maintenance activities relate to the
interrupting device trip coil.
2. This interpretation is not yet approved. When this interpretation is approved, the
SDT will incorporate it within PRC-005-2. However, the SDT has made changes to
Applicability 4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been
approved by the NERC Board of Trustees and will soon be filed with FERC for
approval, clearly includes only protective relays that respond to electrical quantities.
As for auxiliary relays, the interpretation to which you refer states that they are not
explicitly included, but are included to the degree that an entity’s Protection System
control circuitry addresses them(which has been identified as a reliability gap), and
are being added to PRC-005-2 to resolve the gap.
Segment
6
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Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
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Florida Municipal Power Pool
Thomas E Washburn
the VRF of R1 should be Low since the attached tables are essentially the PSMP.
Thank you for your comments. The SDT disagrees; the Tables establish the intervals and
activities, and Requirement R1 addresses the establishment of an entity’s individual PSMP.
4
Fort Pierce Utilities Authority
Thomas W. Richards
The VRF of R1 should be Low since the attached tables are essentially the PSMP.
Thank you for your comments. The SDT disagrees; the Tables establish the intervals and
activities, and Requirement R1 addresses the establishment of an entity’s individual PSMP.
1, 3
Hydro One Networks, Inc.
Ajay Garg, Michael D. Penstone
Hydro One is casting a negative vote with the following comments:
1. R1 Lower - Include a second part as follows: “Failed to identify calibration tolerances or other
equivalent parameters for one Protection System component type that establish acceptable
parameters for the conclusion of maintenance activities. “
2. R1 Moderate - Similar wording as for the Lower VSL but catering for two Protection System
component types. R1 High - Change the wording of the 3rd part to be similar to the Lower VSL to
match the requirement and to cater for more than two Protection System component types.
Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5
and the associated changes are addressed within the PSMP definition, and that
Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted
within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
2. Requirement R1 ‘Moderate’ appears to be similar to Requirement R1 ‘Lower’ as you
suggest. The SDT believes that, if more than two Protection System component types
are not addressed, the ‘Severe’ VSL is appropriate.
Segment
Organization
5
Indeck Energy Services, Inc.
12
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Member
Comment
Response
Segment
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Response
Rex A Roehl
The Violation Risk Factors should not be the same for all registered entities because the risk in a
violation by a 20 MW wind farm connected at 115 kV is de minimis compared to that same violation
at a 2,000 MW transmission substation or generator. The basic structure of this revision to PRC-005
is totally defective. Combining 4 standards that each have something to do with relays into one
omnibus standard was wrongheaded. The Violation Severity Levels need to match the violation and
four arbitrary categories cannot do so for the myriad of components, systems and varying numbers
of them for one registered entity that are covered by this draft standard.
Thank you for your comments. The VRFs are not dependent on size, and must be assigned
on a requirement-by-requirement basis.
2
Independent Electricity System Operator
Kim Warren
1. R1 Lower - We suggest including a second part as follows: “Failed to identify calibration
tolerances or other equivalent parameters for one Protection System component type that
establish acceptable parameters for the conclusion of maintenance activities. “
2. R1 Moderate - We suggest similar to the Lower VSL but catering for two Protection System
component types. R1 High - We suggest changing the wording of the 3rd part to match the
requirement and to cater for more than two Protection System component types.
3. Editorial Comment to Severe VSL for R3: In part 3, replace “less” with “fewer”.
Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5
and the associated changes are addressed within the PSMP definition, and that
Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Requirement R4 has also been re-drafted to address various related concerns noted
within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
2. Requirement R1 ‘Moderate’ appears to be similar to Requirement R1 ‘Lower’ as you
suggest. The SDT believes that, if more than two Protection System component types
are not addressed, the ‘Severe’ VSL is appropriate.
3. The SDT has elected not to change the VSL for Requirement R3 as suggested.
Segment
Organization
Member
1
Lake Worth Utilities
Walt Gill
13
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC008/011 as being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other
protection system components, e.g., communications (probably not applicable), voltage and
current sensing devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution system
protection, so, these activities would not be covered by other BES protection system
maintenance and testing. I'm sure we are testing batteries and the like, but, we are
probably not testing battery chargers and control circuity, and, in many cases distribution
circuits are such that it is very difficult, if not impossible, to test control circuitry to the trip
coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one or two backup systems, there are thousands and thousands of UFLS relays and if one fails to operate, it
will not be noticeable to the event. It does make sense to test the relays themselves in part
to ensure that the regio0nsl UFLS program is being met, but, to test the other protection
system components is not worthwhile. Note that DC Supplies and most of the control
circuitry of distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits, reducing the
value of testing to just about null. However, this version is better than prior versions
because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of
"transmission Protection System" and should state: "Protection Systems applied on, or
designed to provide protection for a BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the
definition of Protection System (recently approved) does not clearly exclude "non-electrical"
protection,the Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of transformers, etc.
should not be included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical
4. the VRF of R1 should be Low since the attached tables are essentially the PSMP.
5. Table 1-4 requires a comparison of measured battery internal ohmic value to battery
baseline. Since battery manufacturers do not provide this value, it is unclear what the
“baseline” values ought to be if an entity recently began performing this test (assuming it’s
several years after the commissioning of the battery.) Would it be acceptable for an entity
to establish baseline values based on statistical analysis of multiple test results specific to a
14
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
given battery manufacturer and design?
6. Small entities with only one or two BES substations may not have enough components to
take advantage of the expanded maintenance intervals afforded by a performance-based
maintenance program. Aggregating these components across different entities doesn’t seem
too logical considering the variations at the sub-component level (wire gauge, installation
conditions, etc.)
7. Trip circuits are interconnected to perform various functions. Testing a trip path may involve
disabling other features (i.e. breaker failure or reclosing) not directly a part of the test being
performed. Temporary modifications made for testing introduce a chance to unknowingly
leave functions disabled, contacts shorted, jumpers lifted, etc. after testing has been
completed. Trip coils and cable runs from panels to breaker can be made to meet the
requirements for monitored components. The only portions of the circuitry where this may
not be the case is in the inter and intra-panel wiring. Because such portions of the circuitry
have no moving parts and are located inside a control house, the exposure is negligible and
should not be covered by the requirements. Entities will be at increased compliance risk as
they struggle to properly document the testing of all parallel tripping paths.
Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control
circuitry are somewhat constrained relative to similar activities for Protection Systems in
general. Regardless, without proper functioning of these component types, UFLS and
UVLS will not respond as expected, and will therefore degrade BES system reliability,
particularly during the stressed system conditions for which UFLS and UVLS are
installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and UVLS
from maintenance activities relate to the interrupting device trip coil.
2. This interpretation is not yet approved. When this interpretation is approved, the SDT will
incorporate it within PRC-005-2. However, the SDT has made changes to Applicability
4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been
approved by the NERC Board of Trustees and will soon be filed with FERC for approval,
clearly includes only protective relays that respond to electrical quantities. As for auxiliary
relays, the interpretation to which you refer states that they are not explicitly included, but
are included to the degree that an entity’s Protection System control circuitry addresses
them(which has been identified as a reliability gap), and are being added to PRC-005-2 to
resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities and Requirement R1
addresses the establishment of an entity’s individual PSMP.
15
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
5. Typical baseline values for various types of lead-acid batteries can be obtained from the
test equipment manufacturer, the battery vendor, and perhaps other sources for
batteries that are already in service. For new batteries, the initial battery baseline ohmic
values should be measured upon installation and used for trending.
6. Entities are not required to use performance-based maintenance programs. Requirement
R3 and Attachment A are provided for the use of entities that can (and desire to) avail
themselves of this approach.
7. The requirement relative to control circuitry does not explicitly require trip or functional
testing of the entire path; it requires that entities verify all paths without specifying the
method of doing so. Please see Section 15.5 of the Supplementary Reference Document
for a detailed discussion.
Segment
Organization
Member
Comment
1
Lakeland Electric
Larry E Watt
The major reasons are that:
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC008/011 as being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other
protection system components, e.g., communications (probably not applicable), voltage and
current sensing devices (e.g., instrument transformers), Station DC supply, control circuitry.
What's key about this is that these components are all part of distribution system
protection, so, these activities would not be covered by other BES protection system
maintenance and testing. I'm sure we are testing batteries and the like, but, we are
probably not testing battery chargers and control circuity, and, in many cases distribution
circuits are such that it is very difficult, if not impossible, to test control circuitry to the trip
coil of the breaker without causing an outage of the customers on that distribution circuit.
There is no real reliability need for this either. Unlike Transmission and Generation
Protection Systems which are needed to clear a fault and may only have one or two backup systems, there are thousands and thousands of UFLS relays and if one fails to operate, it
will not be noticeable to the event. It does make sense to test the relays themselves in part
to ensure that the regio0nsl UFLS program is being met, but, to test the other protection
system components is not worthwhile. Note that DC Supplies and most of the control
circuitry of distribution lines are "tested" frequently by distribution circuits clearing faults
such as animals, vegetation blow-ins, lightning, etc., on distribution circuits, reducing the
value of testing to just about null. However, this version is better than prior versions
because it essentially requires the entity to determine it's own period of maintenance and
testing for UFLS/UVLS for DC Supply and control circuitry.
16
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of
"transmission Protection System" and should state: "Protection Systems applied on, or
designed to provide protection for a BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes
non-electrical protection (e.g., sudden pressure relays) and auxiliary relays. Because the
definition of Protection System (recently approved) does not clearly exclude "non-electrical"
protection,the Applicability section should. For instance,, a vibration monitor, steam
pressure, etc. protection of generators, sudden pressure protection of transformers, etc.
should not be included in the standard. An alternative is to change the definition of
Protection System to make sure it only includes electrical
4. the VRF of R1 should be Low since the attached tables are essentially the PSMP.
Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control
circuitry are somewhat constrained relative to similar activities for Protection Systems in
general. Regardless, without proper functioning of these component types, UFLS and
UVLS will not respond as expected, and will therefore degrade BES system reliability,
particularly during the stressed system conditions for which UFLS and UVLS are
installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and UVLS from
maintenance activities relate to the interrupting device trip coil.
2. This interpretation is not yet approved. When this interpretation is approved, the SDT will
incorporate it within PRC-005-2. However, the SDT has made changes to Applicability
4.2.1.
3. The recently-balloted revision of the definition of Protection System, which has been
approved by the NERC Board of Trustees and will soon be filed with FERC for approval,
clearly includes only protective relays that respond to electrical quantities. As for auxiliary
relays, the interpretation to which you refer states that they are not explicitly included, but
are included to the degree that an entity’s Protection System control circuitry addresses
them(which has been identified as a reliability gap), and are being added to PRC-005-2 to
resolve the gap.
4. The SDT disagrees; the Tables establish the intervals and activities and Requirement R1
addresses the establishment of an entity’s individual PSMP.
Segment
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6
Lakeland Electric
Paul Shipps
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Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
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Response
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Small entities with only one or two BES substations may not have enough components to take
advantage of the expanded maintenance intervals afforded by a performance-based maintenance
program. Aggregating these components across different entities doesn’t seem too logical
considering the variations at the sub-component level (wire gauge, installation conditions, etc.)
Thank you for your comments. Entities are not required to use performance-based
maintenance programs. Requirement R3 and Attachment A are provided for the use of
entities that can (and desire to) avail themselves of this approach.
5,6
Luminant Energy, Luminant Generation Company LLC
Brad Jones, Mike Laney
Luminant commends the PRC-005-2 Standard Drafting Team for its quality efforts in producing this
version of the Standard however; Luminant must cast a negative ballot vote for the present version
of the VRFs and VSLs for this Standard. The negative vote against is solely based on the addition of
the VSL associated with Requirement R1 Part 1.5.
Thank you for your comments. The SDT has determined that the fundamental concerns of
Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been
removed. Requirement R4 has also been re-drafted to address various related concerns
noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
1,3,6
Manitoba Hydro
Joe D Petaski, Greg C. Parent, Daniel Prowse
-The high VSL for R1 “Failed to include all maintenance activities relevant for the identified
monitoring attributes specified in Tables 1-1 through 1-5” may be interpreted in different ways and
should be further clarified.
Thank you for your comments. The SDT modified the VSL for clarity.
2
Midwest ISO, Inc.
Jason L Marshall
18
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
Response
Segment
Organization
Member
Comment
1. We disagree with the VRFs for R3, R4, and R5. R3, R4, and R5 are administrative
requirements and duplicate to requirements in FAC-008 and FAC-009 that already require
communication of facility ratings including those limited by relays. Thus, it should be Lower.
2. We disagree with the High VRF for Requirement R6 because the criteria in attachment will
identify circuits that are not critical. If the criteria is modified per our comments on the
standard and in the ballot, then we would agree with a High VRF.
3. Requirement R7 should be deleted as it represents double jeopardy. Thus, we do not agree
with any VRF for it.
Thank you for your comments.
1. It appears that this comment was intended to be offered on some other project, and
does not appear relevant to PRC-005-2.
2. It appears that this comment was intended to be offered on some other project, and
does not appear relevant to PRC-005-2.
3. It appears that this comment was intended to be offered on some other project, and
does not appear relevant to PRC-005-2.
1
Nebraska Public Power District
Richard L. Koch
VRF’s:
The definition of a Medium Risk Requirement included on page 8 of the SAR states: "A requirement
that, if violated, could directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system."
1. The PSMP does not "directly" affect the electrical state or the capability of the bulk electric
system. A failure of a Protection System component is required to "directly" affect the BES.
Therefore, the PSMP has only an "indirect" affect on the electrical state or the capability of
the BES. Requirements R1 through R3 and their subparts are administrative in nature in
that they are comprised entirely of documentation. Therefore, I recommend changing the
Violation Risk Factor of Requirements R1, R2, and R3 to Lower to be consistent with the
Violation Risk Factors defined in the SAR.
VSL’s:
2. R2: Tables 1-1 through 1-5 refers to time-based maintenance programs. I recommend
changing "condition-based" to "time-based" in all four severity levels.
3. SAR Attachment B - Reliability Standard Review Guidelines states that violation severity
levels should be based on the following equivalent scores: Lower: More than 95% but less
than 100% compliant Moderate: More than 85% but less than or equal to 95% compliant
High: More than 70% but less than equal to 85% compliant Severe: 70% or less compliant
I recommend revising the percentages of the violation severity levels to be consistent with
19
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Response
the SAR.
4. R3: The performance-based maintenance program identified in PRC-005 Attachment A
provides the requirements to establish the technical justification for the initial use of a
performance-based PSMP and the requirements to maintain the technical justification for
the ongoing use of a performance-based PSMP. However, it appears the VSLs for
Requirement R3 only addresses the ongoing use of the technical justification. I recommend
revising the VSLs for R3 to include the initial use of the technical justification.
a. Item 2) of R3 Severe VSL is a duplicate of Item 2) of R3 Lower VSL. This item is
administrative in nature therefore I recommend deleting Item 2) from R3 Severe VSL.
b. The first and third bullets of item 4) of R3 Severe VSL are administrative in nature and
should be moved to the Lower VSL
c. R4: SAR Attachment B - Reliability Standard Review Guidelines states that violation
severity levels should be based on the following equivalent scores: Lower: More than
95% but less than 100% compliant Moderate: More than 85% but less than or equal to
95% compliant High: More than 70% but less than equal to 85% compliant Severe:
70% or less compliant I recommend revising the percentages of the violation severity
levels to be consistent with the SAR.
Thank you for your comments.
1. Requirements R1, R2, and R3 are not administrative; they are foundational. Without
the fundamental development of a PSMP, an entity is unlikely to actually implement a
PSMP that satisfies the reliability needs of the BES.
2. The SDT concluded that Requirement R2 is redundant with Requirement R1, Part 1.4,
and has deleted Requirement R2 (together with the associated Measure and VSL).
3. The guidelines within the SAR have been superseded by subsequent revisions to the
VSL Guidelines. The VSLs in the draft standard adhere to the latest VSL Guidelines
and to the June 19, 2008 FERC order on VSLs in Docket No RR08-04-000.
4. Part a – The VSL for Requirement R3 has been modified in consideration of your
comments.
Part b – These requirements are not administrative; they are foundational. Without
compliance with these requirements, an entity does not have an effective
performance-based PSMP, and may be detrimentally affecting reliability.
Part c – The latest VSL Guidelines also provide examples of VSLs similar to those in the
draft standard.
Segment
1
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Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
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Comment
Oncor Electric Delivery
Michael T. Quinn
Oncor cast a negative ballot vote for the present version of the VRFs and VSLs for this Standard.
The negative vote against is solely based on the addition of the VSL associated with Requirement
R1 Part 1.5.
Thank you for your comments. The SDT has determined that the fundamental concerns of
Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been
removed. Requirement R4 has also been re-drafted to address various related concerns
noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
6
Seattle City Light
Dennis Sismaet
The proposed Standard PRC-005-2 is an improvement over the previous draft in that it provides
more consistency in maintenance and testing duration internals. Notwithstanding, two issues are of
concern to Seattle City Light such that it is compelled to vote no:
1) the establishment of bookends for standard verification and
2) the implementation timelines for entities with systems where electro-mechanical relays still
compose a significant number of components in their protection systems.
1. Bookends: Proposed Standard PRC-005-2 specifies long inspection and maintenance intervals, up
to 12 years, which correspondingly exacerbates the so-called “bookend” issue. To demonstrate that
interval-based requirements have been met, two dates are needed - bookends. Evidencing an initial
date can be problematic for cases where the initial date would occur prior to the effective date of a
standard. NERC has provided no guidance on this issue, and the Regions approach it differently.
Some, such as Texas Regional Entity, require initial dates beginning on or after the effective date of
a Standard. Compliance with intervals is assessed only once two dates are available that occur on or
after a standard took effect. Other regions, such as Western Electricity Coordinating Council
(WECC), require that entities evidence an initial date prior to the effective date of a standard. For
WECC, compliance with intervals is assessed as soon as a standard takes effect. Such variation
makes application of standards involving bookends uncertain, arbitrary, capricious, and in the case
of WECC, possibly illegal. Proposed Standard PRC-005-2 will be another such standard. Indeed this
Standard will involve by far the largest number of bookends of any NERC standard - many
thousands for a typical entity. Furthermore, the long inspection and maintenance intervals
21
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
introduced in the draft will require entities in WECC, for instance, to evidence initial bookend dates
prior to the date original PRC-005-1 took effect. For the 12-year intervals for CTs and VTs in
proposed Standard PRC-005-2, many initial dates will occur prior to the 2005 Federal Power Act that
authorized Mandatory Reliability Standards and even reach back before the 2003 blackout that
catalyzed the effort to pass the Federal Power Act. As a result, many entities in WECC maybe at risk
of being found in violation of proposed Standard PRC-005-2 immediately upon its implementation.
Seattle City Light requests that NERC address the bookends issue, either within proposed Standard
PRC-005-2 or in a separate, concurrent document.
Response
Segment
Organization
Member
2. Legacy Systems: Many entities still have legacy protection systems that rely upon electromechanical relays. Effective testing approaches differ between electro-mechanical and digital relay
systems. Thus, although the proposed standard rightly looks to the future of digital relays by
specifying testing and maintenance focused on protection systems as a whole, the proposed
implementation timelines create a level of hardship for those utilities with legacy systems. In
example, auxiliary relay and trip coil testing may be essential to prove the correct operation of
complex, multi-function digital protection systems. However, for legacy systems with single-function
electro-mechanical components, the considerable documentation and operational testing needed to
implement and track such testing is not necessarily proportional to the relative risk posed by the
equipment to the bulk electric system. Performance testing of electro-mechanical systems,
particularly regarding control circuits, will require extensive disconnection and reconnection of
portions of the circuits. Such activities will likely cause far more problems on restoration-to-service
than they will locate and correct. As such, to assist entities in their implementation efforts, we
believe provision of alternatives are necessary, such as additional implementation time through
phasing and/or through technical feasibility exceptions.
Thank you for your comments.
1. This issue has been addressed by NERC in Compliance Application Notice CAN-008
“PRC-005 R2 Pre-June 18 Evidence”.
2. Please see Sections 8 and 15.3 of the Supplementary Reference Document for a
discussion on this topic. FERC Order 693 directs that NERC establish requirements for
the maintenance of the Protection System and control circuitry is a portion thereof.
Therefore, requirements for the maintenance of the control circuitry are necessary and
the SDT has developed those requirements in a fashion that affords entities with the
opportunity to best meet those requirements.
1,3, 3, 3
Southern Company Services, Inc., Alabama Power, Georgia Power, Mississippi Power
Horace Stephen Williamson, Richard J. Mandes, Anthony L Wilson, Don Horsley
22
Consideration of Comments on Non-Binding Poll of VRFs and VSLs for PRC-005-2 — Project 2007-17
Comment
Response
Segment
Organization
Member
Comment
Response
We disagree with the inclusion of the VSLs, VRFs, and time Horizons associated with the new
Requirements 1.5 and 4.2
Thank you for your comments. The SDT has determined that the fundamental concerns of
Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been
removed. Requirement R4 has also been re-drafted to address various related concerns
noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
5
U.S. Bureau of Reclamation
Martin Bauer P.E.
The VSL levels are not consistent with the true impact on reliability. Severe levels are assigned for
failing to document rather than failing to maintain components. Documentation requirements that
are not met should not be assigned a Severe level. The concept of penalizing an entity for failed
components without regard to why they failed is unreasonable. The severely levels should be based
on avoidable failures or failures that could have been detected if the entity had performed
maintenance.
Thank you for your comments.
VSLs depict the level to which an entity has failed to comply with the standard; VRFs reflect
the risk to the BES. Escalations within the VSLs specifically address more egregious
(severe) violations of the standard in accordance with the NERC VSL Guidelines.
23
Consideration of Comments on Protection System Maintenance [Project
2007-17]
The Protection System Maintenance Drafting Team thanks all commenters who submitted
comments on the 3rd draft of the standard for Protection System Maintenance and Testing.
These standards were posted for a 30-day public comment period from November 17, 2010
through December 17, 2010. The stakeholders were asked to provide feedback on the
standards through a special Electronic Comment Form. There were 44 sets of comments,
including comments from more than 81 different people from approximately 82 companies
representing 9 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Extensive changes were made to Requirements R1 and R3 of the Standard, and
also to the Tables referenced within the Requirements. Of particular note,
Requirement R1, Part 1.5 (which required entities to define their acceptance
criteria for maintenance of components), and the associated discussion within
Requirement R4, Part 4.2 were removed. Requirement R2 was removed because it
was duplicative of Requirement R1, Part 1.4. Also, Table 1-4, addressing
maintenance of Station DC Supply, was split into six separate sub-tables
addressing the various specific technologies within this component.
Some commenters continued to object to various requirements within the
standard. Where the standard was not revised in response to these comments,
the SDT explained their rationale within the consideration-of-comments.
Based on the level of consensus on this posting, the SDT will post the Standard
and associated documents for an additional 30-day comment period with
concurrent ballot in the final 10-days of that comment period.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition,
there is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Index to Questions, Comments, and Responses
1.
The SDT has restructured the tables to improve clarity, but did not appreciably
change the content. Do you agree that the restructured tables are clearer? If
not, please provide specific suggestions for improvement.…. ..........................9
2.
The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do
you agree with the changes? If not, please provide specific suggestions for
improvement.…. ............................................................................................. 16
3.
The SDT has provided the “Supplementary Reference” document to provide
supporting discussion for the Requirements within the standard. Do you have
any specific suggestions for improvements?…. .............................................. 24
4.
The SDT has provided the “Frequently-Asked Questions” (FAQ) document to
address anticipated questions relative to the standard. Do you have any
specific suggestions for improvements?…. ..................................................... 31
5.
If you have any other comments on this Standard that you have not already
provided in response to the prior questions, please provide them here.…. .....38
2
Consideration of Comments on Protection System Maintenance [Project 2007-17]
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
David K Thorne
Pepco Holding Inc & Affilates
Additional Member Additional Organization Region
Carlton Bradshaw
RFC
1
2.
Carl Kinsley
RFC
1
3.
Bob Reuter
RFC
3
4.
Mike Mayer
RFC
3
5.
Jim Petrella
RFC
3
Group
Additional Member
Steve Alexanderson
Pacific Northwest Small Public Power Utility
Comment Group
Additional Organization
3
4
5
6
7
8
9
10
X
Segment
Selection
1.
2.
2
X
X
Region Segment Selection
1. Russell Noble
Cowlitz County PUD No. 1
WECC 3, 4, 5
2. Dave Proebstel
Clallam County PUD
WECC 3
3. Ronald Sporseen
Blachly-Lane Electric Cooperative
WECC 3
4. Ronald Sporseen
Central Electric Cooperative
WECC 3
5. Ronald Sporseen
Consumers Power
WECC 3
3
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6. Ronald Sporseen
Clearwater Power Company
WECC 3
7. Ronald Sporseen
Douglas Electric Cooperative
WECC 3
8. Ronald Sporseen
Fall River Rural Electric Cooperative
WECC 3
9. Ronald Sporseen
Northern Lights
WECC 3
10. Ronald Sporseen
Lane Electric Cooperative
WECC 3
11. Ronald Sporseen
Lincoln Electric Cooperative
WECC 3
12. Ronald Sporseen
Raft River Rural Electric Cooperative
WECC 3
13. Ronald Sporseen
Lost River Electric Cooperative
WECC 3
14. Ronald Sporseen
Salmon River Electric Cooperative
WECC 3
15. Ronald Sporseen
Umatilla Electric Cooperative
WECC 3
16. Ronald Sporseen
Coos-Curry Electric Cooperative
WECC 3
17. Ronald Sporseen
West Oregon Electric Cooperative
WECC 3
18. Ronald Sporseen
Pacific Northwest Generating Cooperative WECC 5
19. Ronald Sporseen
Power Resources Cooperative
3.
Group
Additional Member
Dave Davidson
Additional Organization
Tennessee Valley Authority
SERC
NA
2. Paul Baldwin
TOM Support
SERC
NA
3. David Thompson
Hydro Production Engineering SERC
NA
4. Frank Cuzzort
Nuclear Engineering
NA
5. Robert Mares
Fossil Engineering
Additional Member
Guy Zito
4
5
6
7
8
9
10
X
X
Region Segment Selection
TOM Support
Group
3
WECC 3
1. Rusty Hardison
4.
2
SERC
NA
Northeast Power Coordinating Council
Additional Organization
X
Region Segment Selection
1. Al Adamson
New York State Reliability Council, LLC
2. Gregory Campoli
New York Independent System Operator
NPCC 2
10
3. Kurtis Chang
Independent Electricity System Operator
NPCC 2
4. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
5. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7. Dean Ellis
Dynegy Generation
NPCC 5
8. Brian Evans-Mongeon Utility Services
NPCC 8
9. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
11. Kathleen Goodman
ISO - New England
NPCC 2
12. Chantel Haswell
FPL Group, Inc.
NPCC 5
13. David Kiguel
Hydro One Networks Inc.
NPCC 1
14. Michael R. Lombardi
Northeast Utilities
NPCC 1
15. Randy MacDonald
New Brunswick System Operator
NPCC 2
16. Bruce Metruck
New York Power Authority
NPCC 6
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
18. Robert Pellegrini
The United Illuminating Company
NPCC 1
19. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
20. Saurabh Saksena
National Grid
NPCC 1
21. Michael Schiavone
National Grid
NPCC 1
22. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
5.
Group
Deborah Schaneman
Additional Member Additional Organization
Platte River Power Authority System
Maintenance
Region
X
2
3
4
5
6
X
X
X
7
8
9
10
Segment
Selection
1.
Scott Rowley
Platte River Power Authority WECC
1, 3, 5, 6
2.
Gary Whittenberg
Platte River Power Authority WECC
1, 3, 5, 6
3.
Aaron Johnson
Platte River Power Authority WECC
1, 3, 5, 6
6.
Group
Mike Garton
Electric Market Policy
X
X
X
X
7.
Group
Denise Koehn
Bonneville Power Administration
X
X
X
X
5
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
8.
Group
Terry L. Blackwell
Santee Cooper
9.
Group
Mallory Huggins
NERC Staff
10.
Group
Sam Ciccone
11.
Group
2
3
4
5
6
X
X
X
X
FirstEnergy
X
X
X
X
Frank Gaffney
Florida Municipal Power Agency
X
X
X
X
Group
Kenneth D. Brown
PSEG Companies ("Public Service Enterprise
Group Companies")
X
X
X
X
Group
Carol Gerou
MRO's NERC Standards Review
Subcommittee
14.
Individual
Brandy A. Dunn
Western Area Power Administration
15.
Individual
Joanna Luong-Tran
TransAlta Centralia Generation Partnership
12.
13.
X
7
8
9
10
X
X
X
X
6
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
X
3
4
X
5
6
16.
Individual
Silvia Parada Mitchell
NextEra Energy
X
X
17.
Individual
Reza Ebrahimian
City of Austin DBA Austin Energy
18.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
19.
Individual
JT Wood
Southern Company Transmission
X
X
20.
Individual
Jack Stamper
Clark Public Utilities
X
21.
Individual
John Bee
Exelon
X
22.
Individual
Joe Petaski
Manitoba Hydro
X
23.
Individual
Dan Roethemeyer
Dynegy Inc.
24.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
25.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
26.
Individual
Scott Berry
Indiana Municipal Power Agency
27.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
28.
Individual
Ed Davis
Entergy Services
X
X
X
X
29.
Individual
Greg Rowland
Duke Energy
X
X
X
X
30.
Individual
Dale Fredrickson
Wisconsin Electric Power Company
31.
Individual
Dan Rochester
Independent Electricity System Operator
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
7
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
X
X
X
X
6
32.
Individual
Thad Ness
American Electric Power
X
33.
Individual
Michael Moltane
ITC
X
34.
Individual
Kathleen Goodman
ISO New England Inc.
35.
Individual
Rick Koch
Nebraska Public Power District
X
36.
Individual
Armin Klusman
CenterPoint Energy
X
37.
Individual
Andrew Pusztai
American Transmission Company
X
38.
Individual
Eric Salsbury
Consumers Energy
39.
Individual
Bill Shultz
Southern Company Generation
40.
Individual
Martin Bauer
US Bureau of Reclamation
41.
Individual
Kenneth A. Goldsmith
Alliant Energy
42.
Individual
Martyn Turner
LCRA Transmission Services Corporation
X
43.
Individual
Terry Harbour
MidAmerican Energy
X
X
X
X
44.
Individual
Kirit Shah
Ameren
X
X
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
8
Consideration of Comments on Protection System Maintenance [Project 2007-17]
1. The SDT has restructured the tables to improve clarity, but did not appreciably change the content. Do you agree that the
restructured tables are clearer? If not, please provide specific suggestions for improvement.
Summary Consideration: Generally, commenters indicated that the rearrangement of the Tables was beneficial.
Several commenters questioned the arrangement of Table 1-4 and the SDT responded by revising this Table. A
few commenters suggested further rearrangement of the Tables; the SDT observed that there are many potential
ways to organize the Tables and declined to adopt these suggestions. The SDT made minor changes to Table 1-3
and Table 2 verbiage based on stakeholder comments.
Organization
Yes or No
Pepco Holding Inc & Affiliates
Yes
Pacific Northwest Small Public
Power Utility Comment Group
Yes
Tennessee Valley Authority
Yes
Northeast Power Coordinating
Council
No
Question 1 Comment
The wording “Component Type” is not necessary in each title. Just the equipment category should be listed-what is now shown as “Component Type - Protective Relay”, should be Protective Relay. However,
Protective Relay is too general a category. Electromechanical relays, solid state relays, and microprocessor
based relays should have their own separate tables. So instead of reading Protective Relay in the title, it
should read Electromechanical Relays, etc. This will lengthen the standard, but will simplify reading and
referring to the tables, and eliminate confusion when looking for information. The “Note” included in the
heading is also not necessary. “Attributes” is also not necessary in the column heading, “Component”
suffices.
Response: Thank you for your comments. The SDT believes that the table headings are appropriate as reflected in the draft standard.
Platte River Power Authority
System Maintenance
Yes
Electric Market Policy
Yes
Dominion does not feel that clarity has been added to the tables.
1. A numbering structure should be added to the table for referencing each task prescribed.
9
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
2. The tables should more clearly designate and separate time based versus performance based tasks.
3. Additionally, Table 1-4 contains, in several places, an activity to “Verify that the station battery can
perform as designed by evaluating the measured cell/unit internal ohmic values to station battery
baseline.” This seems to suggest that each time the batteries are checked, the measured cell/unit
internal ohmic value should agree with some baseline value. This appears to be overly prescriptive as
the values reading-to-reading should fall within the tolerances established per Requirement R1.5, not
equal a baseline. The activities for other component types are not this prescriptive.
Response: Thank you for your comments.
1. The SDT believes that numbering the tasks within the Tables as you suggest would make the Tables more complex and would not add clarity.
2. Performance-based maintenance requires that the same tasks be completed, but at intervals determined per Attachment A.
3. The station battery baseline value is up to the entity to determine. Please see Section 15.4.1 of the Supplementary Reference for a discussion of
this. The SDT has determined that the fundamental concerns of R1 part 1.5 and the associated changes are addressed within the PSMP definition,
and that R1 part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address various related
concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document, Section 8 for a
discussion of this.
Bonneville Power Administration
Yes
Santee Cooper
Yes
NERC Staff
Yes
FirstEnergy
Yes
While we agree that the clarity of the tables has improved, there are still items that warrant further clarity.
1.In Table 1-1, references to "Verify acceptable measurement of power system input values" is made for
microprocessor relays on 6 and 12 calendar year intervals. Wouldn't this also be prudent on nonmicroprocessor based relays as well on the 6 year interval?
2. Also, in Table 1-3, "Verify that acceptable measurement of the current and voltage signals are received by
the protective relays" is shown on a 12 calendar year interval. What is the difference between this activity
and the similar activity performed in Table 1-1?
3. In Table 1-4, this table is complex and the detailed maintenance activities in this particular table is puzzling
when compared to the more generic detail in the other tables within this section. For example, an incorrect
operation due to a deteriorated signal from a CT or VT has a higher probability than a failure of a battery bank
10
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
to perform when called upon.
4. In Table 1-5, Please provide clarity on the "Unmonitored Control circuitry associated with protective
functions" component attribute. This would most likely be an FAQ item.
Response: Thank you for your comments.
1. For non-microprocessor relays, this activity is fundamentally performed as a part of the calibration process.
2. This activity is used to verify the performance of the voltage and current sensing devices, where the activity in Table 1-1 is used to verify that the
protective relay is performing properly. In some cases, the activity in Table 1-1 may also serve to satisfy the requirement in Table 1-3.
3. Table 1-4 is more detailed than the other tables because of the variability in the technologies of the station dc supply.
4. The draft definition of Protection System establishes “Control circuitry” as “…control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices”. Please see Section 15.3 of the Supplementary Reference for a discussion of this.
Florida Municipal Power Agency
Yes
PSEG Companies ("Public
Service Enterprise Group
Companies")
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Western Area Power
Administration
Yes
TransAlta Centralia Generation
Partnership
Yes
NextEra Energy
Yes
City of Austin DBA Austin Energy
PacifiCorp
Yes
11
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Southern Company Transmission
Yes or No
Yes
Question 1 Comment
The Standard Drafting Team should be commended for making the tables much easier to understand
Response: Thank you for your support.
Clark Public Utilities
No
The SDT has greatly improved the clarity of this document in the areas of relays, communication systems,
voltage and current sensing devices, control circuitry, and alarming paths. The recommendations on station
dc supply are still confusing.
First, there are five different attribute categories for unmonitored dc supply. Are these five categories
mutually exclusive? Are we supposed to follow just the category applicable to the type of battery? Are we
supposed to follow the first category and any of the subsequent four battery type categories as they apply? I
suspect some of the 3 month and 18 month items in the first category are considered to be necessary by the
SDT regardless of battery type. The current categorization is confusing. If we are required to perform the 3
month and 18 month activities listed in the first category regardless of battery type AS WELL AS the other
applicable battery type activities, please indicate this in Table 1-4. As a different option, just eliminate the first
category entirely and place the appropriate 3 month and 18 month verification and inspection requirements in
the four battery type specific categories. It may be repetitive but clarity is paramount in this standard. Second,
the FAQ examples seem to indicate that the SDT views the performance of an internal ohmic battery test or a
battery performance test as valid forms for verifying the individual battery cell states (i.e. state of charge of the
individual battery cells/units, battery continuity, battery terminal connection resistance, and battery internal
cell-to-cell or unit-to-unit connection resistance). It would be helpful if this were more obviously stated in table
1-4. Currently it could be interpreted that we need to do all of the individual cell-cell verification in addition to
the ohm test or the full performance test. I don’t believe this is the intent of the SDT (based on the FAQ
examples) but we need to see the intent in Table 1-4.Third, does a monitored dc supply have to monitor some
or all of each of the different line items listed? The FAQ examples indicate that if only some are monitored,
the dc supply can still be treated as monitored as long as the unmonitored items are verified. This means that
for a VLA battery with a low voltage alarm and unintentional ground alarm, all that is needed is to check
electrolyte level every 3 months, check float voltage and battery rack every 18 months and perform either an
internal ohm check at 18 months or a battery performance test at 6 years. Also battery alarms need to be
verified at 6 years. This is not clear in Table 1-4 and it could be interpreted by some that a monitored station
dc supply monitors ALL of the listed items not just SOME. The FAQs imply that partial monitoring is
acceptable but Table 1-4 does not indicate this very clearly. I do wish to say once again that this proposed
standard is much easier to understand and that with a little more clarification in the dc supply section I would
vote in the affirmative.
Response: Thank you for your comments. Table 1-4 has been modified in consideration of your comments. Specifically, Table 1-4 has been revised to
12
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
remove “state of charge” from the activities.
Exelon
Manitoba Hydro
No
The maintenance requirements for batteries listed in Table 1-4 do not appear to be consistent with example 1
in Section V, 1A of the FAQ. Specifically the FAQ does not mention the state of charge of the individual
battery cells/units, the battery continuity, the battery terminal connection resistance, the battery internal cellto-cell or unit-to-unit connection resistance, or the cell condition, which are indicated as 18 month interval
tasks in table 1-4.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove
“state of charge” from the activities.
Dynegy Inc.
Yes
Oncor Electric Delivery Company
LLC
Yes
Ingleside Cogeneration LP
Yes
The tables clearly tie to each component type in a Protection System. This is consistent with the required
PSMP format, making it straight forward to incorporate the intervals and to demonstrate compliance.
Response: Thank you for your support.
Indiana Municipal Power Agency
Yes
South Carolina Electric and Gas
Yes
Entergy Services
No
The tables are generally much clearer and the SDT is to be commended on their efforts.
However, we believe the Alarming Point Table needs additional clarification with regard to the Maximum
Maintenance Interval. If an “alarm producing device” is considered to be a device such as an SCADA RTU,
individual entity intervals for such a device would differ, and there isn’t necessarily a maximum interval
established as there is for Protection System components.
Also, if an entity’s alarm producing device maintenance is performed in sections and triggered by segment or
component maintenance, there would essentially be multiple maximum intervals for the alarm producing
13
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
device of that entity.
On that basis, we suggest the interval verbiage be revised to “When alarm producing device or system is
verified, or by sections as per the monitored component/protection system specified maximum interval as
applicable”. Alternately, if the intention is to establish maximum intervals as simply being no longer than the
individual component maintenance intervals as we suggest for inclusion above, then the verbiage should be
revised to “When alarm producing component/protection system segment is verified”.
In either case are we to interpret monitored components with attributes which allow for no periodic
maintenance specified as not requiring periodic alarm verification?
Response: Thank you for your comments. For clarity, the ‘Maximum Maintenance Interval’ column entry in Table 2 has been revised to state, “When
alarm producing Protection System component is verified”.
Duke Energy
Yes
Wisconsin Electric Power
Company
Yes
Independent Electricity System
Operator
American Electric Power
No
1. Table 1.5 (Control Circuitry), row 4, indicates a maximum interval of 12 years for unmonitored control
circuitry, yet other portions of control circuitry have a maximum interval of 6 years. AEP does not
understand the rationale for the difference in intervals, when in most cases, one verifies the other.
2. Also, unmonitored control circuitry is capitalized in row 4 such that it infers a defined term.
3. In the first row of table 1-4 on page 16, it is difficult to determine if it is a cell that wraps from the previous
page or is a unique row. This is important because the Maximum Maintenance Intervals are different (i.e.
18 months vs. 6 years). It is difficult to determine to which elements the 6 year Maximum Maintenance
Interval applies.
4. AEP suggests repeating the heading “Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2):” for the bullet points on this page.
Response: Thank you for your comments.
1. The 6-year activities are all related to components with “moving parts”, and the 12-year activities are related to the other portions of the control
14
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
circuitry.
2. The capitalized term has been corrected.
3. Table 1-4 has been modified in consideration of your comments.
4. Table 1-4 has been modified in consideration of your comments.
ITC
Yes
The following question concerns Table 1-3.
1. Our testing program includes “impedance testing” of the current transformers (CTs) along with insulation
testing of the wiring and CT secondary. Impedance testing involves impressing an increasing voltage on the
secondary of the CT (with primary open circuited) until 1 (one) ampere flows. This method determines the
“knee” of the saturation curve that is used as a benchmark for comparison to previous testing and other CTs.
This procedure has successfully identified CT problems over the past several decades. We believe this
procedure to be adequate. Does the SDT agree that this method is sufficient to meet the testing
requirements of Table 1-3 and that a current comparison is not needed in addition to this testing?
2. Another variation of this is for voltage device compliance. Table 1-3 indicates that we should verify the
correct voltages are received by the relay. This means that the VT would need to be energized and we would
measure the secondary voltages to compare with others. Power plant relay testing is normally performed
during plant outages when this measurement cannot be done. Some plants do not allow any testing while the
unit is on line. It would seem that the standard would be written to allow some other type of testing to be
performed other than the measurement test.
3. For Table 1-1 Row 1, we believe the intent is to verify that settings are as specified for non-microprocessor
relays and microprocessor relays alike. If this is the case, consider adding “Verify that settings are as
specified” as a bullet under the headings for non-microprocessor relays and microprocessor relays.
4. Splitting the tables into separate sections for Protective Relays, Communication Systems, VT and CTs,
and Station D.C. Supply helped the clarity.
Response: Thank you for your comments.
1. Table 1-3 has been revised in consideration of your comments. Also, please see Section 15.3 of the Supplementary Reference Document. The SDT
has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document. Your
comments will be considered within that activity.
2. Table 1-3 has been revised in consideration of your comments. Also, please see Section 15.3 of the Supplementary Reference Document. The SDT
has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document. Your
comments will be considered within that activity.
15
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
3. “Verify that settings are as specified” is specified as an activity that applies to all Protective Relays, regardless of technology. The SDT has
decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document. Your
comments will be considered within that activity.
4. Thank you for your support.
ISO New England Inc.
No
The wording “Component Type” is not necessary in each title. Just the equipment category should be listed-what is now shown as “Component Type - Protective Relay”, should be Protective Relay. However,
Protective Relay is too general a category. Electromechanical relays, solid state relays, and microprocessor
based relays should have their own separate tables. So instead of reading Protective Relay in the title, it
should read Electromechanical Relays, etc. This will lengthen the standard, but will simplify reading and
referring to the tables, and eliminate confusion when looking for information. The “Note” included in the
heading is also not necessary. “Attributes” is also not necessary in the column heading, “Component”
suffices.
Response: Thank you for your comments. The SDT believes that the table headings are appropriate as reflected in the draft standard.
Nebraska Public Power District
Yes
CenterPoint Energy
Yes
American Transmission
Company
Yes
Consumers Energy
Yes
Southern Company Generation
Yes
US Bureau of Reclamation
No Comment
Alliant Energy
Yes
LCRA Transmission Services
Corporation
No
1. It would help to add a column to the left labeled Category. I.E. a relay could be classified under Category
1 attributes unmonitored or Cat 2, Cat 3.
2. Table 1-4, Station DC is very difficult to follow.
16
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments.
1. The SDT believes that the table headings are appropriate as reflected in the draft standard.
2. Table 1-4 has been modified in consideration of your comments.
MidAmerican Energy
Yes
Ameren
Yes
Xcel Energy
Yes
17
Consideration of Comments on Protection System Maintenance [Project 2007-17]
2. The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do you agree with the changes? If not, please provide
specific suggestions for improvement.
Summary Consideration: Several commenters objected to the “percentage” steps in several VSLs. The SDT
observes that the ‘percentage’ steps follow the VSL Guidelines which can be found on the NERC website in the
‘Resource Documents’ area of the ‘Reliability Standards’ section. Other commenters requested that the VSLs
permit some level of non-compliance before incurring a ‘Low’ VSL, again the SDT notes that this is not acceptable
per the VSL Guidelines.
Organization
Yes or No
Pepco Holding Inc & Affiliates
Yes
Pacific Northwest Small Public
Power Utility Comment Group
Yes
Tennessee Valley Authority
No
Question 2 Comment
1. There is no allowance for deferral of maintenance because of factors beyond the control of the TO, GO, or
DP. These include the unavailability of customer outages, generation outages, system configuration, high risk
of loss of generation or customer load or impact to power quality.
Proposed Change: Provide a process for acceptable deferral of maintenance activities.
2. Table 1-4 The requirement to perform cell internal ohmic resistance measurements every 18 months for
vented lead-acid batteries is excessive. Our normal battery life is 20+ years. A 3-year internal resistance test
frequency is adequate to prove battery integrity. IEEE 1188 recommends verification of internal ohmic
resistance to be on a quarterly basis. It appears other intervals take into account recommended inspection
interval plus some grace period.
Proposed Change: Change maintenance interval from 3 months to 6 months.
3. Section: R1.5 This new requirement will require significant documentation with no known improvement to
the reliability of the BES. What data is being used to determine the need for this requirement? How far does
this requirement go?
4. Table 1-4 requires the inspection of “physical condition of battery rack” What are “identify calibration
tolerance or other equivalent parameters” for this task? You already have verified, test, inspect, and calibrate
defined. Leave out R1.5 which requires more than meeting the definitions.
Response: Thank you for your comments.
18
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
1. FERC Order 693 directs NERC to establish maximum allowable intervals. A “deferral process” would not satisfy this directive.
2. The SDT disagrees, and believes that 18-months is the proper interval for this activity.
3. The SDT has determined that the fundamental concerns of R1 part 1.5 and the associated changes are addressed within the PSMP definition, and
that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address various
related concerns noted within comments. Please see Supplementary Reference Document, Section 8 for a discussion of this. The associated VSL
has also been revised.
4. The SDT has determined that the fundamental concerns of R1 part 1.5 and the associated changes are addressed within the PSMP definition, and
that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address various
related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document, Section 8
for a discussion of this.
Northeast Power Coordinating
Council
No
1. Because all the requirements deal with protective system maintenance and testing, violations could
directly cause or contribute to bulk electric system instability, etc., the VRFs should all be “High”.
2. The Time Horizons should all be “Operations Planning” because of the immediacy of a failure to meet the
requirements.
3. For the R1 Lower VSL, include a second part to read: Failed to identify calibration tolerances or other
equivalent parameters for one Protection System component type that establish acceptable parameters
for the conclusion of maintenance activities. For the R1 Moderate VSL, suggest similar wording as for the
Lower VSL but specifying two Protection System component types. For the R1 High VSL, suggest
changing the wording of the 3rd part to be similar to the Lower VSL to match the requirement and to cater
for more than two Protection System component types.
4. For the R3 Severe VSL, in part 3, replace “less” with fewer.
Response: Thank you for your comments.
1. Consideration of the VRFs, in association with the VRF Guidelines, yields the VRFs as established within the draft Standard.
2. The SDT has reviewed the time horizons, and feels that R1 is properly assigned a Long-Term Planning time horizon, as the activities to develop a
program and to determine the monitoring attributes of components is performed within the related time period. The SDT had concluded that
Requirement R2 is redundant with Requirement R1, Part 1.4, and has deleted R2 (together with the associated Measure and VSL).
3. The SDT has determined that the fundamental concerns of R1 part 1.5 and the associated changes are addressed within the PSMP definition, and
that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The associated VSL has also been revised.
4. The SDT believes that your suggestion is similar to the existing text, and declines to modify the standard.
19
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Platte River Power Authority
System Maintenance
Yes or No
No
Question 2 Comment
The 5%, 10%, and 15% levels for R2 & R4 exaggerate the severity levels for small companies. A small DP
with only 9 relays in a protection system would only have to be missing 1 record for a severe VSL.
Response: Thank you for your comments. The percentage levels for Requirement R4 are consistent with many other NERC Standards and are also
consistent with the guidance within the VSL Guidelines. The SDT concluded that Requirement R2 was redundant with Requirement R1, Part 1.4, and
deleted Requirement R2 (together with the associated Measure and VSL).
Electric Market Policy
No
VSL R3. How do you measure a percentage of countable events over a period of time? How are you to
determine what the total population to be considered? An entity should not be penalized if they are following
their program, correcting issues, and documenting all actions, even if there is a high failure rate in an
instance.
Response: Thank you for your comments. Attachment A, to which Requirement R3 refers, specifies that countable events are assessed on the basis
of ” for the greater of either the last 30 components maintained or all components maintained in the previous year.”
Bonneville Power Administration
Yes
Santee Cooper
NERC Staff
FirstEnergy
No
The VSL for R2 need to be adjusted since "Condition Based Maintenance" has been removed from the
standard.
Response: Thank you for your comments. The SDT concluded that Requirement R2 was redundant with Requirement R1, Part 1.4, and deleted
Requirement R2 (together with the associated Measure and VSL).
Florida Municipal Power Agency
No
The VRF of R1 should be Low since the attached tables are essentially the PSMP.
Response: Thank you for your comments. The SDT disagrees; the Tables establish the intervals and activities, and Requirement R1 addresses the
establishment of an entities’ individual PSMP.
PSEG Companies ("Public
Service Enterprise Group
Companies")
No comment
20
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
MRO's NERC Standards Review
Subcommittee
Yes
Western Area Power
Administration
Yes
TransAlta Centralia Generation
Partnership
No
Question 2 Comment
Please provide acronyms list and its explanations in the standard.
Response: Thank you for your comments. In accordance with established NERC custom, acronyms are either established at the first use of the term,
or are general acronyms used throughout NERC Standards.
NextEra Energy
Yes
City of Austin DBA Austin Energy
PacifiCorp
Yes
Southern Company Transmission
No
We disagree with the inclusion of the VSLs, VRFs, and time Horizons associated with the new Requirements
1.5 and 4.2
Response: Thank you for your comments. The SDT determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Clark Public Utilities
Yes
Exelon
Manitoba Hydro
No
The high VSL for R1 “Failed to include all maintenance activities relevant for the identified monitoring
attributes specified in Tables 1-1 through 1-5” may be interpreted in different ways and should be further
clarified.
Response: Thank you for your comments. The SDT does not understand your concern; further details are needed.
21
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Dynegy Inc.
Yes or No
No
Question 2 Comment
For R4, the VRF has been changed to high. We question the need to change to high since there are
numerous elements that will still protect the system while repairs are being made.
Response: Thank you for your comments. Requirement R4 addresses implementation of the overall PSMP; that is – maintaining all devices within the
program. This VRF is consistent with the “high” assigned to R2 of PRC-005-1.
Oncor Electric Delivery Company
LLC
No
Oncor strongly disagrees with the modification to the Violation Severity Levers (VSL) table under the High
VSL column where it states that it is a high VSL for “Failed to establish calibration tolerance or equivalent
parameters to determine if components are within acceptable parameters.” Oncor feels modifying the
standard by adding a requirement that requires a Transmission Owner, Generation Owner or Distribution
Provider to “identify calibration tolerances or other equivalent parameters for each Protection System
component type that establish acceptable parameters for the conclusion of maintenance activities” is too
intrusive and divisive for what it brings to the reliability of the BES. The requirement (Requirement R1 part
1.5) and its associated High VSL should be removed from PRC-005-2.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Ingleside Cogeneration LP
Indiana Municipal Power Agency
No
IMPA does not agree with the percentage in the VSL table for R4. For smaller entities that have six or less of
any one type of Protection System Component and they fail, for whatever reason (even if it's a matter of
incomplete documentation), to complete scheduled program maintenance on that component they will be
subjected to the severe VSL penalty Matrix.
Consideration should be given to entities having less than say, 100 of a component. There should be some
type of tiered sub table within the VSL matrix for this consideration - registered entities having a certain
component in quantities greater than or equal to 100 and registered entities having quantities of that certain
component of less than 100.
Response: Thank you for your comments. The percentage levels within Requirement R4 are consistent with many other NERC Standards, and are also
consistent with the guidance within the VSL Guidelines. The SDT concluded that Requirement R2 was redundant with Requirement R1, Part 1.4, and
deleted Requirement R2 (together with the associated Measure and VSL).
South Carolina Electric and Gas
Yes
22
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Entergy Services
Yes or No
Question 2 Comment
No
R1.5 calls for “identification of calibration tolerances or equivalent parameters...” whereas the associated VSL
references “failure to establish calibration criteria....” and is listed as high. If R1.5 is to be included in this
standard, then we suggest the severity level of a failure to simply “identify” or document such calibration
tolerances would be analogous to the severity level(s) of a “failure to specify one (or the severity level should
be consistent with the other elements of R1. Both cases appear to be more of a documentation issue as
opposed to a failure to implement. Shouldn’t a failure to implement any necessary calibration tolerance be
accounted for in R4?
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised.
Duke Energy
No
1. R1.3 appears to be missing from the VSL for R1.
2. Also, it’s unclear to us what the expectation is for compliance documentation for “monitoring attributes and
related maintenance activities” in R1.4 and “calibration tolerances or other equivalent parameters” in R1.5.
This is fairly straightforward for relays, but not for other component types.
3. R4 - More clarity must be provided on the expectation for compliance documentation. This is a High VRF
requirement, and there may only be a small number of maintenance-correctable items, hence a significant
exposure to an extreme penalty.
Response: Thank you for your comments.
1. The High VSL for Requirement R1 has been revised in consideration of your comment.
2. The SDT concluded that Requirement R2 was redundant with Requirement R1, Part 1.4, and deleted R2 (together with the associated Measure and
VSL).
3. Examples of compliance documentation are included within Measure M4 and discussed within Section 15.7 of the Supplementary Reference
Document.
Wisconsin Electric Power
Company
Independent Electricity System
Operator
No
1. R1 Lower - We suggest including a second part as follows: “Failed to identify calibration tolerances or
other equivalent parameters for one Protection System component type that establish acceptable
parameters for the conclusion of maintenance activities. “
23
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
2. R1 Moderate - We suggest similar to the Lower VSL but catering for two Protection System component
types.R1 High - We suggest changing the wording of the 3rd part to match the requirement and to cater
for more than two Protection System component types.
3. Editorial Comment to Severe VSL for R3: In part 3, replace “less” with “fewer”.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The associated VSL has also been revised.
2. The ‘Moderate’ VSL for Requirement R1 appears to be similar to the ‘Lower’ VSL for Requirement R1 as you suggest. The SDT believes that, if
more than two Protection System component types are not addressed, the ‘Severe’ VSL is appropriate.
3. Thank you. The SDT elected not to change the VSL for Requirement R3 as suggested.
American Electric Power
No
1. The VSL table should be revised to remove the reference to the Standard Requirement 1.5 in the R1
“High” VSL.
2. All four levels of the VSL for R2 make reference to a “condition-based PSMP.” However, no where in the
standard is the term “condition-based” used in reference to defining ones PSMP. The VSL for R2 should
be revised to remove reference to a condition-based PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard Requirements and Table 1.
3. In multiple instances, Table 1 uses the phrase “No periodic maintenance specified” for the Maximum
Maintenance Interval. Is this intended to imply that a component with the designated attributes is not
required to have any periodic maintenance? If so, the wording should more clearly state “No periodic
maintenance required” or perhaps “Maintain per manufacturers recommendations.” Failure to clearly
state the maintenance requirement for these components leaves room for interpretation on whether a
Registered Entity has a maintenance and testing program for devices where the Standard has not
specified a periodic maintenance interval and the manufacturer states that no maintenance is required.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The associated VSL has also been revised.
2. The SDT concluded that Requirement R2 is redundant with R1, Part 1.4, and deleted Requirement R2 (together with the associated Measure and
VSL).
3. If the indicated monitoring attributes are present, no “hands-on” periodic maintenance is required, as the monitoring of the component is
24
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
providing a continuing indication of its functionality.
ITC
Yes
ISO New England Inc.
No
1. Because all the requirements deal with protective system maintenance and testing, violations could
directly cause or contribute to bulk electric system instability, etc., the VRFs should all be “High”.
2. The Time Horizons should all be “Operations Planning” because of the immediacy of a failure to meet the
requirements.
3. For the R1 Lower VSL, include a second part to read: Failed to identify calibration tolerances or other
equivalent parameters for one Protection System component type that establish acceptable parameters
for the conclusion of maintenance activities.
4. For the R1 Moderate VSL, suggest similar wording as for the Lower VSL but specifying two Protection
System component types.
5. For the R1 High VSL, suggest changing the wording of the 3rd part to be similar to the Lower VSL to
match the requirement and to cater for more than two Protection System component types.
6. For the R3 Severe VSL, in part 3, replace “less” with fewer.
Response: Thank you for your comments.
1. The SDT set the VRFs in accordance with the FERC’s and NERC’s VRF guidance.
2. The SDT has reviewed the time horizons, and feels that Requirement R1 is properly assigned a Long-Term Planning time horizon, as the activities
to develop a program and to determine the monitoring attributes of components is performed within the related time period. The SDT concluded
that Requirement R2 was redundant with Requirement R1, Part 1.4, and deleted Requirement R2 (together with the associated Measure and VSL).
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. The associated VSL has also been revised.
4. The ‘Moderate’ VSL for Requirement R1 appears to be similar to the ‘Lower’ VSL for Requirement R1 as you suggest.
5. The SDT believes that, if more than two Protection System component types are not addressed, the ‘Severe’ VSL is appropriate.
6. The SDT believes that your suggestion is similar to the existing text, and declines to modify the standard.
Nebraska Public Power District
No
VRF’s:
1. The definition of a Medium Risk Requirement included on page 8 of the SAR states: "A requirement that,
25
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system." The PSMP does not "directly" affect the
electrical state or the capability of the bulk electric system. A failure of a Protection System component is
required to "directly" affect the BES. Therefore, the PSMP has only an "indirect" affect on the electrical
state or the capability of the BES. Requirements R1 through R3 and their subparts are administrative in
nature in that they are comprised entirely of documentation. Therefore, I recommend changing the
Violation Risk Factor of Requirements R1, R2, and R3 to Lower to be consistent with the Violation Risk
Factors defined in the SAR.
VSL’s:
2. R2: Tables 1-1 through 1-5 refers to time-based maintenance programs. I recommend changing
"condition-based" to "time-based" in all four severity levels.
3. SAR Attachment B - Reliability Standard Review Guidelines states that violation severity levels should be
based on the following equivalent scores: Lower: More than 95% but less than 100% compliant
Moderate: More than 85% but less than or equal to 95% compliant High: More than 70% but less than
equal to 85% compliant Severe: 70% or less complaint recommend revising the percentages of the
violation severity levels to be consistent with the SAR.
4. R3: The performance-based maintenance program identified in PRC-005 Attachment A provides the
requirements to establish the technical justification for the initial use of a performance-based PSMP and
the requirements to maintain the technical justification for the ongoing use of a performance-based
PSMP. However, it appears the VSLs for Requirement R3 only addresses the ongoing use of the
technical justification.
a. I recommend revising the VSLs for R3 to include the initial use of the technical justification. Item
2) of R3 Severe VSL is a duplicate of Item 2) of R3 Lower VSL. This item is administrative in
nature therefore I recommend deleting Item 2) from R3 Severe VSL.
b. The first and third bullets of item 4) of R3 Severe VSL are administrative in nature and should be
moved to the Lower VSL
c.
R4: SAR Attachment B - Reliability Standard Review Guidelines states that violation severity
levels should be based on the following equivalent scores: Lower: More than 95% but less than
100% compliant Moderate: More than 85% but less than or equal to 95% compliant High:
More than 70% but less than equal to 85% compliant Severe: 70% or less complaint
recommend revising the percentages of the violation severity levels to be consistent with the
SAR.
26
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comments.
1. Requirements R1, R2, and R3 are not administrative; they are foundational. Without the fundamental development of a PSMP, an entity is unlikely
to actually implement a PSMP that satisfies the reliability needs of the BES. The SDT had concluded that Requirement R2 is redundant with
Requirement R1, Part 1.4, and deleted Requirement R2 (together with the associated Measure and VSL).
2. The SDT concluded that Requirement R2 is redundant with Requirement R1, Part 1.4, and deleted Requirement R2 (together with the associated
Measure and VSL).
3. The guidelines within the SAR have been superseded by subsequent revisions to the VSL Guidelines. The VSLs in the draft standard adhere to the
latest VSL Guidelines and to the June 19, 2008 FERC order on VSLs in Docket No RR08-04-000.
4. Part a – The VSL for Requirement R3 has been modified in consideration of your comments.
Part b – These requirements are not administrative; they are foundational. Without compliance with these requirements, an entity does not have an
effective performance-based PSMP, and may be detrimentally affecting reliability.
Part c – The latest VSL Guidelines also provide examples of VSLs similar to those in the draft standard.
CenterPoint Energy
American Transmission
Company
Yes
Consumers Energy
Yes
Southern Company Generation
Yes
US Bureau of Reclamation
Yes
The tables rely on a reference document which is not a part of the standard and as such may be altered
without due process. Either the relevant text from the reference needs to be inserted into the standard or the
reference itself incorporated into the standard. Specific References such as
Response: Thank you for your comments. The Tables do not provide a reference to either the Supplementary Reference Document. An entity must
comply with the standard when approved. The reference documents provide additional explanation, discussion, and rationale, but are not part of the
mandatory standard. Since the reference documents are being developed to accompany the standard, the NERC Standard Development Procedure
requires that they be posted with the draft standard and undergo stakeholder review, both initially and with any revision of the standard.
Alliant Energy
Yes
27
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
LCRA Transmission Services
Corporation
Yes
MidAmerican Energy
Yes
Ameren
No
Question 2 Comment
(1)The Lower VSL for all Requirements should begin above 1% of the components. For example for R4:
“Entity has failed to complete scheduled program on 1% to 5% of total Protection System components.”
PRC-005-2 unrealistically mandates perfection without providing technical justification. A basic premise of
engineering is to allow for reasonable tolerances, even Six Sigma allows for defects. Requiring perfection
may well harm reliability in that valuable resources will be distracted from other duties.
Response: Thank you for your comments. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation.
Xcel Energy
Yes
28
Consideration of Comments on Protection System Maintenance [Project 2007-17]
3. The SDT has provided the “Supplementary Reference” document to provide supporting discussion for the Requirements within the
standard. Do you have any specific suggestions for improvements?
Summary Consideration: Some commenters questioned whether the Supplementary Reference Document was a
part of the Standard and thus mandatory and enforceable; the SDT responded that this document is not a part of
the standard but instead offers guidance/rationale to assist in the implementation of the standard. Various other
comments were offered regarding the content of the Supplementary Reference Document, to which the SDT
responded accordingly.
Organization
Yes or No
Pepco Holding Inc & Affiliates
Yes
Pacific Northwest Small Public
Power Utility Comment Group
No
Tennessee Valley Authority
No
Northeast Power Coordinating
Council
No
Platte River Power Authority
System Maintenance
No
Electric Market Policy
Yes
Question 3 Comment
The document on page 3 states that data available from EPRI (et.al) was utilized by the Standard Drafting
Team; however, there are no references to EPRI documents in Section 16. Suggest including EPRI
references for completeness.
Response: Thank you for your comments. Page 3 of the Supplementary Reference Document has been revised to remove reference to EPRI
documents.
Bonneville Power Administration
Santee Cooper
No
29
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
NERC Staff
Yes or No
Question 3 Comment
Yes
1. In section 2.3, NERC staff recommends noting that the present NERC Glossary definition of Bulk Electric
System will be revised in response to FERC Order No. 743.
2. In Section 2.4, NERC staff recommends changing the phrase “relays that use measurements of voltage,
current, frequency and/or phase angle” with “protective relays that respond to electrical quantities” for
consistency with recent changes to the proposed definition of Protection System.
Response: Thank you for your comments.
1. The SDT believes that it is not advisable to reference future activities, but notes that the standard will be applicable to whatever is defined to be the
BES, either today or in the future.
2. The Supplementary Reference Document has been revised as suggested.
FirstEnergy
Yes
The discussions surrounding implementing the PSMP on pages 10 and 11 of the clean copy are troublesome
for the following reasons.
1. On Pg. 10, under Sec. 8.1, the 4th bullet item states "If your PSMP (plan) requires more activities then you
must perform and document to this higher standard". This statement's use of the word "must" implies that an
entity will be audited to their documented maintenance practices, even if those practices exceed the
requirements of the PRC-005 standard. The PRC-005 standard, and any standard, details the minimum
requirements that must be met to achieve a certain reliability goal. For example, if an entity's program states
that it will do maintenance on a relay every 4 years, but the standard only requires maintenance every 6
years, the entity shall be held compliant to the standard's 6 year interval. If the entity in this example decides
that in year 4 it must delay its maintenance to year six, that should be allowable since the standard PRC-0052 requires maintenance every 6 years.
2. Since the standard no longer discusses Condition Based Maintenance, it should be removed from the
reference document for consistency.
Response: Thank you for your comments.
1. This text is in the Supplementary Reference Document as a caution to entities that they may be expected to be held accountable for their entire
documented PSMP, even if it exceeds the minimum requirements of the standard.
2. The Supplementary Reference Document discusses condition-based maintenance in a conceptual manner, as a generally-recognized term. The
SDT did make some changes within the Supplementary Reference document to clarify the manner in which condition-based maintenance is
discussed.
30
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Florida Municipal Power Agency
Yes
PSEG Companies ("Public
Service Enterprise Group
Companies")
Yes
Question 3 Comment
Figure 2 “typical generation system” shows a typical auxiliary medium voltage bus, in addition to the color
coded elements suggest that a very distinct line of demarcation (dark dotted line) be added to the figure that
defines the elements associated with the MV bus protection served by the station Aux Transformer and unit
aux transformer are not part of the BES- PSMP PRC5 requirements. Also see comment 5 below; we suggest
that the station service transformer must be connected to BES for inclusion in standard requirements.
Suggest adding an explanation note to figure 2 to clarify this.
Response: Thank you for your comments. Figure 2 is intended to provide an example to users, not to describe the entire applicability of the draft
standard. As such, the SDT does not believe that this figure needs to reflect all possible arrangements, nor does it need to suffice to describe the
entire applicability. As for your comment regarding the unit auxiliary transformer, please see the SDT response to your more detailed comments in
Question 5.
MRO's NERC Standards Review
Subcommittee
No
Western Area Power
Administration
No
TransAlta Centralia Generation
Partnership
No
NextEra Energy
No
City of Austin DBA Austin Energy
PacifiCorp
Southern Company Transmission
Yes
1. Page 11 and 12, (Additional Notes for Table 1-1 through 1-5)
Comment ->> The standard does not reference these notes. Should these notes be referenced and
included in the Standard?
2. Page 12, Additional Notes for Table 1, item #7 (“performing an operational trip test”)
31
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
Comment ->> Standard does not state that an operational/full functional test is required. Please clarify.
3. Page 22, 15.3, Control Circuitry Functions, paragraph 1 (“verify, with a volt-meter, the existence of proper
voltage at the open contacts”
Comment ->> The example of measuring the proper voltage with a volt-meter at the open contacts to
verify the circuit indicates that the 12-year “full functional” trip test of control circuits is not required.
Please clarify.
4. Page 22, 15.3, Control Circuitry Functions, paragraph 3 (“UVLS or UFLS scheme are excluded from the
tripping requirement, but not from the circuit test requirements”)
Comment ->> This indicates to me that measuring the proper voltage with a volt-meter at the open
contacts will verify the circuit. Please confirm. Please clarify - If a suitable monitoring system is installed
that verifies every parallel trip path then the manual-intervention testing of those parallel trip paths can be
“extended beyond 12 years”. Standard indicates that no periodic maintenance is required. Consider
changing “extended beyond 12 years” to “eliminated”.
5. Page 23, 15.3, Control Circuitry Functions, paragraph 5 (“When verifying the operation of the 94 and 86
relays each normally-open contact that closes to pass a trip signal must be verified as operating
correctly.”)
Comment ->> This indicates that we must verify that trip and auxiliary device contacts change state.
Please confirm. The standard does not state that the contacts must be verified to change states. If this is
required, please add to the standard.
Response: Thank you for your comments.
1. These notes are provided as application guidance relative to the Tables, which as you note, does not reference them.
2. This note has been revised within the Supplementary Reference Document in consideration of your comment.
3. This example is stated within the Supplementary Reference Document as an example method of testing the dc control circuitry. The draft standard
no longer requires a “functional trip test”, although it does require that lockout relays and auxiliary relays be operated at least once every 6 years
to verify that they function properly.
4. The Supplementary Reference Document has been revised as suggested.
5. The draft standard specifies “Verify electrical operation” of these components every 6 years. This seems implicitly to require a change of state of
the contacts. However, it may be possible to verify electrical operation without having to check the change of state of the individual contacts, but
the contacts will have to be checked as part of the 12-year full test. The cited clause/paragraph Supplementary Reference Document has been
revised to clarify.
32
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Clark Public Utilities
Yes or No
Question 3 Comment
No
Exelon
Manitoba Hydro
No
Dynegy Inc.
No
Oncor Electric Delivery Company
LLC
No
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration, LP, believes that the Section 15.5 of the Supplementary Reference “Associated
communications equipment (Table 1-2)” properly reflects the intent of the validation of relay-to-relay
communications. It states that any “evidence of operational test or documentation of measurement of signal
level, reflected power or data-error rates can fulfill the requirements.” However, Table 1-2 - which will be the
ultimate reference used by audit teams - only clearly allows for the measurement of channel parameters.
Although the newer technology relays provide read-outs of signal level or data-error rates that do not require
intrusive testing, older relays do not. The tools required to perform such testing are not easily available - and
may leave the communications channel in worse shape after testing than it was prior to testing.
We believe that Table 1-2 should be updated to clearly state that an operational test is sufficient for the
testing of relay-to-relay communication - consistent with the Supplementary Reference.
Response: Thank you for your comments. The standard does not explicitly require measurement of channel parameters, but instead specifies that
they may be verified. The Supplementary Reference Document has been revised to remove the discussion of operational testing of the
communications channel.
Indiana Municipal Power Agency
No
South Carolina Electric and Gas
No
Entergy Services
Yes
R1.5 calls for “identification of calibration tolerances or equivalent parameters for each Protection System
Component Type....”. We believe the Supplementary Reference document should provide additional
information and examples of calibration tolerances or equivalent parameters which would be expected for the
various component types. Especially for any “equivalent” parameters which would be required for compliance
33
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
for a component type besides protective relays.
Response: Thank you for your comments. The SDT determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed.
Duke Energy
No
Wisconsin Electric Power
Company
No
Independent Electricity System
Operator
No
American Electric Power
Yes
With such a complex standard as this, the FAQ and Supplementary Reference documents do aid the
Protection System owner in demystifying the requirements. But AEP holds strong doubt on how much weight
the documents carry during audits. It would be better to include them as an appendix in the actual standard,
but in a more compact version with the following modifications:
1. Section 5 of the Supplementary Reference, refers to “condition-based” maintenance programs. However,
no where in the standard is the term “condition-based” used in reference to defining ones PSMP. The
Supplementary Reference should be revised to remove reference to a condition-based PSMP;
alternatively the Standard could be revised to include the term “condition-based” within the Standard
Requirements and Table 1.
2. Section 15.7, page 26, appears to have a typographical error “...can all be used as the primary action is
the maintenance activity...”
3. Figure 2 is difficult to read. The figure is grainy and the colors representing the groups are similar enough
that it is hard to distinguish between groups.
Response: Thank you for your comments. The discussion within the Supplementary Reference Document and FAQ are informative, not normative,
and thus do not belong as part of the standard.
1. The Supplementary Reference Document discusses condition-based maintenance in a conceptual manner, as a generally-recognized term. The
SDT did make some changes within the Supplementary Reference Document to clarify the manner in which condition-based maintenance is
discussed.
2. This clause has been corrected.
34
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
3. A higher-quality version of Figure 2 has been substituted.
ITC
Yes
1. Auxiliary Relay Testing: We repeat our objection to the 6 year requirement for testing of auxiliary relays.
The STD response to our previous objection was:
Please see new Table 1-5. The SDT believes that mechanical solenoid-operated devices share
performance attributes (and failure modes) with electromechanical relays and need to be tested at similar
intervals. Performance-based maintenance is an option to increase the intervals if the performance of
these devices supports those intervals. Auxiliary relays are, of course, electromechanical relays, but
much less complicated than impedance, differential or even time-overcurrent electromechanical relays. It
has been our experience that trip failures are rare and that our present 10 year control, trip tests, and
other related testing are sufficient in verifying the integrity of the scheme. Section 8.3 of the
Supplementary Reference notes statistical surveys were done to determine the maintenance intervals.
Were auxiliary relays included in these surveys in a such a way to verify that they indeed require a 6 year
maintenance interval? We recommend they be considered part of the control circuitry, with a 12 year test
cycle.
2. High Speed Ground Switch Testing: We repeat our recommendation that the standard state that a high
speed ground switch is an interrupting device. We also recommend that testing requirements for HighSpeed ground switches be clearly stated in the standard.
Section 15.3 of the Supplementary Reference contains the following: It is necessary, however, to classify
a device that actuates a high-speed auto-closing ground switch as an interrupting device if this ground
switch is utilized in a Protection System and forces a ground fault to occur that then results in an
expected Protection System operation to clear the forced ground fault. The SDT believes that this is
essentially a transferred-tripping device without the use of communications equipment. If this high-speed
ground switch is “...applied on, or designed to provide protection for the BES...” then this device needs to
be treated as any other Protection System component. The control circuitry would have to be tested
within 12 years and any electromechanically operated device will have to be tested every 6 years. If the
spring-operated ground switch can be disconnected from the solenoid triggering unit then the solenoid
triggering unit can easily be tested without the actual closing of the ground blade.
We disagree that a high-speed ground switch can be adequately tested by disconnecting the solenoid
triggering unit. The ability of the trip coil to “operate the circuit breaker” must be verified per Table 1-5
Row 1. The ability of the “solenoid triggering unit” to operate the ground switch should be required also.
A high-speed ground switch is a unique device. Its maintenance requirements should be specifically
included in the standard itself. Based on Draft 3 of the standard, this is a electromechanically operated
device and would have to be tested every 6 years. A logical location would be in Table 1-5. Is there test
35
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
data to support the test method of disconnecting the solenoid triggering unit?
Response: Thank you for your comments.
1. The SDT believes that the appropriate interval for electromechanical devices such as aux or lockout relays should remain at 6 years, as these
devices contain “moving parts” which must be periodically exercised to remain reliable.
2. PRC-005-2 includes high-speed grounding switch trip coils within the dc control circuitry to the degree that the initiating Protection Systems are
characterized as “transmission Protection Systems”. There is currently an unapproved interpretation response (project 2009-17) addressing what
is a “transmission protection system.” When this interpretation is approved, the SDT will incorporate it within PRC-005-2. Section 15.3 of the
Supplementary Reference Document will be revised to clarify the discussion of testing of the ground-switch trip coil.
ISO New England Inc.
No
Nebraska Public Power District
Yes
The Supplementary Reference Documents identified are unapproved and in draft form. I believe that only
approved documents should be referenced in the Standard. Therefore, I recommend updating the
Supplementary Reference Documents section with approved versions of the documents.
Response: Thank you for your comments. The SDT revised the Supplementary Reference Document section of the draft Standard.
CenterPoint Energy
American Transmission
Company
No
Consumers Energy
No
Southern Company Generation
Yes
1. On Page 4, Paragraph 2.2 is no longer proposed - the paragraphs just before 2.2 need to be revised.
2. On Page 12, item 7, the phrase “operational trip test” is not used in the standard. Please consider using
this phrase in the standard.
3. On Pages 14-15, several paragraphs describing the contents of Sections 9, 10, 11, & 13 are given –
these appear to be out of place and don’t seem to belong here (just before “9. Performance-Based
Maintenance Process).
4. On Page 24, correct the bulleted Protection System Definition to match the most recent definition.
36
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
5. On Page 29, please improve the clarity of Figure 2.
6. On Page 31, please revise the flowchart references to R4.4.1 and R4.4.2.
7. Please correct the following formatting: Page 2, Table of Contents; Page 18, the bulleted item list; Page
23, add a space before the last paragraph.
Response: Thank you for your comments.
1. This Section of the Supplementary Reference Document has been corrected.
2. This Section of the Supplementary Reference Document has been revised.
3. The Supplementary Reference Document has been revised to address your comment.
4. The Supplementary Reference Document has been revised to address your comment.
5. The Supplementary Reference Document has been revised to address your comment.
6. The Supplementary Reference Document has been revised to address your comment.
7. The Supplementary Reference Document has been revised to address your comment.
US Bureau of Reclamation
Yes
The Supplementary reference provides significant clarity to the intent and application of standard; however, in
doing so, it reveals conflicts and ambiguity in the text of the standard. It is suggested that some of the
clarifying language be inserted into the text of the standard.
Response: Thank you for your comments. To the extent possible, the clarifying language of the Supplementary Reference Document will be
incorporated into the next version of PRC-005 when the standard is drafted in the Results-based format.
Alliant Energy
No
LCRA Transmission Services
Corporation
Yes
Well written and helpful document. In Section 8.1, the document states that if your PSMP requires activities
more often than the Tables maximum, then you must perform to that higher standard. While it is
understandable that an entity may desire to maintain their PRS at a higher level, they should not be fined or
penalized for achieving less than their standard but within the intervals stated in the Tables. This point should
be clarified, preferably within the standard itself.
Response: Thank you for your comments. Requirement R1, Part 1.3 and Requirement R4 within the Standard has been revised in a manner which
addresses your comment. However, the SDT re-emphasizes that entities may be expected to be held to their PSMP developed in accordance to
37
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
Requirement R1, whether it minimally addresses the remainder of the requirements in the standard or exceeds those requirements.
MidAmerican Energy
Yes
The Supplementary Reference should have clear disclaimers indicating that nothing in the reference is
mandatory and enforceable.
Response: Thank you for your comments. NERC establishes that only the Standard is mandatory and enforceable, and Section F of the standard
introduces the Supplementary Reference Document as presenting supporting discussion. The introductory area of the Supplementary Reference
Document will be revised to clarify this.
Ameren
No
Xcel Energy
Yes
1. Requirement R1 of the standard has been changed and no longer states that only relays which sense
current, voltage, and phase angle to detect anomalies are in scope. However, it is noted that the new
definition of Protection System states “Protective Relays which respond to electrical parameters.” Does
Section 2.4 of the Supplementary Reference and, in particular, the last sentence of this section, still align
with the standard such that sudden pressure devices are not classified as a relay requiring calibration per
Table 1-1? Is the tripping path through the Sudden Pressure Device included as DC Control Circuitry per
Table 1-5? FAQ II.4.F would indicate testing of trips from 63 devices are also not required. If so, perhaps
this should be restated in Section 2.4 of the Supplementary reference.
2. Section 2.4 could be read to imply that “applicable relays” includes IEEE device #86, lockout relays and
IEEE device #94, tripping or trip free relays. However, it is apparent from Table 1-1 “Component Type –
Protective Relays” that there are no maintenance activities applicable to 86 or 94 devices. On the other
hand, Table 1-5 “Component Type - Control Circuitry” does include maintenance activities for
electromechanical trip or auxiliary devices. Thus the tables of the standard imply that 86 and 94 devices
would be more accurately classified as DC control circuitry rather than relays. We suggest that Section 2.4
be written to clarify the SDT’s intent for the component type classification of devices 86 and 94. Note that
auditors of PRC-005-1 frequently ask for a list of in scope relays and it would nice to have a definite rationale
for excluding 86 and 94 devices from these relay lists.
Response: Thank you for your comments.
1. The Supplementary Reference Document has been revised to clarify this point.
2. The SDT re-emphasizes that auxiliary and lockout relays are included within the standard as mechanical-operating devices that must be verified to
operate within a 6-year interval, and also as devices which must be verified within the verification of all paths of the trip circuits on a 12-year
interval. It is left to the entity to determine how to best demonstrate compliance with that requirement to the compliance monitor. The
38
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 3 Comment
Supplementary Reference Document has been revised to clarify this point.
39
Consideration of Comments on Protection System Maintenance [Project 2007-17]
4. The SDT has provided the “Frequently-Asked Questions” (FAQ) document to address anticipated questions relative to the standard.
Do you have any specific suggestions for improvements?
Summary Consideration: Commenters suggested corrective language and requested additional discussions within
the FAQ document. The SDT decided to eliminate the FAQ document and incorporate its contents into the
Supplementary Reference Document as appropriate. The SDT considered all commenters’ suggestions during that
activity.
Organization
Yes or No
Pepco Holding Inc & Affiliates
Yes
Pacific Northwest Small Public
Power Utility Comment Group
Yes
Question 4 Comment
WECC does not use the definition of the BES that NERC supplied to FERC via
http://www.nerc.com/docs/docs/ferc/RM06-16-6-14-07CompFilingPar77ofOrder693FINAL.pdf,so the answer
to III.1.3 (page 19-20) is not accurate.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Tennessee Valley Authority
No
Northeast Power Coordinating
Council
Yes
See response to Question 5 below.
Response: Thank you for your comments. Please see our response to your comments in Question 5.
Platte River Power Authority
System Maintenance
No
Electric Market Policy
Yes
The FAQ’s do not appear to have kept up with the current draft Standard.
1. For example, Question B under Section 2 for Protective Relays, refers to the use of the word
“Restoration” in the definition of a Protection System Maintenance Program. The current definition uses
the word “Restore.”
2. Additionally, Answers B, I, and J under Section 2 for Protective Relays each refer to Requirement R4.3,
40
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
which in not in the current Standard. Suggest a final edit of the FAQ’s to clean-up these type of issues.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Bonneville Power Administration
Santee Cooper
No
NERC Staff
Yes
1. At a minimum, the response to Question II.1.A should be revised to reflect the present revision of
Requirement R1. In the current proposed response to the FAQ, the answer refers to text that was deleted
from Requirement R1 in the current posting of the standard; i.e., this standard covers protective relays
“that use measurements of voltage, current and/or phase angle to determine anomalies and to trip a
portion of the BES.” The removal of this text from Requirement R1 makes it less clear whether the
standard applies to reclosing functions and protective functions used to supervise automatic or manual
closing of a circuit breaker to ensure the voltage magnitude and phase angle difference are within
specified tolerances. The drafting team also should consider whether additional specificity is required to
ensure applicability is clearly defined within the standard.
2. In the response to Question II.2.H, NERC staff notes that the word “than” should be changed to “then” in
the phrase “If the component no longer performs Protection System functions than...”
3. In the response to Question II.2.I, NERC staff recommends noting that “When a failure occurs in a
protection system, power system security may be compromised, and notification of the failure must be
conducted in accordance with relevant NERC standard(s).” The recommended text is included in the
Supplementary Reference Document and inclusion in the FAQ response provides consistency and
highlights obligations in other standards necessary for BES reliability.
4. In the response to Question III.1.A, NERC staff recommends noting that the present NERC Glossary
definition of Bulk Electric System will be revised in response to FERC Order No. 743.
5. In the response to Question III.3.A, NERC staff recommends a more generic reference to NERC UFLS
requirements in place of the reference to PRC-007-0, as PRC-007 will be retired pending FERC approval
of PRC-006-1.In the response to Question IV.1.A (third paragraph), NERC staff recommends changing
the phrase “that are certainly coming to the industry” to “may be coming to the industry” for consistency
with the change to the response to Question V.4.A. Both questions appear to address the same or similar
concerns.
41
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
FirstEnergy
No
Florida Municipal Power Agency
Yes
PSEG Companies ("Public
Service Enterprise Group
Companies")
Yes
Suggest that the section 5 - station DC supply have some specific examples added that would be acceptable
methods for verifying the “state of charge” as required by standard table 1-4.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove
“state of charge” from the activities.
MRO's NERC Standards Review
Subcommittee
No
Western Area Power
Administration
No
TransAlta Centralia Generation
Partnership
No
NextEra Energy
No
City of Austin DBA Austin Energy
PacifiCorp
Southern Company Transmission
Yes
1. Page 7, L. (“verify operation of the relay inputs ...”)
Comment ->> Clarification needed. Standard states that each input should be “picked up” or “turned on
and off”. Do you have to change states of the input contact(s) or can you just jumper positive to the
input(s) to verify that the microprocessor relay verifies this change of state?
42
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
2. Page 10, 4.E (“What does functional (or operational) trip test include?”)
Comment ->> The words “functional (or operational) trip test” are not in the Standard. Is this required? If
so, please clarify this in Standard. If not, please remove. (Reference comment regarding “verify all paths
of the control and trip circuits” on page 17 of standard.)
3. Page 18, 7. (Distributed UVLS and UFLS system.) and Page 19 8. (Centralized UVLS and UFLS system.)
Comment ->> Standard does not specify “distributed” or “centralized” UVLS and UFLS systems. Please
consider combining section 7 & 8, omitting items 7.C., 8.E., and omitting “distributed” and “centralized”
references on pages 18 and 19.
Response: Thank you for your comments.
The standard does explicitly require that auxiliary relays, lockout, and trip coils of interrupting devices be verified to have electrically operated every 6
years, and this is the only place in the standard that currently requires this sort of activity.
The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The
SDT considered your comments during this activity.
Clark Public Utilities
Yes
Provide answers to the following questions.
Does the completion of a battery ohm test or a battery performance test satisfy the verification requirements
for state of charge of the individual battery cells/units, battery continuity, battery terminal connection
resistance, and battery internal cell-to-cell or unit-to-unit connection resistance (where available to measure)?
Response: Thank you for your comments. The activities described do not satisfy all of the requirements (at the established intervals) listed in your
comment. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as
appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove “state of charge” from the activities.
Exelon
Yes
1. Clarify what kind of testing is required on lockout relays/86 devices. Specifically, whether functional testing
is adequate or if simple calibration, similar to protective relays, is all that is are required.
2. Clarify if protective relays that trip equipment (e.g., a condensate pump that would in turn cause a main
generator trip) are also included in the scope of this Standard.
3. Clarify if relays which result in generator run back, but do not trip the generator, are included in the scope
of this Standard.
Response: Thank you for your comments.
43
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
1. For lockout relays, the standard requires that they be electrically operated every 6 years, and that the trip path be verified every 12 year. No
calibration/etc is specified.
2. As described in FAQ III.2.A, protective relays which trip equipment within the plant which may eventually result in tripping of the generator, but do
not trip the generator (either directly or via a generator lockout relay) , are not included.
3. If the generator run back scheme is characterized as a Special Protection System within your region, these relays would be included as part of that
system (Section 4.2.6- Applicability of the draft Standard).
The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The
SDT considered your comments during this activity.
Manitoba Hydro
Yes
As previously stated, the maintenance requirements for batteries listed in Table 1-4 do not appear to be
consistent with example 1 in Section V, 1A of the FAQ. Specifically the FAQ does not mention the of the
individual battery cells/units, the battery continuity, the battery terminal connection resistance, the battery
internal cell-to-cell or unit-to-unit connection resistance, or the cell condition which are indicated as 18 month
interval tasks in table 1-4.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove
“state of charge” from the activities.
Dynegy Inc.
No
Oncor Electric Delivery Company
LLC
Yes
There is still confusion in Table 1-4 concerning the “Monitored Station dc supply.” The uncertainty is over
whither an Owner must have all seven (7) monitoring activities (Station dc supply voltage, State of charge of
the individual battery cell/units, Battery continuity of station battery, Cell-to-cell and battery terminal
resistance, Electrolyte level of all cells in station battery, Unintentional dc grounds, and Cell/unit internal
ohmic values of station battery) listed in the table or just one of them to take advantage of forgoing the
maximum maintenance interval for an activity and going to the 6 year maximum maintenance interval to verify
that the monitoring device is calibrated. A FAQ concerning this question would be beneficial to those who are
concerned that they must monitor all seven activities in order to take advantage of condition based
maintenance for the station dc supply. Also an explanation of how each of the 7 monitoring activities relates
to a specific station dc supply maintenance activity might be beneficial.
Response: Thank you for your comments. Table 1-4 has been further revised to address your concern (see Table 1-4(f)). The SDT decided to eliminate
the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The SDT considered your
comments during this activity. Table 1-4 has been revised to remove “state of charge” from the activities.
44
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
Ingleside Cogeneration LP
Indiana Municipal Power Agency
No
South Carolina Electric and Gas
No
Entergy Services
Yes
Section II.2.B references R4.3 which has been revised to R4.2.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Duke Energy
Yes
There are typographical errors on the FAQ Requirements Flowchart (should be R4.1.1 and R4.1.2 instead of
R4.4.1 and R4.4.2).
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
Wisconsin Electric Power
Company
Yes
Table 1-4 requires an activity to verify the state of charge of battery cells. There are no possible options for
meeting this requirement listed in the FAQ document. Unlike other terms used in the standard, this term is
not mentioned or defined in the FAQ. To comply with this standard, the SDT needs to provide more
guidance. For example, for VLA batteries the measured specific gravity could indicate state of charge. For
VRLA batteries, it is not as clear how to determine state of charge, but possibly this can be determined by
monitoring the float current.
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity. Table 1-4 has been revised to remove
“state of charge” from the activities.
Independent Electricity System
Operator
No
American Electric Power
Yes
With such a complex standard as this, the FAQ and Supplementary Reference documents do aid the
Protection System owner in demystifying the requirements. But AEP holds strong doubt on how much weight
the documents carry during audits. It would be better to include them as an appendix in the actual standard,
but in a more compact version with the following modifications:
45
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
1. The section “Terms Used in PRC-005-2” is blank and should be removed as it adds no value.
2. Section I.1 and Section IV.3.G reference “condition-based” maintenance programs. However, no where
in the standard is the term “condition-based” used in reference to defining ones PSMP. The FAQ should
be revised to remove reference to a condition-based PSMP; alternatively the Standard could be revised to
include the term “condition-based” within the Standard Requirements and Table 1.
3. The second sentence to the response in Section I.1 appears to have a typographical error “... an entity
needs to and perform ONLY time-based...”.
Response: Thank you for your comments. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do
not belong as part of the standard. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
ITC
No
ISO New England Inc.
Yes
See response to Question 5 below.
Response: Thank you for your comments. Please see our response to your comments in Question 5.
Nebraska Public Power District
No
CenterPoint Energy
Yes
The need for an FAQ document, in addition to an extensive Supplementary Reference document, illustrates
the complexity and impracticality of the proposed Standard. CenterPoint Energy does not support the
development of an additional type of document, that is, the FAQ document. CenterPoint Energy recommends
eliminating the FAQ document and using only a Supplementary Reference” document. This would also
provide the benefit of not having contradictory information in the two documents.
Response: Thank you for your comments. The SDT believes that entities should be able to implement the standard without either the FAQ or
Supplementary Reference. However, the SDT is also convinced that many entities may find the supporting discussion/rationale useful, particularly to
assist them in implementing the standard in an efficient manner. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents
into the Supplementary Reference Document as appropriate.
American Transmission
Company
Yes
1. FAQ Protective Relays 2.D: The last sentence is not consistent with the discussions at the “March 2010,
Standard Drafting Team Meeting, Project 2007-17”. The understanding from that meeting was that the
relay settings would be verified that the “as left” settings were the same as the “as found” settings and that
the intent was not to verify the settings against a Master Record. Therefore the intent is that the tester will
46
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
verify that no setting changes were made as part of the testing process.
Please include this clarification with the language in the standard.
2. FAQ Group by Type of Maintenance Program 2.B: We agree with the use of either the in-service date
or the commissioning date to start the initial due date calculation for maintenance.
Please include this clarification with the language in the standard.
Response:
1. The intent is that the settings of the component be as specified at the conclusion of maintenance activities, whether those settings may have
“drifted” since the prior maintenance or whether changes were made as part of the testing process.
2. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do not belong as part of the standard. The
SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The
SDT considered your comments during this activity.
Consumers Energy
No
Southern Company Generation
Yes
1. On Page 3, please revise the flow chart references to R4.4.1 and R4.4.2. Also, add (Attachment A) to the
“Performance Based” label.
2. On Page 7, Section I, correct the reference of R4.3 to R4.2.
3. Also, revise the last paragraph in Section I to the following: The entity should assure that the component
performance is acceptable at the conclusion of the maintenance activities or initiate resolution of any
indentified maintenance correctable issues.
4. On Page 7, Section J, correct the reference of R4.3 to R4.2.
5. On Page 10, Section D, a reference is made to “trip test” Table 1. Should this be Table 1-5? The exact
phrase “trip test” is not used in the standard. Should it be?
6. On Page 10, Section e, the phrase “functional (or operational) trip test” is not used in the standard –
should it be?
7. On Page 11, Section 5A, correct the reference of Table 1 to Table 1-4 in the Station Battery and
Emerging Technologies paragraph.
8. On Page 12, Section B, correct the reference of Table 1 to Table 1-4. (2X)
47
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
9. On Page 13, Section F, correct the reference of Table 1 to Table 1-4. (1X)
10. On Page 14, Section G, correct the reference of Table 1 to Table 1-4. (3X)
11. On Page 14, Section G, change the text “The first maintenance activity” to The capacity testing activity”.
12. On Page 14, Section G, change the text “The second maintenance activity”, to The internal ohmic
measurement activity”.
13. On Page 14, Section H, correct the reference of Table 1 to Table 1-4. (1X)
14. On Page 17, Section C, correct the reference of Table 1 to Table 1-5. (1X)
15. Please address what is meant by “Battery terminal connection resistance” on Page 14, Table 1-4 of the
standard.
Response: Thank you for your comments. The discussion within the Supplementary Reference and FAQ are informative, not normative, and thus do
not belong as part of the standard. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the Supplementary
Reference Document as appropriate. The SDT considered your comments during this activity.
US Bureau of Reclamation
No Comment
Alliant Energy
No
LCRA Transmission Services
Corporation
Yes
MidAmerican Energy
Yes
The Frequently Asked Questions should have clear disclaimers indicating that nothing in the reference is
mandatory and enforceable.
Response: Thank you for your comments. NERC establishes that only the Standard is mandatory and enforceable, and Section F of the standard
introduces this (and the Supplementary Reference Document) as presenting supporting discussion. The SDT decided to eliminate the FAQ document
and incorporate the FAQ’s contents into the Supplementary Reference Document as appropriate. The introductory area of the Supplementary
Reference Document will be revised to address your concern.
Ameren
No
This document is helpful.
Xcel Energy
Yes
The changes in the standard and edit attempts on the FAQ have created some problems and confusion.
Examples; The new FAQ I.1 answer does not make sense “An entity needs to and perform ONLY time-based
48
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 4 Comment
. . .” FAQ II.1.A: Requirement R1 no longer contains the statement that “use voltage, current, or phase angle
to detect anomalies” so the answer to this FAQ is now out of synch with the standard. FAQ II.2.B –
“Restoration” is no longer in the PMSP and has been changed to “Restore” and R4.3 no longer exists. FAQ
II.2.I and II.2.J answers also references non-existent requirement R4.3. These are just some examples of
fidelity issues that have been created by the most recent edit of PRC-005-2 – we did not perform a review of
the entire document. The SDT should be commended for its efforts on the FAQ document as it is exceedingly
helpful and well written. However, it needs to be brought back into alignment with the Standard. It is
apparent that this fidelity check between the standard and the FAQ was not done prior to this posting. Finally,
it seems some FAQs would be warranted to help explain the intent of new requirements R1.5 and R4.2
especially in regards to non-quantifiable maintenance results such as battery visual inspection as well as to
provide examples of “other equivalent parameters” acceptance criteria for the various component types
included in the Protection System definition
Response: Thank you for your comments. The SDT decided to eliminate the FAQ document and incorporate the FAQ’s contents into the
Supplementary Reference Document as appropriate. The SDT considered your comments during this activity.
49
Consideration of Comments on Protection System Maintenance [Project 2007-17]
5. If you have any other comments on this Standard that you have not already provided in response to the prior questions, please
provide them here.
Summary Consideration: Many commenters disagreed with Requirement R1, Part 1.5 which was added in the
previous draft; in response, the SDT removed Requirement R1, Part 1.5 from the standard. Commenters also
observed that Requirement R1, Part 1.4 was redundant with Requirement R2, and the SDT removed R2 in
response to these comments. Many commenters objected to 4.2.5.5 in the Applicability Section; the SDT removed
this clause.
Organization
Pepco Holding Inc & Affiliates
Yes or No
Question 5 Comment
Yes
1. What "specific statistical data" was used to validate that unmonitored communication systems are 24 times
more prone to failure than unmonitored protective relays? Comments were previously submitted that the 3
month interval for verifying unmonitored communication systems was much too short. The SDT declined to
change the interval and in their response stated: "The 3 month intervals are for unmonitored equipment and
are based on experience of the relaying industry represented by the SDT, the SPCTF and review of IEEE
PSRC work. Relay communications using power line carrier or leased audio tone circuits are prone to channel
failures and are proven to be less reliable than protective relays." The 3 month interval is very burdensome
and our experience does not appear to justify. A longer interval should be reconsidered.
Response: Thank you for your comments. The SDT reasserts that the 3 month intervals are for unmonitored equipment and are based on experience
of the relaying industry represented by the SDT, the SPCTF and review of IEEE PSRC work. Relay communications using power line carrier or leased
audio tone circuits are prone to channel failures and are proven to be less reliable than protective relays. If an entity’s experience is that these
components require less-frequent maintenance, a performance-based program in accordance with R3 and Attachment A is an option.
Pacific Northwest Small Public
Power Utility Comment Group
No
Tennessee Valley Authority
Yes
1R4 - “Identification of the resolution” and “Initiation of the resolution” are very distinct activities. In other
places in this standard the requirement is for the resolution to be initiated, that is identified in a corrective
maintenance work order, “identification of a resolution” requires technical expertise and can be difficult to
track and might change over time for a particular problem.
Proposed Change: Change “identification” to “initiation” in phrase “including identification of the resolution...”.
Overall: NERC is making significant changes to this sizeable standard and only allowing minimum comment
period. While this is a good standard that has clearly taken many hours to develop, we are primarily voting
50
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
“NO” because of the hurried fashion it is being commented, voted, and reviewed.
Response: Thank you for your comments. Requirement R4 has been revised.
Northeast Power Coordinating
Council
Yes
1. In general, the standard is overly prescriptive and complex. It should not be necessary for a standard at
this level to be as detailed and complex as this standard is. Entities working with manufacturers, and
knowledge gained from experience can develop adequate maintenance and testing programs.
2. Why are “Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation)...” not included? The output contacts from these devices
are oftentimes connected in tripping or control circuits to isolate problem equipment.
3. Due to the critical nature of the trip coil, it must be maintained more frequently if it is not monitored. Trip
coils are also considered in the standard as being part of the control circuitry. Table 1-5 has a row
labeled “Unmonitored Control circuitry associated with protective functions”, which would include trip coils,
has a “Maximum Maintenance Interval” of “12 Calendar Years”. Any control circuit could fail at any time,
but an unmonitored control circuit could fail, and remain undetected for years with the times specified in
the Table (it might only be 6 years if I understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure, then the system must be
operated in real time assuming that that breaker will not trip for a fault or an event, and backup facilities
would be called upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker unable to trip),
instead of one line tripping, you might have many more lines deloaded or tripped because of a bus having
to be cleared because of a breaker failure initiation. The bulk electric system would have to be operated
to handle this contingency.
4. In reference to the FAQ document, Section 5 on Station dc Supply, Question K, clarification is needed
with respect to dc supplies for communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation, would the standard apply to
these batteries or not?
5. To define terms only as they are used in PRC-005-2 is inviting confusion. Although they may be unique
to PRC-005-2, some or all of them may be used in future standards, some already may be used in
existing standards, and may or may not be deliberately defined. Consistency must be maintained, not
only for administrative purposes, but for effective technical communications as well.
6. What is the definition of “Maintenance” as used in the table column “Maximum Maintenance Interval”?
Maintenance can range from cleaning a relay cover to a full calibration of a relay.
7. A control circuit is not a component, it is made up of components.
51
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
8. Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify calibration tolerances or other
equivalent parameters...” means, and may be subject to different interpretations by entities and
compliance enforcement personnel.
9. In the Implementation plan for Requirement R1, recommend changing “six” to fifteen. This change would
restore the 3-month time difference that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require regulatory approval. It will ensure
equity for those entities located in jurisdictions that do not require regulatory approval, as is the case in
Ontario.
10. The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It seems to continue to the next
page to a new box. There are multiple activities without clear delineation.
11. Regarding station service transformers, Item 4.2.5.5 under Applicability should be deleted. The purpose
of this standard is to protect the BES by clearing generator, generator bus faults (or other electrical
anomalies associated with the generator) from the BES. Having this standard apply to generator station
service transformers, that have no direct connection to the BES, does meet this criteria. The FAQs
(III.2.A) discuss how the loss of a station service transformer could cause the loss of a generating unit,
but this is not the purpose of PRC-005. Using this logic than any system or device in the power plant that
could cause a loss of generation should also be included. This is beyond the scope of the NERC
standards.
12. The Drafting Team must respond to the following concerns raised in the FERC NOPR, Docket No. RM105-000, Interpretation of Protection System Reliability Standard, December 16, 2010) to “prevent a gap in
reliability”.
a. Any component that detects any quantity needed to take an action, or that initiates any control
action (initial tripping, reclosing, lockout, etc.) affecting the reliability of the Bulk-Power System
should be included as a component of a Protection System, as well as any component or device
that is designed to detect defective lines or apparatuses or other power system conditions of an
abnormal or dangerous nature and to initiate appropriate control circuit actions.
b. The exclusion of auxiliary relays will result in a gap in the maintenance and testing of Protection
Systems affecting the reliability of the Bulk-Power System.
c.
Excluding the maintenance and testing of reclosing relays will result in a gap in the maintenance
and testing of relays affecting the reliability of the Bulk-Power System.
d. Not establishing the specific requirements relative to the scope and/or methods for a
maintenance and testing program for the DC control circuitry that is necessary to ensure proper
52
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
operation of the Protection System, including voltage and continuity.
Response: Thank you for your comments.
1. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently monitored for
compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that minimum activities also need be
prescribed. If an entity’s experience is that components require less-frequent maintenance, a performance-based program in accordance with
Requirement R3 and Attachment A is an option.
2. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection System definition.
Also, there is currently no technical basis for the maintenance of the devices which respond to non-electrical quantities on which to base
mandatory standards related either to activities or intervals. Absent such a technical basis, we are currently unable to establish mandatory
requirements, but may do so in the future if such a technical basis becomes available.
3. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year interval. As a regional
entity, you can specify Supplementary regional requirements to maintain these devices more frequently if you desire.
4. With respect to dc supply associated only with communications systems, we prescribe, within Table 1-2, that the communications system must be
verified as functional every 3 months, unless the functionality is verified by monitoring. The specific station dc supply requirements (Table 1-4) do
not apply to the dc supply associated only with communications systems. The SDT has decided to eliminate the FAQ and incorporate topics and
discussion from the FAQ within the Supplementary Reference Document. Your comments will be considered within that activity.
5. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms, either now or in the
future, may not be consistent with the terms as used here. They are defined only for clarify within this standard. The SDT will confirm with NERC
staff that this approach is acceptable.
6. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are specified in the Activities
column. The term is capitalized in the column title in conformance with normal editorial practice as a title, rather than as a definition
7. For purposes of this standard, the control circuit IS defined as one component type.
8. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary. Therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
9. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making it consistent with
the remainder of the Implementation Plan.
10. Table 1-4 has been further modified for clarity
11. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
53
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
12. The FERC NOPR is a notice-of-proposed-rulemaking and is not yet a directive. At such a time as a directive is published, NERC will take the
necessary actions to address it.
Platte River Power Authority
System Maintenance
Yes
1. Please clarify what is required by R1.5: Identify calibration tolerances or other equivalent parameters for
each Protection System component type that establish acceptable parameters for the conclusion of
maintenance activities required. Is the intent a brief summary for each component type in the PSMP that
would cover all equipment within that component type, or is it a detailed list of each piece of equipment
within each component type?
2. The inclusion of dated check-off lists in M4 provides much needed clarity to the list of evidence.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address
various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document,
Section 8 for a discussion of this.
2. Thank you for your support.
Electric Market Policy
Yes
1. The draft to PRC-005-2 contains defined terms that upon approval will remain with the standard rather than
being moved to the Glossary of Terms. These terms when used in the Requirements are not designated in
any way (e.g., capitalization, bold, etc.) to point the reader back to the in-standard definition.
2. Need to explicitly state the intent of the SDT to either (1) use the newly defined term “Protection System
(modification)” only in this standard (PRC-005-2) or (2) replace the existing definition of the existing term in
the “Glossary of Terms Used in NERC Reliability Standards” with the proposed definition for the existing term.
3. The language used in Footnote 1 on Attachment A does not agree with the definition of Countable events
provided elsewhere in the draft standard. Suggest footnote be removed.
4. Requirement R1.5 uses the phrase “or other equivalent parameters” which is confusing. Suggest replacing
with “or acceptance criteria.” Requirement R1.5 should read as follows: “Identify calibration program.” The
currently proposed language focuses on specific calibration tolerances and acceptance parameters. These
tolerances are developed on a per device, per location basis and would be captured at a procedural level, not
a program level. To add this at a program level would only complicate the program and would not lend any
improvement to the reliability of the bulk electric system. We recommend maintaining a general calibration
requirement, similar to what is stated above, for an entity to develop their calibration program.
5. Requirement 2 Component should be replaced with Component Type. Creating a program to monitor the
54
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
equipment at this level of equipment would not add any value to the bulk electric system as all components
should already be included in component type maintenance tasks. Recommend removing the definition of
Component.
6. The requirement to address “monitoring attributes” in Requirement 2 for time based maintenance program
is unclear, onerous and unnecessary for a reliable protection system program.
7. Requirement (R4) should identify correctible maintenance issues not the resolution of these issues. The
language in R4.2 should strike correcting maintenance issues related to R1.5 and instead state: Any
maintenance correctible issues found during the maintenance activity should be identified”
8. Table 1.2 change time frame from 3 months to 3 years.
Response: Thank you for your comments.
1. The standard capitalizes defined terms only when they refer to terms which are (or will be) in the NERC Glossary of Terms. Terms will generically
be capitalized when appearing at the beginning of a sentence or within a title, in accordance with common editorial practice.
2. The statement of the definition has been revised in the standard as “NERC Board of Trustees Approved Definition”, but will remain in the posted
draft standard until it is successfully balloted for the convenience of stakeholders.
3. The footnote has been removed.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to address
various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference Document,
Section 8 for a discussion of this.
5. The SDT disagrees; monitoring attributes must be present on the individual components as actually installed, not to the overall component type.
6. The SDT believes that the verifiable presence of the monitoring attributes on the individual components as installed is a necessary element of
using the extended maintenance intervals that result from the monitoring. If you consistently use specific monitoring attributes on all components
within a group, they may be able to address these attributes on a global basis. If an entity does not wish to document these attributes, they are
free to apply the maintenance intervals and activities specified for the unmonitored components.
7. Requirement R4 has been revised. The SDT believes it important that the entity initiate resolution of maintenance correctable issues, in addition to
simply identifying them.
8. The SDT believes that the 3-month interval is proper for verification of the functionality of unmonitored communications systems.
Bonneville Power Administration
Yes
Some of the maintenance tasks need to be defined:
1. The state of charge of each individual cell may need to be better defined. There are means to verify the
55
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
state of charge of the entire bank, but not each individual cell.
2. Battery continuity needs to be defined.- There is no mention to what the limits are for the "other equivalent
parameters" when performing maintenance activities, just that they need to be identified. There are a
large number of battery models which creates a large contrast of parameters, which cannot be grouped
together. It is also difficult to get baseline values for older battery models which could result in moving
baselines until they become more accurate as the database is populated.
3. If corrective actions are required, is there a maximum allowable duration for when they need to be
resolved?
4. The maximum allowable maintenance for station batteries (impedance testing and performance/service
testing) is too frequent and suggest an extension or alternative testing methods to stay in compliance.
The frequency with which BPA performs the 18 month maintenance tasks as prescribed in the standard
are on a 24 month interval along with visual inspections and voltage measurements monthly.BPA has
seen success with this maintenance program with the ability to identify suspect cells or entire banks with
adequate time to perform corrective actions such as repairs or replacements.
5. BPA also does not perform routine capacity testing, this is an as required maintenance task to
confirm/validate our other test results if needed. BPA would like to see clarification for these issues before
we can fully support this standard.
Response: Thank you for your comments.
1. Table 1-4 has been revised to remove “state of charge” from the activities.
2. This is thoroughly discussed in Section 15.4 of the Supplementary Reference Document.
3. No. The SDT appreciates that some corrective actions for maintenance correctable issues may take an extended period of time to complete, and
has therefore not included completion of the corrective actions within PRC-005-2.
4. The SDT believes that the 18-month interval is proper for these activities.
5. For vented lead-acid and valve-regulated lead batteries, alternative activities are specified if desired instead of capacity tests. If Ni-Cad batteries
are used, capacity tests are required.
Santee Cooper
No
We do not agree with the addition of Requirements 1.5 and 4.2 without work on or review by the Power
System Maintenance and Testing Drafting Team. While some maintenance activities on some component
types (such as calibration testing of electromechanical relays) translate inherently well into these
requirements, the requirements of tolerances and documentation do not fit as well to all maintenance
activities on other types of equipment considered part of the protective system. These requirements need to
56
Consideration of Comments on Protection System Maintenance [Project 2007-17]
Organization
Yes or No
Question 5 Comment
be worked on through the drafting team to make them viable and effective for all protective system
component types.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
NERC Staff
Yes
1. Commissioning (Initial) Testing: During development of PRC-005-2, NERC staff has observed a trend in
system disturbances involving Protection System problems that should have been identified and corrected
during commissioning (initial) testing. While NERC staff recognizes that the addition of commissioning
testing may be unrealistic at this stage in the standard drafting process, we want to emphasize its
importance. If the SDT chooses to leave commissioning testing out at this juncture, we plan to pursue other
avenues to ensure its eventual inclusion through a separate standards project.
NERC staff agrees with the SDT’s opinion that without commissioning testing, a registered entity
responsible for compliance with this standard cannot provide proof of its interval testing period as required
by the standard. As soon as the entity puts the protective scheme into service, time “0” for interval testing
begins. The next testing interval would be some specific number of years in the future from time “0.
”An entity’s failure to properly commission new protection system equipment has caused or exacerbated
several recent events, greatly impacting BPS reliability. The following are examples of errors that were not
detected during commissioning. These undetected errors were observed by NERC staff during event
analysis and investigation activities:
oFailure to apply correct relay settings. This has occurred repeatedly and has been due to improper
procedures, poor document control, misapplication or miscalibration of the relay, or a combination of
the above.
oFailure to install the proper CT or PT ratio occurred due to poor document control practices and
resulted in an undesired protection system response after the equipment was placed in service.
oFailure to conduct a functional test of new control circuits to the schematic diagram resulted in an
undesired protection system response after equipment was placed in service.
oAn incorrect CT ratio was not detected during commissioning, and the equipment was subsequently
placed in service. Because in-service testing was not performed, the error remained undetected until
the relay misoperated during a fault.
Many of the above conditions can remain undetected for extended periods, until they are revealed by a
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relay misoperation during fault or heavy load conditions. The affects resulting from these cases could have
been prevented with proper commissioning testing. We believe that by requiring commissioning testing for
new protection system equipment, the reliability of BPS would be improved.
2. Requirement 2:In Requirement 2, it is unclear what is meant by “shall verify those components possess
the monitoring attributes identified in Tables 1-1 through 1-5 in its PSMP” because the use of terms in the
Requirement is not consistent with the column headings used in Tables 1-1 through 1-5. It also is not
clear that components need not possess all attributes; rather, they must possess all attributes consistent
with the Maximum Maintenance Interval specified in an entity’s PSMP.
NERC staff recommends revising R2 to provide additional clarity as follows:”Each Transmission Owner,
Generator Owner, and Distribution Provider that uses maintenance intervals for monitored Protection
Systems described in Tables 1-1 through 1-5, shall verify those components possess the monitoring
attributes Component Attributes identified in the first column of Tables 1-1 through 1-5 consistent with the
Maximum Maintenance Interval specified in its PSMP.”
Response: Thank you for your comments.
1. Thank you for your comments.
2. Requirement R2 of the standard has been modified as you suggested.
FirstEnergy
Yes
REQUIREMENTS
1. Requirement R1 - Subpart 1.5 - We do not support this subpart for the following reasons and offer the
following suggestions:
To satisfy R1.5, a calibration tolerance or other equivalent parameter would have to be established for each
item included in the definition. Many devices which may have similar functionality may also have different
performance criteria that would preclude the use of a "one size fits all" calibration tolerance. Many of these
criteria are provided by the manufacturer and often vary by manufacturer for a similar device. It would be very
difficult to specify in your program all of the calibration tolerances or other equivalent parameters associated
with the protection system components. Therefore, we suggest the team delete Subpart 1.5 of Req. R1, and
revise Subpart 4.2 of Req. R4 to read: "Initiate resolution of any identified maintenance correctable issues at
the conclusion of maintenance activities for Protection System components."
IMPLEMENTATION PLAN
2. On pg. 2 of the implementation plan, under "Retirement of Existing Standards", the statement "The
existing standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired upon regulatory
approval of PRC-005-2" is not accurate. Since the new PRC-005-2 standard allows for at least 12 months
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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to become compliant with Requirement R1 - establish a Protection System Maintenance Program (PSMP)
-the existing standards are still effective during this time. Additionally, we have concerns with the
"General Considerations" describing protocols for compliance audits conducted during the allowed 12
month development period of the PSMP and that entities could specify for "each component type"
whether maintenance of that component is being performed according to its maintenance program under
the "retired" PRC maintenance standards or the new PRC-005-2 standard. In our view, this creates a
level of compliance complexity for both the Registered Entity and Regional Entity that should be avoided
in the transition to PRC-005-2. FirstEnergy proposes that the Implementation Plan state that the existing
standards remain in effect for one year past applicable approval (NERC Board or Regulatory) and that
they are retired coincident with the one-year transition to Requirement R1 of PRC-005-2 which would
establish all Registered Entities having a new PSMP per the expectations of PRC-005-2. At that time all
entities would be required to be under the new PRC-005-2 standard and begin implementing their PSMP
per the phased-in Implementation Plan for the remaining requirements. To summarize, per our above
discussion we propose the team perform the following:1. Revise the Implementation Plan section titled
"Retirement of Existing Standards" section to read as follows: "The existing Standards PRC-005-1, PRC008-0, PRC-011-0 and PRC-017-0 shall be retired on the first day of the first calendar quarter twelve
months following applicable regulatory approvals, or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter 12 months following the Board of Trustees
adoption"2. Remove the entire "General Considerations" section from the Implementation Plan.
3. The bulleted item under the section titled "Implementation plan for R1" has a discrepancy in the time
allowed to implement R1 between entities applicable to regulatory approval of the standard versus those
in jurisdictions where no regulatory approval is needed and base their adherence per the Board of
Trustee adoption. Please revise to reflect a 12 month transition period for each.
DEFINITIONS
4. Maintenance Correctable Issue - This is a maintenance standard and this concept gets into the long term
repair activities. Is this really appropriate in this standard? If NERC feels repairing is critical to BES
reliability, then they should probably initiate a standard in that area.
5. Component - Regarding the phrase "local zone of protection", why is this in quotes? Is there a narrow
definition for this? If so, this term should be defined also.
DATA RETENTION SECTION
6. 1.3 Regarding the data retention for Req. R3 and R4, it is not practical to keep potentially 24 years of data
for components that are maintained every 12 years. We suggest rewording this to "For R3 and R4,
Transmission Owner, Generator Owner, and Distribution Provider shall each keep documentation of the most
recent performances of each distinct maintenance activity for the Protection System components, or to the
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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Question 5 Comment
previous scheduled audit date, whichever is longer".
7. ATTACHMENT A - FOOTNOTE 1This footnote regarding countable events needs to be revised to match the
definition of countable events found at the beginning of the standard.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. The SDT had concluded that Requirement R2 is redundant with Requirement R1, Part 1.4, and has deleted Requirement R2 (together with the
associated Measure and VSL).
3. The Implementation Plan for Requirement R1 has been modified as you suggest.
4. The SDT believes that the activities necessary to restore a Protection System component to proper service is an essential part of the PSMP.
Please note that the related requirements only address initiation of the corrective actions, not completion, in deference to the extended period of
time that some of these activities may take.
5. The quotes have been removed from the definition of component. However, the SDT believes that this term is a commonly-understood term within
the industry.
6. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding one to validate that entities have been in compliance since the last
audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data retention in the posted standard to establish
this level of documentation. This seems to be consistent with the current practices of several Regional Entities.
7. This footnote has been removed.
Florida Municipal Power Agency
Yes
1. UFLS and UVLS maintenance and testing is greatly expanded, e.g., we interpreted PRC-008/011 as
being only the UFLS/UVLS equipment. The new PRC-005 sweeps in other protection system
components, e.g., communications (probably not applicable), voltage and current sensing devices (e.g.,
instrument transformers), Station DC supply, control circuitry. What's key about this is that these
components are all part of distribution system protection, so, these activities would not be covered by
other BES protection system maintenance and testing. I'm sure we are testing batteries and the like, but,
we are probably not testing battery chargers and control circuitry, and, in many cases distribution circuits
are such that it is very difficult, if not impossible, to test control circuitry to the trip coil of the breaker
without causing an outage of the customers on that distribution circuit. There is no real reliability need for
this either. Unlike Transmission and Generation Protection Systems which are needed to clear a fault and
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may only have one or two back-up systems, there are thousands and thousands of UFLS relays and if
one fails to operate, it will not be noticeable to the event. It does make sense to test the relays themselves
in part to ensure that the regio0nsl UFLS program is being met, but, to test the other protection system
components is not worthwhile. Note that DC Supplies and most of the control circuitry of distribution lines
are "tested" frequently by distribution circuits clearing faults such as animals, vegetation blow-ins,
lightning, etc., on distribution circuits, reducing the value of testing to just about null. However, this version
is better than prior versions because it essentially requires the entity to determine it's own period of
maintenance and testing for UFLS/UVLS for DC Supply and control circuitry.
2. Applicability, 4.2.1, should reflect the Y&W and Tri-State interpretation (Project 2009-17) of "transmission
Protection System" and should state: "Protection Systems applied on, or designed to provide protection
for a BES Facility and that trips a BES Facility"
3. Applicability, 4.2. - does not reflect the interpretation of Project 20009-10 that excludes non-electrical
protection (e.g., sudden pressure relays) and auxiliary relays. Because the definition of Protection
System (recently approved) does not clearly exclude "non-electrical" protection, the Applicability section
should. For instance, a vibration monitor, steam pressure, etc. protection of generators, sudden pressure
protection of transformers, etc. should not be included in the standard. An alternative is to change the
definition of Protection System to make sure it only includes electrical
4. Table 1-4 requires a comparison of measured battery internal ohmic value to battery baseline. Battery
manufacturers typically do not provide this value and one manufacturer states that the baseline test are to
be performed after the battery has been in regular float service for 90 days. It is unclear how to comply
with the requirement for the initial 90 days. Additionally, we would recommend that this requirement be
modified to permit an entity to establish a “baseline” value based on statistical analysis of multiple test
results specific to a given battery manufacturer/model. Several commenters previously expressed their
concerns with performing capacity tests. While this may just be an entity’s preference, allowing an entity
to establish a baseline at some point beyond the initial installation period would give entities the option of
using the internal resistance test in lieu of a capacity test.
5. Small entities with only one or two BES substations may not have enough components to take advantage
of the expanded maintenance intervals afforded by a performance-based maintenance program.
Aggregating these components across different entities doesn’t seem too logical considering the
variations at the sub-component level (wire gauge, installation conditions, etc.)
6. Trip circuits are interconnected to perform various functions. Testing a trip path may involve disabling
other features (i.e. breaker failure or reclosing) not directly a part of the test being performed. Temporary
modifications made for testing introduce a chance to accidentally leave functions disabled, contacts
shorted, jumpers lifted, etc. after testing has been completed. Trip coils and cable runs from panels to
breaker can be made to meet the requirements for monitored components. The only portions of the
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Consideration of Comments on Protection System Maintenance [Project 2007-17]
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circuitry where this may not be the case is in the inter- and intra-panel wiring. Because such portions of
the circuitry have no moving parts and are located inside a control house, the exposure is negligible and
should not be covered by the requirements. Entities will be at increased compliance risk as they struggle
to properly document the testing of all parallel tripping paths. The interconnected nature of tripping circuits
will make it difficult to count the number of circuits consistently for the purpose of calculating a VSL.
Response: Thank you for your comments.
1. For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat constrained relative to similar
activities for Protection Systems in general. Regardless, without proper functioning of these component types, UFLS and UVLS will not respond
as expected, and will therefore degrade BES system reliability, particularly during the stressed system conditions for which UFLS and UVLS are
installed. Relative to control circuitry, Table 1-5 specifically excludes UFLS and UVLS from maintenance activities relate to the interrupting device
trip coil.
2. This interpretation is not yet approved by FERC. When this interpretation is approved, the SDT will incorporate it within PRC-005-2
3. The recently-balloted revision of the definition of Protection System, which has been approved by the NERC Board of Trustees and will soon be
filed with FERC for approval, clearly includes only protective relays that respond to electrical quantities. As for auxiliary relays, the interpretation
to which you refer states that they are not explicitly included, but are included to the degree that an entity’s Protection System control circuitry
addresses them (which has been identified as a reliability gap), and are being added to PRC-005-2 to resolve that gap.
4. Typical baseline values for various types of lead-acid batteries can be obtained from the test equipment manufacturer, perhaps the battery vendor,
and perhaps other sources for batteries that are already in service. For new batteries, the initial battery baseline ohmic values should be measured
upon installation and used for trending.
5. Entities are not required to use performance-based maintenance programs. Requirement R3 and Attachment A are provided for the use of entities
that can (and desire to) avail themselves of this approach.
6. The requirement relative to control circuitry does not explicitly require trip or functional testing of the entire path; it requires that entities verify all
paths without specifying the method of doing so. Please see Section 15.5 of the Supplementary Reference Document for a detailed discussion.
PSEG Companies ("Public
Service Enterprise Group
Companies")
Yes
1. The facilities listed in 4.2.5.5 include protection systems for “system connected” station service
transformers associated with generators that are part of the BES. If a station service transformer is
connected to a non BES bus then it would still fall under the PRC5 applicability requirements as written.
The FAQs discuss relays associated with station auxiliary loads as not included in the program
requirements. The non BES connected transformers should be included in that same category of
equipment.
2.
From the FAQ’s - “Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel
handling equipment, etc., need not be included in the program even if the loss of the those loads could
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result in a trip of the generating unit. Furthermore, relays which provide protection to secondary unit
substation (SUS) or low switchgear transformers and relays protecting other downstream plant electrical
distribution system components are not included in the scope of this program even if a trip of these
devices might eventually result in a trip of the generating unit.” Suggest the following added details be
considered to be consistent with intent of BES connected facilities.
Revise Description 4.2.5.5 as follows: “Protection systems for BES system connected station service
transformers connected for generators that are part of the BES”.
3. With respect to DC supply systems (batteries, chargers),the implementation plan is too aggressive.
Some battery checks will have to be done on a 3 month interval, and entities will be required to be
compliant with this new frequency in 1 Calendar year. This timeframe is unreasonable and needs to be
pushed back to at least 2 years.
4. PSEG is also asking for clarification to the Supplementary reference document: On page 4, section 2.3 it
states that the standard is designed to ONLY include “relays that detect a fault on the BES and take
action in response to that fault”. If PSEG is interpreting this correctly, this is a massive shift from the
existing PRC-005-1 standard. The existing PRC-005-1 includes all distribution relays that trip a BES
breaker to be part of the scope. In this revision, PRC-005-2 would exclude those distribution relays if they
are designed to act for faults on the distribution system. PSEG would fully support this interpretation.
PSEG would like this clarified and confirmed. This is very important.
Response: Thank you for your comments.
1. The Applicability of the draft Standard had been revised to remove “system-connected station service transformers”.
2. The FAQs have been merged into the Supplementary Reference Document; this discussion has been revised.
3. The Implementation Plan for Requirement R4 has been revised to add one year to all established dates.
4. Section 2.3 of the Supplementary Reference Document has been extensively revised, and the sentence to which you refer is no longer present. As
for your comment, “The existing PRC-005-1 includes all distribution relays that trip a BES breaker to be part of the scope,” the SDT believes that
this is an element of a Regional practice regarding PRC-005-1, and entities should expect to comply with PRC-005 as established within the NERC
Standard and further defined by Regional practice.
MRO's NERC Standards Review
Subcommittee
Yes
1. In the Purpose statement delete “affecting” and replace it with “protecting”. The purpose of the standard
deals with systems that protect the BES.
2. In sections R1 and R4.2.1 delete “applied on” as unneeded and potentially confusing. The goal is to
cover Protection Systems designed to protect the BES.
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3. The NSRS believes that Article 1.4 needs to be deleted from the standard. It is redundant and serves not
purpose.
4. The NSRS believes that Article 1.5 needs to be deleted from the standard. There is a major concern on
what an “acceptable parameter” is and how it would be interpreted by the Regional Entities.
5. The NSRS believes that Article 4.2 needs to be deleted from the standard. There is no need for this
article if Article 1.5 is deleted.
6. Section 4.2 Applicable Facilities:
We are concerned with this paragraph being interpreted differently by the various regions and thereby
causing a large increase in scope for Distribution Provider protection systems beyond the reach of UFLS
or UVLS.4.2.1 Protection Systems applied on, or designed to provide protection for, the BES.
The description is vague and open for different interpretations for what is “applied on” or “designed to
provide protection”. According to the November 17, 2010 Draft Supplementary Reference page 4, the
Standard will not apply to sub-transmission and distribution circuits, but will apply to any Protection
System that is designed to detect a fault on the BES and take action in response to the fault. The
Standard Drafting Team does not feel that Protection Systems designed to protect distribution substation
equipment are included in the scope of this standard; however, this will be impacted by the Regional
Entity interpretations of ‘protecting” the BES. Most distribution protection systems will not react to a fault
on the BES, but are caught up in the interpretation due to tripping a breaker(s) on the BES.
7. Section F Supplementary Reference Documents: The references listed in this section refer to 2009 dates
and do not match with the 2010 reference documents supplied for comment.
8. Table 1-4 Component Type Station dc Supply: o “Any dc supply for a UFLS or UVLS system” - This
should not tied to the same testing interval as control circuits. The dc supply system is significantly
different from control circuits and should have a maximum maintenance period as other dc supplies do.
9. Replace the words “perform as designed” on page 14 of Table 1-4 with “operate within defined
tolerances.”
10. Table 1-5 Component Type Control Circuitry:
a. This table allows for unmonitored trip coils for UFLS or UVLS breakers to have “no periodic
maintenance”. “Unmonitored control circuitry associated with protective functions” should also
have an exclusion for UFLS and UVLS circuitry that would allow for “no periodic maintenance”.
b. There is a concern that requiring the electrical testing and maintenance of Electromechanical trip
or Auxiliary devices will force entire bus outages to be scheduled, which will compromise the BES
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reliability more by forcing utilities across the US to unnecessarily take multiple non-faulted BES
elements out of service. Such testing is also likely to introduce human error that will cause
outages such as items outlined in the NERC lessons learned” and therefore such testing will
result in more outages than actual failures.
Response: Thank you for your comments.
1. The “Purpose” is defined by the SAR.
2. Requirement R1 and Requirement R4, Part 4.2.1 have been modified as you suggested.
3. The SDT disagrees; Requirement R1, Part 1.4 supports Requirement R1, Part 1.2, and seems necessary to assure that entities have appropriately
applied the longer intervals associated with monitored components.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. Please see Supplementary Reference Document, Section for a discussion of this. The
associated VSL has also been revised.
5. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
6. Applicability 4.2.1 has been revised to remove ‘applied on”. The SDT believes that this addresses your concern. Applicability 4.2.2 and 4.2.3,
respectively, address UFLS and UVLS specifically, and are not related to Applicability 4.2.1. The Supplementary Reference Document has been
revised to clarify.
7. The date in Clause F of the standard related to the Supplementary Reference Document has been revised.
8. The SDT disagrees. Station dc supply for UFLS/UFLS only is limited in its impact, and the SDT believes that using the same intervals as for the
related control circuits.
9. “Tolerances” does not fully describe the parameters for maintenance of station dc supply; “perform as designed” is far more inclusive.
10. a. The SDT intends that tripping of the interrupting device for UFLS/UVLS is not required, but that the other portions of the dc control circuitry still
shall be maintained. See Section 15.3 of the Supplementary Reference Document.
b. The SDT believes that mechanical solenoid-operated devices share performance attributes (and failure modes) with electromechanical relays
and need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these
devices supports those intervals
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Yes or No
Western Area Power
Administration
No
TransAlta Centralia Generation
Partnership
No
NextEra Energy
Yes
Question 5 Comment
The draft standard is too prescriptive.
1. Requirement R1, Part 1.5 would be overwhelming if approved. Requirement R1, Part 1.5 should be
deleted.
2. Requirement R4, Part 4.2 phrase "established in accordance with Requirement R1, Part 1.5" should be
deleted. The standard without these additional requirements would be sufficient to establish that the
Protection System is maintained and protects the BES.
3. Table 1-2 Component Type Communications Systems Maximum Maintenance Interval of 3 Calendar
Months to verify that the communications system is functional for any unmonitored communications
system is unyielding. Most communication failures are caused by power supply failures which Next Era
does monitor. Based on experience and monitoring of communication power supplies, 12 calendar
months would be adequate. The maximum maintenance interval should be changed from 3 calendar
months to 12 calendar months.
4. Table 1-4, Component Type Station dc Supply Maximum Maintenance Interval of 3 Calendar Months to
inspect electrolyte levels on “Any unmonitored station dc supply not having the monitoring attributes of a
category below. (excluding UFLS and UVLS)” is too stringent. Verifying battery charger float voltage
every 18 calendar months is sufficient to prevent excessive gassing and water loss of battery cells. The
maximum maintenance interval should be changed from 3 calendar months to 6 calendar months.
5. Table 1-4, Component Type Station dc Supply Maximum Maintenance Interval of 3 Calendar Months to
measure the internal ohmic values on “Unmonitored Station dc supply with Valve Regulated Lead-Acid
(VRLA) batteries that does not have the monitoring attributes of a category below. (excluding UFLS and
UVLS)” is too stringent. With the standard’s requirement to verify the float voltage every 18 calendar
months, measuring the internal ohmic values every 6 calendar months would be adequate. The
maximum maintenance interval should be changed from 3 calendar months to 6 calendar months.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
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address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
3. The activity to which you refer is an inspection-based activity based on overall functionality, and addresses functionality of various
communications technologies. If an entity monitors the power supply (as suggested), doing so addresses one portion of the functionality, but
does not address channel integrity, etc.
4. The SDT disagrees, and believes that the specified activities, at the specified intervals, are appropriate.
5. Table 1-4(b) has been revised as you suggested.
City of Austin DBA Austin Energy
Yes
1. The Requirement R1.5. is vague and the intent is not well understood. We recommend it be rewritten to
clarify the intent.
2. In the Requirement R2. the phrase “... shall verify those components possess the monitoring attributes ...”
is too vague and not easily understandable. We recommend this requirement be rewritten.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. The SDT had concluded that Requirement R2 is redundant with Requirement R1, Part 1.4, and has deleted Requirement R2 (together with the
associated Measure and VSL).
PacifiCorp
Southern Company Transmission
Yes
1. Page 5, 4.2. (“or initiate resolution”)
Comment ->> Standard does not specify to “follow through” to completion. Is record of completion
required?
2. Page 5, 1.5. (1.5. Identify calibration tolerances or other equivalent parameters for each Protection
System component type that establish acceptable parameters for the conclusion of maintenance
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activities.)
Comment ->> This is too vague, broad, general and all encompassing. For example, what is the
calibration tolerance for “control circuitry” which is made up of many things such as wiring, auxiliary
relays, trip coils, etc. We currently have calibration tolerances on electromechanical relays but not on all
components of a protection system (communications systems, voltage and current sensing devices,
station dc supply, control circuitry). To try to identify calibration tolerances or other equivalent parameters
for each of these components would be extremely difficult and time consuming. Clarification is needed on
what components or parts of components require calibration tolerances. Another option is to remove this
requirement.
3. Page 5, 4.5. (4.2. Either verify that the components are within the acceptable parameters established in
accordance with Requirement R1, Part 1.5 at the conclusion of the maintenance activities, or initiate
resolution of any identified maintenance correctable issues.)Comment ->>
See comments above on 1.5. Clarification is needed on what is required to verify that the components
are within acceptable parameters. We feel it should be adequate to provide a simple way to verify this
requirement such as to include this in our maintenance procedure (equipment is to be left within
tolerance), provide closed work order, show “checked” check box, provide a simple statement that this
was completed, or etc. We feel that having to provide detailed data such as “as found” / “as left” values is
too complicated and time consuming. Please clarify or consider removing this requirement.
4. Page 6, M.4. (“and initiated resolution”)
Comment ->> Standard does not specify to “follow through” to completion. Is record of completion
required?
5. Page 10, F.1 (July 2009) & F.2 (DRAFT 1.0 - June 2009)
Comment ->> Need new dates and draft number.
6. Page 11 (For microprocessor relays, verify operation of the relay inputs and outputs that are essential ...)
Comment ->> Does this require changing the state of the input contacts or can you just jumper voltage to
the inputs and verify that the microprocessor relays acknowledged the change?
7. Page 17 (“Verify electrical operation(1)of EM trip and auxiliary devices(2).”)
Comment ->> (1) Is it required to verify that trip and auxiliary device contacts change state? If so, please
state as a requirement.(2) We recommend that this requirement only includes EM aux LO / tripping relays
that trip interrupting devices directly. Other EM aux relays such as BFI aux. relays should be excluded.
Please state this clearly in the Standard. Note that these aux relays such as BFI aux relays are included
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in the “unmonitored control circuitry associated with protective functions” requirement and will be verified
on a 12 year interval. (3) Please consider including an elementary diagram to show what is included.
8. Page 17 (Verify all paths of the control and trip circuits.)
Comment ->> Clarification needed. Is it required to perform a full functional test, i.e. trip breakers? Or is
reading DC across trip contacts all that is required?
9. Page 14 (Table 1.4) Change the maintenance interval for unmonitored station dc supply from “3 Calendar
Months” to “4 times annually”. This facilitates compliance to the standard by creating completion
milestones for batteries at the end of each quarter of the year.
10. Page 15 (Table 1.4The standard requires the establishment of a battery baseline for cell/unit internal
ohmic values and the comparison of impedance readings every 18 calendar months to that baseline. Due
to the lack of original impedance readings at the time of installation of the battery. Since in many cases no
such data is available; it needs to be made clear that establishing a baseline from , from manufacturer’s
data, the most recent impedance test, or the first impedance test completed after the adoption of the new
standard is acceptable
Response: Thank you for your comments.
1. No. Full resolution of maintenance correctable issues may require extensive work; the SDT intends that INITIATION of the resolution is all that is
required per PRC-005-2.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
4. No. Full resolution of maintenance correctable issues may require extensive work; the SDT intends that INITIATION of the resolution is all that is
required per PRC-005-2.
5. The date has been revised.
6. The SDT believes that it would be sufficient to apply voltage to the input and observe that the relay responds accordingly.
7. 1 – “Verify” means “Determine that the component is functioning correctly”. The SDT intends that the device be electrically operated, but not that
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additional verification be conducted during the electrical operation. However, the 12-year activity for unmonitored control circuitry would require
verification of full functionality, including all of the related contacts. 2- The standard has been modified in consideration of your comment. 3 – An
elementary diagram would be inappropriate in the standard. Additionally, the design of the control circuitry varies so widely from one application
to another that it seems (to the SDT) that it would not be effective to include such an example in the Supplementary Reference Document.
8. The control circuitry can be tested in overlapping segments. It seems to the SDT that it is not necessary to trip the breakers with the functional
test, as long as the entity performs the activities necessary to demonstrate that all overlapping segments will function properly.
9. The SDT believes that your suggestion would not be effective in assuring periodic maintenance of the dc supply.
10. The station battery baseline value is up to the entity to determine. Please see Clause 15.4.1 of the Supplementary Reference Document for a
discussion of this.
Clark Public Utilities
No
Exelon
Yes
1. In response to Exelon’s comments provided to drafts 1 and 2 of PRC-005, the SDT did not explain why a
conflict with an existing regulatory requirement is acceptable. The SDT responded that a conflict does not
exist and that the removal of grace periods simply is there to comply with FERC Order directive 693. This
response does not answer or address dual regulation by the NRC and by the FERC. Specifically, the
request has not been adequately considered for an allowance for NRC-licensed generating units to
default to existing Operating License Technical Specification Surveillance Requirements if there is a
maintenance interval that would force shutting down a unit prematurely or become non-compliant with
PRC-005. Therefore, Exelon requests that the SDT communicate with the NRC and with the FERC to
ensure a conflict of dual regulation is not imposed on a nuclear generating unit without the necessary
evaluation.
2. In addition, although Exelon Nuclear agrees with the SDT that the maximum allowed battery capacity
testing intervals of not to exceed 6 calendar years for vented lead acid or NiCad batteries (not to exceed 3
calendar years for VRLA batteries) could be integrated within the plant’s routine 18 month to 2 year
interval refueling outage schedule, the SDT has not considered that nuclear refueling outages may be
extended past the 18 month to 2 year "normal" periodicity. There are some unique factors related to
nuclear generating units that the SDT has not taken into consideration in that these units are typically
online continuously between refueling outages without shutting down for any other required maintenance.
Historically, generating units have at times extended planned refueling outage shutdown dates days and
even weeks due to requests from transmission operations, fuel issues and electrical demand. Without the
grace period exclusion currently allowed by existing maintenance programs, a nuclear plant will be forced
to either extend outage duration to include testing on an every other refueling outage (i.e., every four
years to ensure compliance for a typical boiling water reactor) or leave the testing on a six year periodicity
with the vulnerability of a forced shut down simply to perform maintenance to meet the six year periodicity
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or a self report of non-compliance. To ensure compliance, the nuclear industry will be forced to schedule
battery testing on a four year periodicity to ensure the six year periodicity is met, thus imposing a
requirement on nuclear generating units that would not apply to other types of generating units.
3. In addition, Exelon has the following technical comments
a. Sections 4.2.5.4 and 4.2.5.5 need to clearly state that only protection which affects the BES is
within the scope of the PRC-005.
b. There is not enough clarity in the statement “each protection system component type” for one to
stay at the component level vs. dropping to sub-component level. If sub-components reviews are
required, the effort becomes unmanageable. Therefore the Standard should identify calibration
tolerances or other equivalent parameters. Suggest rewording to "each protection system major
component type”
Response: Thank you for your comments.
1. If several different regulatory agencies have differing requirements for similar equipment, it seems that the entity must be compliant with the most
stringent of the varying requirements. In the cited case, an entity may need to perform maintenance more frequently than specified within the
requirements to assure that they are compliant.
2. The 18-month (and shorter) interval activities are activities that can be completed without outages – primarily inspection-related activities. An
entity may need to perform maintenance more frequently than specified within the requirements to assure that they are compliant.
3. a. Applicability 4.2.5.5 has been removed. Generator-connected station service transformers are essential to the continuing operation of the
generating plant; therefore, protection on these system components is included within PRC-005-2 if the generation plant is a BES facility.
b.The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
Manitoba Hydro
Yes
1) We disagree with the requirements for battery maintenance outlined in table 1-4. In particular the
requirement for a 3 month check on electrolyte level seems too frequent based on our experience. We would
like to point out that although IEEE std 450 (which seems to be the basis for table 1-4) does recommend
intervals it also states that users should evaluate these recommendations against their own operating
experience.
2) Also, the Implementation Plan is not consistent for areas requiring regulatory approval and areas requiring
regulatory approval. The 6 month time frame proposed for R1 for areas not requiring regulatory approval is
not achievable and is not consistent with areas requiring regulatory approval. To be consistent, the effective
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date for R1 in jurisdictions where no regulatory approval is required should be the first day of the first calendar
quarter 12 months after BOT approval.
Response: Thank you for your comments.
1. The SDT believes that the 3-month interval specified in the standard is appropriate.
2. In consideration of your comment, “6” has been modified to “12” in the Implementation Plan for Requiremnet R1.
Dynegy Inc.
Yes
For R1.5, we feel to much is being asked for since this information is not easilly controlled and the tolerances
vary over time.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
Oncor Electric Delivery Company
LLC
Yes
Comment A: Oncor believes that Requirement R1 Part 1.5 of this Standard should be removed. It is too
vague, intrusive, and divisive for what it brings to the reliability of the BES. Specifically it burdens all
Transmission Owners, Generation Owners or Distribution Providers with the impossible task of having to
“identify calibration tolerances or other equivalent parameters for each Protection System component type
that establish acceptable parameters for the conclusion of maintenance activities.” By definition a Protection
System component type is “any one of the five specific elements of the Protection System definition” and “a
component is any individual discrete piece of equipment included in a Protection System, such as a protective
relay or current sensing device.” What Requirement R1 part 1.5 with its associated High VSL in the Standard
would decree is that all Transmission Owners, Generation Owners and Distribution Providers who “failed to
establish calibration tolerance or equivalent parameters to determine if every individual discrete piece of
equipment in a Protection System is within acceptable parameters” would be in violation of the Standard with a High VSL. Oncor with over 98 years of Protection System maintenance experience feels that most
Owners including itself would be non-compliant with this unclear, meddling and disruptive requirement no
matter how long the implementation plan for the Standard is.
Comment B: Oncor believes that in light of Comment “A” above Requirement R4 Part 4.2 must be modified to
remove all references to Requirement R1 Part 1.5 of the Standard. The new requirement should be modified
to read “Either verify that the components are within acceptable parameters at the conclusion of the
maintenance activities or initiate any necessary activities to correct maintenance correctable issues.” Also in
order to assist both the owners and the compliance authorities who may question how one verifies that the
components are within acceptable parameters the FAQ document should be modified to discuss how many
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utilities are doing this with results that indicate either a pass or fail certified by the qualified persons
performing maintenance.
Comment C: Oncor feels that the wording “no less frequently than” found in Requirement R4 Parts 4.1.1 and
4.1.2 should be chanced back to the wording in the previous version of the Standard “not to exceed.”
Comment D: Oncor recommends that in light of Comment “A” above Measure M1 be modified to remove all
reference to Requirement R1 Part 1.5.
Comment E: Oncor, as stated in Comment “B” above, recommends that the FAQ document be modified to
provide more information on what could be used for evidence that the Transmission Owner, Generation
Owner or Distribution Provider has “initiated resolution of identified maintenance correctable issues.” This will
assist both the owners and the compliance authorities in answering the question of what constitutes proof that
a maintenance correctable issue was identified.
Comment F: The second and third paragraphs added under Compliance 1.3 Data Retention provide more
information as to what data is required to be retained. Oncor feels that these two paragraphs will help the
compliance authorities, the Transmission Owners, Generation Owners and Distribution Providers needed
guidance of what is required for data retention.
Response: Thank you for your comments.
A. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the
PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been redrafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
B. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the
PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been redrafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
C. “No less frequently than” was adopted on recommendation of NERC Staff as the preferred method of addressing this requirement.
D. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the
PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been redrafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
E. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference
Document. Your comments will be considered within that activity.
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F. Thank you for your comment.
Ingleside Cogeneration LP
The latest version of PRC-005-2 includes a new requirement (R1.5) to identify calibration tolerances or
equivalent parameters that must be verified before a maintenance activity is considered complete. Although
we understand the project team’s intent, Ingleside Cogeneration LP is concerned that this requirement will
lead to multiple interpretations of which tolerances or parameters are the most important. In addition, audit
teams may expect to see certain values based upon their own sense of reliability. This is exactly the
ambiguity that PRC-005-2 is trying to eliminate.
In addition, calibration tolerances and reliability parameters may vary by equipment manufacturer or by
configuration. It is not clear that documenting every scenario to demonstrate regulatory compliance is a
benefit to BES reliability.
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
Indiana Municipal Power Agency
Yes
Standard PRC-005-2 Draft 3 contains a section of "Definitions of Terms Used in Standard" that includes newly
defined or revised terms uses in this proposed standard. There are a number of references made to these
Terms in the Standard that are not capitalized. IMPA would propose that anywhere that the terms included in
the "Definition of Terms Used" are used in the standard that they be capitalized. When any word is not
capitalized in a standard then the common practice is to use the Webster Dictionary meaning. IMPA does not
know why the SDT is reluctant to put these terms in the NERC Glossary of Terms, but by putting the terms in
the glossary it would eliminate any confusion. When these terms are capitalized all registered entities will
know that these are defined terms and will be able to consistently apply the definition without confusion.
For example: 1.1 Address all Protection System component types would become1.1 Address all Protection
System Component Types.
If these terms are not capitalized in the standard (meaning they are not referring to the defined term) then the
meaning of these terms could vary not only from utility to utility but also from Region to Region.
Response: Thank you for your comments. The standard capitalizes defined terms only when they refer to terms which are (or will be) in the NERC
Glossary of Terms. Terms will generically be capitalized when appearing at the beginning of a sentence or within a title, in accordance with common
editorial practice. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms, may
change them in a fashion inconsistent with the intended usage within PRC-005-2.
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Yes
Adding Requirement 1.5 is a significant revision and raises questions as to how broadly an accuracy or
equivalent parameter requirement and associated documentation would need to be addressed by entities
and/or will be measured for compliance. Discussion on this new requirement does not seem to be addressed
anywhere in the FAQ or Supplementary Reference documents. Additionally, to the best of our knowledge,
the need for such a requirement was not brought up as a concern or comment on the prior draft version of this
standard, and in the context of a requirement need, we don’t believe it has been attributed to or actually
poses any significant reliability risk. We do not believe this requirement is justified.
South Carolina Electric and Gas
Entergy Services
Response: Thank you for your comments. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated
changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement
R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also been revised. Please see
Supplementary Reference Document, Section 8 for a discussion of this.
Duke Energy
Yes
1. We have previously commented that the FAQ and Supplementary Reference documents should be
made part of this standard. If that cannot be done, then more of the information in those documents
needs to be included in the requirements in the standard to provide clarity. Compliance will only be
measured against what is in the standard, and we need more clarity.
2. R1.4 and R1.5 need more information to provide clarity for compliance. It’s unclear to us what the
expectation is for compliance documentation for “monitoring attributes and related maintenance
activities” in R1.4 and “calibration tolerances or other equivalent parameters” in R1.5. This is fairly
straightforward for relays, but not for other component types. Either provide clarity or delete these
requirements.
3. R4.2 - it is critical that more clarity be provided for R1.5 so that we can also understand what the
compliance expectation is for R4.2
4.
M4 - Need to clarify that these pieces of evidence are all “or”, not “and” (i.e. any of the listed examples
are sufficient for compliance). We reiterate the need for additional clarity on R1.5 and R4.2 such that
compliance can be demonstrated for all component types.
5. Table 2 - We are fairly clear on the expectation for relays, but need more clarity on the expectation for
other component types. Also, need to change the phrase “corrective action can be taken” to “corrective
action can be initiated”, consistent with the Supplementary Reference document.
Response: Thank you for your comments.
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1. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document.
The SDT believes that entities should be able to implement the standard without the Supplementary Reference. However, the SDT is also
convinced that many entities may find the supporting discussion/rationale/etc useful, particularly to assist them in implementing the standard in an
efficient manner.
2. Requirement R1, Part 1.4 has been modified for clarity. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and
the associated changes are addressed within the PSMP definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been
removed. Requirement R4 has also been re-drafted to address various related concerns noted within comments. The associated VSL has also
been revised. Please see Supplementary Reference Document, Section 8 for a discussion of this.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
4. The SDT has provided examples of the sort of evidence that may serve to demonstrate compliance. The degree to which any single evidence type
is sufficient is dependent on the completeness of the evidence itself. The Measure has been modified to clarify this point.
5. Table 2 has been modified to be clearer. “Taken” has been replaced with “initiated” in consideration of your comment.
Wisconsin Electric Power
Company
Independent Electricity System
Operator
Yes
1. Requirement R1, Part 1.5 is vague and needs clarification. It is not clear what “Identify calibration
tolerances or other equivalent parameters” means and this may be subject to different interpretations by
entities and compliance enforcement personnel.
2. Additionally, in the Implementation plan for Requirement R1, we recommend changing “six” to “fifteen” to
restore the 3-month time difference between the durations of the implementation periods for jurisdictions
that do and don’t require regulatory approval, which existed in the previous draft. This change will ensure
equity for those entities located in jurisdictions that do not require regulatory approval as is the case here
in Ontario. More importantly it supports the IESO’s strong belief in the principle that reliability standards
should be implemented in an orderly and coordinated fashion across regions to ensure system reliability
is not compromised.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
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Document, Section 8 for a discussion of this.
2. In consideration of your comment, “6” has been modified to “12” in the Implementation Plan for Requirement R1.
American Electric Power
1. Standards Requirement 1.5 and the reference to R1.5 in Requirement 4.2 should be removed. Specifying
calibration tolerances for every protection system component type, while a seemingly good idea,
represents a substantial change in the direction of the standard. It would be very onerous for companies
to maintain a list of calibration tolerances for every protection system component type and show evidence
of such at an audit. AEP believes entities need the flexibility to determine what acceptance criteria is
warranted and need discretion to apply real-time engineering/technician judgment where appropriate.
2. Three different types of maintenance programs (time-based, performance-based and condition-based)
are referenced in the standard or VSLs, yet the time-based and condition-based programs are neither
defined nor described. Certain terms defined within the definition section (such as Countable Event or
Segment) only make sense knowing what those three programs entail. These programs should be
described within the standard itself and not assume knowledge of material in the Supplementary
Reference or FAQ.
3. ”Protective relay” should be a defined term that lists relay function for applicability. There are numerous
‘relays’ used in protection and control schemes that could be lumped in and be erroneously included as
part of a Protection System. For example, reclosing or synchronizing relays respond to voltage and
hence could be viewed by an auditor as protective relays, but they in fact perform traditional control
functions versus traditional protective functions.
4. The Data Retention requirement of keeping maintenance records for the two most recent maintenance
performances is a significant hurdle for any owners to abide by during the initial implementation period.
The implementation plan needs to account for this such that Registered Entities do not have to provide
retroactive testing information that was not explicitly required in the past.
Response: Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. The term, “condition-based” has been removed from the draft standard. The other terms are used, but are clear in the context in which they are
used.
3. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition within PRC-005. Further,
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the applicability of generically-described protective relays is defined by the Applicability clause of PRC-005-2.
4. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding one to validate that entities have been in compliance since the last
audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data retention in the posted standard to establish
this level of documentation. This seems to be consistent with the current practices of several Regional Entities.
ITC
Yes
1. We would like some further clarification on PRC-005-2 Draft 3, specifically on the statement in Table 1-4 for
unmonitored station DC supply with VLA batteries. In the table it is mentioned that we are to perform either a
capacity test every six years or verify that the station battery can perform as designed by evaluating the
measured cell/unit internal ohmic values to station battery baseline, the latter statement is a little vague and
needs further clarification with regards to the expectations from the standard. Please describe an acceptable
method of establishing a baseline “measured cell/unit internal ohmic value” We would like to know what
exactly is required. We measure the cell internal ohmic value on an annual basis every 12 months, is that
enough? What are the comparison parameters with regards to battery baseline? At what percent should we
look to replace the cell?
2. Is a battery system that only supplies the SCADA RTU considered part of the protective system if alarms
for the monitored protective systems utilize that SCADA RTU?
Response: Response: Thank you for your comments.
1. The station battery baseline value is up to the entity to determine. Please see Section 15.4.1 of the Supplementary Reference for a discussion of
this.
2. No. The Applicability of the standard limits the standard to only those devices within the Protection.
ISO New England Inc.
1. In general, the standard is overly prescriptive and complex. It should not be necessary for a standard at
this level to be as detailed and complex as this standard is. Entities working with manufacturers, and
knowledge gained from experience can develop adequate maintenance and testing programs.
2.
Why are “Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation)...” not included? The output contacts from these devices
are oftentimes connected in tripping or control circuits to isolate problem equipment.
3. Due to the critical nature of the trip coil, it must be maintained more frequently if it is not monitored. Trip
coils are also considered in the standard as being part of the control circuitry. Table 1-5 has a row
labeled “Unmonitored Control circuitry associated with protective functions”, which would include trip coils,
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has a “Maximum Maintenance Interval” of “12 Calendar Years”. Any control circuit could fail at any time,
but an unmonitored control circuit could fail, and remain undetected for years with the times specified in
the Table (it might only be 6 years if I understand that as being the trip test interval specified in the table).
Regardless, if a breaker is unable to trip because of control circuit failure, then the system must be
operated in real time assuming that that breaker will not trip for a fault or an event, and backup facilities
would be called upon to operate. Thus, for a line fault with a “stuck” breaker (a breaker unable to trip),
instead of one line tripping, you might have many more lines deloaded or tripped because of a bus having
to be cleared because of a breaker failure initiation. The bulk electric system would have to be operated
to handle this contingency.
4. In reference to the FAQ document, Section 5 on Station dc Supply, Question K, clarification is needed
with respect to dc supplies for communication within the substation. For example, if the communication
systems were run off a separate battery in separate area in a substation, would the standard apply to
these batteries or not?
5. To define terms only as they are used in PRC-005-2 is inviting confusion. Although they may be unique
to PRC-005-2, some or all of them may be used in future standards, some already may be used in
existing standards, and may or may not be deliberately defined. Consistency must be maintained, not
only for administrative purposes, but for effective technical communications as well.
6. What is the definition of “Maintenance” as used in the table column “Maximum Maintenance Interval”?
Maintenance can range from cleaning a relay cover to a full calibration of a relay.
7. A control circuit is not a component, it is made up of components.
8. Sub-requirement 1.5 needs to be clarified. It is not clear what “Identify calibration tolerances or other
equivalent parameters...” means, and may be subject to different interpretations by entities and
compliance enforcement personnel.
9. In the Implementation plan for Requirement R1, recommend changing “six” to fifteen. This change would
restore the 3-month time difference that existed in the previous draft, between the durations of the
implementation periods for jurisdictions that do and do not require regulatory approval. It will ensure
equity for those entities located in jurisdictions that do not require regulatory approval, as is the case in
Ontario.
10. The ‘box’ for “Monitored Station dc supply...” in Table 1-4 is not clear. It seems to continue to the next
page to a new box. There are multiple activities without clear delineation.
Response: Thank you for your comments.
1. The intervals and activities specified are believed by the SDT to be technically effective, in a fashion that may be consistently monitored for
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compliance. Further, FERC Order 693 directs NERC to establish maximum allowable intervals, which implies that minimum activities also need be
prescribed. If an entities’ experience is that components require less-frequent maintenance, a performance-based program in accordance with R3
and Attachment A is an option.
2. The SDT concentrated their efforts on protective relays which use the entire group of component types within the Protection System definition.
Also, there is currently no technical basis for the maintenance of the devices which respond to non-electrical quantities on which to base
mandatory standards related either to activities or intervals. Absent such a technical basis, we are currently unable to establish mandatory
requirements, but may do so in the future if such a technical basis becomes available.
3. According to Table 1-5, trip coils of interrupting devices must be verified to operate every 6 years, rather than the 12-year interval. You are free to
maintain these devices more frequently if you desire.
4. With respect to dc supply associated only with communications systems, we prescribe, within Table 1-2, that the communications system must be
verified as functional every 3 months, unless the functionality is verified by monitoring. The specific station dc supply requirements (Table 1-4) do
not apply to the dc supply associated only with communications systems. The SDT has decided to eliminate the FAQ and incorporate topics and
discussion from the FAQ within the Supplementary Reference Document. Your comments will be considered within that activity.
5. The SDT has proposed these terms for use only within PRC-005-2 because we are concerned that other uses of these terms, either now or in the
future, may not be consistent with the terms as used here. They are defined only for clarify within this standard. The SDT will confirm with NERC
staff that this approach is acceptable.
6. As used in the “Maximum Maintenance Interval” column title of the table, maintenance refers to whatever activities are specified in the Activities
column. The term is capitalized in the column title in conformance with normal editorial practice as a title, rather than as a definition
7. For purposes of this standard, the control circuit IS defined as one component type.
8. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
9. In consideration of your comment, “six” has been modified to “twelve” in the Implementation Plan for Requirement R1, making it consistent with
the remainder of the Implementation Plan.
10. Table 1-4 has been further modified for clarity
Nebraska Public Power District
Yes
Definitions:
1. The PSMP definition inappropriately extends the maintenance program to include corrective
maintenance. The first bullet of the Detailed Description section of the SAR specifically states: "Analysis
of correct operations or misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard." The comment in the SAR was
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directed toward the Purpose of PRC-017 since it is the only one of the applicable PRC standards that
included corrective measures in its Purpose. However, the concept of not including corrective
maintenance in a maintenance standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC SPCTF Assessment of
Standards referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment of the Standards
identified the need to expand the maintenance and testing program to include corrective maintenance. I
recommend deleting the words "and proper operation of malfunctioning components is restored." from the
first sentence of the PSMP definition. I believe that failure to do so exceeds the scope of the SAR.
2. The definition of a Countable Event should clearly state whether or not multiple conditions on a single
component will count as a single Countable Event or as multiple Countable Events. For example, a
single relay fails its undervoltage setting and its under frequency setting. Is this one Countable Event or
two Countable Events?
3. Applicability Part 4.2.2:The ERO does not establish underfrequency load-shedding requirements. Those
requirements will be established by Reliability Standard PRC-006-1 when it is approved by FERC. I
recommend changing Accountability Part 4.2.2. to "...installed to provide last resort system preservation
measures." (Note this wording is consistent with the Purpose of PRC-006-0.)Applicability Part 4.2.5.4 and
4.2.5.5:
4. Station Service transformers provide energy to plant loads and not the BES. If these plant transformers
are included, why not include the rest of the plant systems? I recommend deleting Applicability Part
4.2.5.4 and 4.2.5.5.
5. Requirement R1 Part 1.2: The wording of the first sentence is unclear about what information is required.
For example, I could state in my PSMP that: "All Protection System component types are addressed
through time-based, performance-based, or a combination of these maintenance methods" and be
compliant with the Requirement. I recommend re-wording the first sentence to state: "Identify which
maintenance method is used to address each Protection System component type. Options include timebased, performance-based (per PRC-005 Attachment A), or a combination of time-based and
performance-based (per PRC-005 Attachment A)." Note that PRC-005 Attachment A does not address a
combination of maintenance methods and therefore the second reference in the first sentence should be
removed if the original wording is retained.
6. Requirement R1 Part 1.4: The column titles in Tables 1-1 through 1-5 have been revised to “Component
Attributes” and “Activities”. I recommend changing "monitoring attributes" to "component attributes" and
"maintenance activities" to "activities" to be consistent with the Tables.
7. Requirement R1 Part 1.5: Maintenance acceptance criteria for a given Protection System component type
may very depending on the manufacturer, model, etc.. Including all acceptance criteria in the PSMP
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document will over-complicate the program document. I recommend clarifying Part 1.5 to allow the
incorporation of device-specific acceptance criteria in the applicable evidentiary documentation. One
possible option is to add a second sentence as follows: "The calibration tolerances or other equivalent
parameters may be included with the maintenance records." Note that a personal preference would be to
use the phrase “acceptance criteria” instead of “calibration tolerances or other equivalent parameters”.
8. Requirement R4:The PSMP definition inappropriately extends the maintenance program to include
corrective maintenance. The first bullet of the Detailed Description section of the SAR specifically states:
"Analysis of correct operations or misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard." The comment in the SAR was
directed toward the Purpose of PRC-017 since it is the only one of the applicable PRC standards that
included corrective measures in its Purpose. However, the concept of not including corrective
maintenance in a maintenance standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC SPCTF Assessment of
Standards referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment of the Standards
identified the need to expand the maintenance and testing program to include corrective maintenance. I
recommend deleting the words "including identification of the resolution of all maintenance correctable
issues" from the first sentence of the Requirement. I believe that failure to do so exceeds the scope of
the SAR.
9. Requirement R4 Part 4.2: What is considered sufficient verification of parameters? Does this require an
engineer or technician signature or simply an indication of pass/fail? The PSMP definition inappropriately
extends the maintenance program to include corrective maintenance. The first bullet of the Detailed
Description section of the SAR specifically states: "Analysis of correct operations or misoperations may
be an integral part of condition-based maintenance processes, but need not be mandated in a
maintenance standard." The comment in the SAR was directed toward the Purpose of PRC-017 since it
is the only one of the applicable PRC standards that included corrective measures in its Purpose.
However, the concept of not including corrective maintenance in a maintenance standard should apply to
all of the applicable PRC standards. The same statement from the SAR identified above was also
included in the NERC SPCTF Assessment of Standards referenced in the SAR. Neither the SAR nor the
NERC SPCTF Assessment of the Standards identified the need to expand the maintenance and testing
program to include corrective maintenance. I recommend re-wording Requirement 4, Part 4.2 to state:
"Verify that the components are within the acceptable parameters established in accordance with
Requirement R1, Part 1.5 at the conclusion of the maintenance activities." I believe that failure to do so
exceeds the scope of the SAR.
10. Measurement M2: Can a single specification document suffice for similar relay types such as one
document for SEL relays? For trip circuit monitoring can a standard document be used for a group of
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similar schemes ?
11. Measurement M4:I assume this is not an all inclusive list of potential forms of evidence. Please clarify
what is meant by "such as". Does this mean that: 1) Any one item is sufficient?; 2) Certain combinations
of evidence are necessary? If so, what combinations?; 3) Are other items that are not identified here
acceptable?
12. Measurement M4 repeatedly refers to "dated" evidence. However, current audit expectations include
either performer signatures or initials on the evidence in addition to the dates. Please revise
Measurement M4 to clearly state the expectations regarding performer signatures or initials on the
evidence documents.
13. The PSMP definition inappropriately extends the maintenance program to include corrective
maintenance. The first bullet of the Detailed Description section of the SAR specifically states: "Analysis
of correct operations or misoperations may be an integral part of condition-based maintenance
processes, but need not be mandated in a maintenance standard." The comment in the SAR was
directed toward the Purpose of PRC-017 since it is the only one of the applicable PRC standards that
included corrective measures in its Purpose. However, the concept of not including corrective
maintenance in a maintenance standard should apply to all of the applicable PRC standards. The same
statement from the SAR identified above was also included in the NERC SPCTF Assessment of
Standards referenced in the SAR. Neither the SAR nor the NERC SPCTF Assessment of the Standards
identified the need to expand the maintenance and testing program to include corrective maintenance. I
recommend deleting the words: "and initiated resolution of identified maintenance correctable issues"
from the last sentence of Measurement M4. I believe that failure to do so exceeds the scope of the SAR
14. .Compliance Part 1.3: Tables 1-1 through 1-5 refers to time-based maintenance programs. I recommend
changing "performance-based" to "time-based" in the last sentence of the third paragraph.
15. The last paragraph of Part 1.3 of the Compliance Section states: "The Compliance Enforcement Authority
shall keep the last periodic audit report and all requested and submitted subsequent compliance records."
This appears to be a requirement of the Compliance Enforcement Authority however they are not
identified in Section 4 Applicability of the Standard. It is also in conflict with the SAR Attachment B Reliability Standard Review Guidelines which states on page SAR-10: "Do not write any requirements for
the Regional Reliability Organization. Any requirements currently assigned to the RRO should be reassigned to the applicable functional entity." I recommend deleting the last paragraph of Part 1.3 of the
Compliance Section to avoid conflict with the SAR.
16. Table 1-1: The Activity of row 1 states: “Verify operation of the relay inputs and outputs that are essential
to ...” Please clarify what is meant by “operation of” the relay inputs and outputs. What is the criteria to
determine if something is “essential”? The first line of row 2 has a double colon. Please delete one of
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them.
17. For the second bullet of row 2 column 1, please clarify what is meant by the last part of this sentence "that
are also performing self monitoring and alarming" and how it relates to the voltage and current sampling
required. It appears the self monitoring is required in the first bullet.
18. For the first bullet of row 2 column 3, many relay settings may not be essential to the protective function of
the relay. I recommend revising the first bullet to: “Settings that are essential to the proper function of the
protection system are as specified.”
19. The format of the Activities column for all three rows is different. Please reformat them to be consistent.
My preference is the second row.
20. Table 1-2: Row 1 Column 2, verifying the functionality of communications systems on a 3 calendar
months basis is excessive and unnecessary. Suggest changing the Maximum Maintenance Interval to
either 6 calendar months or semi-annual.
21. Row 2 Column 1, please provide examples of typical communications systems that fit into this category,
e.g. Mirror Bit or Guard systems?
22. The words “such as” are used repeatedly. Please clarify what is meant by "such as". Is this left up to the
Utility to define in their PSMP?
23. Table 1-5: The Activity for row 1 requires verification that each trip coil is able to operate the device. If a
control circuitry contains multiple trip coils, it is not always possible to determine which trip coil energized
to trip the device. I recommend changing "each trip coil" to "at least one trip coil".
24. Please clarify what is meant by an "Electromechanical trip" device in row 3.
25. Row 3 column 3, does this mean verify the trip contact on the device operates properly but not verify the
trip circuit wiring from this contact to the trip coil since the trip circuit is tested in the row below? It is
difficult to separate the meaning in these two rows.
26. Row 4 column 3 requires verification of all paths of the control and trip circuits. Please clarify if this
includes the control circuitry of Protection Systems located at the other end of a line if the device utilizes a
remote trip scheme?
Response: Response: Thank you for your comments.
1. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues (discovered during
maintenance activities) is included. The SDT considers this inclusion to be appropriate and necessary as part of the maintenance program.
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2. The example cited would be one countable event. The definition has been modified to clarify.
3. Underfrequency load shedding requirements, whether established by Regional Entities (current practice) or by NERC, are ERO requirements.
4. Clause 4.2.5.5 has been removed. Generator-connected station service transformers are essential to the continuing operation of the generating
plant; therefore, protection on these system components is included within PRC-005-2 if the generation plant is a BES facility.
5. Requirement R1, Part 1.2 has been modified essentially as you suggest.
6. “Monitoring attributes” are used within the respective tables; “Component attributes” can include monitoring or not. The Tables have been revised
to specify “Maintenance Activities”.
7. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
8. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues (discovered during
maintenance activities) is included. The SDT considers this inclusion to be appropriate and necessary as part of the maintenance program.
9. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
10. Yes. However, the degree to which any single evidence type is sufficient is dependent on the completeness of the evidence itself. The Measure
has been modified to clarify this point. The Measure M2 to which you refer has been deleted in conjunction with the deletion of the accompanying
requirement.
11. Yes. The SDT has provided examples of the sort of evidence that may serve to demonstrate compliance. The degree to which any single evidence
type is sufficient is dependent on the completeness of the evidence itself. “Such as” was not intended to be an all-inclusive list; additional
examples are provided in Section 15.7 of the Supplementary Reference Document. The Measure has been modified to clarify this point.
12. Signatures, initials, etc, may not apply to all forms of evidence. “Dated” is more universal.
13. Corrective maintenance is included within PRC-005-2 only in that the initiation of resolution of maintenance-correctable issues (discovered during
maintenance activities) is included. The SDT considers this inclusion to be appropriate and necessary as part of the maintenance program.
14. The portion of “Compliance” that referred to the Tables has been deleted.
15. The text to which you refer is part of the standard language for NERC Standards and reflects a general responsibility of the Compliance
Enforcement Authority. The Compliance Enforcement Authority does not need to be indentified as an Applicable Entity.
16. If proper operation of an input or output is required such that the Protection System operate properly, it is “essential”. “Verify operation …” means
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to determine that the component functions properly. The typo has been corrected.
17. The text to which you refer has been deleted in consideration of your comment.
18. The SDT disagrees; settings beyond those “essential for proper function of the relay” may be essential to proper functioning of the monitoring,
etc, which is used to extend the maximum maintenance interval of the relay.
19. The SDT has arranged the format of each of the cells within the Maintenance Activities column for the best clarity within each individual cell.
20. The SDT believes that the 3-month interval is proper for unmonitored communications systems.
21. Examples such as you suggest may violate the NERC Anti-Trust Guidelines by appearing to favor specific proprietary technologies. Some
examples may be found in Section 15.5 of the Supplementary Reference Document.
22. “Such as” refers to examples pertinent to various equipment technologies, and thus are equipment-dependent, as opposed to entity-selectable.
Some examples may be found in Section 15.5 of the Supplementary Reference Document.
23. The SDT believes that each individual trip coil needs to be verified as required within PRC-005-2.
24. “Electromechanical” refers to any device which has moving parts that respond to electrical signals, such as lockout relays and auxiliary relays.
This row in Table 1-5 has been modified.
25. Yes. The verification of the entire control circuitry is performed according to the following row in the Table, on a less-frequent interval.
26. The testing of the “remote trip scheme” seems best characterized as testing of a “Communications System”. Accordingly, testing of the remote
station control circuitry is an independent activity.
CenterPoint Energy
Yes
(a) CenterPoint Energy cannot support this proposed Standard. Any standard that requires a 35 page
Supplementary Reference document and a 37 page FAQ - Practical Compliance and Implementation
document, in addition to extensive tables in the Standard, is much too prescriptive and complex to be
practically implemented.
(b) CenterPoint Energy is opposed to approving a standard that imposes unnecessary burden and reliability
risk by imposing an overly prescriptive approach that in many cases would “fix” non-existent problems. To
clarify this last point, CenterPoint Energy is not asserting that maintenance problems do not exist. However,
requiring all entities to modify their practices to conform to the inflexible approach embodied in this proposal,
regardless of how existing practices are working, is not an appropriate solution. Among other things,
requiring entities to modify practices that are working well to conform to the rigid requirements proposed
herein carries the downside risk that the revised practices, made solely to comply with the rigid requirements,
degrade reliability performance.
(c) CenterPoint Energy is very concerned that a large increase in the amount of documentation will be
required in order to demonstrate compliance - with no resulting reliability benefit. CenterPoint Energy
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believes this Standard could actually result in decreasing system reliability, as the Standard proposes
excessive maintenance requirements. The following is included in the Supplementary Reference document
(page 8): “Excessive maintenance can actually decrease the reliability of the component or system. It is not
unusual to cause failure of a component by removing it from service and restoring it.” System reliability can
be even further reduced by the number of transmission line and autotransformer outages required to perform
maintenance.
(d) The following is included in the FAQ - Practical Compliance and Implementation document: “PRC-005-2
assumes that thorough commission testing was performed prior to a protection system being placed in
service. PRC-005-2 requires performance of maintenance activities that are deemed necessary to detect and
correct plausible age and service related degradation of components such that a properly built and
commission tested Protection System will continue to function as designed over its service life.” CenterPoint
Energy believes some proposed requirements, such as wire checking a relay panel, do not conform to this
statement. CenterPoint Energy’s experience has been that panel wiring does not degrade with age and
service and that problems with panel wiring, after thorough commissioning, is not a systemic issue.
Response: Response: Thank you for your comments.
a. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference
Document.
b. FERC Order 633 directed that NERC establish maximum maintenance intervals. Additionally, the SDT is directed to develop a measurable,
effective continent-wide standard. Entities may continue their current practices as long as those practices meet the minimum requirements
of this standard.
c. FERC Order 633 directed that NERC establish maximum maintenance intervals. The documentation required should not expand
dramatically from the documentation currently required to demonstrate compliance. An entity may minimize hands-on maintenance by
utilizing monitoring to extend the intervals.
d. The standard does not require “wire-checking”, but instead generically specifies “verification” – however an entity chooses to do so.
American Transmission
Company
Yes
ATC recognizes the substantial efforts that the SDT has made on PRC-005 and appreciate the SDT’s
modifications to this Standard based on previous comments made. ATC looks forward to continuing to have
a positive influence on this process via the comment process, ballots and interaction with the SDT. ATC was
very close to an affirmative vote on this Standard prior to the unanticipated changes that appeared in this
most recent posting. These changes introduce a significant negative impact from ATC’s perspective.
Therefore, ATC is recommending a negative ballot in the hope that our concerns regarding R 1.5 and R 4.2
and other clarifications will be included with the standard The two items within the proposed Standard that we
take exception to are not directly related to implementing FERC Order 693. Rather, it is the overly
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prescriptive nature with respect to the “how” as outlined in the proposed Standard that ATC takes exception...
To improve and find the proposed Standard acceptable, ATC would like to see the following modifications:
1. Change the text to require the actuation of a single trip coil (row 1 of table 1.5). This would satisfy
the intent to exercise the mechanism on a regular schedule, given that the mechanism binding is a
much more likely source of a coil failure. The balance of trip coils could then be tested as part of
routine breaker maintenance.
2. Eliminate the additional requirements introduced by the addition of R1.5 and the associated
modifications to R4.2. The additional documentation required for the range of each element is typically
incorporated into the pass/fail mechanism of the existing test equipment (which is reflective of the
manufacturer recommendations) used to conduct these tests. Therefore, requiring the assembly of this
additional documentation from each entity would:
a. Be duplicative and voluminous as it would require us to track thousands of additional data
points due to the variability in element ranges by relay manufacturer, model number and
vintage.
b. Not add to the reliability of the system as this function is already being performed on a
collective basis.
Response: Response: Thank you for your comments.
1. The SDT believes that each individual trip coil needs to be verified as required within PRC-005-2.
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
Consumers Energy
Yes
1. Table 1-3 states, “are received by the protective relays”. Does this require that the inputs to each individual
relay must be checked, or is it sufficient to verify that acceptable signals are received at the relay panel, etc?
2. Relative to Table 1-5, the activities will likely require that system components be removed from service to
complete those activities. If the changes to the BES definition (per the FERC Order) causes system elements
such as 138 kV connected distribution transformers to be considered as BES, these components can not be
removed from service for maintenance without outaging customers. The standard must exempt these
components from the activities of Table 1-5 if the activity would result in deenergizing customers.
3. For the component types addressed in Tables 1-3 and 1-5, the requirements may cause entities to identify
components very differently than they are currently doing, and doing so may take several years to complete.
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The Implementation Plan for R1 and R4 is too aggressive in that it may not permit entities to complete the
identification of discrete components and the associated maintenance and implement their program as
currently proposed. We propose that the Implementation Plan specifically address the components in Table
1-3 and 1-5 with a minimum of 3 calendar years for R1 and 12 calendar years after that for R4.
4. As for the interval in Table 1-4 regarding the battery terminal connection resistance, we believe that an 18month interval is excessively frequent for this activity, and suggest that it be moved to the 6-calendar-year
interval.
5. In Table 1-4, we currently re-torque all of the battery terminal connections every 4-years, rather than
measuring the terminal connection resistance to determine if the connections are sound. Disregarding the
interval, would this activity satisfy the “verify the battery terminal connection resistance” activity?
Response: Response: Thank you for your comments.
1. The SDT intends that the voltage and current signals properly reach each individual relay, but there may be several methods of accomplishing this
activity.
2. This concern seems more properly to be one to be addressed during the activities to develop the new BES definition, rather than within PRC-005-2.
3. The Implementation Plan for Requirement R1 has been modified from 6 months to 12 months. The Standard has also been modified (Requirement
R1, Part 1.1) to not specifically require identification of all individual Protection System components. The Implementation Plan for Requirement R4
has been revised to add one year to all established dates.
4. IEEE 450, 1188, 1106 all recommend this activity at a 12-month interval. Please see Section 15.4.1 of the Supplementary Reference Document for a
discussion of this activity.
5. Re-torqueing the battery terminals would not meet this requirement.
Southern Company Generation
Yes
1. Please consider retaining the definitions stated to be moved to the NERC Glossary - they would be
valuable to entities in the standard.
2. On Page 5, Section 1.2, please consider changing “or a combination of these maintenance methods (per
PRC-005-Attachment A).” to “or a combination of these two maintenance methods.”
3. On Page 5, Section 1.5: recommend deleting this section - the subjectivity of what is an acceptable
value for component testing makes this requirement un-valuable.
4. On Page 5, Section 4.2, it is recommended that the requirement be the following: Either verify that the
component performance is acceptable at the conclusion of the maintenance activities or initiate
resolution of any identified maintenance correctable issue.
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5. On Page 5, Measure M1, replace 1.5 with 1.4 (after eliminating Requirement 1.5)
6. On Page 6, Section 1.3, replace the existing Data Retention text with the following: The TO, GO, and DP
shall each retain documentation for the longer of the these time periods: 1) the two most recent
performances of each distinct maintenance activity for the Protection System component, or (2) all
performances of each distinct maintenance activity for the Protection System component since the
previous scheduled audit date. The Compliance Enforcement Authority shall keep the last periodic audit
report and all requested and submitted subsequent compliance records.
7. On Page 10, Section F, please correct the revision information for the documents listed.
8. On Pages 14 & 15, Table 1-4, move the bottom row to the next page so that it is easier to see that the
maintenance activities are an “either/or” option.
9. On Page 17, Table 1-5, it seems that the 12 calendar year interval activities would automatically be
included in the 6 calendar year activity for verifying the electrical operation of electromechanical trip and
auxiliary devices. Is the 12 year requirement superfluous?
10. On Page 19, Attachment A, it is recommended to delete the footnote #1 since the definition is given
already on Page 2.
Response: Response: Thank you for your comments.
1. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms, may change them in a
fashion inconsistent with the intended usage within PRC-005-2.
2. Requirement R1, Part 1.2 has been modified.
3. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
5. Measure M1 has been modified as you suggest.
6. The Data Retention section has been modified essentially as you suggest.
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7. The Reference information has been corrected.
8. Table 1-4 has been revised.
9. The 12-year interval activities are more extensive than the 6-year interval activities.
10. Footnote #1 has been removed.
US Bureau of Reclamation
Yes
1. The concept of including definitions in this standard that are not a part of the Glossary of Terms will create
a conflict with other standards that choose to use the term with a different meaning. This practice should
be disallowed. If a definition is be introduced it should be added to the Glossary of Terms. This concept
was not provided to industry for comment when the modifications to the Definition of Protection System
were introduced. Additional related to this practice are included later on.
2. The Term "Protective Relays" is overly broad as it is not limited to those devices which are used to protect
the BES. In the reference provided to the standard, the SDT defined "Protective Relays" as "These relays
are defined as the devices that receive the input signal from the current and voltage sensing devices and
are used to isolate a faulted portion of the BES. " The Definition for "Protective Relays" as well as the
components associated with the them should be associated with the protection of the BES in the
definition.
3. The Section 2.4 of the attached reference and the recent FERC NOPR are in conflict with the definition of
"Protective Relays" which include lockout relays and transfer trip relays "The relays to which this standard
applies are those relays that use measurements of voltage, current, frequency and/or phase angle and
provide a trip output to trip coils, dc control circuitry or associated communications equipment.
4. This Draft 2: April3: November 17, 2010 Page 5 definition extends to IEEE device # 86 (lockout relay) and
IEEE device # 94 (tripping or trip-free relay) as these devices are tripping relays that respond to the trip
signal of the protective relay that processed the signals from the current and voltage sensing devices."
The definition should be revised to reflect that is really intended. The SDT as created an implied definition
by specifically defining DC circuits associated with the trip function of a "Protective Relay" but failing to
specifically define voltage and current sensing circuits providing inputs to "Protective Relays". The team
clearly intended the circuits to be included but the definition does not since it only refers the "voltage and
current sensing devices".
5. Starting with the Definitions and continuing through the end of the document, terms that have been
defined are not capitalized. This leaves it ambiguous as to whether the defined term is to be applied or it
is a generic reference. Only defined terms "Protection System Maintenance Program" and "Protection
System" are consistently capitalized.
6. Protection System Maintenance Program (PSMP) definition: The Restore bullet should be revised to read
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as follows: "Return malfunctioning components to proper operation by repair or calibration during
performance of the initial on-site activity."Add the following at the end of the PSMP definition: “NOTE:
Repair or replacement of malfunctioning Components that require follow-up action fall outside of the
PSMP, and are considered Maintenance Correctable Issues.”
7. Protection System (modification) definition: The term "protective functions" that is used herein should be
changed to "protective relay functions" or what is meant by the phrase should become a defined term, as
it is being used as if it is a well known well defined, and agreed upon term. The first bullet text should be
revised to read as follows: "Protective relays that monitor BES electrical quantities and respond when
those quantities exceed established parameters,” the last two bullets should be reversed in order and
modified to read as follows: o control circuitry associated with protective relay functions through the trip
coil(s) of the circuit breakers or other interrupting devices, and o station dc supply (including station
batteries, battery chargers, and non-battery-based dc supply) associated with the preceding four bullets.
8. Statement between the Protection System (modification) definition and the Maintenance Correctable
Issue definition; Is this a NERC accepted practice? There does not appear to be a location in the
standard for defining terms. Having terms that are not contained in the "Glossary of Terms used in NERC
Reliability Standards," and are outside of the terms of the standards, and yet are necessary to understand
the terms of the Requirements is not acceptable. They would become similar to the reference
documents, and could be changed without notice.
9. Maintenance Correctable Issue definition: The last sentence should be modified to read as follows:
"Therefore this issue requires follow-up corrective action which is outside the scope of the Protection
System Maintenance Program and the Standard PRC-005-2 defined Maximum Maintenance Intervals."
The definition could also be easily clarified to read "Maintenance Correctable Issue - Failure of a
component to operate within design parameters such that it cannot be restored to functional order by
repair or calibration; therefore requires replacement." This ensures that any action to restore the
equipment, short of replacement, is still considered maintenance. Otherwise ambiguity is introduced as
what "maintenance" is.
10. Countable Event definition: An explanation should be made that this is a part of the technical justification
for the ongoing use of a performance-based Protection System Maintenance Program for PRC-005.
11. Insert the phrase "Standard PRC-005-2" before the term "Tables 1-1..."
12. Applicability: 4.2. Facilities: 4.2.5.4 and 4.2.5.5: Delete these two parts of the applicability. Station service
transformer protection systems are not designed to provide protection for the BES. Per PRC-005-2
Protection System Maintenance Draft Supplementary Reference, Nov. 17 2010, Section 2.3 - Applicability
of New Protection System Maintenance Standards: “The BES purpose is to transfer bulk power. The
applicability language has been changed from the original PRC-005: “...affecting the reliability of the Bulk
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Electric System (BES)...”To the present language:”... and that are applied on, or are designed to provide
protection for the BES.”The drafting team intends that this Standard will not apply to “merely possible”
parallel paths, (sub-transmission and distribution circuits), but rather the standard applies to any
Protection System that is designed to detect a fault on the BES and take action in response to that
fault.”Station Service transformer protection is designed to detect a fault on equipment internal to a power
plant and not directly related to the BES. In addition, many Station Service protection ensures fail over to
a second source in case of a problem. Thus station service transformer protection system is a power
plant reliability issue and not a BES reliability issue. As such station service transformer protection should
not be included in PRC 005 2.In addition; the SDT appears to have targeted generation station service
without regard to transmission systems. If generating station service transformers are that important,
then why are substation/switchyard station service transformers not also important?
13. B. Requirements Should the sub requirements have the "R" prefix?
14. R4.Change the phrase "... PSMP, including identification of the resolution of all ..." to read "...PSMP
including identification, but not the resolution, of all ...".
15. General comment PRC005-2 is very specific in listing the maximum maintenance interval but is still very
vague in listing the specific components to test. Suggest adding the following to the standard.
a. A sample list of devices or systems that must be verified in a generator to meet the requirements
of this Maintenance Standard:
b. Examples of typical devices and relay systems that respond to electrical quantities and may
directly trip the generator, or trip through a lockout relay may include but are not necessarily
limited to:
Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
Loss-of-field relays
Volts-per-hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator-ground relays
Communications-based protection systems such as transfer-trip systems
Generator differential relays
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Reverse power relays
Frequency relays
Out-of-step relays
Inadvertent energization protection
Breaker failure protection o lockout or tripping relays
c.
For generator step up transformers, operation of any the following associated protective relays
frequently would result in a trip of the generating unit and, as such, would be included in the
program:
Transformer differential relays o Neutral overcurrent relay
Phase overcurrent relays
16. In the Lower, Moderate and Severe VSL descriptions, in addition to not being capitalized, the defined
term Maintenance Correctable Issues should not be hyphenated.
17. In Attachment A Section 2 Page 51 should be modified as follows:
2. Maintain the components in each segment according to the time-based maximum allowable intervals
established in Tables 1-1 through 1-5 until results of maintenance activities for the segment are available
for a minimum of either 30 individual components of the segment or a significant statistical population of
the individual components of a segment." Without the modification the requirement unfairly target smaller
entities. This will allow smaller entities to determine adjust its time based intervals if its experience with
an appropriate number of components supports it. In Attachment A Section 5 Page 51 should be modified
as follows:
5. Determine the maximum allowable maintenance interval for each segment such that the segment
experiences countable events on no more than 4% of the components within the segment, for the greater
of either the last 30 components maintained or a significant statistical population of the individual
components of a segment maintained in the previous year. Without the modification the requirement
unfairly target smaller entities. This will allow smaller entities to determine adjust its time based intervals
if its experience with an appropriate number components supports it.
18. In Attachment A Section 5 Page 52 should be modified as follows:
5. Using the prior year’s data, determine the maximum allowable maintenance interval for each segment
such that the segment experiences countable events on no more than 4% of the components within the
segment, for the greater of either the last 30 components maintained or a significant statistical population
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of the individual components of a segment components maintained in the previous year. Without the
modification the requirement unfairly target smaller entities. This will allow smaller entities to determine
adjust its time based intervals if its experience with an appropriate number of components supports it.
Response: Thank you for your comments.
1. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms, may change them in a
fashion inconsistent with the intended usage within PRC-005-2.
2. “Protective relay” is defined by IEEE, and the SDT sees no need to either change the definition or to repeat the definition within PRC-005. Further,
the applicability of generically-described protective relays is defined by the Applicability clause of PRC-005-2.
3. The issues raised by the FERC NOPR will be addressed as part of the response to the NOPR (and ultimately the Order). The extension to auxiliary
and lockout relays is not part of the protective relay (addressed within Table 1-1), but instead as part of the control circuitry (Table 1-5).
4. The extension to auxiliary and lockout relays is not part of the protective relay (addressed within Table 1-1), but instead as part of the control
circuitry (Table 1-5).
5. Definitions from the NERC Glossary of Terms (or those intended for the Glossary) are consistently capitalized (Protection System and Protection
System Maintenance Program fall within this category). As for terms defined only for use within this standard, these terms are NOT capitalized,
since they are not in the Glossary of Terms.
6. The “restore” portion of PSMP specifically addresses returning malfunctioning components to proper operation. The requirements regarding
maintenance correctable issues are further addressed within that definition (for use only within PRC-005-2).
7. The SDT is currently not planning on further modifying the most recent NERC BOT-approved definition of Protection System.
8. If the terms were placed in the Glossary of Terms, the SDT is concerned that some future SDT, in order to utilize these terms, may change them in a
fashion inconsistent with the intended usage within PRC-005-2.
9. Identifying problems, but not fixing them, does not constitute an effective program. In deference to the time that may be necessary to
repair/replace defective components, the SDT has decided to require only initiation of resolution of maintenance correctable issues, not to
demonstrate completion of them.
10. Since this term is used only in Attachment A, it seems unnecessary to provide the explanation requested.
11. The SDT has elected not to change the reference to the Tables throughout the standard.
12. Applicability 4.2.5.5 has been removed. Generator-connected station service transformers (4.2.5.4) are essential to the continuing operation of the
generating plant; therefore, protection on these system components is included within PRC-005-2 if the generation plant is a BES facility.
13. The current style guide for NERC Standards does not preface the subparts with an “R”.
14. Identifying problems, but not fixing them, does not constitute an effective program. In deference to the time that may be necessary to
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repair/replace defective components, the SDT has decided to require only initiation of resolution of maintenance correctable issues, not to
demonstrate completion of them.
15. The various specific components you suggest are addressed within the Facilities portion of the Applicability 4.2.5, as well as other components
that satisfy the attributes within 4.2.5. These examples are in the Supplementary Reference Document (Section 8.1.3).
16. Within the VSLs, the hyphenated term has been corrected.
17. The SDT has determined that 30 individual components is the minimum acceptable statistically-significant population for use to establish
performance-based intervals. Multiple entities may aggregate component populations to establish this component population, provided that the
programs are sufficiently similar to make the aggregation valid. See Supplementary Reference Document Section 9 for a discussion.
18. The SDT has determined that 30 individual components is the minimum acceptable statistically-significant population for use to establish
performance-based intervals. Multiple entities may aggregate component populations to establish this component population, provided that the
programs are sufficiently similar to make the aggregation valid. See Supplementary Reference Document Section 9 for a discussion.
Alliant Energy
Yes
1. In the Purpose statement delete “affecting” and replace it with “protecting”. The purpose of the standard
deals with systems that protect the BES.
2. In sections R1 and R4.2.1 delete “applied on” as unneeded and potentially confusing. The goal is to
cover Protection Systems designed to protect the BES.
3. Alliant Energy believes that Article 1.4 needs to be deleted from the standard. It is redundant and serves
no purpose.
4. Alliant Energy believes that Article 1.5 needs to be deleted from the standard. There is a major concern
on what an “acceptable parameter” is and how it would be interpreted by the Regional Entities.
5. Section 4.2 Applicable Facilities: We are concerned with this paragraph being interpreted differently by
the various regions and thereby causing a large increase in scope for Distribution Provider protection
systems beyond the reach of UFLS or UVLS.4.2.1 Protection Systems applied on, or designed to provide
protection for, the BES. The description is vague and open for different interpretations for what is “applied
on” or “designed to provide protection”. According to the November 17, 2010 Draft Supplementary
Reference page 4, the Standard will not apply to sub-transmission and distribution circuits, but will apply
to any Protection System that is designed to detect a fault on the BES and take action in response to the
fault. The Standard Drafting Team does not feel that Protection Systems designed to protect distribution
substation equipment are included in the scope of this standard; however, this will be impacted by the
Regional Entity interpretations of ‘protecting” the BES. Most distribution protection systems will not react
to a fault on the BES, but are caught up in the interpretation due to tripping a breaker(s) on the BES. We
request clarification that the examples listed below do not constitute components of a BES Protection
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System:
1. Older distribution substations that lack a transformer high side interrupting device and therefore trip a
transmission breaker or a portion of the transmission system or bus, or
2. Newer distribution substations that contain a transformer high side interrupting device but also
incorporate breaker failure protection that will trip a transmission breaker or a portion of the transmission
system or bus.
6. Since distribution provider systems are typically radial and do not contain the level of redundancy of
transmission or generation protection systems, it is not cheap, safe, maintaining BES reliability, or easy to
coordinate companies to test these protection systems to the level of PRC-005-2 draft recommendations.
7. Section F Supplementary Reference Documents: The references listed in this section refer to 2009 dates
and do not match with the 2010 reference documents supplied for comment.
8. Table 1-4 Component Type Station dc Supply:
a.
“Any dc supply for a UFLS or UVLS system” - This should not have the same testing interval as
control circuits, but should have a maximum maintenance period as other dc supplies do.
b. Replace the words “perform as designed” on page 14 of Table 1-4 with “operate within defined
tolerances.”Table 1-5 Component Type Control Circuitry:
c.
This table allows for unmonitored trip coils for UFLS or UVLS breakers to have “no periodic
maintenance”. The PRC-005-2 Supplementary Frequently Asked Question #7B and #7C give
excellent reasoning for not requiring maintenance on the trip coil component due to the larger
number of failures that would be required to have any substantial impact to the BES as well as
the statement that distribution breakers are operated often on just fault clearing duty already. We
believe that the unmonitored control circuitry has the same level of minimal BES impact and is
also being tested each time the distribution breaker undergoes fault clearing duty. With this logic,
we do not see why there would be different maintenance requirements for these two components.
d. Alliant Energy is concerned that the addition of mandatory 86 and 94 auxiliary lockout relays
(Electromechanical trip or Auxiliary devices) will force entire bus outages that will compromise the
BES reliability more by forcing utilities across the US to unnecessarily take multiple non-faulted
BES elements out of service. Such testing is also likely to introduce human error that will cause
outages such as items outlined in the NERC lessons learned” and therefore such testing will
result in more outages than actual failures. An equivalent non-destructive test needs to be
identified to allow entities to sufficiently trace and test trip paths without taking multiple substation
line outages to physically test a lockout or breaker failure scheme.
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Response: Thank you for your comments.
1. The “Purpose” is defined by the SAR.
2. Requirement R1 and Requirement R4, Part 4.2.1 have been modified as you suggested.
3. The SDT instead elected to remove Requirement R2.
4. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
5. Applicability 4.2.1 has been revised to remove ‘applied on”. The SDT believes that this addresses your concern. Applicability 4.2.2 and 4.2.3,
respectively, address UFLS and UVLS specifically, and are not related to 4.2.1. The Supplementary Reference Document has been revised to
clarify. PRC-005-2 would appear to apply to both cited examples.
6. This is properly a concern to be addressed within the current SDT that is developing a revised definition of Bulk Electric System.
7. The date in Clause F of the standard related to the Supplementary Reference Document has been revised.
8. a. The SDT disagrees. Station dc supply for UFLS/UFLS only is limited in its impact, and the SDT believes that using the same intervals as for the
related control circuits.
b. “Tolerances” does not fully describe the parameters for maintenance of station dc supply; “perform as designed” is far more inclusive.
c. The SDT intends that tripping of the interrupting device for UFLS/UVLS is not required, but that the other portions of the dc control circuitry still
shall be maintained. See Section 15.3 of the Supplementary Reference Document.
d. The SDT believes that mechanical solenoid-operated devices share performance attributes (and failure modes) with electromechanical relays
and need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these
devices supports those intervals
LCRA Transmission Services
Corporation
No
MidAmerican Energy
Yes
1. MidAmerican remains concerned that including requirements for testing of electromechanical trip or
auxiliary devices (Table 1-5 Row 3) will in some cases require entire bus outages that will compromise
the BES reliability due to the need for entities across the US to take multiple BES elements out of service
during the testing. If this requirement is retained additional time should be included in the implementation
plan to allow for system modifications, such as the installation of relay test switches, to potentially allow
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for this testing while minimizing testing outages.
2. Clarify that in the definition of Component Type that Transmission Owners are allowed the latitude to
designate their own definitions for each of the Component Types, not just control circuits.
3. In the implementation schedule time periods are provided within which compliance deadlines and
percentages of compliance are given. The following clarifications are recommended:
1. In calculating percentage of compliance for purposes of demonstrating progress on the implementation
plan the percentages are calculated based on the total population of the protection system components
that an entity has that fit the component category and allowable interval.
2. To obtain compliance with the percentage completion requirements of the implementation schedule an
entity needs to have completed at least one prescribed maintenance activity of that component type and
interval.
4.
In the purpose statement delete “affecting” and replace it with “protecting”. The purpose of the standard
deals with systems that protect the BES.
5.
In sections R1 and R4.2.1 delete “applied on or” as unneeded and potentially confusing. The goal is to
cover protection systems designed to protect.
6.
Clarify the meaning of “state of charge” on page 14 in Table 1-4.
7.
In Table 1-4 Component Type Station dc Supply, “Any dc supply for a UFLS or UVLS system” should
have the same maximum maintenance period as other dc supplies.
8.
Table 1-5 Component Type Control Circuitry, the table allows for unmonitored trip coils for UFLS or UVLS
breakers to have “no periodic maintenance”. The PRC-005-2 Supplementary Frequently Asked
Question #7B and #7C give excellent reasoning for not requiring maintenance on the trip coil
component due to the larger number of failures that would be required to have any substantial impact to
the BES as well as the statement that distribution breakers are operated often on just fault clearing duty
already. We believe that the unmonitored control circuitry has the same level of minimal BES impact
and is also being tested each time the distribution breaker undergoes fault clearing duty. With this
logic, we do not see why there would be different maintenance requirements for these two components.
Response: Thank you for your comments.
1. The SDT believes that mechanical solenoid-operated devices share performance attributes (and failure modes) with electromechanical relays and
need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices
supports those intervals.
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2. For components other than control circuitry, the SDT believes that identification of the components as established within the draft Standard is
appropriate. There is no latitude regarding component types.
3. The SDT believes that the Implementation Plan clearly agrees with your interpretation, and no clarification seems necessary.
4. The “Purpose” is defined by the SAR.
5. Requirement R1 and Requirement R4, Part 4.2.1 have been modified as you suggested.
6. Table 1-4 has been revised to remove “state of charge” from the activities.
7. The SDT disagrees. Station dc supply for UFLS/UVLS only is limited in its impact, and the SDT believes that using the same intervals as for the
related control circuits is appropriate.
8. For the control circuitry of UFLS/UVLS, the relatively frequent breaker operations may not be reflective of proper functioning for UFLS/UVLS
function. Therefore, minimal maintenance activities are necessary for these cases.
Ameren
Yes
(1) We believe that R1.5 and R4.2 “Calibration tolerances or other equivalent parameters” requirements
should be removed. Neither the Supplement nor the FAQ address the expectation for them. While we agree
that tolerances are needed and used, they need not be specified as part of this standard.
(2) The Data retention is too onerous (a) For those components with numerous cycles between on-site audits,
retaining and providing evidence of the two most recent distinct maintenance performances and the date of
the others should be sufficient. Additionally, we are subject to self-certification, spot audits and/or inquiries at
any time between on-site audits as well. (b) For those components with cycles exceeding on-site audit
interval, retaining and providing evidence of the most recent distinct maintenance performance and the date
of the preceding one should be sufficient. Auditors will have reviewed the preceding maintenance record.
Retaining these additional records consumes resources with no reliability gain.
(3) Definition of the BES perimeter should be included in accordance with Project 2009-17 Interpretation.
(a)Facilities Section 4.2.1 “or designed to provide protection for the BES” needs to be clarified so that it
incorporates the latest Project 2009-17 interpretation. The industry has deliberated and reached a conclusion
that provides a meaningful and appropriate border for the transmission Protection System; this needs to be
acknowledged in PRC-005-2 and carried forward.
(4)System-connected station service transformers (4.2.5.5) should be omitted, because (a) Generating Plant
system-connected Station Service transformers should not be included as a Facility because they are serving
load. Omit 4.2.5.5 from the standard. There is no difference between a station service transformer and a
transformer serving load on the distribution system. This has no impact on the BES, which is defined as the
system greater than 100 kV. (b) system-connected station service transformers in the same table as well as
from table-to-table can be overwhelming. This would help keep Regional Entities and System Owners from
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making errors.
(5) Retention of maintenance records for replaced equipment should be omitted. FAQ II 2B final sentence
states that documentation for replaced equipment must be retained to prove the interval of its maintenance.
We disagree with this because the replaced equipment is gone and has no impact on BES reliability; and
such retention clutters the data base and could cause confusion. For example, it could result in saving lead
acid battery load test data beyond the life of its replacement.
(6) Battery inspection every 4 months is sufficient. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for an
interval that might extend past three calendar months due to storms and outages must set a target interval of
two months thereby increasing the number of inspections each year by half again. This is unnecessarily
frequent. We suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar
months.
(7) PSMP Implement Date should commence at the beginning of a Calendar year. This is the most practical
way to transition assets from our existing PRC-005-1 plans.
(8) Please clarify the meaning of “state of charge” for batteries. Does this mean specific gravity testing or
what?
(9) Please clarify that instrument transformer itself is excluded. Please clarify that the instrument transformer
itself is excluded. The standard indicates that only voltage and current signals need to be verified in Table 13, but the recently approved Protection System definition wording can be mis-interpreted to mean they are
included. FAQ 11.3.A is helpful.
Response: Thank you for your comments.
1. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
2. In order that a Compliance Monitor can be assured of compliance, the SDT believes that the Compliance Monitor will need the data of the most
recent performance of the maintenance, as well as the data of the preceding one to validate that entities have been in compliance since the last
audit (or currently, since the beginning of mandatory compliance). The SDT has specified the data retention in the posted standard to establish
this level of documentation. This seems to be consistent with the current practices of several Regional Entities.
3. When the interpretation (Project 2009-17) is approved, the SDT for PRC-005-2 will consider if the interpretation is appropriate for PRC-005-2 and
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make associated changes.
4. In response to many comments, including yours, the SDT has removed 4.2.5.5 from the Applicability of the standard.
5. The SDT has decided to eliminate the FAQ and incorporate topics and discussion from the FAQ within the Supplementary Reference Document.
Your comments will be considered within that activity. The SDT believes that entities should retain the evidence necessary to demonstrate
compliance for the entire period reflected within Data Retention, and the discussion within the Supplementary Reference Document suggests that
this includes records of retired equipment.
6. The SDT believes that the 3-month interval specified in the Standard is appropriate.
7. The guidance provided to the SDT provides that the implementation dates should begin on the first day of a calendar quarter.
8. Table 1-4 has been revised to remove “state of charge” from the activities.
9. The SDT intends that the instrument transformer and associated circuitry be verified to be functional, but believes that customary apparatus
maintenance (dielectric, infrared, etc) are not relevant to PRC-005-2. The SDT has decided to eliminate the FAQ and incorporate topics and
discussion from the FAQ within the Supplementary Reference Document.
Xcel Energy
Yes
1. Requirement R1.4 in part requires that the entity’s PSMP includes all monitoring attributes to include those
specified in Tables 1-1 through 1-5. Requirement R2 requires that entities that use maintenance intervals for
monitored Protection Systems shall verify those components possess the monitoring attributes identified in
Tables 1-1 through 1-5. The intent and differences between these 2 requirements is unclear. If an entity
does not choose to use monitored intervals, it makes no sense to require them to include the monitoring
attributes identified in Tables 1-1 through 1-5 within their PSMP. Furthermore if an entity fails to meet
requirement R1.4 for including identified monitoring attributes in its program, it will by default also have
violated R2. There seems the possibility of double jeopardy between R1.4 and R2. The intent of R2 is fairly
obvious but the intent of including monitoring attributes in R1.4 is not evident. Please provide a discussion
within the FAQ to better explain the differences between these two requirements as they relate to monitoring
attributes.
2. As written, requirement R1.5 and application of R1.5 acceptance criteria via requirement R4.2 would open
entities up to vague interpretations by compliance personnel as to what constitutes adequate acceptance
criteria – particularly in the area of subjective inspection results – e.g., battery cell visual inspections. We
recommend that R1.5 be re-stated to clarify that acceptance criteria need only be provided for numerically
measurable parameters. FAQs should be written to better explain the intent of R1.5 and to provide examples
of acceptance criteria and to hopefully drive consistency amongst compliance personnel interpretation of
acceptance criteria requirements. Consideration should be given to identifying which maintenance
requirements in the Tables would generate quantifiable and measurable test results for which acceptance
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criteria would be expected.
Response: Thank you for your comments.
1. The SDT had concluded that Requirement R2 is redundant with Requirement R1, Part 1.4, and has deleted R2 (together with the associated
Measure and VSL).
2. The SDT has determined that the fundamental concerns of Requirement R1, Part 1.5 and the associated changes are addressed within the PSMP
definition, and that Requirement R1, Part 1.5 is not necessary; therefore, it has been removed. Requirement R4 has also been re-drafted to
address various related concerns noted within comments. The associated VSL has also been revised. Please see Supplementary Reference
Document, Section 8 for a discussion of this.
END OF REPORT
103
Standard PRC-005-2 — Protection System Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approves SAR for posting on June 5, 2007.
2. The SAR was posted for comment from June 11, 2007–July 10, 2007.
3. The SC approves development of the standard on August 13, 2007.
4. First posting of revised standard on July 24, 2009.
5. Second posting of revised standard on June 11, 2010
6. Third posting of revised standard on November 17, 2010
Description of Current Draft:
This is the fourth draft of the Standard. This standard merges previous standards PRC-005-1, PRC-008-0,
PRC-011-0, and PRC-017-0. It also addresses FERC comments from Order 693, and addresses
observations from the NERC System Protection and Control Task Force, as presented in NERC SPCTF
Assessment of Standards: PRC-005-1 — Transmission and Generation Protection System Maintenance
and Testing, PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs, PRC011-0 — UVLS System Maintenance and Testing, PRC-017-0 — Special Protection System Maintenance
and Testing.
Future Development Plan:
Anticipated Actions
1. Post for combined 30-day comment and ballot.
Anticipated Date
April 8-May 7, 2011
2. Conduct successive ballot
April 28-May 7, 2011
3. Drafting Team Responds to Comments
May 11-June 11, 2011
Draft 4: April 12, 2011
1
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Restore – Return malfunctioning components to proper operation.
Protection System (NERC Board of Trustees Approved Definition)
•
•
•
•
•
Protective relays which respond to electrical quantities,
communications systems necessary for correct operation of protective functions,
voltage and current sensing devices providing inputs to protective relays,
station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
The following terms are defined for use only within PRC-005-2, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that
it cannot be restored to functional order by repair or calibration during performance of the initial on-site
activity. Therefore this issue requires follow-up corrective action.
Segment – Protection Systems or components of a consistent design standard, or a particular model or
type from a single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60) individual
components.
Component Type - Any one of the five specific elements of the Protection System definition.
Component – A component is any individual discrete piece of equipment included in a Protection
System, including but not limited to a protective relay or current sensing device. The designation of what
constitutes a control circuit component is very dependent upon how an entity performs and tracks the
testing of the control circuitry. Some entities test their control circuits on a breaker basis whereas others
Draft 4: April 12, 2011
2
Standard PRC-005-2 — Protection System Maintenance
test their circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit components. Another example of where the entity has some
discretion on determining what constitutes a single component is the voltage and current sensing devices,
where the entity may choose either to designate a full three-phase set of such devices or a single device as
a single component.
Countable Event – A component which has failed and requires repair or replacement, any condition
discovered during the verification activities in Tables 1-1 through 1-5 which requires corrective action, or
a Misoperation attributed to hardware failure or calibration failure. Misoperations due to product design
errors, software errors, relay settings different from specified settings, Protection System component
configuration errors, or Protection System application errors are not included in Countable Events.
Draft 4: April 12, 2011
3
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems designed to provide protection for BES Element(s).
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via
generator lockout or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for generator-connected station service transformers for
generators that are part of the BES.
5.
(Proposed) Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems designed to
provide protection for BES Element(s). [Violation Risk Factor: Medium] [Time Horizon:
Long Term Planning]
The PSMP shall:
1.1. Address all Protection System component types.
1.2. Identify which maintenance method (time-based,
performance-based (per PRC-005 Attachment A), or a
Draft 4: April 12, 2011
Component Type - Any one of
the five specific elements of the
Protection System definition.
4
Standard PRC-005-2 — Protection System Maintenance
combination) is used to address each Protection System component type. All batteries
associated with the station dc supply component type of a Protection System shall be
included in a time-based program as described in Table 1-4.
1.3. Identify the associated maintenance intervals for time-based programs, to be no less
frequent than the intervals established in Table 1-1 through 1-5 and Table 2.
1.4. Include all applicable monitoring attributes and related maintenance activities applied to
each Protection System component type consistent with the maintenance intervals
specified in Tables 1-1 through 1-5 and
Table 2.
Maintenance Correctable Issue -
R2. Each Transmission Owner, Generator Owner,
and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall
follow the procedure established in PRC-005
Attachment A to establish and maintain its
performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations
Planning]
Failure of a component to operate
within design parameters such that it
cannot be restored to functional order
by repair or calibration during
performance of the initial on-site
activity. Therefore this issue requires
follow-up corrective action.
R3. Each Transmission Owner, Generator Owner,
and Distribution Provider shall implement and follow its PSMP and initiate resolution of any
identified maintenance correctable issues.
[Violation Risk Factor: High] [Time Horizon: Operations Planning]
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a current or
updated documented Protection System Maintenance Program that addresses all component
types of its Protection Systems, as required by Requirement R1. For each Protection System
component type, the documentation shall include the type of maintenance program applied
(time-based, performance-based, or a combination of these maintenance methods),
maintenance activities, maintenance intervals, and, for component types that use monitoring to
extend the intervals, the appropriate monitoring attributes as specified in Requirement R1,
Parts 1.1 through 1.4.
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses a
performance-based maintenance program shall have evidence that its current performancebased maintenance program is in accordance with Requirement R2, which may include but is
not limited to equipment lists, dated maintenance records, and dated analysis records and
results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has implemented the Protection System Maintenance Program and initiated resolution of
identified Maintenance Correctable Issues in accordance with Requirement R3, which may
include but is not limited to dated maintenance records, dated maintenance summaries, dated
check-off lists, dated inspection records, or dated work orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
Draft 4: April 12, 2011
5
Standard PRC-005-2 — Protection System Maintenance
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to demonstrate compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its
current dated Protection System
Component – A component is any individual
Maintenance Program including
discrete
piece of equipment included in a
the documentation that specifies
Protection
System, including but not limited to
the type of maintenance program
a protective relay or current sensing device.
applied for each Protection
The designation of what constitutes a control
System component type.
circuit component is very dependent upon how
an entity performs and tracks the testing of the
For Requirement R2 and
control circuitry. Some entities test their
Requirement R3, the
control circuits on a breaker basis whereas
Transmission Owner, Generator
others test their circuitry on a local zone of
Owner, and Distribution Provider
protection basis. Thus, entities are allowed
shall each keep documentation of
the latitude to designate their own definitions
the two most recent
of control circuit components. Another
performances of each distinct
example of where the entity has some
maintenance activity for the
discretion on determining what constitutes a
Protection System components,
single component is the voltage and current
or all performances of each
sensing devices, where the entity may choose
distinct maintenance activity for
either to designate a full three-phase set of
the Protection System component
such devices or a single device as a single
since the previous scheduled
component.
audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last periodic audit report and all
requested and submitted subsequent compliance records.
1.4. Additional Compliance Information
None.
Draft 4: April 12, 2011
6
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
R1
Failed to specify whether one
component type is being addressed
by time-based or performance-based
maintenance. (Part 1.2)
R2
Entity has Protection System
elements in a performance-based
PSMP but has:
1) Failed to reduce countable
events to less than 4% within
three years
OR
Failed to annually document
2)
program activities, results,
maintenance dates, or countable
events for 5% or less of
components in any individual
segment
OR
3) Maintained a segment with 54-59
components or containing
different manufacturers.
Draft 4: April 12, 2011
Moderate VSL
Failed to specify whether two
component types are being
addressed by time-based or
performance-based maintenance.
(Part 1.2)
NA
High VSL
Severe VSL
Failed to include station batteries in
a time-based program (Part 1.2)
OR
Failed to include all maintenance
activities or intervals relevant for the
identified monitoring attributes
specified in Tables 1-1 through 1-5.
(Part 1.4)
Entity has not established a PSMP.
OR
The entity’s PSMP failed to address
three or more component types
included in the definition of
‘Protection System’ (Part 1.1)
OR
Failed to specify whether three or
more component types are being
addressed by time-based or
performance-based maintenance.
Entity has Protection System
elements in a performance-based
PSMP but has failed to reduce
countable events to less than 4%
within three years.
Entity has Protection System
components in a performancebased PSMP but has:
1) Failed to establish the entire
technical justification
described within R3 for the
initial use of the performancebased PSMP
OR
2) Failed to reduce countable
events to less than 4% within
five years
OR
3) Failed to annually document
program activities, results,
maintenance dates, or countable
events for over 5% of
components in any individual
segment
OR
4) Maintained a segment with less
7
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
than 54 components
OR
5) Failed to:
• Annually update the list of
components,
• Perform maintenance on the
greater of 5% of the segment
population or 3 components,
• Annually analyze the program
activities and results for each
segment.
R3
Entity has failed to complete
scheduled program on 5% or less of
total Protection System components.
OR
Entity has failed to initiate resolution
on 5% or less of identified
maintenance correctable issues.
Draft 4: April 12, 2011
Entity has failed to complete
scheduled program on greater than
5%, but no more than 10% of total
Protection System components
OR
Entity has failed to initiate
resolution on greater than 5%, but
less than or equal to 10% of
identified maintenance correctable
issues.
Entity has failed to complete
scheduled program on greater than
10%, but no more than 15% of total
Protection System components
OR
Entity has failed to initiate resolution
on greater than 10%, but less than or
equal to 15% of identified.
8
Entity has failed to complete
scheduled program on greater than
15% of total Protection System
components
OR
Entity has failed to initiate
resolution on greater than 15% of
identified maintenance correctable
issues.
Standard PRC-005-2 – Protection System Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — February
2011.
Version History
Version
Date
Action
2
TBD
Complete revision, absorbing maintenance
requirements from PRC-005-1, PRC-008-0,
PRC-011-0, PRC-017
Draft 4: April 12, 2011
Change Tracking
Complete revision
9
Standard PRC-005-2 – Protection System Maintenance
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
• Test and, if necessary calibrate
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
• Verify acceptable measurement of power system input values.
Verify:
Monitored microprocessor protective relay with the following:
• Settings are as specified.
• Internal self diagnosis and alarming.
• Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics (see Table
2).
12 calendar
years
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values.
• Alarming for power supply failure (see Table 2).
Monitored microprocessor protective relay with preceding row attributes
and the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive
error. (See Table 2)
• Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure. (See Table 2)
12 calendar
years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Alarming for change of settings. (See Table 2)
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10
Standard PRC-005-2 – Protection System Maintenance
Table 1-2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, except as noted.
Component Attributes
Maximum
Maintenance
Interval
3 calendar
months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function. (See Table 2)
Any communications system with continuous monitoring or periodic
automated testing for the performance of the channel using criteria pertinent
to the communications technology applied (e.g. signal level, reflected power,
or data error rate, and alarming for excessive performance degradation). (See
Table 2)
Draft 4: April 12, 2011
6 calendar
years
12 calendar
years
No periodic
maintenance
specified
Maintenance Activities
Verify that the communications system is functional.
Verify that the channel meets performance criteria pertinent to
the communications technology applied (e.g signal level,
reflected power, or data error rate).
Verify essential signals to and from other Protection System
components.
Verify that the channel meets performance criteria pertinent to
the communications technology applied (e.g signal level,
reflected power, or data error rate).
Verify essential signals to and from other Protection System
components.
None.
11
Standard PRC-005-2 – Protection System Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems except as noted.
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value as measured by the microprocessor relay to an
independent ac measurement source, with alarming for unacceptable
error or failure.
Draft 4: April 12, 2011
Maximum
Maintenance
Interval
Maintenance Activities
12 calendar years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
12
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(a)
Component Type - Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
18 Calendar
Months
Protection System Station dc supply for distribution breakers
for UFLS or UVLS are excluded (see Table 1-4(e)).
18 Calendar
Months
-or6 Calendar Years
Draft 4: April 12, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
• Physical condition of battery rack
Verify that the station battery can perform as designed by evaluating
the measured cell/unit internal ohmic values to station battery baseline.
-orVerify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the
entire battery bank.
13
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(b)
Component Type - Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
6 Calendar Months
Station dc supply with Valve Regulated Lead-Acid (VRLA)
batteries not having monitoring attributes of Table 1-4(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Months
-or3 Calendar Years
Draft 4: April 12, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
• Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Physical condition of battery rack
Verify that the station battery can perform as designed by evaluating
the measured cell/unit internal ohmic values to station battery baseline.
-orVerify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the
entire battery bank
14
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(c)
Component Type - Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Station dc supply Nickel-Cadmium (NiCad) batteries not
having monitoring attributes of Table 1-4(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Years
Draft 4: April 12, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells.
• Physical condition of battery rack
Verify that the station battery can perform as designed by conducting a
performance service, or modified performance capacity test of the
entire battery bank.
15
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(d)
Component Type - Station dc Supply Using Non Battery Based Energy Storage
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
Protection System Station dc supply for distribution breakers
for UFLS, UVLS and SPS are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Years
Draft 4: April 12, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
Condition of non-battery based dc supply
Verify that the dc supply can perform as designed when ac power is not
present.
16
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(e)
Component Type - Station dc Supply for Distribution Breakers
Component Attributes
Maximum
Maintenance
Interval
Any dc supply for tripping only distribution breakers as part of
a UFLS or UVLS system, or SPS and not having monitoring
attributes of Table 1-4(f).
When control
circuits are verified
(See Table 1-5)
Draft 4: April 12, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
17
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(f)
Exclusions for Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure. (See Table 2)
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2)
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2)
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2)
No periodic maintenance
specified
No periodic verification of float voltage of battery charger is
required
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2)
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2)
No periodic verification of the intercell and terminal
connection resistance is required.
Any lead acid battery based station dc supply with monitoring
and alarming of internal Ohmic values of every cell (if
available for measurement) or each unit and alarming when any
cell/unit deviates by an unacceptable value from the baseline
internal ohmic value. (See Table 2)
Draft 4: April 12, 2011
No periodic measurement and comparison to baseline of
battery cell/unit internal ohmic values for VRLA batteries and
VLA batteries where the cells are not visible are required.
.
18
Standard PRC-005-2 – Protection System Maintenance
Table 1-5
Component Type - Control Circuitry
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (excluding UFLS or UVLS systems).
Trip coils of circuit breakers and interrupting devices in UFLS or UVLS
systems.
Maximum
Maintenance
Interval
6 calendar
years
No periodic
maintenance
specified
Maintenance Activities
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
None.
Electromechanical lockout and/or tripping auxiliary devices which are directly
in a trip path from the protective relay to the interrupting device trip coil.
6 calendar
years
Verify electrical operation of electromechanical trip and
auxiliary devices.
Unmonitored control circuitry associated with protective functions.
12 calendar
years
Verify all paths of the control and trip circuits.
Control circuitry whose continuity and energization or ability to operate are
monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Draft 4: April 12, 2011
19
Standard PRC-005-2 – Protection System Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance activities are
subject to the following maintenance requirements
Maximum
Component Attributes
Maintenance
Maintenance Activities
Interval
Any alarm path through which alarms in Tables 1-1 through 1-5 are conveyed
from the alarm origin to the location where corrective action can be initiated,
and not having all the attributes of the “Alarm Path with monitoring” category
below.
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of DETECTION to a location where
corrective action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 4: April 12, 2011
No periodic
maintenance
specified
No periodic maintenance specified.
20
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
components included in each designated
segment of the Protection System
component population, with a minimum
segment population of 60 components.
Segment – Protection Systems or components
of a consistent design standard, or a
particular model or type from a single
manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
segment. A segment must contain at least
sixty (60) individual components.
2. Maintain the components in each segment
according to the time-based maximum
allowable intervals established in Tables
1-1through 1-5 until results of
maintenance activities for the segment are
available for a minimum of 30 individual components of the segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events
for each included component.
Countable Event – A component which has failed
4. Analyze the maintenance program
activities and results for each segment to
determine the overall performance of the
segment and develop maintenance
intervals.
and requires repair or replacement, any condition
discovered during the verification activities in
Tables 1-1 through 1-5 which requires corrective
action, or a Misoperation attributed to hardware
failure or calibration failure. Misoperations due
to product design errors, software errors, relay
settings different from specified settings,
Protection System component configuration
errors, or Protection System application errors
are not included in Countable Events.
5. Determine the maximum allowable
maintenance interval for each segment
such that the segment experiences
countable events on no more than 4% of
the components within the segment, for
the greater of either the last 30
components maintained or all components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
Draft 4: April 12, 2011
21
Standard PRC-005-2 – Protection System Maintenance
4. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
5. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
Draft 4: April 12, 2011
22
Standard PRC-005-2 — Protection System Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approves SAR for posting on June 5, 2007.
2. The SAR was posted for comment from June 11, 2007–July 10, 2007.
3. The SC approves development of the standard on August 13, 2007.
4. First posting of revised standard on July 24, 2009.
5. Second posting of revised standard on June 11, 2010
6. Third posting of revised standard on September 24November 17, 2010
Description of Current Draft:
This is the third fourth draft of the Standard. This standard merges previous standards PRC-005-1, PRC008-0, PRC-011-0, and PRC-017-0. It also addresses FERC comments from Order 693, and addresses
observations from the NERC System Protection and Control Task Force, as presented in NERC SPCTF
Assessment of Standards: PRC-005-1 — Transmission and Generation Protection System Maintenance
and Testing, PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs, PRC011-0 — UVLS System Maintenance and Testing, PRC-017-0 — Special Protection System Maintenance
and Testing.
Future Development Plan:
Anticipated Actions
1. Post for combined 30-day comment and ballot.
2. Conduct successive ballot
3. Drafting Team Responds to Comments
Draft 4 PRC-005-2 – April 12, 2011
Anticipated Date
November 17-December 17, 201015April 125, 2011
December 7– December 17, 2010May
2 – May 12, 2011
January 5, 2011–January 25 May 16 –
June 3, 2011
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Restore — Return malfunctioning components to proper operation.
Protection System (NERC Board of Trustees modificationApproved Definition)
•
•
•
•
•
Protective relays which respond to electrical quantities,
communications systems necessary for correct operation of protective functions,
voltage and current sensing devices providing inputs to protective relays,
station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
The following terms are defined for use only within PRC-005-2, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that
it cannot be restored to functional order by repair or calibration during performance of the initial on-site
activity. Therefore this issue requires follow-up corrective action.
Segment – Protection Systems or components of a consistent design standard, or a particular model or
type from a single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segmenta segment. A segment must contain at least sixty (60)
individual components.
Component Type - Any one of the five specific elements of the Protection System definition.
Component – A component is any individual discrete piece of equipment included in a Protection
System, such asincluding but not limited to a protective relay or current sensing device. For components
such as control circuits, tThe designation of what constitutes a control circuit component is very
dependent upon how an entity performs and tracks the testing of the control circuitry. Some entities test
Draft 4 PRC-005-2 – April 12, 2011
Standard PRC-005-2 — Protection System Maintenance
their control circuits on a breaker basis whereas others test their circuitry on a “local zone of protection”
basis. Thus, entities are allowed the latitude to designate their own definitions of “control circuit
components.” Another example of where the entity has some discretion on determining what constitutes
a single component is the voltage and current sensing devices, where the entity may choose either to
designate a full three-phase set of such devices or a single device as a single component.
Countable Event – Any failure of aA component which has failed requiresand requires repair or
replacement, any condition discovered during the verification activities in Tables 1-1 through 1-5 which
requires corrective action, or a Misoperation attributed to hardware failure or calibration failure.
Misoperations due to product design errors, software errors, relay settings different from specified
settings, Protection System component configuration errors, or Protection System application errors are
not included in Countable Events.
Draft 4 PRC-005-2 – April 12, 2011
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems applied on, or designed to provide protection for, the BES
Element(s).
4.2.14.2.2
Protection Systems used for underfrequency load-shedding systems
installed per ERO underfrequency load-shedding requirements.
4.2.24.2.3
Protection Systems used for undervoltage load-shedding systems
installed to prevent system voltage collapse or voltage instability for BES
reliability.
4.2.34.2.4
Protection Systems installed as a Special Protection System (SPS) for
BES reliability.
4.2.44.2.5
Protection Systems for generator Facilities that are part of the BES,
including:
4.2.4.14.2.5.1
Protection Systems that act to trip the generator either directly or
via generator lockout or auxiliary tripping relays.
4.2.4.24.2.5.2
Protection Systems for generator step-up transformers for
generators that are part of the BES.
4.2.4.34.2.5.3
Protection Systems for transformers connecting aggregated
generation, where the aggregated generation is part of the BES (e.g.,
transformers connecting facilities such as wind-farms to the BES).
4.2.4.44.2.5.4
Protection Systems for generator-connected station service
transformers for generators that are part of the BES.
4.2.4.5 Protection Systems for system-connected station service transformers for
generators that are part of the BES.
5.
(Proposed) Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems applied on, or
designed to provide protection for, the BES Element(s). The PSMP shall: [Violation Risk
Factor: Medium] [Time Horizon: Long Term Planning]
Draft 4 PRC-005-2 – April 12, 2011
Standard PRC-005-2 — Protection System Maintenance
1.1. Address all Protection System component types.
1.2. Identify which maintenance method (time-based, performance-based (per PRC-005
Attachment A), or a combination) is used to address each Protection System component
types are addressed through time-based, performance-based (per PRC-005 Attachment
A), or a combination of these maintenance methods (per PRC-005-Attachment A). All
batteries associated with the station dc supply component type of a Protection System
shall be included in a time-based program as described in Table 1-4.
1.3. Identify the associated maintenance intervals for time-based programs, to be no less
frequent than the intervals established in Table 1-1 through 1-5 and Table 2.
1.4.Include all applicable monitoring attributes and related maintenance activities applied to
each Protection System component type, to include those consistent with the
maintenance intervals specified in Tables 1-1 through 1-5 and Table 2.
1.5.
Identify calibration tolerances or other equivalent parameters for each Protection System
component type that establish acceptable parameters for the conclusion of maintenance activities.
1.4. Each Transmission Owner, Generator Owner, and Distribution Provider that uses
maintenance intervals for monitored Protection Systems described in Tables 1-1 through
1-5, shall verify those components possess the monitoring attributes identified in Tables
1-1 through 1-5 in its PSMP. [Violation Risk Factor: Medium] [Time Horizon: Long
Term Planning]
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement and
follow its PSMP and initiate resolution of any identified maintenance correctable issues,
including identification of the resolution of all maintenance correctable issues as follows: .
[Violation Risk Factor: High] [Time Horizon: Operations Planning]
R4. Perform the maintenance activities for all Protection System components according to the
PSMP established in accordance with Requirement R1:
R5. For time-based maintenance programs, perform maintenance activities no less frequently than
the maximum allowable intervals established in Tables 1-1 through 1-5.
R6. For performance-based maintenance programs, perform the maintenance activities no less
frequently than the intervals established in Requirement R3.
R7.R3.
Either verify that the components are within the acceptable parameters established in
accordance with Requirement R1, Part 1.5 at the conclusion of the maintenance activities, or
initiate resolution of any identified maintenance correctable issues.
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a current or
updated documented Protection System Maintenance Program that addresses all component
types of its Protection Systems, as required by Requirement R1. For each Protection System
component type, the documentation shall include the type of maintenance program applied
(time-based, performance-based, or a combination of these maintenance methods),
maintenance activities, and maintenance intervals, and, for component types that use
Draft 4 PRC-005-2 – April 12, 2011
Standard PRC-005-2 — Protection System Maintenance
monitoring to extend the intervals, the appropriate monitoring attributes as specified in
Requirement R1, Parts 1.1 through 1. 54.
M1. Each Transmission Owner, Generator Owner, and Distribution Provider that uses maintenance
intervals for monitored Protection Systems shall have evidence such as engineering drawings
or manufacturer’s information showing that the components possess the monitoring attributes
identified in Tables 1-1 through 1-5, as required by Requirement R2.
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses a
performance-based maintenance program shall have evidence which may include but not
limited to such as equipment lists, dated maintenance records, and dated analysis records and
results that its current performance-based maintenance program is in accordance with
Requirement R3R2.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such aswhich may include but not limited to dated maintenance records, dated maintenance
summaries, dated check-off lists, dated inspection records, or dated work orders as evidence
that it has implemented the Protection System Maintenance Program and initiated resolution of
identified maintenance correctable issues in accordance with Requirement R4R3.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to demonstrate compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program
including the documentation that specifies the type of maintenance program applied for
each Protection System component type.
For R2, the Transmission Owner, Generator Owner, and Distribution Provider shall each
keep the evidence that proves the Protection System components possess the identified
monitoring attributes as long as they are used to justify the intervals and activities
associated with a performance-based maintenance program as identified within Tables 11 through 1-5.
Draft 4 PRC-005-2 – April 12, 2011
Standard PRC-005-2 — Protection System Maintenance
For Requirement R3 R2 and Requirement R4R3, the Transmission Owner, Generator
Owner, and Distribution Provider shall each keep documentation of the two most recent
performances of each distinct maintenance activity for the Protection System
components, or all performances of each distinct maintenance activity for the Protection
System component since or to the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last periodic audit report and all
requested and submitted subsequent compliance records.
1.4. Additional Compliance Information
None.
Draft 4 PRC-005-2 – April 12, 2011
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels
Requirement
Number
R1
Lower VSL
Failed to specify whether one
component type is being addressed
by time-based or performance-based
maintenance. (ClausePart 1.2)
R2
Entity has Protection System
components in a condition-based
PSMP, but documentation to support
the monitoring attributes used to
determine relevant intervals is
incomplete on no more than 5% of
the Protection System components
maintained according to Tables 1-1
through 1-5.
R3R2
Entity has Protection System
elements in a performance-based
PSMP but has:
1) 1) Failed to reduce countable
events to less than 4% within
three years
OR
Draft 4 PRC-005-2 – April 12, 2011
Moderate VSL
High VSL
Severe VSL
Failed to specify whether two
component types are being
addressed by time-based or
performance-based maintenance.
(ClausePart 1.2)
Failed to include station batteries in
a time-based program (ClausePart
1.2)
Entity has not established a PSMP.
OR
The entity’s PSMP failed to address
three or more component types
included in the definition of
‘Protection System’ (ClausePart
1.1)
OR
Failed to specify whether three or
more component types are being
addressed by time-based or
performance-based maintenance.
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support monitoring attributes used
to determine relevant intervals is
incomplete on more than 5%, but
10% or less, of the Protection
System components maintained
according to Tables 1-1 through 1-5.
Entity has Protection System
elements in a condition-based
PSMP, but documentation to support
monitoring attributes used to
determine relevant intervals is
incomplete on more than 10%, but
15% or less, of the Protection
System components maintained
according to Tables 1-1 through 1-5.
Entity has Protection System
elements in a condition-based
PSMP, but documentation to
support monitoring attributes used
to determine relevant intervals is
incomplete on more than 15% of
the Protection System components
maintained according to Tables 1-1
through 1-5.
Entity has Protection System
elements in a performance-based
PSMP but has failed to reduce
countable events to less than 4%
within four years.
Entity has Protection System
components in a performancebased PSMP but has:
1) Failed to establish the entire
technical justification
described within R3 and
Attachment A for the initial
use of the performance-based
NA
OR
Failed to include all maintenance
activities or intervals relevant for the
identified monitoring attributes
specified in Tables 1-1 through 1-5.
(ClausePart 1.4)
OR
Failed to establish calibration
tolerance or equivalent parameters to
determine if components are within
acceptable parameters.
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
2)
Moderate VSL
High VSL
2) Failed to annually document
program activities, results,
maintenance dates, or countable
events for 5% or less of
components in any individual
segment
OR
PSMP
OR
1)2) Failed to reduce countable
events to less than 4% within
five years
OR
23) Failed to annually document
program activities, results,
maintenance dates, or countable
events for over 5% of
components in any individual
segment
OR
34) Maintained a segment with less
than 54 components
OR
45) Failed to:
• Annually update the list of
components,
• Perform maintenance on the
greater of 5% of the segment
population or 3 components,
• Annually analyze the program
activities and results for each
segment.
3) Maintained a segment with 54-59
components or containing
different manufacturers.
R4R3
Entity has failed to complete
scheduled program on 5% or less of
total Protection System components.
OR
Entity has failed to initiate resolution
on 5% or less of identified
maintenance- correctable issues.
Draft 4 PRC-005-2 – April 12, 2011
Severe VSL
Entity has failed to complete
scheduled program on greater than
5%, but no more than 10% of total
Protection System components
OR
Entity has failed to initiate
resolution on greater than 5%, but
less than or equal tono more than
10% of identified maintenance-
Entity has failed to complete
scheduled program on greater than
10%, but no more than 15% of total
Protection System components
OR
Entity has failed to initiate resolution
on greater than 10%, but less than or
equal tono more than 15% of
Entity has failed to complete
scheduled program on greater than
15% of total Protection System
components
OR
Entity has failed to initiate
resolution on greater than 15% of
identified maintenance- correctable
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Moderate VSL
correctable issues.
Draft 4 PRC-005-2 – April 12, 2011
High VSL
identified.
Severe VSL
issues.
Standard PRC-005-2 – Protection System Maintenance
E. Regional Variances
None
F. Supplemental Reference Documents
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — July
2009February 2011.
1. NERC Protection System Maintenance Standard PRC-005-2 FREQUENTLY ASKED
QUESTIONS — Practical Compliance and Implementation DRAFT 1.0 — June 2009
Version History
Version
Date
Action
2
TBD
Complete revision, absorbing maintenance
requirements from PRC-005-1, PRC-008-0,
PRC-011-0, PRC-017
Draft 3: November 17, 2010
Change Tracking
Complete revision
11
Standard PRC-005-2 – Protection System Maintenance
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
• Test and, if necessary calibrate
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
• Verify acceptable measurement of power system input values.
Verify:
Monitored microprocessor protective relay with the following::
• Settings are as specified.
• Internal self diagnosis and alarming.
• Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics that are also
performing self monitoring and alarming (see Table 2).
12 calendar
years
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values.
• Alarming for power supply failure (see Table 2).
Monitored microprocessor protective relay with preceding row attributes
and the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive
error. (See Table 2)
• Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure. (See Table 2)
12 calendar
years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Alarming for change of settings. (See Table 2)
Draft 3: November 17, 2010
12
Standard PRC-005-2 – Protection System Maintenance
Table 1-2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
3 calendar
months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function. (See Table 2)
Any communications system with continuous monitoring or periodic
automated testing for the performance of the channel using criteria pertinent
to the communications technology applied (e.ge.g. such as signal level,
reflected power, or data error rate, and alarming for excessive performance
degradation). (See Table 2)
Draft 3: November 17, 2010
6 calendar
years
12 calendar
years
No periodic
maintenance
specified
Maintenance Activities
Verify that the communications system is functional.
Verify that the channel meets performance criteria pertinent to
the communications technology applied (e.g such as signal
level, reflected power, or data error rate).
Verify essential signals to and from other Protection System
components.
Verify that the channel meets performance criteria pertinent to
the communications technology applied (e.g such as signal
level, reflected power, or data error rate).
Verify essential signals to and from other Protection System
components.
None.
13
Standard PRC-005-2 – Protection System Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value as measured by the microprocessor relay to an
independent ac measurement source, with alarming for unacceptable
error or failure.
Draft 3: November 17, 2010
Maximum
Maintenance
Interval
Maintenance Activities
12 calendar years
Verify that acceptable measurements of the current and voltage
signals signal values are received byprovided to the protective
relays.
No periodic
maintenance
specified
None.
14
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Any dc supply for a UFLS or UVLS system.
Maximum
Maintenance
Interval
When control
circuits are
verified
3 Calendar
Months
Any unmonitored station dc supply not having the monitoring
attributes of a category below. (excluding UFLS and UVLS)
18 Calendar
Months
Any unmonitored Station dc supply in which a battery is not used and
not having the monitoring attributes of a category below. (excluding
UFLS and UVLS)
Unmonitored Station dc supply with Valve Regulated Lead-Acid
(VRLA) batteries that does not have the monitoring attributes of a
category below. (excluding UFLS and UVLS)
Draft 3: November 17, 2010
Activities
Verify dc supply voltage
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level (excluding valve-regulated lead acid
batteries)
• For unintentional grounds
Verify:
• State of charge of the individual battery cells/units
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery internal cell-to-cell or unit-to-unit connection resistance
(where available to measure)
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
6 Calendar Years
Verify that the dc supply can perform as designed when ac power
from the grid is not present.
3 Calendar
Months
Verify that the station battery can perform as designed by
evaluating the measured cell/unit internal ohmic values to station
battery baseline.
15
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Activities
--------------------------------- or ---------------------------------
3 Calendar Years
Verify that the station battery can perform as designed by
evaluating the measured cell/unit internal ohmic values to station
battery baseline.
18 Calendar
Months
Unmonitored Station dc supply with Vented Lead-Acid Batteries
(VLA) that does not have the monitoring attributes of a category
below. (excluding UFLS and UVLS)
Unmonitored Station dc supply with Nickel-Cadmium (Ni-Cad)
batteries that does not have the monitoring attributes of a category
below. (excluding UFLS and UVLS)
Monitored Station dc supply (excluding UFLS and UVLS) with:
Monitor and alarm for variations from defined levels (See Table 2):
• Station dc supply voltage (voltage of battery charger)
• State of charge of the individual battery cell/units
• Battery continuity of station battery
• Cell-to-cell (if available) and battery terminal resistance
Draft 3: November 17, 2010
Verify that the station battery can perform as designed by
conducting a performance or service capacity test of the entire
battery bank.
--------------------------------- or ---------------------------------
6 Calendar Years
Verify that the station battery can perform as designed by
conducting a performance, service, or modified performance
capacity test of the entire battery bank.
6 Calendar Years
Verify that the station battery can perform as designed by
conducting a performance service, or modified performance
capacity test of the entire battery bank.
18 calendar
months
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
16
Standard PRC-005-2 – Protection System Maintenance
Table 1-4
Component Type - Station dc Supply
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
• Electrolyte level of all cells in a station battery
• Unintentional dc grounds
• Cell/unit internal ohmic values of station battery
Continuously monitored Station dc supply (excludes UFLS and
UVLS) with preceding row attributes and the following:
• The monitoring devices themselves are monitored.
Draft 3: November 17, 2010
Maximum
Maintenance
Interval
6 calendar years
18 calendar
months
Activities
Verify that the monitoring devices are calibrated (where
necessary)
Inspect:
• Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
• Physical condition of battery rack
• Condition of non-battery-based dc supply
17
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(a)
Component Type - Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Station dc supply with Vented Lead-Acid (VLA) batteries not
having monitoring attributes of Table 1-4(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
18 Calendar
Months
-or6 Calendar Years
Draft 3: November 17, 2010
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
• Physical condition of battery rack
Verify that the station battery can perform as designed by evaluating
the measured cell/unit internal ohmic values to station battery baseline.
-orVerify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the
entire battery bank.
18
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(b)
Component Type - Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
6 Calendar Months
Station dc supply with Valve Regulated Lead-Acid (VRLA)
batteries not having monitoring attributes of Table 1-4(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Months
-or3 Calendar Years
Draft 3: November 17, 2010
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
• Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Physical condition of battery rack
Verify that the station battery can perform as designed by evaluating
the measured cell/unit internal ohmic values to station battery baseline.
-orVerify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the
entire battery bank
19
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(c)
Component Type - Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Station dc supply Nickel-Cadmium (NiCad) batteries not
having monitoring attributes of Table 1-4(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Years
Draft 3: November 17, 2010
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells.
• Physical condition of battery rack
Verify that the station battery can perform as designed by conducting a
performance service, or modified performance capacity test of the
entire battery bank.
20
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(d)
Component Type - Station dc Supply Using Non Battery Based Energy Storage
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Any station dc supply not using a battery and not having
monitoring attributes of Table 1-4(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Years
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
Condition of non-battery based dc supply
Verify that the dc supply can perform as designed when ac power is not
present.
Table 1-4(e)
Component Type - Station dc Supply for Distribution Breakers
Component Attributes
Maximum
Maintenance
Interval
Any dc supply for tripping only distribution breakers as part of
a UFLS or UVLS system, or SPS and not having monitoring
attributes of Table 1-4(f).
When control
circuits are verified
Draft 3: November 17, 2010
Maintenance Activities
Verify:
• Station dc supply voltageVerify:
dc supply voltage
21
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(f)
Exclusions for Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure. (See Table 2)
No periodic verification of station battery chargerdc supply
voltage is required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2)
No periodic verification inspection of the electrolyte level for
each cell is required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2)
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply.Any battery based station dc supply with
monitoring and alarming of the state of charge of the battery
system (See Table 2)
No periodic maintenance
specified
6 calendar years
6 calendar years
6 calendar years
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2)
6 calendar years
Any battery based station dc supply with monitoring and
alarming of the Cell-to-intercell and/or terminal connection
detail resistance of the entire battery (See Table 2)
6 calendar years
Any lead acid battery based station dc supply with monitoring
and alarming of internal Ohmic values of every cell (if
available for measurement) or each unit and alarming when any
cell/unit deviates by an unacceptable value from the baseline
internal ohmic value. (See Table 2)
Draft 3: November 17, 2010
6 calendar years
No periodic verification inspection of unintentional dc
grounds is required.
No periodic verification of float voltage of battery charger is
requiredNo periodic verification of the battery state of charge
is required.
No periodic verification of the battery string continuity is
required.
No periodic verification of the cell-to-intercell and terminal
connection resistance is required.
No periodic measurement and comparison to baseline of
battery cell/unit internal ohmic values for VRLA batteries and
VLA batteries where the cells are not visible are required.
verification of each cell or unit’s Ohmic resistance is required.
22
Standard PRC-005-2 – Protection System Maintenance
Table 1-5
Component Type - Control Circuitry
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (excluding UFLS or UVLS systems).
Trip coils of circuit breakers and interrupting devices in UFLS or UVLS
systems.
Maximum
Maintenance
Interval
6 calendar
years
No periodic
maintenance
specified
Maintenance Activities
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
None.
Electromechanical trip or lockout and/or tripping auxiliary devices which are
directly in a trip path from the protective relay to the interrupting device trip
coil.
6 calendar
years
Verify electrical operation of electromechanical trip and
auxiliary devices.
Unmonitored Control control circuitry associated with protective functions.
12 calendar
years
Verify all paths of the control and trip circuits.
Control circuitry whose continuity and energization or ability to operate are
monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Draft 3: November 17, 2010
23
Standard PRC-005-2 – Protection System Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance activities are
subject to the following maintenance requirements
Maximum
Component Attributes
Maintenance
Maintenance Activities
Interval
Any alarm path through which alarms in Tables 1-1 through 1-5 are conveyed
from the alarm origin to the location of where corrective action can be initiated,
and not having all the attributes of the category “Alarm Path with monitoring”
category below.
Alarms are automatically reported within 24 hours of DETECTION to a
location where corrective action can be takeninitiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be takeninitiated.
Draft 3: November 17, 2010
When alarm
producing device or
system is verified12
Calendar Years
No periodic
maintenance
specified
Verify that the alarm path conveys alarm signals
are conveyed to a location where corrective action
can be takeninitiated.
No periodic maintenance specifiedNone.
24
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of components included in each designated segment of
the Protection System component population, with a minimum segment population of 60
components.
2. Maintain the components in each segment according to the time-based maximum
allowable intervals established in Tables 1-1through 1-5 until results of maintenance
activities for the segment are available for a minimum of 30 individual components of the
segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events 1 for each included component.
4. Analyze the maintenance program activities and results for each segment to determine the
overall performance of the segment and develop maintenance intervals.
5. Determine the maximum allowable maintenance interval for each segment such that the
segment experiences countable events on no more than 4% of the components within the
segment, for the greater of either the last 30 components maintained or all components
maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
4. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
5. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
1
Countable events include any failure of a component requiring repair or replacement, any condition discovered
during the verification activities in Table 1a through Table 1c which requires corrective action, or a Misoperation
attributed to hardware failure or calibration failure.
Draft 3: November 17, 2010
25
Standard PRC-005-2 – Protection System Maintenance
Draft 3: November 17, 2010
26
Implementation Plan for PRC-005-02
Standards Involved:
• Approval:
o PRC-005-2 – Protection System Maintenance and Testing
•
Retirements:
o PRC-005-1 – Transmission and Generation Protection System Maintenance and Testing
o PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding
o Equipment Maintenance Program
o PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
o PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
• Revised definition of “Protection System”
Background:
The Implementation Plan reflects consideration of the following:
1. The requirements set forth in the proposed standard establish maximum allowable maintenance
intervals for the first time. The established maximum allowable intervals may be shorter than those
currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the proposed
standard, it is unrealistic for those entities to be immediately in compliance with the new intervals.
Further, entities should be allowed to become compliant in such a way as to facilitate a continuing
maintenance program.
3. Entities that have previously been performing maintenance within the newly specified intervals may
not have all the documentation needed to demonstrate compliance with all of the maintenance
activities specified.
4. The Implementation Schedule set forth in this document requires that entities develop their revised
Protection System Maintenance Program within 12 months following applicable regulatory approvals,
or in those jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter twelve months following Board of Trustees adoption.
5. The Implementation Schedule set forth in this document further requires implementation of the
revised Protection System Maintenance Program in roughly equally-distributed steps over the
maintenance intervals prescribed for each respective maintenance activity in order that entities may
implement this standard in a systematic method that facilitates an effective ongoing Protection
System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall follow the protection
system maintenance and testing program it used to perform maintenance and testing to comply with PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 (for the Protection System components identified in
PRC-005-2 Tables 1-1 through 1-5) until that Transmission Owner, Generator Owner or Distribution
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Provider meets initial compliance for maintenance of the same Protection System component, in
accordance with the phasing specified below.
For audits that are conducted during the time period when entities are modifying their existing protection
system maintenance and testing programs to become compliant with the maintenance activities and
intervals specified in PRC-005-2, each responsible entity must be prepared to identify:
•
All of its applicable protection system components.
•
For each component, whether maintenance of that component is still being addressed under PRC005-1 or is being performed according toPRC-005-2.
•
Evidence that each component has been maintained under the relevant requirements.
Retirement of Existing Standards:
The existing Standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired upon
regulatory approval of PRC-005-2.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 and R3 which use this defined term.
Implementation plan for Requirement R1:
•
Entities shall be 100% compliant on the first day of the first calendar quarter twelve months
following applicable regulatory approvals, or in those jurisdictions where no regulatory approval
is required, on the first day of the first calendar quarter twelve months following Board of
Trustees adoption.
Implementation plan for Requirements R2 and R3:
1. For Protection System components with maximum allowable intervals of less than 1 year, as
established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 15
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 15 months
following Board of Trustees adoption.
2. For Protection System components with maximum allowable intervals 1 year or more, but 2 years
or less, as established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 3
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 3 calendar
years following Board of Trustees adoption.
3. For Protection System components with maximum allowable intervals of 3 years, as established
in Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval (or, for generating plants with
Draft 4: April 12, 2011
2
scheduled outage intervals exceeding two calendar years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter 2 calendar years following Board of
Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 3
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 3 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 4
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
4. For Protection System components with maximum allowable intervals of 6 years, as established
in Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 3
calendar years following applicable regulatory approval (or, for generating plants with
scheduled outage intervals exceeding two calendar years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter 3 calendar years following Board of
Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 5
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 5 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 7
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 7 calendar
years following Board of Trustees adoption.
5. For Protection System components with maximum allowable intervals of 12 years, as established
in Tables 1-1 through 1-5 and Table 2:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 5
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 5 calendar
years following Board of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter
following 9 calendar years following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 9 calendar years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 13
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 13
calendar years following Board of Trustees adoption.
Draft 4: April 12, 2011
3
Applicability:
This standard applies to the following functional entities:
•
Transmission Owners
•
Generator Owners
•
Distribution Providers
Draft 4: April 12, 2011
4
Implementation Plan for PRC-005-02
Standards Involved:
• Approval:
o PRC-005-2 – Protection System Maintenance and Testing
•
Retirements:
o PRC-005-1 – Transmission and Generation Protection System Maintenance and Testing
o PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding
o Equipment Maintenance Program
o PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
o PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
• Revised definition of “Protection System”
Background:
The Implementation Plan reflects consideration of the following:
1. The requirements set forth in the proposed standard establish maximum allowable maintenance
intervals for the first time. The established maximum allowable intervals may be shorter than those
currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the proposed
standard, it is unrealistic for those entities to be immediately in compliance with the new intervals.
Further, entities should be allowed to become compliant in such a way as to facilitate a continuing
maintenance program.
3. Entities that have previously been performing maintenance within the newly specified intervals may
not have all the documentation needed to demonstrate compliance with all of the maintenance
activities specified.
4. The Implementation Schedule set forth in this document requires that entities develop their revised
Protection System Maintenance Program within 12 months following applicable regulatory approvals,
or in those jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter twelve months following Board of Trustees adoption.
3.5. The Implementation Schedule set forth in this document further requires implementation of the
revised Protection System Maintenance Program in roughly equally-distributed steps over the
maintenance intervals prescribed for each respective maintenance activity in order that entities may
implement this standard in a systematic method that facilitates an effective ongoing Protection
System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall follow the protection
system maintenance and testing program it used to perform maintenance and testing to comply with PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 (for the protection Protection system System components
identified in PRC-005-2 Tables 1-1 through 1-5) until that Transmission Owner, Generator Owner or
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Distribution Provider meets initial compliance for maintenance of the same protection Protection system
System component, in accordance with the phasing specified below.
For audits that are conducted during the time period when entities are modifying their existing protection
system maintenance and testing programs to become compliant with the maintenance activities and
intervals specified in PRC-005-2, each responsible entity must be prepared to identify:
•
All of its applicable protection system components.
•
For each component, whether maintenance of that component is still being addressed under PRC005-1 or is being performed according toPRC-005-2.
•
Evidence that each component has been maintained under the relevant requirements.
Retirement of Existing Standards:
The existing Standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired upon
regulatory approval of PRC-005-2.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 and, R3, and R4 which use this defined term.
Implementation plan for Requirement R1:
•
Entities shall be 100% compliant on the first day of the first calendar quarter twelve months
following applicable regulatory approvals, or in those jurisdictions where no regulatory approval
is required, on the first day of the first calendar quarter six twelve months following Board of
Trustees adoption.
Implementation plan for Requirements R2, and R3, and R4:
1. For Protection System Components components with maximum allowable intervals of less than 1
year, as established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 12 15
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 12 15 months
following Board of Trustees adoption.
2. For Protection System Components components with maximum allowable intervals 1 year or
more, but 2 years or less, as established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 2 3
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 2 3
calendar years following Board of Trustees adoption.
3. For Protection System components with maximum allowable intervals of 3 years, as established
in Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 2
calendar years following applicable regulatory approval (or, for generating plants with
Draft 34: November 17, 2010April 12, 2011
2
scheduled outage intervals exceeding two calendar years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter 2 calendar years following Board of
Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 3
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 3 calendar
years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 4
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 4 calendar
years following Board of Trustees adoption.
3.4. For Protection System Components components with maximum allowable intervals of 6 years, as
established in Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 2 3
calendar years following applicable regulatory approval (or, for generating plants with
scheduled outage intervals exceeding two calendar years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter 2 3 calendar years following Board
of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 4 5
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 4 5
calendar years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 6 7
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 6 7
calendar years following Board of Trustees adoption.
4.5. For Protection System Components components with maximum allowable intervals of 12 years,
as established in Tables 1-1 through 1-5 and Table 2:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 4 5
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 4 5
calendar years following Board of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter
following 8 9 calendar years following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 8 9 calendar years following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 12 13
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 12 13
calendar years following Board of Trustees adoption.
Draft 34: November 17, 2010April 12, 2011
3
Applicability:
This standard applies to the following functional entities:
•
Transmission Owners
•
Generator Owners
•
Distribution Providers
Draft 34: November 17, 2010April 12, 2011
4
Unofficial Comment Form for 4th Draft of PRC-005-2 – Protection System
Maintenance [Project 2007-17]
Please DO NOT use this form to submit comments on the 4th draft of the standard for
Protection System Maintenance and Testing. Comments must be submitted by May 12,
2011. If you have questions please contact Al McMeekin at [email protected] or by
telephone at 803-530-1963.
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Background Information:
The Protection System Maintenance and Testing Standard Drafting Team (PSMT SDT) has
made substantial changes to the fourth posting of PRC-005-2 based on comments received
from industry. The changes include:
•
Removal of the requirements from the previous draft that addressed calibration
tolerances (R1 part 1.5, R4 part 4.2, and the related Measures and VSLs)
•
Removed Requirement R2 (which was redundant to Requirement R1 Part 4) and the
related Measure and VSL.
•
Removed system-connected station auxiliary transformers from the Applicability of
the Standard (4.2.5.5)
•
Restructured and revised Table 1-4 addressing station dc supply, including removal
of requirements relating to “state of charge”.
•
Removed the FAQ and incorporated the topics within the Supplementary Reference
Document
•
Revised the Implementation Plan
The PSMT SDT would like to receive industry comments on this standard.
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The SDT has restructured the Table for Station DC Supply, separating it into six sub-tables
individually addressing the various different technologies. Do you agree that the restructured tables
provide more clarity? If not, please provide specific suggestions for improvement.
Yes
No
Comments:
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
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Comment Form — Protection System Maintenance and Testing Project Number 2007-17
2. The SDT has modified the Implementation Periods within the Implementation Plan.. Do you agree
with the changes? If not, please provide specific suggestions for improvement.
Yes
No
Comments:
3. The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do you agree with the
changes? If not, please provide specific suggestions for improvement.
Yes
No
Comments:
4. The SDT has incorporated the FAQ document into the “Supplementary Reference” document and has
provided the combined document as support for the Requirements within the standard. Do you have
any specific suggestions for further improvements?
Yes
No
Comments:
5. If you have any other comments on this Standard that you have not already provided in response to
the prior questions, please provide them here.
Comments:
2
PRC-005-2
Protection System
Maintenance
Supplementary Reference & FAQ
Draft
April 12, 2011
Prepared by the
Protection System Maintenance and Testing Standard
Drafting Team
1
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Table of Contents
1.
2.
Introduction and Summary ..................................................................................................... 4
Need for Verifying Protection System Performance .............................................................. 5
2.1 Existing NERC Standards for Protection System Maintenance and Testing .................... 5
2.2 Protection System Definition ............................................................................................ 6
2.3 Applicability of New Protection System Maintenance Standards .................................... 6
2.3.1 Frequently Asked Questions: ................................................................................... 7
2.4 Applicable Relays.............................................................................................................. 8
2.4.1 Frequently Asked Questions: ................................................................................... 8
3.
Protection Systems Product Generations .............................................................................. 10
4.
Definitions............................................................................................................................. 11
4.1 Frequently Asked Questions: .......................................................................................... 11
5.
Time-Based Maintenance (TBM) Programs ......................................................................... 13
5.1 Maintenance Practices ..................................................................................................... 13
5.1.1 Frequently Asked Questions: ................................................................................. 15
5.2 Extending Time-Based Maintenance ............................................................................. 16
5.2.1 Frequently Asked Question: ................................................................................... 17
6.
Condition-Based Maintenance (CBM) Programs ................................................................. 18
6.1 Frequently Asked Questions: .......................................................................................... 19
7.
Time-Based Versus Condition-Based Maintenance ............................................................. 20
7.1 Frequently Asked Questions: .......................................................................................... 20
8.
Maximum Allowable Verification Intervals ......................................................................... 25
8.1 Maintenance Tests ........................................................................................................... 25
8.1.1 Table of Maximum Allowable Verification Intervals ............................................ 25
8.1.2 Additional Notes for Tables 1-1 through 1-5 ......................................................... 27
8.1.3 Frequently Asked Questions: ................................................................................. 28
8.2 Retention of Records ....................................................................................................... 32
8.2.1 Frequently Asked Questions: ................................................................................. 33
8.3 Basis for Table 1 Intervals............................................................................................... 35
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .......................... 36
9.
Performance-Based Maintenance Process ............................................................................ 38
9.1 Minimum Sample Size .................................................................................................... 39
9.2 Frequently Asked Questions: .......................................................................................... 41
10.
Overlapping the Verification of Sections of the Protection System .................................. 47
Draft 4 April 12, 2011
2
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
10.1 Frequently Asked Question: .......................................................................................... 47
11.
Monitoring by Analysis of Fault Records .......................................................................... 48
11.1 Frequently Asked Question: .......................................................................................... 49
12.
Importance of Relay Settings in Maintenance Programs ................................................... 50
12.1 Frequently Asked Questions: ........................................................................................ 50
13.
Self-Monitoring Capabilities and Limitations ................................................................... 53
13.1 Frequently Asked Question: .......................................................................................... 54
14.
15.
Notification of Protection System Failures ........................................................................ 55
Maintenance Activities ...................................................................................................... 56
15.1 Protective Relays (Table 1-1) ........................................................................................ 56
15.1.1 Frequently Asked Question: ................................................................................. 56
15.2 Voltage & Current Sensing Devices (Table 1-3) .......................................................... 56
15.2.1 Frequently Asked Questions: ............................................................................... 58
15.3 Control circuitry associated with protective functions (Table 1-5) ............................... 59
15.3.1 Frequently Asked Questions: ............................................................................... 61
15.4.1 Frequently Asked Questions: .............................................................................. 62
15.5 Associated communications equipment (Table 1-2) ..................................................... 74
15.5.1 Frequently Asked Questions: ............................................................................... 74
15.6 Alarms (Table 2) ........................................................................................................... 77
15.6.1 Frequently Asked Question: ................................................................................. 77
15.7 Examples of Evidence of Compliance .......................................................................... 78
15.7.1 Frequently Asked Questions: ............................................................................... 78
Figures........................................................................................................................................... 81
Figure 1: Typical Transmission System ................................................................................ 81
Figure 2: Typical Generation System .................................................................................... 82
Appendix B — Protection System Maintenance Standard Drafting Team .................................. 87
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This supplementary reference to PRC-005-2 is not mandatory and enforceable.
1. Introduction and Summary
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and address various aspects of maintenance and testing of Protection and Control systems.
These standards are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for Protection
Systems, and that these entities must be able to demonstrate they are carrying out such a
program, there are no specifics regarding the technical requirements for Protection System
maintenance programs. Furthermore, FERC Order 693 directed additional modifications
respective to Protection System maintenance programs. PRC-005-2 combines and replaces PRC005, PRC-008, PRC-011 and PRC-017.
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2. Need for Verifying Protection System
Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate their
performance until a fault or other power system problem requires that they operate to protect
power system elements, or even the entire Bulk Electric System (BES). Lacking faults, switching
operations or system problems, the Protection Systems may not operate, beyond static operation,
for extended periods. A misoperation - a false operation of a Protection System or a failure of the
Protection System to operate, as designed, when needed - can result in equipment damage,
personnel hazards, and wide area disturbances or unnecessary customer outages. Maintenance or
testing programs are used to determine the performance and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be visited
at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct plausible
age and service related degradation of the Protection System components such that a properly
built and commissioned Protection System will continue to function as designed over its service
life.
Similarly station batteries which are an important part of the station dc supply are not called
upon to provide instantaneous dc power to the Protection System until power is required by the
Protection System to operate circuit breakers or interrupting devices to clear faults or to isolate
equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC Standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC-005, briefly
restated as follows:
Purpose: To ensure all transmission and generation Protection Systems affecting the reliability
of the Bulk Electric System (BES) are maintained and tested.
PRC-005-1 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC-005-2, the definition of Protection System was:
Protective relays, associated communications systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
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Requirements: The owner shall have a documented maintenance program with test intervals. The
owner must keep records showing that the maintenance was performed at the specified intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
•
Protective relays which respond to electrical quantities,
•
communications systems necessary for correct operation of protective functions,
•
voltage and current sensing devices providing inputs to protective relays,
•
station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
•
control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“… and that are designed to provide protection for the BES.”
The drafting team intends that this Standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the element is a BES element then the Protection
System protecting that element should then be included within this Standard. If there is regional
variation to the definition then there will be a corresponding regional variation to the Protection
Systems that fall under this Standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the Standard language should simply be applicable to relays for BES elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions. See
the NERC glossary of terms for the present, in-force, definition. See the applicable regional
reliability organization for any applicable allowed variations.
While this Standard will undergo revisions in the future, this Standard will not attempt to keep
up with revisions to the NERC definition of BES but rather simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because
GO’s and TO’s have equipment that is BES equipment. The Standard brings in Distribution
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Providers (DP) because depending on the station configuration of a particular substation, there
may be Protection System equipment installed at a non-transmission voltage level (Distribution
Provider equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would
apply to this equipment. An example is underfrequency load-shedding, which is frequently
applied well down into the distribution system to meet PRC-007-0.
As this Standard is intended to replace the existing PRC-005, PRC-008, PRC-011 and PRC-017,
those Standards are used in the construction of this revision of PRC-005-1. Much of the original
intent of those Standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example the original PRC-008 was
constructed quite differently than the original PRC-005. The drafting team agrees with the intent
of this and notes that distributed tripping schemes would have to exhibit multiple failures to trip
before they would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential Lock-Out Relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just fault clearing duty and therefore the distribution circuit breakers are
operated at least as frequently as any requirements that might have appeared in this Standard.
Additionally, since this Standard will now replace PRC-011 it will be important to make the
distinction between under-voltage Protection Systems that protect individual loads and
Protection Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had
been applicable under PRC-011 will now be applicable under this revision of PRC-005-1. An
example of an Under-Voltage Load Shedding scheme that is not applicable to this Standard is
one in which the tripping action was intended to prevent low distribution voltage to a specific
load from a transmission system that was intact except for the line that was out of service, as
opposed to preventing a cascading outage or transmission system collapse.
It had been correctly noted that the devices needed for PRC-011 are the very same types of
devices needed in PRC-005.
Thus a Standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems and replace some other Standards at the same time.
2.3.1 Frequently Asked Questions:
What, exactly, is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used
in Reliability Standards, and is not being modified within this draft Standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving only
load with one transmission source are generally not included in this definition.
Each Regional Entity implements a definition of the Bulk Electric System that is based on this
NERC definition, in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 16, 2007 Informational Filing.
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Why is Distribution Provider included within the Applicable Entities and as a responsible
entity within several of the requirements? Wouldn’t anyone having relevant facilities be a
Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
We have an Under Voltage Load Shedding (UVLS) system in place that prevents one of our
distribution substations from supplying extremely low voltage in the case of a specific
transmission line outage. The transmission line is part of the BES. Does this mean that our
UVLS system falls within this Standard?
The situation as stated indicates that the tripping action was intended to prevent low distribution
voltage to a specific load from a transmission system that was intact except for the line that was
out of service, as opposed to preventing cascading outage or transmission system collapse.
This Standard is not applicable to this UVLS.
We have a UFLS scheme that sheds the necessary load through distribution-side circuit
breakers and circuit reclosers. Do the trip-test requirements for circuit breakers apply to
our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential Lock-Out Relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just fault clearing duty and therefore the distribution circuit breakers are
operated at least as frequently as any requirements that might have appeared in this Standard.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this Standard applies are those protective relays that respond to electrical quantities and
provide a trip output to trip coils, dc control circuitry or associated communications equipment.
This definition extends to IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or
trip-free relay) as these devices are tripping relays that respond to the trip signal of the protective
relay that processed the signals from the current and voltage sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration schemes
covered in this Standard?
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No. As stated in Requirement R1, this Standard covers protective relays that use measurements
of electrical quantities to determine anomalies and to trip a portion of the BES. Reclosers,
reclosing relays, closing circuits and auto-restoration schemes are used to cause devices to close
as opposed to electrical-measurement relays and their associated circuits that cause circuit
interruption from the BES; such closing devices and schemes are more appropriately covered
under other NERC Standards. There is one notable exception: if a Special Protection System
incorporates automatic closing of breakers, the related closing devices are part of the SPS and
must be tested accordingly.
I use my protective relays only as sources of metered quantities and breaker status for
SCADA and EMS through a substation distributed RTU or data concentrator to the
control center. What are the maintenance requirements for the relays?
This Standard addresses only devices “that are applied on, or are designed to provide protection
for the BES.” Protective relays, providing only the functions mentioned in the question, are not
included.
Is a Sudden Pressure Relay an Auxiliary Tripping Relay?
No. IEEE C37.2-2008 assigns the device number 94 to auxiliary tripping relays. Sudden
pressure relays are assigned device number 63. Sudden pressure relays are excluded from the
Standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded.
My mechanical device does not operate electrically and does not have calibration settings;
what maintenance activities apply?
You must conduct a test(s) to verify the integrity of the trip circuit. This Standard does not cover
circuit breaker maintenance or transformer maintenance. The Standard also does not cover
testing of devices such as sudden pressure relays (63), temperature relays (49), and other relays
which respond to mechanical parameters rather than electrical parameters.
The Standard specifically mentions Auxiliary and Lock-out relays; what is an Auxiliary
Tripping Relay?
An auxiliary relay, IEEE Device Number 94, is described in IEEE Standard C37.2-2008 as “A
device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate
tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should
open automatically, even though its closing circuit is maintained closed.”
What is a Lock-out Relay?
A lock-out relay, IEEE Device Number 86, is described in IEEE Standard C37.2 as “A device
that trips and maintains the associated equipment or devices inoperative until it is reset by an
operator, either locally or remotely.”
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3. Protection Systems Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System, both depends on the technological generation of the relays as well as how long they
have been in service. Unlike many other transmission asset groups, protection and control
systems have seen dramatic technological changes spanning several generations. During the past
20 years, major functional advances are primarily due to the introduction of microprocessor
technology for power system devices such as primary measuring relays, monitoring devices,
control systems, and telecommunications equipment.
Modern microprocessor based relays have six significant traits that impact a maintenance
strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified periodically.
•
Ability to capture fault records showing how the Protection System responded to a fault
in its zone of protection, or to a nearby fault for which it is required not to operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-fault times. The relays can compute values such as MW and
MVAR line flows that are sometimes used for operational purposes such as SCADA.
•
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording, and measurement.
•
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages or from relay front
panel button requests.
•
Construction from electronic components some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of Battery Chargers, Associated
Communications Equipment, Voltage and Current Measuring Devices and even the control
circuitry (in the form of software-latches replacing lock-out relays, etc).
Any Protection System component can have self-monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
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4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which
Protection System components are kept in working order and proper operation of malfunctioning
components is restored. A maintenance program for a specific component includes one or more
of the following activities:
•
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Restore — Return malfunctioning components to proper operation.
4.1 Frequently Asked Questions:
Why does PRC-005-2 not specifically require maintenance and testing procedures as
reflected in the previous Standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2 requires
a documented maintenance program, and is focused on establishing requirements rather than
prescribing methodology to meet those requirements. Between the activities identified in the
tables 1-1 through 1-5 and Table 2 (collectively the “Tables”), and the various components of the
definition established for a “Protection System Maintenance Program”, PRC-005-2 establishes
the activities and time-basis for a Protection System Maintenance Program to a level of detail not
previously required.
Please clarify what is meant by restore in the definition of maintenance.
The description of “Restore” in the definition of a Protection System Maintenance Program,
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R3 of the Standard does
require that the entity “initiate resolution of any identified maintenance correctable issues”.
Some examples of restoration (or correction of maintenance-correctable issues) include, but are
not limited to, replacement of capacitors in distance relays to bring them to working order;
replacement of relays, or other Protection System components, to bring the Protection System to
working order; upgrade of electro-mechanical or solid-state protective relays to micro-processor
based relays following the discovery of failed components. Restoration, as used in this context is
not to be confused with Restoration rules as used in system operations. Maintenance activity
necessarily includes both the detection of problems and the repairs needed to eliminate those
problems. This Standard does not identify all of the Protection System problems that must be
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detected and eliminated, rather it is the intent of this Standard that an entity determines the
necessary working order for their various devices and keeps them in working order. If an
equipment item is repaired or replaced then the entity can restart the maintenance-time-intervalclock if desired, however the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements; in other words do not discard maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that the
maintenance intervals had been in compliance. For example, a long range plan of upgrades might
lead an entity to ignore required maintenance; retaining the evidence of prior maintenance that
existed before any retirements and upgrades proves compliance with the Standard.
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5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which Protection Systems are maintained or verified
according to a time schedule. The scheduled program often calls for technicians to travel to the
physical site and perform a functional test on Protection System components. However, some
components of a TBM program may be conducted from a remote location - for example, tripping
a circuit breaker by communicating a trip command to a microprocessor relay to determine if the
entire Protection System tripping chain is able to operate the breaker. Similarly, all Protection
System components can have the ability to remotely conduct tests, either on-command or
routinely, the running of these tests can extend the time interval between hands-on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have
been developed from prior experience or manufacturers’ recommendations. The TBM
verification interval is based on a variety of factors, including experience of the particular
asset owner, collective experiences of several asset owners who are members of a country
or regional council, etc. The maintenance intervals are fixed, and may range in number
of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time clock
can be reset for those components.
•
PBM – performance-based maintenance - intervals are established based on analytical or
historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses
accompanied by adjustments to maintenance intervals are used to justify continued use of
PBM-developed extended intervals when test failures or in-service failures occur
infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from
non-disruptive self monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what parts
are included as part of the self diagnostics. While the term “Condition-BasedMaintenance” (CBM) is no longer used within the Standard itself, it is important to note
that the concepts of CBM are a part of the Standard (in the form of extended time
intervals through status-monitoring). These extended time intervals are only allowed (in
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the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored-basis-time-intervals” existing within the Standard the
explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor based Protection System components that perform continuous selfmonitoring verify correct operation of most components within the device. Selfmonitoring capabilities may include battery continuity, float voltages, unintentional
grounds, the ac signal inputs to a relay, analog measuring circuits, processors and
memory for measurement, protection, and data communications, trip circuit monitoring,
and protection or data communications signals (and many, many more measurements).
For those conditions, failure of a self-monitoring routine generates an alarm and may
inhibit operation to avoid false trips. When internal components, such as critical output
relay contacts, are not equipped with self-monitoring, they can be manually tested. The
method of testing may be local or remote, or through inherent performance of the scheme
during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours or even milliseconds between non-disruptive self monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
•
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
•
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been
subject to TBM.
•
Region 3: Optimal TBM intervals based on regions 1 and 2.
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TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
5.1.1 Frequently Asked Questions:
The Standard seems very complicated, and is difficult to understand. Can it be simplified?
Because the Standard is establishing parameters for condition-based Maintenance (R1) and
performance-based Maintenance (R2) in addition to simple time-based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time-based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened time
intervals then it may, as long as the component has the listed monitoring attributes. If an entity
wishes to use historical performance of its Protection System components to perform
performance-based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the Standard.
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We have an electromechanical (unmonitored) relay that has a trip output to a lockout relay
(unmonitored) which trips our transformer off-line by tripping the transformer’s high-side
and low-side circuit breakers. What testing must be done for this system?
This system is made up of components that are all unmonitored. Assuming a time-based
protection system maintenance program schedule (as opposed to a performance-based
maintenance program), each component must be maintained per the most frequent hands-on
activities listed in the Tables 1-1 through 1-5.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly
established to assure proper functioning of each component of the Protection System, when data
on the reliability of the components is not available other than observations from time-based
maintenance. The following factors may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self monitoring device), then the intervals may be extended or
manual testing may be eliminated. This is referred to as condition-based maintenance or
CBM. CBM is valid only for precisely the components subject to monitoring. In the case
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of microprocessor-based relays, self-monitoring may not include automated diagnostics
of every component within a microprocessor.
•
Previous maintenance history for a group of components of a common type may indicate
that the maintenance intervals can be extended while still achieving the desired level of
performance. This is referred to as performance-based maintenance or PBM. It is also
sometimes referred to as reliability-centered maintenance or RCM, but PBM is used in
this document.
•
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor-based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a fault verifies the trip contact and trip path, but only through
the relays in series that actually operated; one operation of this relay cannot verify correct
calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is not
unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Question:
If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R3) (in essence) state “…shall implement and follow
its PSMP …” if not then actions must be initiated to correct the deviance. The type of corrective
activity is not stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device tested
bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information
available from modern microprocessor-based relays and other intelligent electronic devices
(IEDs) that monitor Protection System elements. These devices generate monitoring information
during normal operation, and the information can be assessed at a convenient location remote
from the substation. The information from these relays and IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
faults and disturbances, metered values, and binary input status reports. Some of these are
available on the device front panel display, but may be available via data communications
ports. Large files of fault information can only be retrieved via data communications.
These results comprise a mass of data that must be further analyzed for evidence of the
operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
1. Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
2. Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems by
incorrect operation before being caught in the next test round. The frequent or continuous
nature of CBM makes the effective verification interval far shorter than any required
TBM maximum interval.
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6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a 24-hour
attended control room. Does this qualify as an extended time interval condition-based
system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels of
monitoring as per Requirement R1.4 of the Standard, is it necessary to provide this
documentation about the device by listing of every component and the specific monitoring
attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible, it
is not necessary. Global statements can be made to document appropriate levels of monitoring
for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are Monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered Monitored and subject to the rows
for monitored equipment of Table 1-4 requirements as all substation dc supply battery
chargers are equipped with dc voltage alarms and ground detection alarms that are sent to the
manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered Monitored
and subject to the rows for monitored equipment of Table 1-4 requirements as all substation
dc supply battery chargers are equipped with dc voltage alarms and ground detection alarms
that are sent to the manned control center. The dc supply battery chargers of Substation X,
Substation Y, and Substation Z are considered Unmonitored and subject to the rows for
unmonitored equipment in Table 1-4 requirements as they are not equipped with ground
detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes, by
global statements of the monitoring attributes of an entire population of component types, or by
some combination of these methods, it should be noted that auditors may request supporting
drawings or other documentation necessary to validate the inclusion of the device(s) within the
appropriate level of monitoring. This supporting background information need not be
maintained within the program document structure but should be retrievable if requested by an
auditor.
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7. Time-Based Versus Condition-Based Maintenance
Time-based and condition-based maintenance programs are both acceptable, if implemented
according to technically sound requirements. Practical programs can employ a combination of
time-based and condition-based maintenance. The Standard requirements introduce the concept
of optionally using condition monitoring as a documented element of a maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability
Standards for the Bulk-Power System, directed NERC to submit a modification to PRC-005-1
that includes a requirement that maintenance and testing of a protection system must be carried
out within a maximum allowable interval that is appropriate to the type of the protection system
and its impact on the reliability of the Bulk Power System. Accordingly, this Supplementary
Reference Paper refers to the specific maximum allowable intervals in PRC-005-2. The defined
time limits allow for longer time intervals if the maintained component is monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay between
the moment of a protection failure and time the protection system owner knows about it, for the
monitored segments of the protection system. In some cases, the verification is practically
continuous - the time interval between verifications is minutes or seconds. Thus, technically
sound, condition-based verification, meets the verification requirements of the FERC order even
more effectively than the strictly time-based tests of the same system components.
The result is that:
This NERC Standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern protection systems to
reduce the need for periodic site visits and invasive testing of components by on-site technicians.
This periodic testing must be conducted within the maximum time intervals specified in Tables
1-1 through 1-5 and Table 2 of PRC-005-2.
7.1 Frequently Asked Questions:
Please provide an example of the unmonitored versus other levels of monitoring available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no alarm
output connected is considered to be un-monitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits must
alert, within 24 hours, a location wherein corrective action can be initiated. This location might
be, but not limited to an Operations Center, Dispatch Office, Maintenance Center or even a
portable SCADA system.
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There can be a combination of monitored and unmonitored Protection Systems within any given
scheme, substation or plant; there can also be a combination of monitored and unmonitored
components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
•
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A vented lead-acid battery with a low voltage alarm for the station dc supply voltage and
an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
•
A circuit breaker with a trip coil and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (“Maximum
Allowable Testing Intervals and Maintenance Activities”) and Table 2 (“Alarming Paths and
Monitoring”), the particular components have maximum activity intervals of:
Every 3 calendar months, verify:
Electrolyte level (station dc supply voltage and unintentional ground detection is being
maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Every 6 calendar years, perform/verify the following:
Battery performance test (if ohmic tests are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electro-mechanical lock-out relays and auxiliary relays, electrical operation of
electromechanical trip and auxiliary devices
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
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Operation of the microprocessor’s relay inputs and outputs that are essential to proper
functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Instrumentation transformers
Protection system component monitoring for the battery system signals are conveyed to
a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all paths of the control and trip circuits
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
•
Instrument transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A vented lead-acid battery with a low voltage alarm for the station dc supply voltage and
an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
•
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (“Maximum
Allowable Testing Intervals and Maintenance Activities”) and Table 2 (“Alarming Paths and
Monitoring”), the particular components have maximum activity intervals of:
Every 3 calendar months, verify:
Electrolyte level (Station dc supply voltage and unintentional ground detection is being
maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Every 6 calendar years, verify/perform the following:
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Verify operation of the relay inputs and outputs that are essential to proper functioning
of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electro-mechanical lock-out relays and auxiliary relays, electrical operation of
electromechanical trip and auxiliary devices
Battery performance test (if ohmic tests are not opted)
Every 12 calendar years, verify the following:
Instrumentation transformers
Protection system component monitoring for the battery system signals are conveyed to
a location where corrective action can be initiated
Verify all paths of the control and trip circuits
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed operations
center; it has internal self diagnosis and alarms. (monitored)
•
Instrument transformers, with monitoring, connected as inputs to that relay (monitored)
•
Vented lead acid battery without any alarms connected to SCADA (unmonitored)
•
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”) and Table 2 (“Alarming Paths and
Monitoring”), the particular components shall have maximum activity intervals of:
Every 3 calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
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Cell condition of all individual battery cells (where visible)
Every 6 calendar years, perform/verify the following:
Battery performance test (if ohmic tests are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electro-mechanical lock-out relays and auxiliary relays, electrical operation of
electromechanical trip and auxiliary devices
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to proper
functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all paths of the control and trip circuits
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of Protection
System components. Condition-Based Maintenance is a valuable asset to improve reliability.
Can all components in a Protection System be monitored?
No. For some components in a protection system, monitoring will not be relevant. For example
a battery will always need some kind of inspection.
We have a 30 year old oil circuit breaker with a red indicating lamp on the substation relay
panel that is illuminated only if there is continuity through the breaker trip coil. There is
no SCADA monitor or relay monitor of this trip coil. The line protection relay package
that trips this circuit breaker is a microprocessor relay that has an integral alarm relay
that will assert on a number of conditions that includes a loss of power to the relay. This
alarm contact connects to our SCADA system and alerts our 24-hour operations center of
relay trouble when the alarm contact closes. This microprocessor relay trips the circuit
breaker only and does not monitor trip coil continuity or other things such as trip current.
Are the components monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years or when a maintenance
correctable issue arises. The control circuitry can be maintained every 12 years. The trip coil(s)
has to be electrically operated at least once every 6 years.
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8. Maximum Allowable Verification Intervals
The Maximum Allowable Testing Intervals and Maintenance Activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older Protection
System components require. As explained below, there are some sections of the Protection
System that monitoring or data analysis may not verify. Verifying these sections of the
Protection Systems requires some persistent TBM activity in the maintenance program.
However, some of this TBM can be carried out remotely - for example, exercising a circuit
breaker through the relay tripping circuits using the relay remote control capabilities can be used
to verify function of one tripping path and proper trip coil operation, if there has been no fault or
routine operation to demonstrate performance of relay tripping circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure that
individual components are still operating within acceptable performance parameters - this type of
test is needed for components susceptible to degraded or changing characteristics due to aging
and wear. Full system performance tests may be used to confirm that the total Protection System
functions from measurement of power system values, to properly identifying fault
characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1-1 through 1-5), in the
Standard, specifies maximum allowable verification intervals for various generations of
protection systems and categories of equipment that comprise protection systems. The right
column indicates maintenance activities required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications-assisted line protection system comprising substation
equipment at each terminal and a telecommunications channel for relaying between the two
substations. Figure 2 shows an example of a Generation station layout. The various subsystems
of a Protection System that need to be verified are shown. UFLS, UVLS, and SPS are additional
categories of Table 1 that are not illustrated in these Figures. UFLS, UVLS and SPS all use
identical equipment as Protection Systems in the performance of their functions and therefore
have the same maintenance needs.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC-005-2:
• First find the Table associated with your component. The tables are arranged in the order
of mention in the definition of Protection System;
o Table 1-1 is for protective relays,
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o Table 1-2 is for the associated communications systems,
o Table 1-3 is for current and voltage sensing devices,
o Table 1-4 is for station dc supply and
o Table 1-5 is for control circuits. There is an additional table,
o Table 2, which brings alarms into the maintenance arena; this was broken out to
simplify the other tables.
•
Next look within that table for your device and its degree of monitoring. The tables have
different hands-on maintenance activities prescribed depending upon the degree to which
you monitor your equipment. Find the maintenance activity that applies to the monitoring
level that you have on your piece of equipment.
•
This Maintenance Activity is the minimum maintenance activity that must be
documented.
•
If your PSMP (plan) requires more activities then you must perform and document to this
higher standard.
•
After the maintenance activity is known, check the Maximum Maintenance Interval; this
time is the maximum time allowed between hands-on maintenance activity cycles of this
component.
•
If your PSMP (plan) requires activities more often than the Tables maximum then you
must perform and document those activities to your more stringent standard.
•
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system; this
combination would require hands-on maintenance activity on the relay at least once every
12 years and attention paid to the communications system as often as every 3 months.
•
An entity does not have to utilize the extended time intervals made available by this use
of condition-based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available on each of the 5 Tables. While the
maintenance activities resulting from this choice would require more maintenance manhours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. These degrees of monitoring, or levels, range from the legacy
unmonitored through a system that is more comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC-005-2.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC-005-2, most notable of which is an entity using performance
based maintenance methodology. (Another reason for having a more stringent plan than is
required could be a regional entity could have more stringent requirements.) Regardless of the
rationale behind an entity’s more stringent plan, it is incumbent upon them to perform the
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activities, and perform them at the stated intervals, of the entity’s PSMP. A quality PSMP will
help assure system reliability and adhering to any given PSMP should be the goal.
8.1.2 Additional Notes for Tables 1-1 through 1-5
1. For electro-mechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor-relays with no remote
monitoring of alarm contacts, etc, are un-monitored relays and need to be verified within
the Table interval as other un-monitored relays but may be verified as functional by
means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a protection
system or SPS (as opposed to a monitoring task) must be verified as a component in a
protection system.
4. In addition to verifying the circuitry that supplies dc to the protection system, the owner
must maintain the station dc supply. The most widespread station dc supply is the station
battery and charger. Unlike most Protection System components physical inspection of
station batteries for signs of component failure, reduced performance, and degradation
are required to ensure that the station battery is reliable enough to deliver dc power when
required. IEEE Standards 450, 1188, and 1106 for Vented Lead-Acid, Valve-Regulated
Lead-Acid, and Nickel-Cadmium batteries, respectively (which are the most commonly
used substation batteries on the NERC BES) have been developed as an important
reference source of maintenance recommendations. The Protection System owner might
use the applicable IEEE recommended practice which contains information and
recommendations concerning the maintenance, testing and replacement of its substation
battery. However, the methods prescribed in these IEEE recommendations cannot be
specifically required because they do not apply to all battery applications.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform properly,
it will not affect the integrity of the overall program. Thus these distributed systems have
decreased requirements as compared to other Protection Systems.
6. Voltage & Current Sensing Device circuit input connections to the protection system
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should be
verified to be as expected, (phase value and phase relationships are both equally
important to verify).
7.
“End-to-end test” as used in this Supplementary Reference is any testing procedure that
creates a remote input to the local communications-assisted trip scheme. While this can
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be interpreted as a GPS-type functional test it is not limited to testing via GPS. Any
remote scheme manipulation that can cause action at the local trip path can be used to
functionally-test the dc Control Circuitry. A documented real-time trip of any given trip
path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc Control Circuit trip. Or, another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a real-time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure acceptable
measurement of power system input values.
9. Notes 1-8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the Standard is technology and method neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor based relays.
For relay maintenance departments that choose to test microprocessor based relays in the same
manner as electro-mechanical relays are tested, the testing process sometimes requires that some
specific functions be disabled. Later tests might enable the functions previously disabled but
perhaps still other functions or logic statements were then masked out. It is imperative that, when
the relay is placed into service, the settings in the relay be the settings that were intended to be in
that relay or as the Standard states “…settings are as specified.”
Many of the microprocessor based relays available today have software tools which provide this
functionality and generate reports for this purpose.
For evidence or documentation of this requirement a simple recorded acknowledgement that the
settings were checked to be as specified is sufficient.
The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would result
in the correct intended operation of the interrupting device. While that is a noble intention, the
measurable proof of such a requirement is immense. The intent is that settings of the component
be as specified at the conclusion of maintenance activities, whether those settings may have
“drifted” since the prior maintenance or whether changes were made as part of the testing
process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
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verification by voltage and/or current injection, and thus the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral currents, or
3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring that
phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 requires that a trip test must verify that the auxiliary tripping relay(s) and/or lockout
relay(s) which are directly in a trip path from the protective relay to the interrupting device trip
coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e. annunciation or DME input)
are not required, by this Standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the overall
SPS does not need to have a single end-to-end test. In other words it may be tested in piecemeal
fashion provided all of the pieces are verified.
What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or Relay Sensing for Centralized UFLS or
UVLS Systems?
Since components of the SPS, UFLS, or UVLS are the same types of components as those in
Protection Systems then these components should be maintained like similar components used
for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS are
also used for other protective functions. The same maintenance activities apply with the
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exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example an SPS that trips a remote circuit breaker might be tested
by testing the various parts of the scheme in overlapping segments. Another method is to
document the real-time tripping of an SPS scheme should that occur. Forced trip tests of circuit
breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled outages
for my power plant. Can I extend the maintenance to the next scheduled outage following
the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance intervals
were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance as required due to a major natural disaster
(hurricane, earthquake, etc), how will this affect my compliance with this Standard.
The Sanction Guidelines of the North American Electric Reliability Corporation effective
January 15, 2008 provides that the Compliance Monitor will consider extenuating circumstances
when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance relays, or,
even worse, I am experiencing numerous relay misoperations due to the relays being outof-tolerance?
The established maximum time intervals are mandatory only as a not-to-exceed limitation. The
establishment of a maximum is measurable. But, any entity can choose to test some or all of their
Protection System components more frequently (or, to express it differently, exceed the
minimum requirements of the Standard). Particularly, if you find that the maximum intervals in
the Standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay Misoperations
is in no one’s best interest. The BES and an entity’s bottom line both suffer.
We believe that the 3-month interval between inspections is unneccessary, why can we not
perform these inspections twice per year?
The standard drafting team believes that routine monthly inspections are the norm. To align
routine station inspections with other important inspections the 3-month interval was chosen. In
lieu of station visits many activities can be accomplished with automated monitoring and
alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3 years; if
we are unable to achieve this schedule but we are able to complete the procedures in less
than the Maximum Time Interval then are we in or out of compliance?
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You are out of compliance. You must maintain your equipment to your stated intervals within
your maintenance plan. The protective relays (and any Protection System component) cannot be
tested at intervals that are longer than the maximum allowable interval stated in the Tables and
yet you must conform to your own maintenance plan. Therefore you should design your
maintenance plan such that it is not in conflict with the Minimum Activities and the Maximum
Intervals. You then must maintain your equipment according to your maintenance plan. You will
end up being compliant with both the Standard and your own plan.
Please provide a sample list of devices or systems that must be verified in a generator,
generator step-up transformer, and generator connected station auxiliary transformer to
meet the requirements of this Maintenance Standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay may include but are not necessarily limited to:
•
Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
•
Loss-of-field relays
•
Volts-per-hertz relays
•
Negative sequence overcurrent relays
•
Over voltage and under voltage protection relays
•
Stator-ground relays
•
Communications-based protection systems such as transfer-trip systems
•
Generator differential relays
•
Reverse power relays
•
Frequency relays
•
Out-of-step relays
•
Inadvertent energization protection
•
Breaker failure protection
For generator step up or generator-connected station auxiliary transformers, operation of any the
following associated protective relays frequently would result in a trip of the generating unit and,
as such, would be included in the program:
•
Transformer differential relays
•
Neutral overcurrent relay
•
Phase overcurrent relays
Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program even if the loss of the those loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to secondary
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unit substation (SUS) or low switchgear transformers and relays protecting other downstream
plant electrical distribution system components are not included in the scope of this program
even if a trip of these devices might eventually result in a trip of the generating unit. For
example, a thermal overcurrent trip on the motor of a coal-conveyor belt could eventually lead to
the tripping of the generator, but it does not cause the trip.
What is meant by “verify operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping” one needs to realize that
sometimes there are more Inputs and Outputs than simply the output to the trip coil. Many
important protective functions include things like Breaker Fail Initiation, Zone Timer Initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from the
microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dcv to the input and verify that the relay registered the change of state.
Electro-mechanical Lock-out relays (86) and Auxiliary tripping relays (94) (used to convey the
tripping current to the trip coils) need to be electrically operated to prove the capability of the
device to change state. These tests need to be accomplished at least every 6 years, unless PBM
methodology is applied.
The contacts on the 86 or 94 that change state to pass on the trip current to a breaker trip coil
need only be checked every twelve years with the control circuitry.
Other devices in the control circuitry that are used for other protective functions besides tripping
(including, but not limited to, electro-mechanical Breaker Fail Initiation relays) need only be
verified with the control circuitry every twelve years.
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three year retention cycle, the records of verification for a protection
system might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC-005-2 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for the
Protection System components, or to the previous scheduled (on-site) audit date, whichever is
longer.
This requirement assures that the documentation shows that the interval between maintenance
cycles correctly meets the maintenance interval limits. The requirement is actually alerting the
industry to documentation requirements already implemented by audit teams. Evidence of
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compliance bookending the interval shows interval accomplished instead of proving only your
planned interval.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records to
demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electro-mechanical protective relays be
tested, for routine scheduled tests, every 3 calendar years with a maximum allowed grace period
of an additional 18 months. This entity would be required to maintain its records of maintenance
of its last two routine scheduled tests. Thus its test records would have a latest routine test as
well as its previous routine test. The interval between tests is therefore provable to an auditor as
being within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two test
results proving the last interval. The drafting team contends that this minimizes storage
requirements while still having minimum data available to demonstrate compliance with time
intervals.
Realistically, the Standard is providing advanced notice of audit team documentation requests;
this type of information has already been requested by auditors.
If an entity prefers to utilize Performance Based Maintenance then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced then the entity can restart the maintenance-time-interval-clock if
desired, however the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements; in other words do not discard maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that the
maintenance intervals had been in compliance. For example, a long range plan of upgrades might
lead an entity to ignore required maintenance; retaining the evidence of prior maintenance that
existed before any retirements and upgrades proves compliance with the Standard.
What does this Maintenance Standard say about commissioning? Is it necessary to have
documentation in your maintenance history of the completion of commission testing?
This Standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the maintenance
activities specified in the Tables of PRC-005-2, verification of the adequacy of initial installation
necessitates the performance of testing and inspections that go well beyond these routine
maintenance activities. For example, commission testing might set baselines for future tests;
perform acceptance tests and/or warranty tests; utilize testing methods that are not generally
done routinely like staged-fault-tests.
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However, many of the Protection System attributes which are verified during commission testing
are not subject to age related or service related degradation and need not be re-verified within an
ongoing maintenance program. Example – it is not necessary to re-verify correct terminal strip
wiring on an ongoing basis.
PRC-005-2 assumes that thorough commission testing was performed prior to a protection
system being placed in service. PRC-005-2 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components such that a properly built and commission tested Protection System will continue to
function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the Standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content and
therefore, it is not necessary to maintain commission testing records within the maintenance
program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC-005-2 would help that entity
prove time interval maximums by setting the initial time clock.
How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was tested.
Alternatively, an entity may choose to use the date of completion of the commission testing of
the Protection System component and the system was placed into service as the starting point in
determining its first maintenance due dates. Whichever method is chosen, for newly installed
Protection Systems the components should not be placed into service until minimum
maintenance activities have taken place.
It is conceivable that there can be a (substantial) difference in time between the date of testing as
compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non-compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year). However,
if there is a substantial amount of time difference between testing and in-service dates then the
testing date should be followed because it is the degradation of components that is the concern.
While accuracy fluctuations may decrease when components are not energized there are cases
when degradation can take place even though the device is not energized. Minimizing the time
between commissioning tests and in-service dates will help.
If I miss two battery inspections four times out of 100 protection system components on my
transmission system, does that count as 2 percent or 8 percent when counting Violation
Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its one hundred protection system
components which would equate to two percent for application to the VSL Table for
Requirement R3.
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How do I achieve a “grace period” without being out of compliance?
For the purposes of this example, concentrating on just unmonitored protective relays,– Table 11 specifies a maximum time interval (between the mandated maintenance activities) of 6
calendar years. Your plan must ensure that your unmonitored relays are tested at least once every
6 calendar years. You could, within your PSMP, require that your unmonitored relays be tested
every 4 calendar years with a maximum allowable time extension of 18 calendar months. This
allows an entity to have deadlines set for the auto-generation of work orders but still have the
flexibility in scheduling complex work schedules. This also allows for that 18 calendar months to
act as a buffer, a grace period, in the event of unforeseen events. You will note that this example
of a maintenance plan interval has a planned time of 4 years; it also has a built-in time extension
allowed within the PSMP and yet does not exceed the maximum time interval allowed by the
Standard. So while there are no time extensions allowed beyond the Standard, an entity can still
have substantial flexibility to maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007.
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I-17 (Transmission Relay System
Performance Comparison). Review of the I-17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the members
to also provide definitively-known data for other entities. The survey represented 470 GW of
peak load, or 64% of the NERC peak load. Maintenance interval averages were compiled by
weighting reported intervals according to the size (based on peak load) of the reporting utility.
Thus, the averages more accurately represent practices for the large populations of protection
systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of 5 years for
electromechanical or solid state relays, and 7 years for un-monitored microprocessor relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond 7
years, based on favorable experience with the particular products they have installed. To provide
a technical basis for such extension, the SPCTF authors developed a recommendation of 10 years
using the Markov modeling approach from [1] as summarized in Section 8.4. The results of this
modeling depend on the completeness of self-testing or monitoring. Accordingly, this extended
interval is allowed by Table 1 only when such relays are monitored as specified in the attributes
of monitoring contained in Tables 1-1 through 1-5 and Table 2. Monitoring is capable of
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reporting protection system health issues that are likely to affect performance within the 10 year
time interval between verifications.
It is important to note that, according to modeling results, protection system availability barely
changes as the maintenance interval is varied below the 10-year mark. Thus, reducing the
maintenance interval does not improve protection system availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval actually
degrades protection system availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level. The
industry has experience with self-monitoring microprocessor relays that leads to the Table 1
value for a monitored relay as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
•
Relay Unavailability - the probability that the relay is out of service due to failure or
maintenance activity while the power system element to be protected is in service.
•
Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a fault occurs, leading to failure to operate for the fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test).
ST = 0 if there is no self-monitoring; ST = 1 for full monitoring. Practical ST values are
estimated to range from .75 to .95. The SPCTF simulation runs used constants in the Markov
model that were the same as those used in [1] with the following exceptions:
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a protection system)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a protection system repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for Relay Unavailability and Abnormal Unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
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the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay Mean Time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields no
failure discoveries that approach the negative impact of removing the relays from service and
running the tests.
The PSMT SDT discussed the practical need for “time-interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “timeinterval extension” or “grace periods”. To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time-interval extension while still
following FERC Order 693 the Standard Drafting Team arrived at a 6 year interval for the
electro-mechanical relay instead of the 5 year interval arrived at by the SPCTF. The PSMT SDT
has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10 year interval was chosen even though there was “…no
significant change in unavailability value over the range of 9, 10, or 11 years. This was true
even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection System;
thus the maximum allowed interval for these components has been set to12 years. Twelve years
also fits well into the traditional maintenance cycles of both substations and generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum Maintenance
Interval”. The PSMT SDT deemed it necessary to include the term “Calendar” to facilitate
annual maintenance planning, scheduling and implementation. This need is the result of known
occurrences of system requirements that could cause maintenance schedules to be missed by a
few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need to have
schedules be met to the day. An electro-mechanical protective relay that is maintained in year #1
need not be revisited until 6 years later (year #7). For example: a relay was maintained April 10,
2008; maintenance would need to be completed no later than December 31, 2014.
Though not a requirement of this Standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP the entity should abide
by their chosen language.
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9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a performance-based maintenance process may be used to
establish maintenance intervals (PRC-005 Attachment A Criteria for a Performance-Based
Protection System Maintenance Program). A performance-based maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a performance-based maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered protection systems in order to
provide historical justification for intervals other than those established in Table 1. Furthermore,
the asset owner must regularly analyze these records of corrective actions to develop a ranking of
causes. Recurrent problems are to be highlighted, and remedial action plans are to be
documented to mitigate or eliminate recurrent problems.
Utilities with performance-based maintenance track performance of protection systems,
demonstrate how they analyze findings of performance failures and aberrations, and implement
continuous improvement actions. Since no maintenance program can ever guarantee that no
malfunction can possibly occur, documentation of a performance-based maintenance program
would serve the utility well in explaining to regulators and the public a Misoperation leading to a
major system outage event.
A performance-based maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001-2000, Quality management systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
•
The completeness of the documented maintenance process
•
Organizational knowledge of and adherence to the process
•
Performance metrics and documentation of results
•
Remediation of issues
•
Demonstration of continuous improvement.
In order to opt into a Performance-based Maintenance (PBM) program the asset owner must first
sort the various Protection System components into population segments. Any population
segment must be comprised of at least 60 individual units; if any asset owner opts for PBM but
does not own 60 units to comprise a population then that asset owner may combine data from
other asset owners until the needed 60 units is aggregated. Each population segment must be
composed of a grouping of Protection Systems or components of a consistent design standard or
particular model or type from a single manufacturer and subjected to similar environmental
factors. For example: One segment cannot be comprised of both GE & Westinghouse electromechanical lock-out relays; likewise, one segment cannot be comprised of 60 GE lock-out
relays, 30 of which are in a dirty environment and the remaining 30 from a clean environment.
This PBM process cannot be applied to batteries but can be applied to all other components of a
Protection System including (but not limited to) specific battery chargers, instrument
transformers, trip coils and/or control circuitry (etc.).
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9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling distribution
of the sample mean can be approximated by a normal probability distribution.” The Central
Limit Theorem states: “In selecting simple random samples of size n from a population, the
sampling distribution of the sample mean x can be approximated by a normal probability
distribution as the sample size becomes large.” (Essentials of Statistics for Business and
Economics, Anderson, Sweeney, Williams, 2003)
To use the Central Limit Theorem in statistics, the population size should be large.
references below are supplied to help define what is large.
The
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution of
the sample mean can be approximated by a normal distribution.” (Essentials of
Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation σ, the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics - Picturing the World, Larson, Farber,
2003)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005)
“… the normal is often used as an approximation to the t distribution in a test of a
null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a “Pass/Fail”
format and will be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
Β = bound on the error of distribution (allowable error)
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z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
z
n = π(1 − π)
Β
2
Minimum Population Size to use Performance-based Program
One entity’s population of components should be large enough to represent a sizeable sample of
a vendor’s overall population of manufactured devices. For this reason the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are recommended
(and required within the Standard):
Minimum Population Size to use Performance-based Maintenance Program = 60
Minimum Sample Size to evaluate Performance-based Program = 30.
Once the population segment is defined then maintenance must begin within the intervals as
outlined for the device described in the Tables 1-1 through 1-5. Time intervals can be lengthened
provided the last year’s worth of components tested (or the last 30 units maintained, whichever is
more) had fewer than 4% countable events. It is notable that 4% is specifically chosen because
an entity with a small population (60 units) would have to adjust its time intervals between
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maintenance if more than 1 countable event was found to have occurred during the last analysis
period. A smaller percentage would require that entity to adjust the time interval between
maintenance activities if even one unit is found out of tolerance or causes a Misoperation.
The minimum number of units that can be tested in any given year is 5% of the population. Note
that this 5% threshold sets a practical limitation on total length of time between intervals at 20
years.
If at any time the number of countable events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more) then the time period between
manual maintenance activities must be decreased. There is a time limit on reaching the decreased
time at which the countable events is less than 4%; this must be attained within three years.
This additional time period of three years to restore segment performance to <4% countable
events is mandated to keep entities from “gaming the PBM system”. It is believed that this
requirement provides the economic disincentives to discourage asset owners from arbitrarily
pushing the PBM time intervals out to up to 20 years without proper statistical data.
9.2 Frequently Asked Questions:
I’m a small entity and cannot aggregate a population of Protection System components to
establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect to
the requirements of the Standard. The requirements established for performance-based
maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across the
population, including any relevant environmental factors such as geography, power-plant vs.
substation, and weather conditions.
Can an owner go straight to a performance-based maintenance program schedule, if they
have previously gathered records?
Yes. An owner can go to a performance-based maintenance program immediately. The owner
will need to comply with the requirements of a performance-based maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner finds
that a gap exists such that they cannot prove that they have collected the data as required for a
performance-based maintenance program then they will need to wait until they can prove
compliance.
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When establishing a performance-based maintenance program, can I use test data from the
device manufacturer, or industry survey results, as results to help establish a basis for my
performance-based intervals?
No. You must use actual in-service test data for the components in the segment.
What types of misoperations or events are not considered countable events in the
performance-based Protection System Maintenance (PBM) Program?
Countable events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned.
For this purpose of tracking hardware issues, human errors resulting in Protection System
misoperations during system installation or maintenance activities are not considered countable
events. Examples of excluded human errors include relay setting errors, design errors, wiring
errors, inadvertent tripping of devices during testing or installation, and misapplication of
Protection System components. Examples of misapplication of Protection System components
include wrong CT or PT tap position, protective relay function misapplication, and components
not specified correctly for their installation. Obviously, if one is setting up relevant data about
hardware failures then human failures should be eliminated from the hardware performance
analysis.
One example of human-error is not pertinent data might be in the area of testing “86” Lock-Out
Relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move
into a performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial sixyear interval they find zero type “X” failures, but human error led to tripping a BES element 100
times; they find 100 type “Y” failures and had an additional 100 human-error caused tripping
incidents. In this example the human-error caused misoperations should not be used to judge the
performance of either type of LOR. Analysis of the data might lead “Entity A” to change time
intervals. Type “X” LOR can be placed into extended time interval testing because of its low
failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
Certain types of Protection System component errors that cause misoperations are not considered
countable events. Examples of excluded component errors include device malfunctions that are
correctable by firmware upgrades and design errors that do not impact protection function.
What are some examples of methods of correcting segment perfomance for PerformanceBased Maintenance?
There are a number of methods that may be useful for correcting segment performance for malperforming segments in a performance-based maintenance system. Some examples are listed
below.
•
The maximum allowable interval, as established by the performance-based maintenance
system, can be decreased. This may, however, be slow to correct the performance of the
segment.
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•
Identifiable sub-groups of components within the established segment, which have been
identified to be the mal-performing portion of the segment, can be broken out as an
independent segment for target action. Each resulting segment must satisfy the minimum
population requirements for a performance-based maintenance program in order to
remain within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
Components within the mal-performing segment can be replaced with other components
(electromechanical distance relays with microprocessor relays, for example) to remove
the mal-performing segment.
If I find (and correct) a maintenance-correctable issue as a result of a misoperation
investigation (Re: PRC-004), how does this affect my performance-based maintenance
program?
If you perform maintenance on a Protection System component for any reason (including as part
of a PRC-004 required misoperation investigation/corrective action), the actions performed can
count as a maintenance activity, and, if you desire, “reset the clock” on everything you’ve done.
In a performance-based maintenance program, you also need to record the maintenancecorrectable issue with the relevant component group and use it in the analysis to determine your
correct performance-based maintenance interval for that component group. Note that “resetting
the clock” should not be construed as interfering with an entity’s routine testing schedule
because the “clock-reset” would actually make for a decreased time interval by the time the next
routine test schedule comes around.
For example a relay scheme, consisting of 4 relays, is tested on 1-1-11 and the PSMP has a time
interval of 3 calendar years with an allowable extension of 1 calendar year. The relay would be
due again for routine testing before the end of the year 2015. This mythical relay scheme has a
misoperation on 6-1-12 that points to one of the four relays as bad. Investigation proves a bad
relay and a new one is tested and installed in place of the original. This replacement relay
actually could be retested before the end of the year 2016 (clock-reset) and not be out of
compliance. This requires tracking maintenance by individual relays and is allowed. However,
many companies schedule maintenance in other ways like by substation or by circuit breaker or
by relay scheme. By these methods of tracking maintenance that “replaced relay” will be retested
before the end of the year 2015. This is also acceptable. In no case was a particular relay tested
beyond the PSMP of 4 years max, nor was the 6 year max of the Standard exceeded. The entity
can reset the clock if they desire or the entity can continue with original schedules and, in effect,
test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from condition
based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their freshness
(charge), but periodic inspection to determine if there are problems associated with their aging
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process and testing to see if they are maintaining a charge or can still deliver their rated output as
required.
Besides being perishable, a second unique feature of a battery that is unlike any other Protection
System element is that a battery uses chemicals, metal alloys, plastics, welds, and bonds that
must interact with each other to produce the constant dc source required for Protection Systems,
undisturbed by ac system disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to make
batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation from
the factory to the job site, length of time before a charge is put on the battery, the method of
installation, the voltage level and duration of equalize charges, the float voltage level used, and
the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control of
the Functional Entities that want to use a performance-based Protection System Maintenance
(PBM) program. These inherent variances in the aging process of a battery cell make
establishment of a designated segment based on manufacturer and type of battery impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electro-chemical
process to completely isolate all of the performance-changing criteria.
Similarly Functional Entities that want to establish a condition-based maintenance program using
the highest levels of monitoring; resulting in the least amount of hands-on maintenance activity,
of the battery used in a station dc supply cannot completely eliminate some periodic
maintenance. Inspection of the battery is required on a Maximum Maintenance Interval listed in
the tables due to the aging processes of station batteries. However, higher degrees of monitoring
of a battery can eliminate the requirement for some periodic testing and some inspections (see
Table 1-4).
Please provide an example of the calculations involved in extending maintenance time
intervals using PBM.
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60.
They start out testing all of the relays within the prescribed Table requirements (6 year max) by
testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is greater than
the minimum sample size requirement of 30.
For the sake of example only the following will show 6 failures per year, reality may well have
different numbers of failures every year. PBM requires annual assessment of failures found per
units tested.
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After the first year of tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure
rate.
This entity is now allowed to extend the maintenance interval if they choose.
The entity chooses to extend the maintenance interval of this population segment out to 10 years.
This represents a rate of 100 units tested per year; entity selects 100 units to be tested in the
following year.
After that year of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate such that the failure rate is found to be less than 4% per
year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 8 years. This means
that they will now test 125 units per year (1000/8). The entity has just two years left to get the
test rate corrected.
After a year they again find 6 failures out of the 125 units tested. 6/125= 5% failures.
In response to the 5% failure rate, the entity decreases the testing interval to 7 years. This means
that they will now test 143 units per year (1000/7). The entity has just one year left to get the test
rate corrected.
After a year they again find 6 failures out of the 143 units tested. 6/143= 4.2% failures.
(Note that the entity has tried 5 years and they were under the 4% limit and they tried 7 years and
they were over the 4% limit. They must be back at 4% failures or less in the next year so they
might simply elect to go back to 5 years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to 6 years.
This means that they will now test 167 units per year (1000/6).
After a year they again find 6 failures out of the 167 units tested. 6/167= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by maintaining
the testing interval at 6 years or less. Entity chose 6 year interval and effectively extended their
TBM (5 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing test
rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; this is there to prevent an
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entity from “gaming the system”. An entity might arbitrarily extend time intervals from 6 years
to 20 years. In the event that an entity finds a failure rate greater than 4% then the test rate must
be accelerated such that within three years the failure rate must be brought back down to 4% or
less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to
be Tested
(U= P/I)
1
2
3
4
5
1000
1000
1000
1000
1000
200
100
125
143
167
5 yrs
10 yrs
8 yrs
7 yrs
6 yrs
# of
Failures
Found
(F)
6
6
6
6
6
Failure
Rate
(=F/U)
3%
6%
5%
4.2%
3.6%
Decision
to Change
Interval
Yes or No
Yes
Yes
Yes
Yes
No
Interval
Chosen
10 yrs
8 yrs
7 yrs
6 yrs
6 yrs
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10. Overlapping the Verification of Sections of the
Protection System
Tables 1-1 through 1-5 require that every protection system component be periodically verified.
One approach, but not the only method, is to test the entire protection scheme as a unit, from the
secondary windings of voltage and current sources to breaker tripping. For practical ongoing
verification, sections of the protection system may be tested or monitored individually. The
boundaries of the verified sections must overlap to ensure that there are no gaps in the
verification. See Appendix A of this Supplementary Reference for additional discussion on this
topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a protection system
may be divided into multiple overlapping sections with a different maintenance methodology for
each section:
•
Time-based maintenance with appropriate maximum verification intervals for
categories of equipment as given in the Tables 1-1 through 1-5;
•
Monitoring as described in Tables 1-1 through 1-5;
•
A performance-based maintenance program as described in Section 9 above or
Attachment A of the Standard;
•
Opportunistic verification using analysis of fault records as described in Section
11
10.1 Frequently Asked Question:
My system has alarms that are gathered once daily through an auto-polling system; this is
not really a conventional SCADA system but does it meet the Table 1 requirements for
inclusion as a monitored system?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the maintenance-correctable issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the problem,
but rather a location where the action can be initiated.
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11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve fault event records and oscillographic records by
data communications after a fault. They analyze the data closely if there has been an apparent
misoperation, as NERC Standards require. Some advanced users have commissioned automatic
fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured digital fault
recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time-interval based check on protection systems whose operations are analyzed. Even
electromechanical protection systems instrumented with DFR channels may achieve some CBM
benefit. The completeness of the verification then depends on the number and variety of faults in
the vicinity of the relay that produce relay response records, and the specific data captured.
A typical fault record will verify particular parts of certain protection systems in the vicinity of
the fault. For a given protection system installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external fault records that
completely verify the protection system.
For example, fault records may verify that the particular relays that tripped are able to trip via the
control circuit path that was specifically used to clear that fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other nearby
protection systems may verify that they restrain from tripping for a fault just outside their
respective zones of protection. The ensemble of internal fault and nearby external fault event
data can verify major portions of the protection system, and reset the time clock for the Table 1
testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple faults close to either side
of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection System
that can actually be proven using the PMU or DME data.
If fault record data is used to show that portions or all of a protection system have been verified
to meet Table 1 requirements, the owner must retain the fault records used, and the maintenance
related conclusions drawn from this data and used to defer Table 1 tests, for at least the retention
time interval given in Section 8.2.
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11.1 Frequently Asked Question:
I use my protective relays for fault and disturbance recording, collecting oscillographic
records and event records via communications for fault analysis to meet NERC and DME
requirements. What are the maintenance requirements for the relays?
For relays used only as disturbance monitoring equipment, the NERC Standard PRC-018-1 R3 &
R6 states the maintenance requirements, and is being addressed by a Standards activity that is
revising PRC-002-1 and PRC-018-1. For protective relays “that are designed to provide
protection for the BES,” this Standard applies, even if they also perform DME functions.
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12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single selfmonitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to protection system performance.
Monitoring does not check measuring element settings. Analysis of fault records may or may not
reveal setting problems. To minimize risk of setting errors after commissioning, the user should
enforce strict settings data base management, with reconfirmation (manual or automatic) that the
installed settings are correct whenever maintenance activity might have changed them. For
background and guidance, see [5].
Table 1 requires that settings must be verified to be as specified. The reason for this requirement
is simple. With legacy relays (non-microprocessor protective relays) it is necessary to know the
value of the intended setting in order to test, adjust and calibrate the relay. Proving that the relay
works per specified setting was the de facto procedure. However, with the advanced
microprocessor relays it is possible to change relay settings for the purpose of verifying specific
functions and then neglect to return the settings to the specified values. While there is no specific
requirement to maintain a settings management process there remains a need to verify that the
settings left in the relay are the intended, specified settings. This need may manifest itself after
any of the following:
•
One or more settings are changed for any reason.
•
A relay fails and is repaired or replaced with another unit.
•
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be installed.
Other entities may rely upon the vigorous testing of the firmware OEM. An entity has the
latitude to install devices and/or programming that they believe will perform to their satisfaction.
If an entity should choose to perform the maintenance activities specified in the Tables following
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a firmware upgrade then they may, if they choose, reset the time clock on that set of maintenance
activities so that they would not have to repeat the maintenance on its regularly scheduled cycle.
(However, for simplicity in maintenance schedules, some entities may choose to not reset this
time clock; it is merely a suggested option.)
If I upgrade my old relays then do I have to maintain my previous equipment maintenance
documentation?
If an equipment item is repaired or replaced then the entity can restart the maintenance-activitytime-interval-clock if desired, however the replacement of equipment does not remove any
documentation requirements. The requirements in the Standard are intended to ensure that an
entity has a maintenance plan and that the entity adheres to minimum activities and maximum
time intervals. The documentation requirements are intended to help an entity demonstrate
compliance. For example, saving the dates and records of the last two maintenance activities is
intended to demonstrate compliance with the interval. Therefore, if you upgrade or replace
equipment then you still must maintain the documentation for the previous equipment, thus
demonstrating compliance with the time interval requirement prior to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system rating
changes that merely required taking relays “out-of-service”. What are our responsibilities
when it comes to “out-of-service” devices?
Assuming that your system up-rates, upgrades and overall changes meet any and all other
requirements and standards then the requirements of PRC-005-2 are simple – if the
Protection system component performs a Protection system function then it must be
maintained. If the component no longer performs Protection System functions then it
does not require maintenance activities under the Tables of PRC-005-2. While many
entities might physically remove a component that is no longer needed there is no
requirement in PRC-005-2 to remove such component(s). Obviously, prudence would
dictate that an “out-of-service” device is truly made inactive. There are no record
requirements listed in PRC-005-2 for Protection System components not used.
While performing relay testing of a protective device on our Bulk Electric System it was
discovered that the protective device being tested was either broken or out of calibration.
Does this satisfy the relay testing requirement even though the protective device tested bad,
and may be unable to be placed back into service?
Yes, PRC-005-2 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-2
requirement although the protective device may be unable to be returned to service under normal
calibration adjustments. R3 states (the entity must):
R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement
and follow its PSMP and initiate resolution of any identified maintenance correctable issues.
Also, when a failure occurs in a protection system, power system security maybe comprised, and
notification of the failure must be conducted in accordance with relevant NERC Standards.
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If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R3) (in essence) state “…shall implement and follow
its PSMP and initiate resolution of any identified maintenance correctable issues...” The type of
corrective activity is not stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device tested
bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products for
nearly 20 years. Theoretically, any element that is monitored does not need a periodic manual
test. A problem today is that the community of manufacturers and users has not created clear
documentation of exactly what is and is not monitored. Some unmonitored but critical elements
are buried in installed systems that are described as self-monitoring.
To utilize the extended time intervals allowed by monitoring the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with the
unmonitored intervals established in Table 1.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands-on
maintenance requirement), the manufacturers of the microprocessor-based self-monitoring
components in the protection system should publish for the user a document or map that shows:
•
How all internal elements of the product are monitored for any failure that could
impact protection system performance.
•
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
With this information in hand, the user can document monitoring for some or all sections by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
•
Extending the monitoring to include the alarm transmission facilities through
which failures are reported within a given time frame to allocate where action can
be taken to initiate resolution of the alarm attributed to a maintenance correctable
issue, so that failures of monitoring or alarming systems also lead to alarms and
action.
•
Documenting the plans for verification of any unmonitored components according
to the requirements of Table 1.
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13.1 Frequently Asked Question:
I can’t figure out how to demonstrate compliance with the requirements for the highest
level of monitoring of Protection Systems. Why does this Maintenance Standard describe a
maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This Standard does
not presume to specify what documentation must be developed; only that it must be documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring; the Standard establishes the necessary requirements for when
such equipment becomes available.
By creating a roadmap for development, this provision makes the Standard technology-neutral.
The Standard Drafting Team wants to avoid the need to revise the Standard in a few years to
accommodate technology advances that are maybe coming to the industry.
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14. Notification of Protection System Failures
When a failure occurs in a protection system, power system security may be compromised, and
notification of the failure must be conducted in accordance with relevant NERC Standard(s).
Knowledge of the failure may impact the system operator’s decisions on acceptable loading
conditions.
This formal reporting of the failure and repair status to the system operator by the protection
system owner also encourages the system owner to execute repairs as rapidly as possible. In
some cases, a microprocessor relay or carrier set can be replaced in hours; wiring termination
failures may be repaired in a similar time frame. On the other hand, a component in an
electromechanical or early-generation electronic relay may be difficult to find and may hold up
repair for weeks. In some situations, the owner may have to resort to a temporary protection
panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance but if its battery
maintenance program is lacking then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC-005-2 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore manual intervention to perform
certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and voltage
sensing devices and are used to isolate a faulted element of the BES. Devices that sense thermal,
vibration, seismic, pressure, gas or any other non-electrical inputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor based equipment
in the following ways, the relays should meet the asset owners’ tolerances.
•
Non-microprocessor devices must be tested with voltage and/or current applied to the
device.
•
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Question:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber-optic Hall-effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
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quantities that represent the primary values of voltage and current are considered to be a type of
voltage and current sensing devices included in this Standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these signals
is to know that the expected output from these components actually reaches the protective relay.
Therefore, the proof of the proper operation of these components also demonstrates the integrity
of the wiring (or other medium used to convey the signal) from the current and voltage sensing
device all the way to the protective relay. The following observations apply.
•
There is no specific ratio test, routine test or commissioning test mandated.
•
There is no specific documentation mandated.
•
It is required that the signal be present at the relay.
•
This expectation can be arrived at from any of a number of means; by calculation, by
comparison to other circuits, by commissioning tests, by thorough inspection, or by any
means needed to verify the circuit meets the asset owner’s protection system maintenance
program.
•
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this therefore tests the CT as well as the wiring from the relay all the back
to the CT.
•
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during load conditions, at the input to the relay.
•
Another example of testing the various voltage and/or current sensing devices is to query
the microprocessor relay for the real-time loading; this can then be compared to other
devices to verify the quantities applied to this relay. Since the input devices have supplied
the proper values to the protective relay then the verification activity has been satisfied.
Thus event reports (and oscillographs) can be used to verify that the voltage and current
sensing devices are performing satisfactorily.
•
Still another method is to measure total watts and vars around the entire bus; this should
add up to zero watts and zero vars thus proving the voltage and/or current sensing devices
system throughout the bus.
•
Another method for proving the voltage and/or current sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
•
Any other methods that provide documentation that the expected transformer values as
applied to the inputs to the protective relays are acceptable.
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15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage and
current sensing devices to the protective relays …” Do we need to perform ratio, polarity
and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all-inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional testing
on the panel wiring to ensure that the values arrive at those relays) with the other phases,
and verify that residual currents are within expected bounds
•
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay (such as, but not limited to, a
query to the microprocessor relay), to another protective relay monitoring the same line,
with currents supplied by different CT’s.
•
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi-meters, voltmeter, clamp-on ammeters, etc) and verified
by calculations and known ratios to be the values expected. For example a single PT on a
100KV bus will have a specific secondary value that when multiplied by the PT ratio
arrives at the expected bus value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that, an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring systems.
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Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test to
verify that the instrument transformer secondary signals are actually making it to the relay and
not being shunted off to ground. For instance, you could use CT excitation tests and PT turns
ratio tests and compare to baseline values to verify that the instrument transformer outputs are
acceptable. However, to conclude that these acceptable transformer instrument output signals
are actually making it to the relay inputs, it also would be necessary to verify the insulation of
the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions as do microprocessor based relays. In order for me to compare the
instrument transformer inputs to these relays to the secondary values of other metered
instrument transformers monitoring the same primary voltage and current signals, it
would be necessary to temporarily connect test equipment like voltmeters and clamp on
ammeters to measure the input signals to the relays. This practice seems very risky and a
plant trip could result if the technician were to make an error while measuring these
current and voltage signals. How can I avoid this risk? Also, what if no other instrument
transformers are available which monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying the
instrument transformer inputs to the relays but is not required by the Standard. Plants can choose
how to best manage their risk. If online testing is deemed too risky, offline tests such as, but not
limited to, CT excitation test and PT turns ratio tests can be compared to baseline data and be
used in conjunction with CT and PT secondary wiring insulation verification tests to adequately
“verify the current and voltage circuit inputs from the voltage and current sensing devices to the
protective relays …” while eliminating the risk of tripping an in service generator or transformer.
Similarly, this same offline test methodology can be used to verify the relay input voltage and
current signals to relays when there are no other instrument transformers monitoring available
for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the relays. It
includes the wiring (or other signal conveyance) from every trip output to every trip coil. It
includes any device needed for the correct processing of the needed trip signal to the trip coil of
the interrupting device; this requirement is meant to capture inputs and outputs to and from a
protective relay that are necessary for the correct operation of the protective functions. In short,
every trip path must be verified; the method of verification is optional to the asset owner. An
example of testing methods to accomplish this might be to verify, with a volt-meter, the
existence of the proper voltage at the open contacts, the open circuited input circuit and at the
trip coil(s). As every parallel trip path has similar failure modes, each trip path from relay to trip
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coil must be verified. Each trip coil must be tested to trip the circuit breaker (or other interrupting
device) at least once. There is a requirement to operate the circuit breaker (or other interrupting
device) at least once every six years as part of the complete functional test. If a suitable
monitoring system is installed that verifies every parallel trip path then the manual-intervention
testing of those parallel trip paths can be eliminated, however the actual operation of the circuit
breaker must still occur at least once every six years. This 6-year tripping requirement can be
completed as easily as tracking the real-time fault-clearing operations on the circuit breaker or
tracking the trip coil(s) operation(s) during circuit breaker routine maintenance actions.
The circuit-interrupting device should not be confused with a motor-operated disconnect. The
intent of this Standard is to require maintenance intervals and activities on Protection Systems
equipment and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground
switch as an interrupting device if this ground switch is utilized in a Protection System and
forces a ground fault to occur that then results in an expected Protection System operation to
clear the forced ground fault. The SDT believes that this is essentially a transferred-tripping
device without the use of communications equipment. If this high-speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years and any electromechanically operated device will have to be tested every 6 years. If the
spring-operated ground switch can be disconnected from the solenoid triggering unit then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
Circuit breakers that participate in a UFLS or UVLS scheme are excluded from the tripping
requirement, but not from the circuit test requirements; however the circuitry must be tested at
least once every 12 years. There are many circuit interrupting devices in the distribution system
that will be operating for any given under-frequency event that requires tripping for that event. A
failure in the tripping-action of a single distributed system circuit breaker will be far less
significant than, for example, any single Transmission Protection System failure such as a failure
of a bus differential lock-out Relay. While many failures of these distributed system circuit
breakers could add up to be significant, it is also believed that many circuit breakers are operated
often on just fault clearing duty and therefore these circuit breakers are operated at least as
frequently as any requirements that appear in this Standard.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay
(86) that may exist in any particular trip scheme. If these devices are electro-mechanical
components then they must be trip tested. The PSMT SDT considers these components to share
some similarities in failure modes as electro-mechanical protective relays; as such there is a six
year maximum interval between mandated maintenance tasks unless PBM is applied.
Contacts of the 86 or 94 that pass the trip current on to the circuit interrupting device trip coils
will have to be checked as part of the 12 year requirement. Normally-open contacts that are not
used to pass a trip signal and normally-closed contacts do not have to be verified. Verification of
the tripping paths is the requirement.
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New technology is also accommodated here; there are some tripping systems that have replaced
the traditional hard-wired trip circuitry with other methods of trip-signal conveyance such as
fiber-optics. It is the intent of the PSMT SDT to include this, and any other, technology that is
used to convey a trip signal from a protective relay to a circuit breaker (or other interrupting
device) within this category of equipment.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval) than
when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual components’ maximum
allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying the
tripping of circuit breakers. What is this telling me about maintenance of circuit breakers?
Requirements in PRC-005-2 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC-005-2 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit path, as established in Table 1-5 “Protection System
Control Circuitry (Trip coils and auxiliary relays)”?
Table 1-5 specifies that each breaker trip coil, auxiliary relay that carries trip current to a
trip coil, and lockout relays that carry trip current to a trip coil must be operated within
the specified time period. The required operations may be via targeted maintenance
activities, or by documented operation of these devices for other purposes such as fault
clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
Yes. PRC-005-2 includes high-speed grounding switch trip coils within the dc control circuitry
to the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
15.4 Batteries and DC Supplies (Table 1-4)
IEEE guidelines were consulted to arrive at the maintenance activities for batteries. The
following guidelines were used: IEEE 450 (for Vented Lead-Acid batteries), IEEE 1188 (for
Valve-Regulated Lead-Acid batteries) and IEEE 1106 (for Nickel-Cadmium batteries).
The currently proposed NERC definition of a Protection System is
•
Protective relays which respond to electrical quantities,
•
Communications systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
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•
Station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.”
•
The station battery is not the only component that provides dc power to a Protection
System. In the new definition for Protection System “station batteries” are replaced with
“station dc supply” to make the battery charger and dc producing stored energy devices
(that are not a battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the Standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner to
the two methods recommended in the IEEE standards. Continuity as used in Table 1-4 of the
Standard refers to verifying that there is a continuous current path from the positive terminal of
the station battery set to the negative terminal. Without verifying continuity of a station battery,
there is no way to determine that the station battery is available to supply dc power to the station.
An open battery string will be an unavailable power source in the event of loss of the battery
charger.
Batteries cannot be a unique population segment of a Performance-based Maintenance Program
(PBM) because there are too many variables in the electro-chemical process to completely
isolate all of the performance-changing criteria necessary for using PBM on battery systems.
However, nothing precludes the use of a PBM process for any other part of a dc supply besides
the batteries themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply as mentioned in the definition of Protective System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers as well as dc systems that do not utilize batteries. This revision
of PRC-005-2 is intended to capture these devices that were not included under the previous
definition. The station direct current (dc) supply normally consists of two components: the
battery charger and the station battery itself. There are also emerging technologies that provide a
source of dc supply that does not include either a battery or charger.
Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays in
the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1-4.
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Emerging Technologies - Station dc supplies are currently being developed that use other energy
storage technologies beside the station battery to prevent loss of the station dc supply when ac
power is lost. Maintenance of these station dc supplies will require different kinds of tests and
inspections. Table 1-4 presents maintenance activities and maximum allowable testing intervals
for these new station dc supply technologies. However, because these technologies are relatively
new the maintenance activities for these station dc supplies may change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the Standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner to
the two methods recommended in the IEEE standards. Continuity as used in Table 1-4 of the
Standard refers to verifying that there is a continuous current path from the positive terminal of
the station battery set to the negative terminal. Without verifying continuity of a station battery,
there is no way to determine that the station battery is available to supply dc power to the station.
An open battery string will be an unavailable power source in the event of loss of the battery
charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity (an
open circuit) in any part of the electrochemical or metallic path the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery must
be capable of supplying dc current, both for continuous dc loads and for tripping breakers and
switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
•
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
harmonics. With the loss of continuity in the battery, the filter provided by the battery is
no longer present.
•
Loss of electrical continuity of the station battery will cause, regardless of the battery
charger’s output current capability, a delayed response in full output current from the
charger. Almost all chargers have an intentional 1 to 2 second delay to switch from a low
substation dc load current to the maximum output of the charger. This delay would cause
the opening of circuit breakers to be delayed which could violate system performance
standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery unless the battery charger is taken out of service. At that time a
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break in the continuity of the station battery current path will be revealed because there will be
no voltage on the station dc circuitry. This particular test method, while proving battery
continuity, may not be acceptable to all installations.
Although the Standard prescribes what must be accomplished during the maintenance activity it
does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the only
possible methods, simply a sampling of some methods:
•
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path through
the battery.
•
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of the
various dc-supplied equipment in the station should be considered before using this
approach.
•
Manufacturers of microprocessor controlled battery chargers have developed methods for
their equipment to periodically (or continuously) test for battery continuity For example,
one manufacturer periodically reduces the float voltage on the battery until current from
the battery to the dc load can be measured to confirm continuity.
•
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
•
Internal ohmic measurements of the cells and units of Lead Acid Batteries (VRLA &
VLA) can detect lack of continuity within the cells of a battery string and when used in
conjunction with resistance measurements of the battery’s external connections can prove
continuity. Also some methods of taking internal ohmic measurements by their very
nature can prove the continuity of a battery string without having to use the results of
resistance measurements of the external connections.
•
Specific Gravity tests can infer continuity because without continuity there could be no
charging occurring and if there is no charging then Specific Gravity will go down below
acceptable levels.
No matter how the electrical continuity of a battery set is verified it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1-4 to insure that the station
dc supply has a path that can provide the required current to the Protection System at all times.
When should I check the station batteries to see if they have sufficient energy to perform as
designed?
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The answer to this question depends on the type of battery (valve regulated lead-acid, vented
lead acid, or nickel-cadmium), and the maintenance activity chosen.
For example, if you have a Valve Regulated Lead-Acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline, you
will have to perform verification at a maximum maintenance interval of no greater than every six
months. While this interval might seem to be quite short, keep in mind that the 6 month interval
is consistent with IEEE guidelines for VRLA batteries; this interval provides an accumulation of
data that better shows when a VRLA battery is no longer capable of its design capacity.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every 3 calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when lead
acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are most
indicative of the station batteries ability to perform as designed they should be made upon
installation of the station battery and the completion of a performance test of the battery’s
capacity.
When internal ohmic measurements are taken, the type of test equipment used to establish the
baseline must be used for any future trending of the cells internal ohmic measurements because
of variances in test equipment and the type of ohmic measurement used by different
manufacturer’s equipment.
For all new installations of Valve Regulated Lead-Acid (VRLA) batteries and Vented Lead-Acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to be
used to determine the ability of the station battery to perform as designed, the establishment of
the baseline as described above should be followed at the time of installation to insure the most
accurate trending of the cell/unit. However, often for older VLRA batteries the owners of the
station batteries have not established a baseline at installation. Also for owners of VLA batteries
who want to establish a maintenance activity which requires trending of measured ohmic values
to a baseline, there was typically no baseline established at installation of the station battery to
trend to.
To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, all manufacturers of internal ohmic measurement devices
have established libraries of baseline values for VRLA and VLA batteries using their testing
device. Also several of the battery manufacturers have libraries of baselines for their products
that can be used to trend to. However it is important that when using battery manufacturer
supplied data that it is verified that the baseline readings to be used were taken with the same
ohmic testing device that will be used for future measurements.
Although the manufactures provided base line values which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a baseline
for each cell/unit at the time of installation of the station battery.
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Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be a
very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged the battery is available to deliver its existing capacity. As a
battery is discharged its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
IEEE Standards 450, 1188, and 1106 for vented lead-acid (VLA), valve-regulated lead-acid
(VRLA), and nickel-cadmium (NiCd) batteries respectively discuss state of charge in great detail
in their standards or annexes to their standards. The above IEEE standards are excellent sources
for describing how to determine state of charge of the battery system.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged the battery is
available to deliver its existing capacity. As a battery is discharged its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For Vented Lead-Acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the battery
discharges the active electrolyte, sulphuric acid, is consumed and the concentration of the
sulphuric acid in water is reduced. This in turn reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can therefore
be used as an indication of the state of charge of the battery. Hydrometer readings may not tell
the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA battery. If
measured right after charging, you might see high specific gravity readings at the top of the cell,
even though it is much less at the bottom. Conversely if taken shortly after adding water to the
cell the specific gravity readings near the top of the cell will be lower than those at the bottom.
Nickel-cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and Valve Regulated Lead-Acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
readings. For these two types of batteries and also for VLA batteries, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by using
the battery charger and taking voltage and current readings during float and equalize (high-rate
charge mode). This method is an effective means of determining when the state of charge is low
and when it is approaching a fully charged condition which gives the assurance that the available
battery capacity will be maximized.
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Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery a
very high resistance can cause severe damage. The maintenance requirement to verify battery
terminal connection resistance in table 1-4 is established to verify that the integrity of all battery
electrical connections is acceptable. This verification includes cell-to-cell (intercell) and external
circuit terminations.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen not to exceed the maximum
maintenance interval of table 1-4. Trending of the interval measurements to the baseline
measurements will identify any degradation in the battery connections. When the connection
resistance values exceed the acceptance criteria for the connection, the connection is typically
disassembled, cleaned, reassembled and measurements taken to verify that the measurements are
adequate when compared to the baseline readings.
IEEE Standard 450 for vented lead-acid (VLA) batteries “informative” annex F, and IEEE
Standard 1188 for valve-regulated lead-acid (VRLA) batteries “informative” annex D provide
excellent information and examples on performing connection resistance measurements using a
microohmmeter and connection detail resistance measurements. Although this information is
contained in standards for lead acid batteries the information contained is applicable to nickelcadmium batteries also.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of table 1-4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to the
electro-chemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking on the plates are signs of sulfation of the plates, abnormal color (possible
copper contamination) and abnormal conditions such as cracked grids. The visual inspection
could look for symptoms of hydration that would indicate that the battery has been left in a
completely discharged state for a prolonged period. Besides looking at the plates for signs of
aging, all internal connections such as the bus bar connection to each plate and the connections
to all posts of the battery need to be visually inspected for abnormalities. In a complete visual
inspection for the condition of the cell the cell plates, separators and sediment space of each cell
must be looked at for signs of deterioration. An inspection of the station battery’s cell condition
also includes looking at all terminal posts and cell-to-cell electric connections to ensure they are
corrosion free. The case of the battery containing the cell or cells must be inspected for cracks
and electrolyte leaks through cracks and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
table 1-4 by a Performance-based Maintenance Program (PBM) because of the electro-chemical
aging process of the station battery nor can there be any monitoring associated with it because
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there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval of
table 1-4.
Why consider the ability of the station battery to perform as designed?
Determining the ability of a station battery to perform as designed is critical in the process of
determining when the station battery must be replaced or when an individual cell or battery unit
must be removed or replaced. For lead acid batteries the ability to perform as designed can be
determined in more than one manner.
The two acceptable methods for proving that a station lead acid battery can perform as designed
are based on two different philosophies. The first maintenance activity requires tests and
evaluation of the internal ohmic measurements on each of the individual cells/units of the station
battery to determine that each component can perform as designed and therefore the entire
station battery can be verified to perform as designed. The second activity requires a capacity
discharge test of the entire station battery to verify that degradation of one or several components
(cells) in the station battery has not deteriorated to a point where the total capacity of the station
battery system falls below its designed rating.
The first maintenance activity listed in Table 1-4 for verifying that a station battery can perform
as designed uses maximum maintenance intervals for evaluating internal ohmic measurements in
relation to their baseline measurements that are based on industry experience, EPRI technical
reports and application guides, and the IEEE battery standards. By evaluating the internal ohmic
measurements for each cell and comparing that measurement to the cell’s baseline ohmic
measurement low-capacity cells can be identified and eliminated or the whole station battery
replaced to keep the station battery capable of performing as designed. Since the philosophy
behind internal ohmic measurement evaluation is based on the fact that each battery component
must be verified to be able to perform as designed, the interval for verification by this
maintenance activity must be shorter to catch individual cell/unit degradation.
It should be noted that even if a lead acid battery unit is composed of multiple cells where the
ohmic measurement of each cell cannot be taken, the ohmic test can still be accomplished. The
data produced becomes trending data on the multi-cell unit instead of trending individual cells.
Care must be taken in the evaluation of the ohmic measures of entire units to detect a bad cell
that has a poor ohmic value. Good ohmic values of other cells in the same battery unit can make
it harder to detect the poor ohmic measurement of a bad cell because the only ohmic
measurement available is of all the cells in the battery unit.
This first maintenance activity is applicable only for Vented Lead-Acid (VLA) and Valve
Regulated Lead-Acid (VRLA) batteries; this trending activity has not shown to be effective for
NiCd batteries thus the only choices for owners of NiCd batteries are the performance tests of the
second activity (see applicable IEEE guideline for specifics on performance tests).
The second maintenance activity listed in Table 1-4 for verifying that a station battery can
perform as designed uses maximum maintenance intervals for capacity testing that were
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designed to align with the IEEE battery standards. This maintenance activity is applicable for
vented lead-acid, valve-regulated lead-acid, and nickel-cadmium batteries.
The maximum maintenance interval for discharge capacity testing is longer than the interval for
testing and evaluation of internal ohmic cell measurements. An individual component of a
station battery may degrade to an unacceptable level without causing the total station battery to
fall below its designed rating under capacity testing.
IEEE Standards 450, 1188, and 1106 for vented lead-acid (VLA), valve-regulated lead-acid
(VRLA), and nickel-cadmium (NiCd) batteries respectively (which together are the most
commonly used substation batteries on the BES) go into great detail about capacity testing of the
entire battery set to determine that a battery can perform as designed or needs to be replaced
soon.
Why in Table 1-4 of PRC-005-2 is there a maintenance activity to inspect the structural
intergrity of the battery rack?
The three IEEE standards (1188, 450, and 1106) for VRLA, vented lead-acid, and nickelcadmium batteries all recommend that as part of any battery inspection the battery rack should be
inspected. The purpose of this inspection is to verify that the battery rack is correctly installed
and has no deterioration that could weaken its structural integrity.
Because the battery rack is specifically designed for the battery that is mounted on it, weakening
of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the unintentional
ground that appears on the opposite pole that becomes problematic. Even then many systems are
designed to operate favorably under some unintentional DC ground situations. It is up to the
owner of the Protection System to determine if corrective actions are needed on detected
unintentional DC grounds. The Standard merely requires that a check be made for the existence
of Unintentional DC Grounds. Obviously a “check-off” of some sort will have to be devised by
the inspecting entity to document that a check is routinely done for Unintentional DC Grounds
because to the possible consequences to the Protection System.
Where the Standard refers to “all cells” is it sufficient to have a documentation method
that refers to “all cells” or do we need to have separate documentation for every cell? For
example to I need 60 individual documented check-offs for good electrolyte level or would a
single check-off per bank be sufficient?
A single check-off per battery bank is sufficient for documentation, as long as the single checkoff attests to checking all cells/units.
Does this Standard refer to Station batteries or all batteries, for example Communications
Site Batteries?
This Standard refers to Station Batteries. The drafting team does not believe that the scope of this
Standard refers to communications sites. The batteries covered under PRC-005-2 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part of
the Protection System. The SDT believes that a loss of power to the communications systems at
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a remote site would cause the communications systems associated with protective relays to alarm
at the substation. At this point the corrective actions can be initiated.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how am I
expected to comply with the cell-to-cell ohmic measurement requirements on these units
that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in table 14.
What are cell/unit internal ohmic measurements?
With the introduction of Valve Regulated Lead Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead-Acid (VLA)
batteries were unable to be used on this new type of lead-acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells and
periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The inductive
reactance in the current path through the battery is so minuscule when compared to the huge
capacitive reactance of the cells that it is often ignored in most circuit models of the battery cell.
Taking the basic model of a battery cell manufacturers of battery test equipment have developed
and marketed testing devices to take measurements of the current path to detect degradation in
the internal path through the cell.
In the battery industry these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac conductance,
ac impedance, and dc resistance. They are defined by the test equipment providers and IEEE and
refer to the method of taking ohmic measurements of a lead acid battery. For example in one
manufacturer’s ac conductance equipment measurements are taken by applying a voltage of a
known frequency and amplitude across a cell or battery unit and observing the ac current flow it
produces in response to the voltage. A manufacture of an ac impedance meter measures ac
current of a known frequency and amplitude that is passed through the whole battery string and
determines the impedances of each cell or unit by measuring the resultant ac voltage drop across
them. On the other hand dc resistance of a cell is measured by a third manufacture’s equipment
by applying a dc load across the cell or unit and measuring the step change in both the voltage
and current to calculate the internal dc resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices there were no standards developed or used to mandate the test signals used
in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of measurement
devices. This diversity in test signals coupled with the three different types of ohmic
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measurements techniques (impedance conductance and resistance) make it impossible to get the
same ohmic measurement for a cell with different ohmic measurement devices. However, IEEE
has recognized the great value for choosing one device for ohmic measurement, no matter who
makes it or the method to calculate the ohmic measurement. The only caution given by IEEE
and the battery manufacturers is that when trending the cells of a lead acid station battery the
same ohmic measurement device must be used to establish the baseline measurement and to
trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (maintenance, testing and replacement of VRLA
batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements” and trending them at frequent intervals over the life of the battery.
There are extensive discussions about the need for taking these measurements in these standards.
IEEE Standard 1188 requires taking internal ohmic values as described in Annex C4 during
regular inspections of the station battery. For VRLA batteries IEEE Standard 1188 in talking
about the necessity of establishing a base line and trending it over time says, “depending on the
degree of change a performance test, cell replacement or other corrective action may be
necessary.
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guide lines
about establishing baseline measurements on newly installed lead acid stationary batteries. The
standard also discusses the need to look for significant changes in the ohmic measurements, the
caution that measurement data will differ with each type of model of instrument used, and lists a
number of factors that affect ohmic measurements.
At the beginning of the 21st century EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as designed. By evaluation of the trending of the
ohmic measurements over time the owner could track the performance of the individual
components of the station battery and determine if a total station battery or components of it
required capacity testing, removal, replacement or in many instances replacement of the entire
station battery. By taking this approach these owners have eliminated having to perform
capacity testing at prescribed intervals to determine if a battery needs to be replaced and are still
able to effectively determine if a station battery can perform as designed.
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Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in table
1-4. These two required activities are to verify station dc supply voltage and float voltage of the
battery charger, and have different maximum maintenance intervals. Both of these voltage
verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove that
the charger has not been lost or is not malfunctioning. Low battery voltage below float voltage
indicates that the battery may be on discharge and if not corrected the station battery could
discharge down to some extremely low value that will not operate the Protection System. High
voltage, close to or above the maximum allowable dc voltage for equipment connected to the
station dc supply indicates the battery charger may be malfunctioning by producing high dc
voltage levels on the Protection System. If corrective actions are not taken to bring the high
voltage down, the dc power supplies and other electronic devices connected to the station dc
supply may be damaged. The maintenance activity of verifying the float voltage of the battery
charger is not to prove that a charger is lost or producing high voltages on the station dc supply,
but rather to prove that the charger is properly floating the battery within the proper voltage
limits.
Why check for the electrolyte level?
In Vented Lead Acid (VLA) and Nickel-Cadmium (NiCd) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of table 1-4. Because the
electrolyte level in Valve Regulated Lead Acid (VRLA) batteries cannot be observed there is no
maintenance activity listed in table 1-4 of the Standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCd station battery is a condition requiring
correction. Typically the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCd) by adding distilled or other approved-quality water to the cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to check
the electrolyte level. In many of the modern station batteries the jar containing the electrolyte is
so large with the band between the high and low electrolyte level so wide that normal
evaporation which would require periodic watering of all cells takes several years to occur.
However, because loss of electrolyte due to cracks in the jar, overcharging of the station battery
or other unforeseen events can cause rapid loss of electrolyte the shorter maximum maintenance
intervals for checking the electrolyte level are required. A low level of electrolyte in a VLA
battery cell which exposes the tops of the plates can cause the exposed portion of the plates to
accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
Why does it appear that there are two maintenance activities in table 1-4(b) (for VRLA
batteries) that appear to be the same activity and have the same maximum maintenance
interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for Valve Regulated Lead-Acid (VRLA) batteries. The first similar activity for
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VRLA batteries (table 1-4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health of
the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for Vented Lead Acid (VLA) due to some unique failure modes for VRLA batteries.
Some of the potential problems that VRLA batteries are susceptible to that do not affect VLA
batteries are thermal runaway, cell dry-out, and cell reversal when one cell has a very low
capacity.
The other similar activity listed in table 1-4(b) is “verify that the station battery can perform as
designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.”
This activity allows an owner the option to choose between this activity with its much shorter
maximum maintenance interval or the longer maximum maintenance interval for the
maintenance activity to “Verify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. A comparison and trending against the baseline new battery ohmic
reading can be used in lieu of capacity tests to determine remaining battery life. Remaining
battery life is analogous to stating that the battery is still able to "perform as designed". This is
the intent of the “capacity 6 month test” at Row 4 on Table 1-4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1-4b. In order to detect a cell in thermal runaway,
you need not have a formal trending program to track when a cell has reached a 25%
increase over baseline. Rather it will stick out like a sore thumb when compared to the other
cells in a string at a given point in time regardless of the age of all the cells in a string. In other
words, if the battery is 10 years old and all the cells are gradually approaching a 25% increase in
ohmic values over baseline, then you have a battery which is approaching end of life. You need
to get ready to buy a new battery but you do not have to worry about an impending catastrophic
failure. On the other hand, if the battery is five years old and you have one cell that has a
markedly different ohmic reading than all the other cells, then you need to be worried that this
cell is in thermal runaway and catastrophic failure is imminent.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this does
not eliminate the need to be concerned about thermal runaway – the entity still needs to do the 6
month readings and look for cells which are outliers in the string but they need not trend results
against the factory/as new baseline. Some entities will not mind the extra administrative burden
of having the ongoing trending program against baseline - others would rather just do the
capacity test and not have to trend the data against baseline. Nonetheless, all entities must look
for ohmic outliers on a 6 month basis.
It is possible to accomplish both tasks listed (trend testing for capacity and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of watching
the trend from baselines and watching for the oblique cell measurement.
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested.
Besides the trip output and wiring to the trip coil(s) there is also a communications medium that
must be maintained.
Newer technologies now exist that achieve communications-assisted tripping without the
conventional wiring practices of older technology.
For example: older technologies may have included Frequency Shift Key methods. This
technology requires that guard and trip levels be maintained.
The actual tripping path(s) to the trip coil(s) may be tested as a parallel trip path within the dc
control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals.
The requirements apply to the communicated signal needed for the proper operation of the
protective relay trip logic or scheme. Therefore this Standard is applied to equipment used to
convey both trip signals (permissive or direct) and block signals.
It was the intent of this Standard to require that a test be made of any communications-assisted
trip scheme regardless of the vintage of the technology. The essential element is that the tripping
(or blocking) occurs locally when the remote action has been asserted; or that the tripping (or
blocking) occurs remotely when the local action is asserted.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on-site integrity checking to be performed at least every three months
during a substation visit. Some examples are, but not limited to:
•
On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check-back test from one terminal.
•
Systems which use frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
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loss-of-guard indication or alarm. For frequency-shift power-line carrier systems, the
guard signal level meter can also be checked.
•
Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
•
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms that
can be monitored remotely. Some examples are, but not limited to:
•
On-off power-line carrier systems can be shown to be operational by automated periodic
power-line carrier check-back tests, with remote alarming of failures.
•
Systems which use a frequency-shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored with
a loss-of-guard alarm or low signal level alarm.
•
Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
•
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
•
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
•
•
In many communications systems signal quality measurements including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
What is needed for the 3-month inspection of communications-assisted trip scheme
equipment?
The 3-month inspection applies to unmonitored equipment. An example of compliance with this
requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms, check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e. FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
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inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard.
Does a fiber optic I/O scheme used for breaker tripping or control within a station, for
example - transmitting a trip signal or control logic between the control house and the
breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System Control Circuitry
and tested per the portions of Table 1 applicable to Protection System Control Circuitry rather
than those portions of the table applicable to communications equipment.
In Table 1-2, the Maintenance Activities section of the Protective System Communications
Equipment and Channels refers to the quality of the channel meeting “performance
criteria”. What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally
an alarm will be indicated. For unmonitored systems this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each protective system
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following are
some examples of protective system communications channel performance measuring:
•
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
•
An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check-back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes this
signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
•
Pilot wire relay systems use a hardwire communications circuit to communicate between
the local and remote ends of the protective zone. This circuit is monitored by circulating
a dc current between the relay systems. A typical level may be 1 mA. If the level drops
below the setting of the alarm monitor, the system will indicate an alarm.
•
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme commonly
used on transmission lines. The protective relays communicate current magnitude and
phase information over the communications path to determine if the fault is located in the
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protective zone. Quantities such as digital packet loss, bit error rate and channel delay
are monitored to determine the quality of the channel. These limits are determined and
set during relay commissioning. Once set, any channel quality problems that fall outside
the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This Standard does not state what the performance criteria will be - it
just requires that the entity establish nominal criteria so protective system channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment involved
in the maintenance program?
An entity determines the acceptable performance criteria depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre-determined performance criteria for that system then these results should be investigated
and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot and thus make it easier to read the
Tables 1-1 through 1-5. The alarms need to arrive at a site wherein a corrective action can be
initiated. This could be a control room, operations center, etc. The alarming mechanism can be a
Standard alarming system or an auto-polling system, the only requirement is that the alarm be
brought to the action-site within 24 hours. This effectively makes manned-stations equivalent to
monitored stations. The alarm of a monitored point (for example a monitored trip path with a
lamp) in a manned-station now makes that monitored point eligible for monitored status.
Obviously, these same rules apply to a non-manned-station, which is that if the monitored point
has an alarm that is auto-reported to the operations center (for example) within 24 hours then it
too is considered monitored.
15.6.1 Frequently Asked Question:
Why are there activities defined for varying degrees of monitoring a Protection System
component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the Standard establishes the necessary requirements for
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when such equipment becomes available. By creating a roadmap for development, this provision
makes the Standard technology-neutral. The Standard Drafting Team wants to avoid the need to
revise the Standard in a few years to accommodate technology advances that may be coming to
the industry.
15.7 Examples of Evidence of Compliance
To comply with the requirements of this Standard an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team recognizes
that there are concurrent evidence requirements of other NERC Standards that could, at times,
fulfill evidence requirements of this Standard.
15.7.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the Requirement being documented, include but
are not limited to:
•
Process documents or plans
•
Data (such as relay settings sheets, photos, SCADA, and test records)
•
Database lists, records and/or screen shots that demonstrate compliance information
•
Prints, diagrams and/or schematics
•
Maintenance records
•
Logs (operator, substation, and other types of log)
•
Inspection forms
•
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
•
Check-off forms (paper or electronic)
•
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
If I replace a failed Protection System component with another component, what testing do
I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-005-2?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus the reporting requirements that one may have to do for the Misoperation of a
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Special Protection Scheme under PRC-016 could work for the activity tracking requirements
under this PRC-005-2.
I maintain disturbance records which show Protection System operations. Can I use these
records to show compliance?
These records can be concurrently utilized as dc trip path verifications to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my components of my Protection System
components. Can I use these test reports to show that I have verified a maintenance
activity?
Yes.
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16. References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power
Engineering Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group
C3 of Power System Relaying Committee of IEEE Power Engineering Society,
December 2006.
7. “Proposed Statistical Performance Measures for Microprocessor-Based TransmissionLine Protective Relays, Part I - Explanation of the Statistics, and Part II - Collection
and Uses of Data,” Working Group D5 of Power System Relaying Committee of
IEEE Power Engineering Society, May 1995; Papers 96WM 016-6 PWRD and
96WM 127-1 PWRD, 1996 IEEE Power Engineering Society Winter Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report
of CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
PSMT SDT References
10. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
11. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore,
2005
12. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
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Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – Components of Protection
Systems
(Return)
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Figure 2: Typical Generation System
For information on components, see Figure 1 & 2 Legend – Components of Protection
Systems
(Return)
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Figure 1 & 2 Legend – Components of Protection Systems
Number
in
Figure
Includes
Excludes
1
Protective
relays which
respond to
electrical
quantities
All protective relays that use
current and/or voltage inputs from
current & voltage sensors and that
trip the 86, 94 or trip coil.
Devices that use non-electrical methods of
operation including thermal, pressure, gas
accumulation, and vibration. Any ancillary
equipment not specified in the definition of
Protection systems. Control and/or monitoring
equipment that is not a part of the automatic
tripping action of the Protection System
2
Voltage and
current sensing
devices
providing
inputs to
protective
relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that are not a
part of the Protection System, including synccheck systems, metering systems and data
acquisition systems.
Control
circuitry
associated with
protective
functions
All control wiring (or other medium
for conveying trip signals)
associated with the tripping action
of 86 devices, 94 devices or trip
coils (from all parallel trip paths).
This would include fiber-optic
systems that carry a trip signal as
well as hard-wired systems that
carry trip current.
Closing circuits, SCADA circuits, other devices in
control scheme not passing trip current
4
Station dc
supply
Batteries and battery chargers and
any control power system which
has the function of supplying power
to the protective relays, associated
trip circuits and trip coils.
Any power supplies that are not used to power
protective relays or their associated trip circuits
and trip coils.
5
Communicatio
ns systems
necessary for
correct
operation of
protective
functions
Tele-protection equipment used to
convey specific information, in the
form of analog or digital signals,
necessary for the correct operation
of protective functions.
Any communications equipment that is not used to
convey information necessary for the correct
operation of protective functions.
3
Component
of
Protection
System
(Return)
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Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A-1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two-terminal pilot protection scheme to protect for line faults, and to avoid overtripping for faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors
report the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered
values of volts, amperes, plus Watts and VARs on the line. These metered values are
reported by data communications. For maintenance, the user elects to compare these
readings to those of other relays, meters, or DFRs. The other readings may be from
redundant relaying or measurement systems or they may be derived from values in
other protection zones. Comparison with other such readings to within required
relaying accuracy verifies Voltage & Current Sensing Devices, wiring, and analog
signal input processing of the relays. One effective way to do this is to utilize the
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relay metered values directly in SCADA, where they can be compared with other
references or state estimator values.
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2).
Status indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by
the relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the
protection system, so each carrier set has a connected or integrated automatic
checkback test unit. The automatic checkback test runs several times a day. Newer
carrier sets with integrated checkback testing check for received signal level and
report abnormal channel attenuation or noise, even if the problem is not severe
enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the
protection system elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
Draft 4 April 12, 2011
85
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
1. The continuity of trip coils is verified, but no means is provided for validating the
ability of the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision
have been verified by internal monitoring. However, the trip circuit is actually
energized by the contacts of a small telephone-type "ice cube" relay within the line
protective relay. The microprocessor energizes the coil of this ice cube relay through
its output data port and a transistor driver circuit. There is no monitoring of the output
port, driver circuit, ice cube relay, or contacts of that relay. These components are
critical for tripping the circuit breaker for a fault.
3. The check-back test of the carrier channel does not verify the connections between
the relaying microprocessor internal decision programs and the carrier transmitter
keying circuit or the carrier receiver output state. These connections include
microprocessor I/O ports, electronic driver circuits, wiring, and sometimes telephonetype auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored,
but this does not confirm that the state change indication is correct when the breaker
or switch opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally-occurring faults are
demonstrations of operation that reset the time interval clock for testing of each breaker tripped
in this way. If faults do not occur, manual tripping of the breaker through the relay trip output via
data communications to the relay microprocessor meets the requirement for periodic testing.
PRC-005 does not address breaker maintenance, and its protection system test requirements can
be met by energizing the trip circuit in a test mode (breaker disconnected) through the relay
microprocessor. This can be done via a front-panel button command to the relay logic, or
application of a simulated fault with a relay test set. However, utilities have found that breakers
often show problems during protection system tests. It is recommended that protection system
verification include periodic testing of the actual tripping of connected circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
Draft 4 April 12, 2011
86
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Appendix B — Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Mark Lucas
ComEd
Merle E. Ashton
Tri-State G&T
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
Bob Bentert
Florida Power & Light Company
Mark Peterson
Great River Energy
John Ciufo
Hydro One Inc
Leonard Swanson, Jr
National Grid USA
Sam Francis
Oncor
Eric A. Udren
Quanta Technology
Carol A. Gerou
Midwest Reliability Organization
Philip B. Winston
Southern Company Transmission
William D. Shultz
Southern Company Generation
John A. Zipp
ITC Holdings
Russell C. Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
Draft 4 April 12, 2011
87
Standards Announcement
Successive Ballot and Non-Binding Poll Now Open
May 3 – 12, 2011
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-17: Protection System Maintenance and Testing
A successive ballot for the proposed standard, PRC-005-2 — Protection System Maintenance, and a concurrent,
non-binding poll of the revised VRFs and VSLs are being conducted through 8:00 pm Eastern on Thursday,
May 12, 2011.
Instructions
All members of the ballot pool must cast a new ballot since the votes and comments from the last ballot will not
be carried over. In addition, members of the ballot pool will need to cast a new opinion on the revised VRFs and
VSLs. The drafting team will consider all comments (those submitted with a comment form, and those
submitted with a ballot or with the non-binding poll) and will determine whether to make additional changes to
the standard and its implementation plan.
Special Instructions for Submitting Comments With a Ballot
Comments submitted with ballots are extremely valuable to help the drafting team revise its work. In an effort
to reduce the burden on stakeholders providing comments, the drafting team requests that all comments (both
those submitted with a ballot and those submitted by stakeholders not balloting) be submitted through the
electronic comment form posted at:
https://www.nerc.net/nercsurvey/Survey.asp?s=88fc1b48299643f2b8acd43c76dcc30f.
This will ensure that stakeholders only provide a single set of comments, but have an opportunity to notify the
drafting team if they have provided comments.
During the successive ballot window, members of the ballot pool associated with this project may log in and
submit their votes from the following page: https://standards.nerc.net/CurrentBallots.aspx . When submitting
a ballot with comments, simply record a “Comments submitted” in the comments field of the ballot to
indicate that comments were submitted.
Documents for this project, including an off-line unofficial copy of the questions listed in the comment forms
are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Note that PRC-005-2 reflects the merging of the following standards into a single standard, making it
impractical to post a “redline” of proposed PRC-005-2 that shows the changes to the last balloted version of the
standard.
• PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
• PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
• PRC-011-0 — UVLS System Maintenance and Testing
• PRC-017-0 — Special Protection System Maintenance and Testing
The last approved versions of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 have been posted on the
project’s web page for easy reference at:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Next Steps
The drafting team will consider all comments and will determine whether to make additional changes to the
standard and its implementation plan.
Project Background
The proposed PRC-005-2 – Protection System Maintenance standard addresses FERC directives from FERC
Order 693, as well as issues identified by stakeholders. In accordance with the FERC directives, this draft
standard establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a condition-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect the known and reported
condition of the relevant devices. For a performance-based maintenance program, it ascertains where the
hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant devices.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate. For more information or assistance, please contact Monica Benson at
[email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Project 2007-17 Protection System Maintenance and Testing
Successive Formal Comment Period Open
April 13 – May 12, 2011
Successive Ballot: May 3 – May 12, 2011
Now available at: http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_200717.html
The Protection System Maintenance and Testing drafting team has posted its consideration of comments (those
submitted with a ballot, those submitted with a non-binding poll, and those submitted with a comment form),
and revised PRC-005-2 and its associated implementation plan and VRFs and VSLs in response to feedback
received in comments as well as a quality review. Clean and redline versions of PRC-005-2 — Protection
System Maintenance, clean and redline versions of the associated implementation plan and VRFs and VSLs,
and a revised technical reference document that combines the former supplemental reference and FAQ
documents are posted for a 30-day formal comment period through 8:00 pm Eastern on Thursday, May 12th.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Monica Benson at [email protected].
Documents for this project, including an off-line unofficial copy of the questions listed in the comment forms
are posted at the following site:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Note that PRC-005-2 reflects the merging of the following standards into a single standard, making it
impractical to post a “redline” of proposed PRC-005-2 that shows the changes to the last balloted version of the
standard.
• PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
• PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Program
• PRC-011-0 — UVLS System Maintenance and Testing
• PRC-017-0 — Special Protection System Maintenance and Testing
The last approved versions of PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 have been posted on the
project’s web page for easy reference at:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
Next Steps – Successive Ballot and New, Non-binding Poll of VRFs and VSLs
A successive ballot of the revised standard and its associated implementation plan, and a new non-binding poll
of the revised VRFs and VSLs will be conducted during the last 10 days of the comment period, beginning on
Tuesday, May 3, 2011 through Friday, May 13, 2011.
Project Background
The proposed PRC-005-2 – Protection System Maintenance standard addresses FERC directives from FERC
Order 693, as well as issues identified by stakeholders. In accordance with the FERC directives, this draft
standard establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a condition-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect the known and reported
condition of the relevant devices. For a performance-based maintenance program, it ascertains where the
hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant devices.
Applicability of Standards in Project
Transmission Owners
Generator Owners
Distribution Providers
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Project 2007-17 Protection System Maintenance and Testing
Successive Ballot and Non-binding Poll Results
Now available at: https://standards.nerc.net/Ballots.aspx
A successive ballot on revisions to PRC-005-2 Protection System Maintenance concluded on May 13, 2011,
and a concurrent non-binding poll of associated VRF and VSLs concluded on May 16, 2011. The non-binding
poll was held open past the closing of the ballot to allow a quorum to be achieved.
Ballot Results for Revisions to PRC-005-2
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum: 78.33 %
Approval: 67.00 %
Non-binding Poll Results for Associated VRF and VSLs
Of those who registered to participate, 75% provided an opinion or an abstention; 66% of those who provided an
opinion indicated support for the VRFs and VSLs that were proposed.
Next Steps
The drafting team will consider all comments received during the formal comment period, ballot, and nonbinding poll, and will determine whether to make additional changes to the standard and its implementation
plan and associated VRFs and VSLs. If the team makes substantive changes to address issues raised in
comments, an additional 30-day formal comment period will be conducted with a successive ballot during the
last 10 days of the comment period. If the team makes only minor clarifying changes to address issues
identified in comments, a recirculation ballot may be conducted.
Background:
The proposed PRC-005-2 – Protection System Maintenance standard addresses FERC directives from FERC
Order 693, as well as issues identified by stakeholders. In accordance with the FERC directives, this draft
standard establishes requirements for a time-based maintenance program, where all relevant devices are
maintained according to prescribed maximum intervals. It further establishes requirements for a condition-based
maintenance program, where the hands-on maintenance intervals are adjusted to reflect the known and reported
condition of the relevant devices. For a performance-based maintenance program, it ascertains where the
hands-on maintenance intervals are adjusted to reflect the historical performance of the relevant devices.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-17 PRC-005-2 SB_in
Password
Ballot Period: 5/3/2011 - 5/13/2011
Ballot Type: Initial
Log in
Total # Votes: 253
Register
Total Ballot Pool: 323
Quorum: 78.33 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
67.00 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
89
9
71
24
68
38
0
11
6
7
323
#
Votes
1
0.6
1
1
1
1
0
0.8
0.5
0.6
7.5
#
Votes
Fraction
46
4
38
11
23
17
0
5
5
6
155
Negative
No
# Votes Vote
Fraction
0.687
0.4
0.704
0.5
0.548
0.586
0
0.5
0.5
0.6
5.025
Abstain
21
2
16
11
19
12
0
3
0
0
84
0.313
0.2
0.296
0.5
0.452
0.414
0
0.3
0
0
2.475
4
1
1
1
4
1
0
1
1
0
14
18
2
16
1
22
8
0
2
0
1
70
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Baltimore Gas & Electric Company
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Robert D Smith
John Bussman
Scott Kinney
John J. Moraski
https://standards.nerc.net/BallotResults.aspx?BallotGUID=9c9d4dca-0b4b-4787-81c7-cd57d1fde4bb[5/18/2011 2:57:57 PM]
Ballot
Comments
Affirmative
Affirmative
Negative
Negative
Negative
View
View
View
View
View
Affirmative
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnesota Power, Inc.
National Grid
Nebraska Public Power District
New York Power Authority
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Ronald D. Schellberg
Michael Moltane
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
Doug Bantam
Robert Ganley
Martyn Turner
Joe D Petaski
Ernest Hahn
Terry Harbour
Randi Woodward
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Brad Chase
Lawrence R. Larson
Chifong Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
David Thorne
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Chad Bowman
Catherine Koch
Tim Kelley
Robert Kondziolka
Terry L. Blackwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=9c9d4dca-0b4b-4787-81c7-cd57d1fde4bb[5/18/2011 2:57:57 PM]
Affirmative
Negative
Negative
Negative
View
View
Negative
Affirmative
Affirmative
Negative
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
Negative
View
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
View
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Arizona Public Service Co.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Leesburg
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Faramarz Amjadi
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L. Marshall
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Thomas R. Glock
James V. Petrella
Pat G. Harrington
Rebecca Berdahl
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C. Parent
Steven Grego
Thomas C. Mielnik
https://standards.nerc.net/BallotResults.aspx?BallotGUID=9c9d4dca-0b4b-4787-81c7-cd57d1fde4bb[5/18/2011 2:57:57 PM]
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
View
View
View
View
View
View
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
View
View
View
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salem Electric
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Tri-State G & T Association, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
Y-W Electric Association, Inc.
AEP Service Corp.
Amerenue
APS
Avista Corp.
Black Hills Corp
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Don Horsley
Steven M. Jackson
John S Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David T. Anderson
Ballard Keith Mutters
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Anthony Schacher
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
David Schiada
Jeff Nelson
Ronald L Donahey
Janelle Marriott
James R. Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Timothy Beyrle
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
Affirmative
Affirmative
Negative
Affirmative
Abstain
View
Affirmative
Negative
View
View
Affirmative
Negative
Negative
Affirmative
Negative
View
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
John D. Martinsen
Affirmative
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Affirmative
Affirmative
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Christopher Plante
Joseph G. DePoorter
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
James A Ziebarth
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
George Tatar
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
Amir Y Hammad
View
View
View
View
View
View
View
View
View
Negative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Abstain
View
Affirmative
Negative
View
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
Consumers Energy
Cowlitz County PUD
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Entergy Corporation
FirstEnergy Solutions
Florida Municipal Power Agency
Green Country Energy
Horizon Wind Energy
Indeck Energy Services, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
New Harquahala Generating Co. LLC
New York Power Authority
Northern Indiana Public Service Co.
Otter Tail Power Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Public Utility District No. 1 of Lewis County
Reedy Creek Energy Services
RRI Energy
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Centralia Generation, LLC
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
James B Lewis
Bob Essex
Mike Garton
Robert Smith
Dan Roethemeyer
Stephen Ricker
Negative
Affirmative
Affirmative
View
Affirmative
Affirmative
Doug Ramey
Kenneth Parker
Stanley M Jaskot
Kenneth Dresner
David Schumann
Greg Froehling
Brent Hebert
Rex A Roehl
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Daniel Duff
Dennis Florom
Charlie Martin
Mike Laney
Mark Aikens
David Gordon
Nicholas Q Hayes
Gerald Mannarino
Michael K Wilkerson
Stacie Hebert
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A Heimbach
Wayne Lewis
Jerzy A Slusarz
Steven Grega
Bernie Budnik
Thomas J. Bradish
Bethany Hunter
Glen Reeves
Daniel Baerman
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Richard Jones
Jerry W Johnson
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Joanna Luong-Tran
Barry Ingold
Melissa Kurtz
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
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Affirmative
View
Affirmative
Negative
Affirmative
View
View
Negative
View
Negative
Negative
View
Affirmative
Negative
View
View
Abstain
Affirmative
View
Affirmative
View
Negative
Affirmative
Affirmative
Negative
Negative
View
View
Affirmative
Negative
Negative
View
View
Affirmative
Negative
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
View
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Energy
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
OTP Wholesale Marketing
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Ascendant Energy Services, LLC
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
SPS Consulting Group Inc.
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daryn Barker
Brad Jones
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
David Ried
Bruce Glorvigen
Carol Ballantine
John T Sturgeon
James D. Hebson
Hugh A. Owen
Trent Carlson
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
View
View
View
Affirmative
Negative
Affirmative
View
Affirmative
Negative
View
View
Negative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
View
Negative
Negative
Abstain
View
View
Negative
View
David F. Lemmons
James A Maenner
Merle Ashton
Roger C Zaklukiewicz
Kristina M. Loudermilk
Raymond Tran
Jim D. Cyrulewski
Margaret Ryan
Peggy Abbadini
Jim R Stanton
Brian Evans-Mongeon
Terry Volkmann
William Mitchell Chamberlain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
Negative
Negative
View
Affirmative
Affirmative
Negative
Affirmative
View
Donald E. Nelson
Affirmative
Diane J. Barney
Affirmative
Jerome Murray
Philip Riley
Ric Campbell
Linda Campbell
Dan R Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B. Edge
Louise McCarren
Abstain
Affirmative
Affirmative
Affirmative
John Stonebarger
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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NERC Standards
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A New Jersey Nonprofit Corporation
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Ballot Results
Non-Binding Poll
Project 2007-17 PRC-005-2 Non-binding poll VRFs and VSLs_in
Name:
Poll Period: 5/3/2011 - 5/15/2011
Total # Opinions: 172
Total Ballot Pool: 351
75% of those who registered to participate provided an opinion or
Summary Results: abstention; 66% of those who provided an opinion indicated support for the
VRFs and VSLs that were proposed.
Individual Ballot Pool Results
Segment
Organization
Member
Opinions
1
Allegheny Power
Rodney Phillips
1
Ameren Services
Kirit S. Shah
1
American Electric Power
Paul B. Johnson
1
American Transmission Company,
LLC
Jason Shaver
Abstain
1
Arizona Public Service Co.
Robert D Smith
Abstain
1
Associated Electric Cooperative,
Inc.
John Bussman
Abstain
1
Avista Corp.
Scott Kinney
1
Baltimore Gas & Electric Company
John J. Moraski
Abstain
1
BC Transmission Corporation
Gordon Rawlings
Abstain
1
Beaches Energy Services
Joseph S.
Stonecipher
1
Black Hills Corp
Eric Egge
1
Bonneville Power Administration
Donald S. Watkins
1
CenterPoint Energy
Paul Rocha
1
Central Maine Power Company
Brian Conroy
Comments
Abstain
Negative
Negative
View
View
Abstain
Negative
1
1
City of Vero Beach
1
City Utilities of Springfield, Missouri Jeff Knottek
Affirmative
1
Clark Public Utilities
Jack Stamper
Affirmative
1
Cleco Power LLC
Danny McDaniel
1
Colorado Springs Utilities
Paul Morland
1
Commonwealth Edison Co.
Daniel Brotzman
1
Consolidated Edison Co. of New
York
Christopher L de
Graffenried
Affirmative
1
Dairyland Power Coop.
Robert W. Roddy
Abstain
1
Dayton Power & Light Co.
Hertzel Shamash
Affirmative
1
Deseret Power
James Tucker
Abstain
1
Dominion Virginia Power
John K Loftis
Abstain
1
Duke Energy Carolina
Douglas E. Hils
Affirmative
1
East Kentucky Power Coop.
George S. Carruba
Affirmative
1
Empire District Electric Co.
Ralph Frederick
Meyer
Affirmative
1
Entergy Corporation
George R. Bartlett
1
FirstEnergy Energy Delivery
Robert Martinko
1
Florida Keys Electric Cooperative
Assoc.
Dennis Minton
Negative
1
Gainesville Regional Utilities
Luther E. Fair
Abstain
1
GDS Associates, Inc.
Claudiu Cadar
Negative
1
Georgia Transmission Corporation
Harold Taylor, II
Affirmative
1
Great River Energy
Gordon Pietsch
Affirmative
1
Hydro One Networks, Inc.
Ajay Garg
Affirmative
1
Idaho Power Company
Ronald D. Schellberg
Affirmative
1
International Transmission
Randall McCamish
Michael Moltane
Negative
Abstain
View
View
Affirmative
View
Abstain
2
Company Holdings Corp
1
Kansas City Power & Light Co.
Michael Gammon
Affirmative
1
Keys Energy Services
Stan T. Rzad
Negative
1
Lake Worth Utilities
Walt Gill
Negative
1
Lakeland Electric
Larry E Watt
Negative
1
Lee County Electric Cooperative
John W Delucca
Negative
1
Lincoln Electric System
Doug Bantam
Affirmative
1
Long Island Power Authority
Robert Ganley
Affirmative
1
Lower Colorado River Authority
Martyn Turner
Affirmative
1
Manitoba Hydro
Joe D Petaski
Negative
1
Metropolitan Water District of
Southern California
Ernest Hahn
Abstain
1
MidAmerican Energy Co.
Terry Harbour
Abstain
1
National Grid
Saurabh Saksena
1
Nebraska Public Power District
Richard L. Koch
1
New York Power Authority
Arnold J. Schuff
Affirmative
1
Northeast Utilities
David H. Boguslawski
Affirmative
1
NorthWestern Energy
John Canavan
Affirmative
1
Ohio Valley Electric Corp.
Robert Mattey
Affirmative
1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
1
Omaha Public Power District
Douglas G
Peterchuck
1
Oncor Electric Delivery
Michael T. Quinn
1
Orlando Utilities Commission
Brad Chase
1
Otter Tail Power Company
Lawrence R. Larson
1
Pacific Gas and Electric Company
Chifong Thomas
View
Abstain
Affirmative
Affirmative
3
1
PacifiCorp
Mark Sampson
1
PECO Energy
Ronald Schloendorn
Affirmative
1
Platte River Power Authority
John C. Collins
Affirmative
1
Portland General Electric Co.
Frank F. Afranji
Affirmative
1
Potomac Electric Power Co.
David Thorne
Affirmative
1
PowerSouth Energy Cooperative
Larry D. Avery
Negative
1
PPL Electric Utilities Corp.
Brenda L Truhe
Abstain
1
Public Service Company of New
Mexico
Laurie Williams
1
Public Service Electric and Gas Co.
Kenneth D. Brown
1
Public Utility District No. 1 of Chelan
Chad Bowman
County
1
Puget Sound Energy, Inc.
1
Sacramento Municipal Utility District Tim Kelley
1
Salt River Project
Robert Kondziolka
Affirmative
1
Santee Cooper
Terry L. Blackwell
Negative
1
SCE&G
Henry Delk, Jr.
Abstain
1
Seattle City Light
Pawel Krupa
Abstain
1
South Texas Electric Cooperative
Richard McLeon
1
Southern California Edison Co.
Dana Cabbell
Affirmative
1
Southern Company Services, Inc.
Horace Stephen
Williamson
Affirmative
1
Southern Illinois Power Coop.
William G. Hutchison
1
Southwest Transmission
Cooperative, Inc.
James L. Jones
1
Southwestern Power Administration Gary W Cox
1
Sunflower Electric Power
Corporation
View
Abstain
Abstain
Catherine Koch
Noman Lee Williams
View
Negative
View
Negative
Affirmative
Affirmative
4
1
Tennessee Valley Authority
Larry Akens
Affirmative
1
Tri-State G & T Association, Inc.
Keith V Carman
1
Tucson Electric Power Co.
John Tolo
Affirmative
1
United Illuminating Co.
Jonathan Appelbaum
Affirmative
1
Westar Energy
Allen Klassen
1
Western Area Power Administration Brandy A Dunn
1
Xcel Energy, Inc.
Gregory L Pieper
2
Alberta Electric System Operator
Jason L. Murray
2
BC Transmission Corporation
Faramarz Amjadi
2
Electric Reliability Council of Texas,
Chuck B Manning
Inc.
2
Independent Electricity System
Operator
Kim Warren
2
ISO New England, Inc.
Kathleen Goodman
2
Midwest ISO, Inc.
Jason L. Marshall
2
New York Independent System
Operator
Gregory Campoli
Abstain
2
PJM Interconnection, L.L.C.
Tom Bowe
Abstain
2
Southwest Power Pool
Charles H Yeung
Abstain
3
Alabama Power Company
Richard J. Mandes
3
Allegheny Power
Bob Reeping
3
Ameren Services
Mark Peters
3
American Electric Power
Raj Rana
3
Arizona Public Service Co.
Thomas R. Glock
3
Atlantic City Electric Company
James V. Petrella
Affirmative
3
BC Hydro and Power Authority
Pat G. Harrington
Abstain
3
Blachly-Lane Electric Co-op
Bud Tracy
Abstain
Abstain
Affirmative
Negative
Affirmative
View
View
Abstain
5
3
Bonneville Power Administration
Rebecca Berdahl
Abstain
3
Central Electric Cooperative, Inc.
(Redmond, Oregon)
Dave Markham
Abstain
3
Central Lincoln PUD
Steve Alexanderson
Abstain
3
City of Bartow, Florida
Matt Culverhouse
Negative
3
City of Clewiston
Lynne Mila
Negative
3
City of Farmington
Linda R. Jacobson
Negative
View
3
City of Green Cove Springs
Gregg R Griffin
Negative
View
3
City of Leesburg
Phil Janik
3
Clearwater Power Co.
Dave Hagen
3
Cleco Utility Group
Bryan Y Harper
3
ComEd
Bruce Krawczyk
Affirmative
3
Consolidated Edison Co. of New
York
Peter T Yost
Affirmative
3
Consumers Energy
David A. Lapinski
Affirmative
3
Consumers Power Inc.
Roman Gillen
3
Coos-Curry Electric Cooperative, Inc Roger Meader
3
Cowlitz County PUD
Russell A Noble
Affirmative
3
Delmarva Power & Light Co.
Michael R. Mayer
Affirmative
3
Detroit Edison Company
Kent Kujala
3
Dominion Resources Services
Michael F Gildea
Abstain
3
Douglas Electric Cooperative
Dave Sabala
Abstain
3
Duke Energy Carolina
Henry Ernst-Jr
Affirmative
3
East Kentucky Power Coop.
Sally Witt
Affirmative
3
Entergy
Joel T Plessinger
3
Fall River Rural Electric Cooperative Bryan Case
Abstain
View
Abstain
Abstain
Negative
Negative
Abstain
6
3
FirstEnergy Solutions
Kevin Querry
Affirmative
3
Florida Power Corporation
Lee Schuster
Affirmative
3
Gainesville Regional Utilities
Kenneth Simmons
Affirmative
3
Georgia Power Company
Anthony L Wilson
Affirmative
3
Georgia System Operations
Corporation
R Scott S. BarfieldMcGinnis
3
Great River Energy
Sam Kokkinen
Affirmative
3
Gulf Power Company
Gwen S Frazier
Affirmative
3
Hydro One Networks, Inc.
Michael D. Penstone
Affirmative
3
JEA
Garry Baker
Affirmative
3
Kansas City Power & Light Co.
Charles Locke
Affirmative
3
Kissimmee Utility Authority
Gregory David
Woessner
Negative
3
Lakeland Electric
Mace Hunter
Affirmative
3
Lane Electric Cooperative, Inc.
Rick Crinklaw
Abstain
3
Lincoln Electric Cooperative, Inc.
Michael Henry
Abstain
3
Lincoln Electric System
Bruce Merrill
3
Los Angeles Department of Water &
Kenneth Silver
Power
3
Lost River Electric Cooperative
Richard Reynolds
3
Louisville Gas and Electric Co.
Charles A. Freibert
3
Manitoba Hydro
Greg C. Parent
3
MEAG Power
Steven Grego
3
MidAmerican Energy Co.
Thomas C. Mielnik
3
Mississippi Power
Don Horsley
Affirmative
3
Municipal Electric Authority of
Georgia
Steven M. Jackson
Affirmative
View
View
Affirmative
Abstain
Negative
View
Abstain
View
7
3
Muscatine Power & Water
John S Bos
Affirmative
3
New York Power Authority
Marilyn Brown
Affirmative
3
Niagara Mohawk (National Grid
Company)
Michael Schiavone
Affirmative
3
North Carolina Municipal Power
Agency #1
Denise Roeder
3
Northern Indiana Public Service Co. William SeDoris
3
Northern Lights Inc.
Jon Shelby
3
Ocala Electric Utility
David T. Anderson
3
Okanogan County Electric
Cooperative, Inc.
Ray Ellis
Abstain
3
Orlando Utilities Commission
Ballard Keith Mutters
Abstain
3
OTP Wholesale Marketing
Bradley Tollerson
3
PacifiCorp
John Apperson
3
PECO Energy an Exelon Co.
Vincent J. Catania
3
Platte River Power Authority
Terry L Baker
Affirmative
3
Potomac Electric Power Co.
Robert Reuter
Affirmative
3
Progress Energy Carolinas
Sam Waters
3
Public Service Electric and Gas Co.
Jeffrey Mueller
3
Public Utility District No. 1 of Chelan
Kenneth R. Johnson
County
3
Public Utility District No. 2 of Grant
Greg Lange
County
3
Raft River Rural Electric Cooperative Heber Carpenter
3
Sacramento Municipal Utility District James Leigh-Kendall
3
Salem Electric
Anthony Schacher
3
Salmon River Electric Cooperative
Ken Dizes
3
Salt River Project
John T. Underhill
Abstain
Negative
View
Abstain
Abstain
Abstain
Affirmative
Negative
View
Abstain
Affirmative
Abstain
Affirmative
8
3
San Diego Gas & Electric
Scott Peterson
3
Santee Cooper
Zack Dusenbury
3
Seattle City Light
Dana Wheelock
3
South Mississippi Electric Power
Association
Gary Hutson
3
Southern California Edison Co.
David Schiada
3
Springfield Utility Board
Jeff Nelson
3
Tampa Electric Co.
Ronald L Donahey
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
Umatilla Electric Cooperative
Steve Eldrige
Abstain
3
West Oregon Electric Cooperative,
Inc.
Marc Farmer
Abstain
3
Wisconsin Electric Power Marketing James R. Keller
3
Wisconsin Public Service Corp.
Gregory J Le Grave
3
Xcel Energy, Inc.
Michael Ibold
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Negative
4
American Municipal Power
Kevin Koloini
Negative
4
American Public Power Association
Allen Mosher
Affirmative
4
City of Clewiston
Kevin McCarthy
Negative
4
City of New Smyrna Beach Utilities
Timothy Beyrle
Commission
Negative
4
Consumers Energy
David Frank Ronk
Affirmative
4
Cowlitz County PUD
Rick Syring
Affirmative
4
Detroit Edison Company
Daniel Herring
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
Fort Pierce Utilities Authority
Thomas W. Richards
4
Georgia System Operations
Guy Andrews
Abstain
Affirmative
Abstain
Affirmative
View
Abstain
Abstain
View
View
Affirmative
9
Corporation
4
Illinois Municipal Electric Agency
Bob C. Thomas
Abstain
4
Integrys Energy Group, Inc.
Christopher Plante
Abstain
4
Madison Gas and Electric Co.
Joseph G. DePoorter
Abstain
4
Ohio Edison Company
Douglas Hohlbaugh
Affirmative
4
Old Dominion Electric Coop.
Mark Ringhausen
Abstain
4
Public Utility District No. 1 of
Douglas County
Henry E. LuBean
Affirmative
4
Public Utility District No. 1 of
Snohomish County
John D. Martinsen
Affirmative
4
Sacramento Municipal Utility District Mike Ramirez
4
Seattle City Light
4
Seminole Electric Cooperative, Inc. Steven R Wallace
4
South Mississippi Electric Power
Association
Steve McElhaney
4
Wisconsin Energy Corp.
Anthony Jankowski
Abstain
4
Y-W Electric Association, Inc.
James A Ziebarth
Abstain
5
AEP Service Corp.
Brock Ondayko
5
Amerenue
Sam Dwyer
Abstain
5
APS
Mel Jensen
Abstain
5
Avista Corp.
Edward F. Groce
Abstain
5
BC Hydro and Power Authority
Clement Ma
Abstain
5
Black Hills Corp
George Tatar
5
Bonneville Power Administration
Francis J. Halpin
5
Chelan County Public Utility District
John Yale
#1
Abstain
5
City of Grand Island
Abstain
Hao Li
Jeff Mead
Abstain
Abstain
Negative
Negative
View
Affirmative
Abstain
10
5
City of Tallahassee
Alan Gale
Negative
5
City Water, Light & Power of
Springfield
Karl E. Kohlrus
5
Consolidated Edison Co. of New
York
Wilket (Jack) Ng
Affirmative
5
Constellation Power Source
Generation, Inc.
Amir Y Hammad
Negative
5
Consumers Energy
James B Lewis
Negative
5
Cowlitz County PUD
Bob Essex
5
Dominion Resources, Inc.
Mike Garton
5
Duke Energy
Robert Smith
5
Dynegy Inc.
Dan Roethemeyer
Affirmative
5
East Kentucky Power Coop.
Stephen Ricker
Affirmative
5
Energy Northwest - Columbia
Generating Station
Doug Ramey
5
Entegra Power Group, LLC
Kenneth Parker
5
Entergy Corporation
Stanley M Jaskot
5
Exelon Nuclear
Michael Korchynsky
5
ExxonMobil Research and
Engineering
Martin Kaufman
Negative
5
FirstEnergy Solutions
Kenneth Dresner
Affirmative
5
Florida Municipal Power Agency
David Schumann
Negative
5
Great River Energy
Cynthia E Sulzer
5
Green Country Energy
Greg Froehling
5
Horizon Wind Energy
Brent Hebert
5
Indeck Energy Services, Inc.
Rex A Roehl
5
JEA
Donald Gilbert
5
Kansas City Power & Light Co.
Scott Heidtbrink
View
View
Affirmative
Abstain
Abstain
Affirmative
View
Affirmative
Negative
View
Affirmative
11
5
Kissimmee Utility Authority
Mike Blough
5
Lakeland Electric
Thomas J Trickey
5
Liberty Electric Power LLC
Daniel Duff
5
Lincoln Electric System
Dennis Florom
5
Louisville Gas and Electric Co.
Charlie Martin
5
Luminant Generation Company LLC Mike Laney
5
Manitoba Hydro
5
Massachusetts Municipal Wholesale
David Gordon
Electric Company
5
New Harquahala Generating Co.
LLC
Nicholas Q Hayes
5
New York Power Authority
Gerald Mannarino
5
Northern Indiana Public Service Co. Michael K Wilkerson
5
Otter Tail Power Company
Stacie Hebert
5
Pacific Gas and Electric Company
Richard J. Padilla
Affirmative
5
PacifiCorp
Sandra L. Shaffer
Abstain
5
Portland General Electric Co.
Gary L Tingley
5
PowerSouth Energy Cooperative
Tim Hattaway
5
PPL Generation LLC
Mark A Heimbach
5
Progress Energy Carolinas
Wayne Lewis
5
PSEG Power LLC
Jerzy A Slusarz
5
Public Utility District No. 1 of Lewis
Steven Grega
County
Negative
5
Reedy Creek Energy Services
Bernie Budnik
Negative
5
RRI Energy
Thomas J. Bradish
5
Sacramento Municipal Utility District Bethany Hunter
5
Salt River Project
Mark Aikens
Glen Reeves
Negative
Negative
View
Affirmative
View
Negative
View
Abstain
Affirmative
Abstain
Abstain
Affirmative
12
5
San Diego Gas & Electric
Daniel Baerman
5
Santee Cooper
Lewis P Pierce
Negative
View
5
Seattle City Light
Michael J. Haynes
Negative
View
5
Seminole Electric Cooperative, Inc. Brenda K. Atkins
5
South Carolina Electric & Gas Co.
Richard Jones
5
South Mississippi Electric Power
Association
Jerry W Johnson
5
Southern Company Generation
William D Shultz
5
SRW Cogeneration Limited
Partnership
Michael Albosta
5
Tampa Electric Co.
RJames Rocha
Negative
5
Tenaska, Inc.
Scott M. Helyer
Abstain
5
Tennessee Valley Authority
George T. Ballew
5
TransAlta Centralia Generation, LLC Joanna Luong-Tran
5
Tri-State G & T Association, Inc.
Barry Ingold
Affirmative
5
U.S. Army Corps of Engineers
Melissa Kurtz
Affirmative
5
U.S. Bureau of Reclamation
Martin Bauer P.E.
Affirmative
5
Wisconsin Electric Power Co.
Linda Horn
5
Wisconsin Public Service Corp.
Leonard Rentmeester
5
Xcel Energy, Inc.
Liam Noailles
6
AEP Marketing
Edward P. Cox
6
Ameren Energy Marketing Co.
Jennifer Richardson
Abstain
6
Bonneville Power Administration
Brenda S. Anderson
Abstain
6
Cleco Power LLC
Matthew D Cripps
6
Consolidated Edison Co. of New
York
Nickesha P Carrol
6
Constellation Energy Commodities
Brenda Powell
Affirmative
Affirmative
Abstain
View
Abstain
Affirmative
Negative
Affirmative
View
View
Abstain
13
Group
6
Dominion Resources, Inc.
Louis S. Slade
Abstain
6
Duke Energy Carolina
Walter Yeager
Affirmative
6
Entergy Services, Inc.
Terri F Benoit
6
Eugene Water & Electric Board
Daniel Mark Bedbury
Affirmative
6
Exelon Power Team
Pulin Shah
Affirmative
6
FirstEnergy Solutions
Mark S Travaglianti
Affirmative
6
Florida Municipal Power Pool
Thomas E Washburn
Negative
6
Florida Power & Light Co.
Silvia P. Mitchell
6
Great River Energy
Donna Stephenson
6
Kansas City Power & Light Co.
Thomas Saitta
6
Lakeland Electric
Paul Shipps
6
Lincoln Electric System
Eric Ruskamp
6
Louisville Gas and Electric Co.
Daryn Barker
6
Luminant Energy
Brad Jones
6
Manitoba Hydro
Daniel Prowse
6
New York Power Authority
Thomas
Papadopoulos
6
Northern Indiana Public Service Co. Joseph O'Brien
6
Omaha Public Power District
David Ried
6
OTP Wholesale Marketing
Bruce Glorvigen
6
Platte River Power Authority
Carol Ballantine
Affirmative
6
Progress Energy
John T Sturgeon
Affirmative
6
PSEG Energy Resources & Trade
LLC
James D. Hebson
Abstain
6
Public Utility District No. 1 of Chelan
Hugh A. Owen
County
View
Abstain
Negative
Affirmative
Affirmative
View
Negative
View
Negative
View
Affirmative
Abstain
14
6
RRI Energy
Trent Carlson
6
Santee Cooper
Suzanne Ritter
Negative
View
6
Seattle City Light
Dennis Sismaet
Negative
View
6
Seminole Electric Cooperative, Inc. Trudy S. Novak
6
South Carolina Electric & Gas Co.
Matt H Bullard
6
Tennessee Valley Authority
Marjorie S. Parsons
6
Western Area Power Administration
John Stonebarger
- UGP Marketing
6
Xcel Energy, Inc.
Abstain
Affirmative
David F. Lemmons
8
Roger C Zaklukiewicz
Affirmative
8
James A Maenner
8
Merle Ashton
Affirmative
8
Kristina M.
Loudermilk
Affirmative
Abstain
8
Ascendant Energy Services, LLC
Raymond Tran
8
JDRJC Associates
Jim D. Cyrulewski
Abstain
8
Pacific Northwest Generating
Cooperative
Margaret Ryan
Abstain
8
Power Energy Group LLC
Peggy Abbadini
8
SPS Consulting Group Inc.
Jim R Stanton
8
Utility Services, Inc.
Brian EvansMongeon
8
Volkmann Consulting, Inc.
Terry Volkmann
Negative
9
California Energy Commission
William Mitchell
Chamberlain
Affirmative
9
Commonwealth of Massachusetts
Department of Public Utilities
Donald E. Nelson
Affirmative
9
National Association of Regulatory
Utility Commissioners
Diane J. Barney
Affirmative
View
Affirmative
Abstain
15
9
North Carolina Utilities Commission Kimberly J. Jones
9
Oregon Public Utility Commission
9
Public Service Commission of South
Philip Riley
Carolina
Affirmative
9
Utah Public Service Commission
Ric Campbell
Affirmative
10
Florida Reliability Coordinating
Council
Linda Campbell
10
Midwest Reliability Organization
Dan R Schoenecker
10
New York State Reliability Council
Alan Adamson
Affirmative
10
Northeast Power Coordinating
Council, Inc.
Guy V. Zito
Affirmative
10
ReliabilityFirst Corporation
Jacquie Smith
Negative
10
SERC Reliability Corporation
Carter B. Edge
Abstain
10
Western Electricity Coordinating
Council
Louise McCarren
Jerome Murray
Abstain
Negative
View
View
16
Individual or group. (55 Responses)
Name (33 Responses)
Organization (33 Responses)
Group Name (22 Responses)
Lead Contact (22 Responses)
Question 1 (47 Responses)
Question 1 Comments (55 Responses)
Question 2 (45 Responses)
Question 2 Comments (55 Responses)
Question 3 (38 Responses)
Question 3 Comments (55 Responses)
Question 4 (40 Responses)
Question 4 Comments (55 Responses)
Question 5 (0 Responses)
Question 5 Comments (55 Responses)
Individual
Robert W. Kenyon
NERC - EA & I
Recommend entities be explictly required to document the Relay Maintenance Program in one
document. Many entities presently maintain their Protection Maintenace Program in several
documents, such as one for relays, one for batteries, etc. This complicates compliance review and
contributes to non-compliance since personnel in diffeernt departments writing these have different
levels of understanding of NERC standards. Separate documents also allow inconsistencies to slip in.
Recommend Requirement 1 to changed to the following to address this problem. "Each Transmission
Owner, Generator Owner, and Distribution Provider shall establish a Protection System Maintenance
Program (PSMP), RECORDED AND UPDATED AS A SINGLE DOCUMNET for its Protection Systems
designed to provide protection for BES Element(s). "
Individual
Daniel Duff
Liberty Electric Power LLC
Yes
Yes
No
See comments at end.
Apologies to the drafting team for submitting this with the ballot, repeated here to insure the
comments are captured and addressed. While the SDT has done a very good job at responding to the
most objectionable parts of the previous version, there are still a number of issues which makes the
standard problematic. 1. The standard introduces the term "initiate resolution". This is an
interpretable term, and has the potential for an auditor and an entity to disagree on an action. Would
issuing a work order be considered "initiating resolution"? What if the WO had a completion date
many years into the future? I would suggest adding the term to the list of definitions which will
remain with the standard, and defining it as "preforming any task associated with conducting
maintenance activities, including but not limited to issuing purchase orders, soliciting bids, scheduling
tasks, issuing work requests, and performing studies". 2. Some clarity is needed to differentiate
system connected and generator connected station service transformers. A statement that a station
service transformer connected radially to the generator bus is considered a system connected
transformer if the transformer cannot be used for service unless connected to the BES. 3. The
"bookends" issue, brought up in the prior round of comments, still exists. Although the SDT rightly
notes a CAN has been issued regarding bookends, the CAN covers the documentation for system
components that entities were required to self-certify to on June 18, 2007. PRC-005-2 adds additional
components to the protection system scheme which were not part of that certification, and has the
potential to put entities into violation space due to a lack of records for those components. The SDT
should add to M3 a statement that entities may demonstrate compliance with the standard by
demonstrating that required activities took place twice within the maximum maintenance interval starting from the effective date of the standard - for all components not listed in PRC-005-1.
Group
Northeast Power Coordinating Council
Guy Zito
Yes
Yes
Yes
Yes
Suggest that to FAQ be added: 1. Regarding Table 2 in the standard, does a fail-safe “form b” contact
that is alarmed to a 24/7 operation center qualify as an alarm path with monitoring? 2. Add a
clarification as part of the FAQ document that defines whether the control circuitry and trip coil of a
non-BES breaker, tripped via a BES protection component, must be tested as per Table 1.5.
Group
MISO Standards Collaborators
Marie Knox
Yes
Yes, however, in the “Supplemental reference and FAQ” document on page 65 there are two areas of
concern. Page 65, paragraph 4: “… the type of test equipment used to establish the baseline must be
used for any future trending of the cells internal ohmic measurements because of variances in test
equipment and the type of ohmic measurement used by different manufacturer’s equipment.” While
we understand the importance of creating a baseline, it is not feasible to expect the test equipment
be the same as the manufacturer’s test equipment or even the same test equipment over the life of
the battery. The expected life of a battery may be in excess of 20 years and it is not feasible to
expect that the type of equipment will not change during this period. On Page 65, paragraph 6, it
states: “… all manufacturers of internal ohmic measurement devices have established libraries of
baseline values …” We question the availability of baseline libraries for all manufacturers considering
the variety and longevity of installations.
Yes
Yes
Yes
The additional documentation seems to be quite large, and the additional content seems to go far
beyond what is necessary for the PRC-005-2 standard. We recommend the SDT lessen the amount of
content provided in the “Supplementary Reference” document.
R3 speaks of a Maintenance Correctable Issue and implementing your Protection System Maintenance
Program (PSMP). In the definition of Maintenance Correctable Issue, it states "...of the initial on-site
activity". The intent seems to be that during any maintenance activity, and something is found not
working properly, you should repair it. Some may look at the word "initial" as during the
commissioning of a facility. We recommend the SDT delete the word "initial" to cause less confusion.
We recommend the SDT change the text of “Standard PRC-005-2 – Protection System Maintenance”
Table 1-5 on page 19, Row 1, Column 3 to “Verify that each a trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.” Or alternately, “Electrically operate each
interrupting device every 6 years”. Trip coils are designed to be energized no longer than the breaker
opening time (3-5 cycles). They are robust devices that will successfully operate the breaker for
5,000-10,000 electrical operations. The most likely source of trip coil failure is the breaker operating
mechanism binding, thereby preventing the breaker auxiliary stack from opening and keeping the trip
coil energized for too long of a time period. Therefore, trip coil failure is a function of the breaker
mechanism failure. Exercising the breakers and circuit switchers is an excellent practice. We would
encourage language that would suggest this task be done every 2 years, not to exceed 3 years.
Exercising the interrupting devices would help eliminate mechanism binding, reducing the chance that
the trip coils are energized too long. The language as currently written in Table 1-5, Row 1, will also
have the unintentional effect of changing an entities existing interrupting device maintenance interval
(essentially driving interrupting device testing to a less than 6 year cycle). We recommend the SDT
change the text of “Standard PRC-005-2 – Protection System Maintenance” Table 1-5 on page 19,
Row 3, Column 2 to “12 calendar years”. The maximum maintenance interval for “Electromechanical
lockout and/or tripping devices which are directly in a trip path from the protective relay to the
interrupting device trip coil” should be consistent with the “Unmonitored control circuit” interval which
is 12 calendar years. In order to test the lockout relays, it may be necessary to take a bus outage
(due to lack of redundancy and associated stability issues with delayed clearing). Increasing the
frequency of bus outages (with associated lines or transformers) will also increase the amount of time
that the BES is in a less intact system configuration. Increasing the time the BES is in a less intact
system configuration also increases the probability of a low frequency, high impact event occurring.
Therefore, the Maximum Maintenance Interval should be 12 years for lockout relays. We recognize
the substantial efforts and improvements to PRC-005-2 that have been made and appreciate the
dedicated work of the SDT. We appreciate the removal of Requirement R1.5 and R4 and other
clarifications from draft 3. Our remaining concern for PRC-005-2 is with definition and timelines
established in Table 1-5. We believe that, as written, the testing of “each” trip coil and the proposed
maintenance interval for lockout testing will result in the increased amount of time that the BES is in
a less intact system configuration. We hope that the SDT will consider these changes.
Group
Electric Market Policy
Mike Garton
Yes
Yes
No
IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not
maximums. An entity wishing to avoid non-compliance for an interval that might extend past three
calendar months must implement a policy of two months with one month of grace period thereby
increasing the number of inspections each year by half again. This is unnecessarily frequent. We
suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, Dominion suggests that all battery maintenance intervals expressed as 3 calendar
months be changed to 4 calendar months.
Group
Luminant
David Youngblood
Yes
No comments.
Yes
No comments.
Yes
No comments.
Yes
The document was valuable in understanding PRC-005-2 by providing clarification using practical
protective relay system examples. Below are two comments for further improvement. 1. It would be
beneficial if the document could provide additional information for relaying in the high-voltage
switchyard (transmission owned) - power plant (generation owned) interface. While Figures 1 and 2
are typical generation and transmission relay diagrams, it would be helpful if protective relays
typically used in the interface also be included. For example, a transmission bus differential would
remove a generator from service by tripping the generator lockout. 2. Figures 1 and 2 refer to a
“Figure 1 and 2 Legend” table which provides additional information on qualifications for relay
components. Should a footnote be used to point toward Reference 1 (Protective System Maintenance:
A Technical Reference) located in Section 16?
The red-lined version did not appear to agree with the clean copy. In reading the "red lined"
document it appears that R3 was intended to be "Each Transmission Owner, Generation Owner, and
distribution Provider shall implement and follow its PSPM and initiate resolution of any identified
maintenance correctable issues."
Individual
Russ Schneider
FHEC
Yes
No
Can't locate the implementation plan in the posted materials.
No
For Distribution Provider level equiment there should be no High or Severe VSLs
Yes
It is unclear what compliance obiligations may be created or clarified with the FAQ. It is a good
explanatory document and a helpful reference, but the Standard should speak for itself as it relates to
what it takes to achieve compliance.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration, LP, continues to believe that the six year requirement to verify channel
performance on associated communications equipment will prove to be more detrimental than
beneficial on older relays. Clearly newer technology relays which provide read-outs of signal level or
data-error rates will easily verified, but the tools which measure power levels and error rates on nonmonitored communication links are far more intrusive. After the technician uncouples and re-attaches
a fiber optic connection, the communications channel may be left in worse shape after verification
than it was prior to the start of the test. However, we have found that the remainder of the items in
the Tables are logically organized and correspond effectively with the five components of a Protection
System. The maintenance activities and intervals are technically solid and reasonable. In our opinion,
the benefits to proceed outweigh our one concern with the validation of communications channel
performance.
Yes
Yes
No
The removal of R1.5 and R7 which required Protection System owners to identify and verify
calibration tolerances or equivalent parameters upon conclusion of a maintenance activity was
fundamental to Ingleside Cogeneration’s “yes” vote. The amount of ambiguity introduced by the
requirements and associated documentation did not serve to improve BES reliability in our view.
Group
Santee Cooper
Terry L. Blackwell
Yes
Yes
Yes
No
Comments: Santee Cooper does not agree with the expansion of the UFLS and UVLS requirements to
include the dc supply. We understand that, in the previous consideration of comments, it is stated
that “For UFLS and UVLS, the maintenance activities related to station dc supply and control circuitry
are somewhat constrained relative to similar activities for Protection Systems in general.” In the
table, the requirement for dc supply for UFLS is to verify the station dc supply voltage when the
control circuits are verified, which could be 6 or 12 years. It seems like the restraint shown in the
requirement, if an indication of the level of need for the verification, is of a much longer timeframe
than what would actually happen in the typical operation of a distribution system. Therefore, proof of
this verification seems to be of minimal value compared to the extra documentation required due to
this now being an auditable maintenance activity. We also agree that maintenance activities with fast
intervals, especially the 3 month ones, should be adjusted to 4 months to allow for the actual interval
the entities use to be 3 months. Having the requirement at 3 months forces the utilities to schedule
even faster (such as every month or 2 months) to ensure compliance.
Individual
Beth Young
Tampa Electric Company
No
If during a UF operation there were ever any breakers that did not trip properly, there may be enough
that do trip to return things to balance. There is more room for error with UFLS than with BES. The
standard does make some allowance for differences between UFLS equipment and BES equipment.
For example the DC source testing requirement for UFLS is to just test the battery voltage when the
control circuit is tested. It is not necessary that the breaker be tripped for UFLS testing every six
years as is the case for BES. However, every 12 years all unmonitored control circuitry must be
tested, which may include tripping the breaker.
No
The new maintenance plan has to be completed in 1 year. Would that mean it is required to identify
and list every element that requires testing in a database within the first year. This will be a time
intensive effort that probably that would be difficult to complete in a year with current personnel.
After 1 year, would entities be required to start implementing the plan depending on the maintenance
intervals of the equipment. Qualified people would have to be in place to start the work, again this
would be difficult to accomplish with current personnel.
No
VSL is severe for more than 4% Countable Events on R2. It does not seem feasible.
No
Tampa Electric requests further differentiation between BES protection elements and UFLS
equipment.
As written PRC-005-2 would have a very significant impact on Tampa Electric Company with very little
reliability benefit. For the testing of the DC control circuits Tampa Electric would need to remove from
service each BES element (circuit, bus, transformer, breaker) and perform an R&C checkout
somewhat equivalent to what Tampa Electric does for new construction. That process would have to
be repeated no less often than every six years. The testing of DC control circuits to the level
described / required in the proposed standard in an energized station is a very risky proposition. Even
though an element can be taken out of service for testing, the DC control circuits are often
interconnected for functions such as breaker failure, bus and transformer lockouts etc. It is very easy
to accidentally trip other in service equipment while doing this testing. Another concern is getting
outages on equipment to perform the proposed testing. Tampa Electric believes that there is an
unnecessary expansion of the scope of equipment covered by the proposed PRC-005-2 standard into
the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries,
instrument transformers, DC control circuitry and communications in addition to the relays for BES
protection systems. PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay
components are included in those standards. The proposed PRC-005-2 includes the non-relay
components into UFLS and UVLS. The problem is, for UFLS and UVLS, the non-relay components are
mostly distribution class equipment; hence, the result of this version 2 standard will be inclusion of
most distribution class protection system components into PRC-005-2. This is a huge expansion of the
scope of equipment covered by the proposed standard with negligible benefit to BES reliability. In
addition, testing of protection systems on distribution circuits is difficult for distribution circuits that
are radial in nature. In addition, non-relay protection components operate much more frequently on
distribution circuits than on transmission Facilities due to more frequent failures due to trees, animals,
lightning, traffic accidents, etc., and have much less of a need for testing since they are operationally
tested. As another comment, station service transformers are not BES Elements and should not be
part of the Applicability - they are radial serving only load. Tampa Electric’s Energy Supply
Department has the following comment / question regarding Data Retention: • For Requirement R3
R2 and Requirement R4R3, the Transmission Owner, Generator Owner, and Distribution Provider shall
each keep documentation of the two most recent performances of each distinct maintenance activity
for the Protection System components, or all performances of each distinct maintenance activity for
the Protection System component since or to the previous scheduled audit date, whichever is longer.
If all of the data which the proposed PRC-005-2 standard requires to be collected is not be available
or kept for the prescribed period of time, how does a registered entity comply with the required data
retention?
Group
Bonneville Power Administration
Denise Koehn
Yes
No
Many of the maintenance intervals in the standard are given in the terms calendar years or calendar
months. There is no description of these terms in the NERC Glossary. My Webster's dictionary defines
calendar year as the period that begins on January 1 and ends on December 31. There is no definition
in my dictionary of calendar month. Is the intent of the term calendar year in the standard that
maintenance intervals start on January 1 and end on December 31? This would make all maintenance
due on December 31, and December would be a very busy time. Does this mean that if I do
maintenance on something with a maximum interval of six calendar years in June of 2011 that it will
be due again on January 1 of 2017 instead of June 1 of 2017? We believe that the drafting team
intends for maintenance to be due after a given number of years that begins to elapse immediately
after the previous maintenance is completed so that in the previous example the maintenance would
be due on June 1, 2017. Please remove the word calendar from the maximum maintenance intervals
to remove this confusion.
In the header of Tables 1-1, 1-2, 1-3, and 1-5 there is a note that says "Table requirements apply to
all components of Protection Systems except as noted." Since each table only applies to the specific
component type shown in the header, we do not understand what this note means. The definition
given for component only makes the note more confusing. Please clarify the note. Additionally, BPA is
voting no during this round due to an issue with the Applicability Section and Section 4.2. Once this
issue is clarified, BPA would be in support of a yes vote. Issue: Section 4.2 Facilities lists 5 separate
items that the standard is applicable for (4.2.1. – 4.2.5). However Requirement 1 uses language that
only addresses one of the items (4.2.1). There is no language contained anywhere within any of the
requirements in PRC-005-2 that apply to the types of protection systems described in Applicability
Sections 4.2.2 – 4.2.5. Therefore, it could be argued that this leaves it open to interpretation as to
whether UFLS/UVLS/SPS are addressed by R1. In the NOPR (¶ 105), FERC states that “the
Requirements within a standard define what an entity must do to be compliant”. Further, in Order 693
(¶ 253) FERC explicitly states that “compliance will in all cases be measured by determining whether
a party met or failed to meet the Requirement”. Given this, then from a compliance perspective, the
actual applicability of the standard appears to not be as broad as intended. We ask that this issue be
resolved by modifying the language in R1 in a manner that explicitly encompasses all types of
protection systems to which it is intended to be applied.
Group
Progress Energy
Jim Eckelkamp
Comments on Draft Standard 1. Table 1-1, 2nd row, 2nd bullet: The comment “(see Table 2)” does
not apply to this bullet, but applies to the first bullet. 2. Table 1-3, 2nd row: Need to add “(See Table
2).” Comments on Implementation Plan 1. Section 3a states that “The entity shall be at least 30%
compliant on the first day of the first calendar quarter 2 calendar years following applicable regulatory
approval…” If regulatory approval occurs on January 31, 2012, does this mean that the entity has
until December 31, 2014 to be 30% compliant? It might be beneficial to provide an example
explaining “calendar year.” Comments on Supplementary Reference 1. Table of Contents does not list
Section 15.4 2. Page 54, last paragraph, last sentence: “…advances that are may be coming…” 3.
Page 65, 5th paragraph: VLRA should be VRLA 4. Page 67, 4th paragraph, 4th sentence: “…typically
looking for on the plates…” 5. Page 69, 4th paragraph, last sentence: “…Grounds because to of the
possible…” 6. Page 69, 5th paragraph, 2nd sentence: “For example, to do I need…” 7. Page 70 5th
paragraph, 5th sentence: “A manufacturer of…” 8. Page 70 5th paragraph, 6th sentence: “…by a third
manufacturer’s equipment…” 9. Page 71, first line: “…(impedance, conductance, and resistance)…”
Group
SPP reliability standard development Team
Jonathan Hayes
Yes
Yes
No
If the maintenance is done prior to the maximum interval would it then reset the clock. Or should it
read that maintenance and testing should be done at least once per quarter etc. We would like to see
the plan split up into generation time horizons and transmission time horizons, these can be
significantly different.
No
Would like more clarification in table 1-5 to address verification tests on different circuits. Is this an
end to end test or partial test can you test one part of the circuit one way and another a different
way? Should table 1-5 read Complete a terminal test of unmonitored circuitry?
Group
Western Electricity Coordinating Council
Steve Rueckert
No
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace.
However, section 4.2 identifies five types of protection systems that the standard is applicable to, but
the language of Requirement 1 indicates that applicable entities need to establish a Protection System
Maintenance Program (PSMP) for the Protection Systems designed to provide protection for BES
Element(s) (Part 4.2.1 of Section 4.2). We believe the intent is to have a PSMP for all Protection
Systems identified in Section 4.2 and that the language of Requirement 1 may cause confusion or be
misleading. We suggest changing the language of Requirement 1 from: Each Transmission Owner,
Generator Owner, and Distribution Provider shall establish a Protection System Maintenance Program
(PSMP) for its Protection Systems designed to provide protection for BES Element(s). to: Each
Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection System
Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Group
Pepco Holdings Inc
David Thorne
Yes
Yes
No
1. Are the bullet items listed for the R2 Severe Violation Severity Level , Item 5 an "and" or an "or"?
5) Failed to: • Annually update the list of components, • Perform maintenance on the greater of 5%
of the segment population or 3 components, • Annually analyze the program activities and results for
each segment. 2. The wording of the R3 Lower Violation Severity Level seems to imply that an entity
that fails to complete 0% (i.e., completes 100%) of its maintenance correctable issues is noncompliant. Entity has failed to complete scheduled program on 5% or less of total Protection System
components. OR Entity has failed to initiate resolution on 5% or less of identified maintenance
correctable issues. The following re-phrasing is suggested: Entity has failed to complete scheduled
program on greater than 0%, but no more than 5% of total Protection System components. OR Entity
has failed to initiate resolution on greater than 0%, but less than or equal to 5% of identified
maintenance correctable issues.
Yes
The Supplementary Reference and FAQ should be an attachment to the standard (Appendix A)and not
just referenced. If not attached it will not be readily accessible to those that will be using the
standard.
There were numerous comments submitted for each of the previous drafts indicating that the 3 month
interval for verifying unmonitored communication systems was much too short. The SDT declined to
change the interval and in their response stated: "The 3 month intervals are for unmonitored
equipment and are based on experience of the relaying industry represented by the SDT, the SPCTF
and review of IEEE PSRC work. Relay communications using power line carrier or leased audio tone
circuits are prone to channel failures and are proven to be less reliable than protective relays."
Statistics on the causes of BES protective system misoperations, however, do not support this
assertion. The PJM Relay Subcommittee has been tracking 230kV and above protective system
misoperations on the PJM system for many years. For the six year period from 2002 to 2007, the
number of protective system misoperations due to communication system problems was lower (and in
many cases significantly lower) than those caused by defective relays, in every year but one.
Similarly, RFC has conducted an analysis of BES protection system misoperations for 2008 and 2009,
and found the number of misoperations caused by communication system problems to be in line with
the number attributed to relay related problems. If unmonitored protective relays have a 6 year
maximum maintenance/inspection interval, it does not seem reasonable to require the associated
communication system to be inspected 24 times more frequently, particularly when relay failures are
statistically more likely to cause protective system misoperations. As such, a 12 or 18 calendar month
interval for inspection of unmonitored communication systems would seem to be more appropriate.
FAQ II 6 B states that the concept should be that the entity verify that the communication
equipment...is operable through a cursory inspection and site visit. However, unlike FSK schemes
where channel integrity can easily be verified by the presence of a guard signal, ON-OFF carrier
schemes would require a check-back or loop-back test be initiated to verify channel integrity. If the
carrier set was not equipped with this feature, verification would require personnel to be dispatched to
each terminal to perform these manual checks. The SDT responded that they still felt the 3 month
interval as stated in the standard was appropriate. PHI respectfully requests that the SDT reconsider
this issue and also cite what "specific statistical data" they used to validate that unmonitored
communication systems are 24 times more prone to failure than unmonitored protective relays.
Individual
Joe O'Brien
NIPSCO
Yes
Sub-tables are good. A related question: Some devices such as reclosers and circuit breakers may
include batteries within the device itself. Does Table 1-4 apply to such batteries and DC supply?
Recloser batteries do not provide access to intercell connections.
No
This new standard’s calibration intervals outlined here will require additional staff at our organization.
In order to get people hired and trained the implementation plan should allow more time for the
phase-in period. From experience, calibration should have been de-emphasized since more concerns
are discovered during full tests.
no comments at this time
Yes
We used the FAQ Supplemental Reference while reviewing this draft standard and found it useful.
The present PRC-005 standard is 2 pages while the proposed PRC-005-2 is 22 pages, with an
implementation plan of 4 pages and a supplemental document of 87 pages. The review process
appears to be somewhat daunting especially considering that NERC is trying to simply things with
such concepts as the “traffic ticket” approach. In R3 we’re not sure if there is a time requirement
regarding the completion of the resolution process. We like the use of "calendar year" in requirements
which should provide flexibility in getting the work completed. Another comment for our response
concerns Table 1-2, Communications Systems (page 11): The first maintenance interval is 3 calendar
months. Does this mean the same as 1 calendar quarter? 1. Example for 3 calendar
months:Maintenance performed on 1/4/11. Next maint due by 4/30/11. Maintenance performed on
4/12/11. Next maint due by 7/31/11. Maintenance performed on 7/30/11. Next maint due by
10/31/11. This would yield 3 inspections for 2011. Maintenance performed on 10/12/11. Next maint
due by 1/31/12. 2. Example for 1 calendar quarter: Maintenance performed on 1/4/11. Next maint
due by 6/30/11. This would yield 4 inspections for 2011 (1 per quarter).
Individual
Linda Jacobson
Farmington Electric Utility System
Yes
Yes
No
VSL on R2: Lower criteria item 1; the wording is identical High VSL. FEUS recommends keeping the
criteria in the Lower VSL.
No
Individual
Greg Rowland
Duke Energy
Yes
We believe the table could be improved further to aid compliance by adding a footnote to the term
“baseline” in the sub-tables 1-4(a), 1-4(b) and 1-4(f). The following proposed footnote text is taken
from page 65 of the Supplementary and FAQ Reference Document: “Often for older VLRA batteries
the owners of the station batteries have not established a baseline at installation. Also for owners of
VLA batteries who want to establish a maintenance activity which requires trending of measured
ohmic values to a baseline, there was typically no baseline established at installation of the station
battery to trend to. To resolve the problem of the unavailability of baseline internal ohmic
measurements for the individual cell/unit of a station battery, all manufacturers of internal ohmic
measurement devices have established libraries of baseline values for VRLA and VLA batteries using
their testing device. Also several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to.”
Yes
No
Typographical error - the High VSL for R2 has been incorrectly changed to “within three years” from
“within four years”. This is now the same as the Lower VSL.
Yes
Along the lines of what we have suggested in our comment to Question #1 above, we believe it would
make compliance more certain if selected language from the Supplementary reference could be
incorporated into the standard, either directly in requirements, or in footnotes.
The Standard Drafting Team has done an outstanding job on this standard. We are voting
“Affirmative” but note that implementation questions remain, particularly with regards to classifying
component attributes as “monitored”, “unmonitored”, “internal self diagnosis”, “alarming”, “alarming
for excessive error”, and “alarming for excessive performance degradation”. The sheer size of the
population of protective relays, communications systems, voltage and current sensing devices,
batteries, and dc supply components means that the size of the effort required to categorize each
individual component could drive us to test and maintain on the more frequent unmonitored time
intervals, simply because of the difficulty in assembling “monitored” compliance documentation.
Individual
Steve Alexanderson
Central Lincoln
Yes
Yes
Yes
No
The first FAQ under 2.3.1 is incorrect, referencing a FERC informational filing. Included in the filing
was a WECC test that was never approved by the WECC board and is not being used. Using this
document as suggested will get WECC entities into trouble.
As we stated two ballots ago, we continue to believe that IEEE battery standard quarterly
maintenance was never intended to be performed at a maximum interval of three months. Instead,
three months is a target value that might be extended due to emergency. We continue to support a
maximum interval of four months for these activities.
Individual
Bob Thomas
Illinois Municipal Electric Agency
Yes
Yes
No
The scope of the equipment to which the draft standard applies is still overly broad. Specifically, PRC005-2 should not apply to non-relay equipment for UFLS and UVLS systems. Subjecting UFLS and
UVLS batteries, instrument transformers, DC control circuitry, and communications to the
requirements of PRC-005-2 would drastically increase the scope of equipment covered by the
standard, with no corresponding benefit to reliabiltiy of the BES. This comment/recommendation is
provided to address the resource and customer service interests of a TO and/or DP systems serving
distribution load. Illinois Municipal Electric Agency supports comments submitted by the Transmission
Access Policy Study Group.
Individual
Joe Petaski
Manitoba Hydro
Yes
The restructured tables are an improvement, but we suggest that conductance (siemens) should be
listed as an acceptable measurement in addition to the resistance measurements already included in
the tables.
Yes
No
VSL for Requirement 2: -Needs to use consistent terminology. The standard requirements refer to
components and component types, not elements. -The violation “Entity has Protection System
elements in a performance-based PSMP but has failed to reduce countable events to less than 4%
within three years” appears in both the Lower VSL column and the High VSL column. The violation
cannot be both Lower and High. VSL for Requirement R3: -Suggested wording “completed its
scheduled program”.
A red line was not provided making this document difficult to review. We suggest that a redline of this
document be posted.
-Grace periods Grace periods should be permitted on the maintenance time intervals. While we
understand that grace periods can be built into a PSMP, maintenance decisions that compromise
reliability may still have to be made just to meet the specified time intervals and avoid penalty. An
example of this would be removing a hydraulic generator from service at a time of low reserve to
meet a maintenance interval and avoid non-compliance (removing an asset in a time of constraint).
Grace periods are also required in the case of extreme weather conditions. Such conditions may make
it unsafe to perform maintenance within the maintenance interval or may create a risk to reliability if
the equipment being maintained is removed from service during these conditions. Utilities need to
retain a reasonable amount of discretion and flexibility to make maintenance decisions that are best
for reliability without risking non-compliance. -Battery Check Interval Manitoba Hydro maintains our
position that the 3 month battery check interval should be extended to 6 months. The 3 month
interval is too frequent based on our experience and while IEEE std 450 (which seems to be the basis
for table 1-4) does recommend intervals, it also states that users should evaluate these
recommendations against their own operating experience. With the 3 month battery check frequency
and no allowance for a grace period, there may be a negative impact on reliability caused by diverting
resources away from projects that are critical to reliability to meet this maintenance interval.
Individual
Mike Hancock
Shermco Industries
Yes
Yes
Yes
No
Please provide clarification on "Communications" in regards to the following: If our customers are
utilizing Schweitzer SEL311 relays and utilizing the fiber for transfer trip, is this considered a
communications circuit? Our experiences in regards to testing these devices that have transfer trips
out into a main substation, that could affect a main ring tie or open a major 138kV loop, are that the
T&D utilities will not allow us to perform these tests and trip their breakers. Therefore, what is
required to satisfy testing? In regards to Function / Trip testing, if we have a sudden pressure device,
this is considered an auxiliary relay and the sudden pressure relay itself is not required to be tested.
However, the trip path is required to be tested for DC tripping, if it directly trips the breaker feeding
the BES, on the DC Control verification testing. Please clarify if this is correct.
Individual
Michael Crowley
Dominion Virginia Power
Yes
Yes
No
Comments: IEEE battery maintenance standards call for quarterly inspections. These are targets,
though, not maximums. An entity wishing to avoid non-compliance for an interval that might extend
past three calendar months must implement a policy of two months with one month of grace period
thereby increasing the number of inspections each year by half again. This is unnecessarily frequent.
We suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, Dominion suggests that all battery maintenance intervals expressed as 3 calendar
months be changed to 4 calendar months.
Individual
Edward J Davis
Entergy Services
In Section 4.2, ‘Facilities’ add the following subsection 4.2.6: Protection Systems for generating units
in extended forced outage or in inactive reserve status are excluded from the requirements of this
standard. However, the required maintenance and testing of the Protection Systems at these units
must be completed prior to connecting the units to the Bulk Electric System (BES). Reason for the
above comment: The above units are not connected to the BES and therefore do not affect the
reliability of the BES. However, to ensure the reliability of the BES, required maintenance and testing
of the Protection Systems at these units must be completed prior to connecting them to the BES.
Individual
Thad Ness
American Electric Power
Yes
No
On page 2 of the implementation plan, it is indicated that PRC-005-1, PRC-008-0, PRC-011-0 and
PRC-017-0 shall be retired and that entities will be required to identify which components will be
addressed under PRC-005-1 or PRC-005-2. There is no wording to cover those components that are
still being addressed under PRC-008-0, PRC-011-0 or PRC-017-0 during the implementation period.
No
This standard encompasses a very broad range of component types and functionality. It also
encompasses broad segments of the BES. The proposed VSLs and VRFs place the same level of
severity or priority on facilities that serve local load with that of an EHV facility. The percentages
indicated in the VSLs seem to be too strict based upon the vast quantity of elements in scope and
broad range of application.
No
Individual
Jose H Escamilla
CPS Energy
Yes
Yes
Yes
No
Table 1-5 The new standard requires that every 6 years it is verified that “each trip coil is able to
operate the breaker,…”. The supplementary reference states that this requirement can be met by
tracking real-time fault-clearing operations on the circuit breakers. With transmission breakers
typically having dual trip coils, how can tracking real-time operations meet this requirement? Would a
breaker operations where relays in both the primary and secondary trip coils indicated operation be
sufficient or would some type of trip coil monitoring that showed coil energization be needed?
Additionally, regarding the verification of all trip paths of the trip circuit. If a microprocessor relay is
used to trip a breaker, and two contacts are paralleled on the relay through a single test switch for
breaker tripping, would it be necessary to verify each contact independently or could an assertion of
both contacts through the test switch be adequate? In this instance, the functionality of each contact
would be fully identical. Table 1-2 A 3-month inspection is required for communications equipment
that does not have “continuous monitoring or periodic automated testing for the presence of the
channel function, and alarming for loss of function” has to be verified that the communication
equipment is “functional” with a 3-month site visit. Would a carrier on-off system, that did not
perform periodic check back testing, but did have an alarm contact (loss of power, failure, etc.) that
was monitored through SCADA would need to have a 3-month inspection? According to the
supplemental reference, this inspection should be to verify that the equipment is “operable through a
cursory inspection and site visit”. It sounds as if this cursory inspection and site visit would
accomplish the same as the alarm contact. It does not appear that end-end functional testing of the
blocking signal is required by what is provided in the supplemental reference. Is this correct? Table 13 The maintenance activity for the 12 calendar year testing should include a little more specificity. It
should have something stating the values provided to the relay are accurate. I know that this
discussed in the supplemental reference, but requirement in Table1-3 sounds as if any relay that
measured for loss of signal, such as a loss-of-potential function, would be sufficient when the purpose
to verify that the signal not only gets to the relay but also has some accuracy as needed by the
application of the relay.
Group
Tennessee Valley Authority
Dave Davidson
Yes
However, The requirement to perform battery cell internal ohmic measurements every 18 months for
vented lead-acid batteries is excessive, and no technical justification is provided for an 18-month
interval. A 3-year internal ohmic test frequency is adequate to prove battery integrity. IEEE 450 does
not provide a recommended interval for internal ohmic measurements. For standard capacity testing,
the recommended interval is no greater than 25% of expected battery life. Our normal battery life is
20+ years, so the recommended capacity test interval would be about 5 years. EPRI also
recommends capacity testing at 5 year intervals. There is no justification for performing internal
ohmic measurements every 18 months (which equals every 7.5% interval of the expected battery
life). Recommendation: Set the interval for battery internal cell ohmic testing at 3 years.
Yes
No
TVA has 590 Pilot Relay (Carrier Blocking) Terminals that are tested twice a year. After an extensive
study of carrier failures over a 5-year period, it was determined that we were not having any failures
that could have been prevented by a functional test. In January 2008, we reduced our frequency from
4 times per year to 2 times per year. The failure rate has remained about the same since that
change. As PRC 005-2 currently states, the PM frequency would be 3 months. Allowing for a onemonth grace period would actually require the interval to be set at 2 months. Therefore, the interval
we used prior to 2008 (4 times per year) still would not make TVA compliant with the stated 3 month
interval. TVA Power Control Systems is in the process of developing extensive PM tests for carrier
terminals to complement the existing PM program. This PM would record signal levels, reflected
power, line losses, and other pertinent data. It is my position that this PM will improve reliability more
than increasing the frequency of the functional test.
No
Individual
Melissa Kurtz
US Army Corps of Engineers
Yes
Yes
Yes
Yes
The reference material provides a significant insight into the intent of the proposed changes to the
standard. In some cases an interpretation is provided which is not supported by the explicit
interpretation of the standard text. The SDT is encouraged to either attach the reference material to
the standard or add relevant sections to standard as Background. The Background section could
reference the Supplemental Reference & FAQ. The reference material provides more detail indicating
that “Voltage & Current Sensing Device circuit input connections to the protection system relays can
be verified by (but not limited to) comparison of measured values on live circuits or by using test
currents and voltages on equipment out of service for maintenance. . . . . . The values should be
verified to be as expected, (phase value and phase relationships are both equally important to
verify).” This interpretation is not consistent with the text of the standard and would suggest that it
be incorporated into Table 1-3.
Section 4.2.5.4 - please clarify generator connected station service transformer. We believe this to
mean a station service transformer with no breaker between the transformer and teh generator bus.
R3 - the term 'initiate resolution' is vague and needs to be further defined. Does this mean putting in
a work order or is further action required. Data Retention: The proposed standard clarifies that two of
the most recent records of maintenance are to be retained to demonstrate compliance with the
prescribed maintenance intervals. When equipment is replaced, the reference information indicates
that the information associated with the original equipment must be retained to show compliance with
the standard until the performance with the new equipment can be established. This is not explicitly
stated in the requirements and warrants a comment.
Group
Imperial Irrigation District
Jose Landeros
Yes
Yes
Yes
No
Group
PNGC Comment Group
Ron Sporseen
No
We agree the changes to the tables have added clarity, but disagree with the maintenance intervals
for DC supply. Comments: “PNGC’s comment group views the Maximum Maintenance Interval for
station DC Power Supply (Table -14a/b/c/d) to be unnecessarily onerous and restrictive to many
smaller-rural entities, in the west and probably throughout the US, and this prevents us from being
able to support PRC-005-2 as written. We make these comments with the understanding that others
have made similar comments in the past but we feel strongly that this is an important issue worthy of
further review by the SDT. We believe a quarterly inspection schedule can be met while at the same
time allowing entities the flexibility they need. IEEE 1188-2005 suggests a quarterly inspection
schedule for lead acid batteries and we believe the standard interval for verifying and inspecting dc
supply should be 3 months with a maximum interval of 6 months. This meets the quarterly threshold
and gives some flexibility to account for unusual conditions. There are substations in Pacific Northwest
rural areas that can be inaccessible during long periods of time during the winter, potentially exposing
an entity to sanction if weather conditions prevent access to equipment for an extended period of
time. Additionally, due to a smaller workforces and greater distances between equipment subject to
PRC-005, small-rural entities face obstacles that large entities may not have. The three month
maximum interval assumes ideal conditions and resource access and is not realistic. We thank the
SDT for considering our comments.”
Yes
Yes
Yes
Section 9.2 (copied below)indicates that small entities can utilize Performance-Based PSMP if they
aggregate with other entities. Does this section indicate that only a parent entity with individually
owned components can aggregate, or can independent entities under a G&T aggregate? In other
words, individual DP/LSE/TOs with different audits. Can they aggregate under a common PSMP for
performance based maintenance? 9.2 Frequently Asked Questions: I’m a small entity and cannot
aggregate a population of Protection System components to establish a segment required for a
Performance-Based Protection System Maintenance Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All entities
participating in a joint program should have a single documented joint management process, with
consistent Protection System Maintenance Programs (practices, maintenance intervals and criteria),
for which the multiple owners are individually responsible with respect to the requirements of the
Standard. The requirements established for performance-based maintenance must be met for the
overall aggregated program on an ongoing basis. The aggregated population should reflect all factors
that affect consistent performance across the population, including any relevant environmental factors
such as geography, power-plant vs. substation, and weather conditions.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
No
Although considerable clarity was achieved in the structuring of the table for the different types of
technologies associated with the DC supply, there is issue on the maximum allowable intervals. The
standard remains too prescriptive in the intervals and maintenance activities. As an example it is
believed the intent of the interval for verifying voltages and inspecting electrolyte levels and
unintentional grounds level would be every 3 months. However, for the entity to ensure compliance
and not incur a violation it would have to have a shorter interval, probably every 2 months just to
ensure compliance and not incur a violation. The 3 month interval is in question based on programs
that have been in service for many years where four months have been proven as reliable for
operation, an even shorter period than 3 or 4 months is not only a burden but an unnecessary
expense without a benefit of increase reliability of the Bulk Electric System.
Yes
NERC continues to be too prescriptive in the standard. For example, Table 1-4(a) requires battery
verifications and inspection every three months. We have been performing similar tests every four
months for over a decade, with no adverse consequences. Although FERC Order 693 directs NERC to
establish maximum allowable intervals, the maximum interval must be “appropriate to the type of
protection system and its impact on the reliability of the Bulk-Power System.” (Order 693 at 1475)
The Standard Drafting Team (SDT) has not demonstrated a mechanism that connects the maximum
maintenance interval with its impact on the reliability of the Bulk-Power System. An example can be
found on the bottom of page 18 and the top of page 19 of the Consideration of Comments on
Protection System Maintenance [Project 2007-17] for draft 3. Although the commenting organization
provided a concrete example of successful maintenance under a longer interval, the Standards
Drafting Team commented that it “… believes that 18-months is the proper interval for this activity.”
(Emphasis added) An organization cannot challenge the SDT’s beliefs, only facts. The basis for each
maximum maintenance interval, with appropriate linkage to its impact on the reliability of the BulkPower System, needs to be published and voted upon so that factual based proposals to modify the
maximum interval can be rationally challenged.
Individual
Kenneth A. Goldsmith
Alliant Energy
Yes
Yes
No
The LOW and HIGH VSL for R2 are the same. There are additional possibilities for the LOW, but it is
possible to be in both the LOW and HIGH VSL at the same time. We recommend removing #1 in the
LOW VSL category to resolve the issue.
Yes
Comment 1 If PRC-005-2 is going to incorporate PRC-008 (UFLS) and PRC-011 (UVLS) the Purpose
needs to be revised to include Distribution Protection Systems designed to protect the BES. Comment
2 We do not believe a distribution relaying system, designed to protect the distribution assets, that
may open a transmission element (ie; breaker failure) should be considered part of the BES
Protection System. R1 should add the following sentence “Distribution Protection Systems intended
solely for the protection of distribution assets are not included as a BES Protection System, even if
they may open a BES Element.” Comment 3 Table 1-5 (Component Type – Control Circuitry) Item 4 –
“Unmonitored control circuitry associated with protective functions” require a 12 calendar year
maximum maintenance interval. We believe UFLS and UVLS control circuitry should be exempted
from this requirement. It would take multiple failures to have any impact, and the impact on the BES
would be minimal.
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
Yes
Yes, however, in the “Supplemental reference and FAQ” document on page 65 this is one area of
concern. Page 65, paragraph 4 “… the type of test equipment used to establish the baseline must be
used for any future trending of the cells internal ohmic measurements because of variances in test
equipment and the type of ohmic measurement used by different manufacturer’s equipment.” While
we understand the importance of creating a baseline, it’s not feasible to expect the test equipment to
be the same as the manufacturer’s test equipment or even the same test equipment over the life of
the battery. The expected life of a battery may be in excess of 15 years and it is not feasible to
expect that the type of test equipment will not change during this period. We suggest changing the
wording to read that consistent test equipment should be used to provide consistent/comparable
results.
Yes
Yes
No
In the checkbox for Requirement R3 please change the wording to read, “Maintenance Correctable
Issue - Failure of a component to operate within design parameters such that it cannot be restored to
functional order by repair or calibration during performance of the initiating on-site activity. Therefore
this issue requires follow-up corrective action.”
Individual
Kirit Shah
Ameren
Yes
Please carry the grid across in Table 1-4(f) to show the Maintenance Activities that go with the
Component Attribute.
Yes
While we agree with the Implementation Periods, it would be best to alter R2 and R3 implementation
such that components with maximum allowable intervals of 1 year or longer align with a true calendar
year (i.e. begin with January 1).
Yes
Yes
1. Comments: Supplement FAQ 12.1 on page 51 final sentence states that documentation for
replaced equipment must be retained to prove the interval of its maintenance. We oppose this
because: the replaced equipment is gone and has no impact on BES reliability; and such retention
clutters the data base and could cause confusion. For example, it could result in saving lead acid
battery load test data beyond the life of its replacement. Since BES Element protection is the
objective, we suggest a compromise of keeping the evidences of last test for the removed equipment
and using that with the equivalent function replacement equipment commissioning or in-service date
to prove interval. 2. Clarify p17 Table 1-4(e) interval meaning. We think this means we need to verify
the Station dc supply voltage on 12 calendar year interval if unmonitored, or no periodic maintenance
if monitored as stated. 3. In Supplement examples on pp 22-23, replace “Instrumentation
transformers” with “Verify that current and voltage signal values are provided to the protective
relays” to be consistent with Table 1-3. 4. Remove “Reverse power relays” from the sample list of
generator devices in Supplement p31 because reverse power relays are applied for mechanical
protection of the prime mover, not electrical protection of the generator. 5. Revise Supplement Figure
1 & 2 Legend p83 to align with Draft 4 (a) state “Protective relays designed to provide protection for
BES Element(s)”. (b) state “Current and voltage signals provided to the protective relays” 6. Please
add a Performance-Based maintenance example for control circuitry, and /or voltage and current
sensing.
Measure M3 on page 5 should apply to 99% of the components. “Each … shall have evidence that it
has implemented the Protection System Maintenance Program for 99% of its components and
initiated….” PRC-005-2 unrealistically mandates perfection without providing technical justification. A
basic premise of engineering is to allow for reasonable tolerances, even Six Sigma allows for defects.
Requiring perfection may well harm reliability in that valuable resources will be distracted from other
duties. 2. Define BES perimeter in accordance with Project 2009-17 Interpretation. Facilities Section
4.2.1 “or designed to provide protection for the BES” needs to be clarified so that it incorporates the
latest Project 2009-17 interpretation. The industry has deliberated and reached a conclusion that
provides a meaningful and appropriate border for the transmission Protection System; this needs to
be acknowledged in PRC-005-2 and carried forward. The BOT adopted this 2/17/2011. 3. Battery
inspection every 4 months is sufficient. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for
an interval that might extend past three calendar months due to storms and outages must set a
target interval of two months thereby increasing the number of inspections each year by half again.
This is unnecessarily frequent. We suggest changing the maximum interval for battery inspections to
4 calendar months. For consistency, we also suggest that all intervals expressed as 3 calendar
months be changed to 4 calendar months.
Individual
Rex Roehl
Indeck Energy Services
No
The tables are limited to a few battery technologies and will be out of date in short order with the
many types of advanced batteries already on the market. The testing requirements should be
performance based as opposed to prescriptive.
No
The last part of the implementation plan is vague, if not undefined. The implementation should “follow
the previous maintenance intervals until all maintenance is transitioned to the new intervals.”
No
The VSL’s for R1 should combine the ones for Lower, Moderate and High VSL into Lower VSL. The
Severe VSL should be moved to the Moderate VSL. Because R1 is administrative, it shouldn’t have
High or Severe VSL’s. The R2 High VSL (3 yrs) is more stringent than the Severe VSL (5 yrs). The R3
VSL’s need to have combined numbers of components or percentages because small generators may
only have 25 relays or 1 battery and would be categorized as High or Severe VSL with a few
components affected. The percentage could apply to RE’s with more than 250 components included in
the PSMP. The Medium VRF for R1 should be Low VRF because R1 is administrative. Only the
performance of the maintenance has anything more than Low VRF. The Medium VRF for R2 is OK.
Having a High VRF for R3 is without basis. R3 should have Medium VRF.
No
Individual
Kevin Luke
Georgia Transmission Corporation
No
We need clarification on the UFLS or UVLS system Station DC Supply test. We trip the high side
device (non-BES asset) for each of our distribution stations UFLS or UVLS schemes, not the individual
distribution breakers. It is hard to distinguish what maintenance interval and maintenance activities
we should engage for Station DC Supply test. Since the device is not a distribution breaker as
mentioned in the Table 1-4 (a-f) we would be conservative and choose to perform maintenance at all
our distribution stations with UFLS or UVLS schemes as per Table 1-4(a). Reading the statements in
the Supplementary Reference and FAQ, we notice our devices perform similar functions as the
distribution breakers. Reference pg 60 of Supp. Ref. and FAQ paragraph 4. Since tripping the high
side device of a distribution transformer still constitutes a distributed system would our system meat
the exclusion criteria although it is not a distribution breaker, would this meet the same requirements
and exempt the station from Table 1-4(a) and require only maintenance for DC systems as per Table
1-4(e)? Please clarify. We recommend changing the term distribution breaker to distribution asset
interruption device or non-BES equipment interruption device.
Yes
Yes
Yes
See comments for item 1 and continue clarification where we could include high side or distributed
interrupting devices, exchange nomenclature removing distribution breaker and adding distributed
interrupting device or non-BES equipment.
Individual
Andrew Z Pusztai
American Transmission Company, LLC
Yes
Yes, however, in the “Supplemental reference and FAQ” document on page 65 there are two areas of
concern. - Page 65, paragraph 4 “… the type of test equipment used to establish the baseline must be
used for any future trending of the cells internal ohmic measurements because of variances in test
equipment and the type of ohmic measured used by different manufacturer’s equipment.” While ATC
understands the importance of creating a baseline, it is not feasible to expect the test equipment be
the same as the manufacturer’s test equipment or even the same test equipment over the life of the
battery. The expected life of a battery may be in excess of 20 years and it is not feasible to expect
that the type of equipment will not change during this period. - Page 65, paragraph 6 “… all
manufacturers of internal ohmic measurement devices have established libraries of baseline values …”
ATC question’s the availability of baseline libraries for all manufacturers considering the variety and
longevity of installations.
Yes
Change the text of “Standard PRC-005-2 – Protection System Maintenance” Table 1-5 on page 19,
Row 1, Column 3 to: “Verify that a trip coil is able to operate the circuit breaker, interrupting device,
or mitigating device.” Or alternately, “Electrically operate each interrupting device every 6 years” Trip
coils are designed to be energized no longer than the breaker opening time (3-5 cycles). They are
robust devices that will successfully operate the breaker for 5,000-10,000 electrical operations. The
most likely source of trip coil failure is the breaker operating mechanism binding, thereby preventing
the breaker auxiliary stack from opening and keeping the trip coil energized for too long of a time
period. Therefore, trip coil failure is a function of the breaker mechanism failure. Exercising the
breakers and circuit switchers is an excellent practice. We would encourage language that would
suggest this task be done every 2 years, not to exceed 3 years. Exercising the interrupting devices
would help eliminate mechanism binding, reducing the chance that the trip coils are energized too
long. The language as currently written in table1-5 row 1, will also have the unintentional effect of
changing an entities existing interrupting device maintenance interval (essentially driving interrupting
device testing to a less than 6 year cycle). Change the text of “Standard PRC-005-2 – Protection
System Maintenance” Table 1-5 on page 19, Row 3, Column 2 to: “12 calendar years” The maximum
maintenance interval for “Electromechanical lockout and/or tripping devices which are directly in a trip
path from the protective relay to the interrupting device trip coil” should be consistent with the
“Unmonitored control circuit” interval which is 12 calendar years. In order to test the lockout relays, it
may be necessary to take a bus outage (due to lack of redundancy and associated stability issues
with delayed clearing). Increasing the frequency of bus outages (with associated lines or
transformers) will also increase the amount of time that the BES is in a less intact system
configuration. Increasing the time the BES is in a less intact system configuration also increases the
probability of a low frequency, high impact event occurring. Therefore, the Maximum Maintenance
Interval should be 12 years for lockout relays. ATC recognizes the substantial efforts and
improvements to PRC-005-2 that have been made and appreciate the dedicated work of the SDT. We
appreciate the removal of Requirement R1.5 and R4 and other clarifications from draft 3. ATC’s
remaining concern for PRC-005-2 is with definition and timelines established in Table 1-5. ATC
believes that, as written, the testing of “each” trip coil and the proposed maintenance interval for
lockout testing will result in the increased amount of time that the BES is in a less intact system
configuration. ATC hopes that the SDT will consider these changes.
Group
The Detroit Edison Company
Daniel Herring
Yes
Yes, the tables do provide more clarity. It is much easier to understand the requirements now that
they are broken down by technology, and the exclusion of intervals on certain activities based on the
individual monitoring attributes is helpful. I appreciate the thought that went into revising this.
Yes
No
R2 - It appears that the Lower VSL point 1) and High VSL are identical.
No
Countable Event - This definition should be clarified. As it stands, it appears that if a technician were
to adjust the settings on an electromechanical relay - even if it were not outside of the entity's
acceptable tolerance - it would need to be classified as a countable event. I would recommend that
the definition be limited to repairing or replacing a failed component during the maintenance activity.
These activities would address conditions that would potentially cause a Protection System
misoperation (either a failure to trip or an unintentional trip). Routine maintenance activities to bring
component test values back within tolerance should be excluded from the definition of a Countable
Event. These activities are performed to keep the protection systems performance at its most ideal
state. In addition, the definition as stated appears to classify battery maintenance activities such as
cleaning corrosion, adding water, or applying an equalize charge, as countable events. If this is the
intent, I disagree. These are activities that are expected to occur on a regular, routine basis due to
the chemical properties of the battery (as described at length in the Supplementary Reference). As
such, they should also not be classified as countable events. Table 1-1 and Table 1-5 Based on
experience with DECo equipment, a 6 year interval for testing monitored relays and performing tests
on the breaker trip coil is substantially shorter than required. Currently, the interval for both is 10
years. This interval lines up both with the Transmission Owner's interval for relay maintenance as well
as the maintenance interval for the associated current interrupting devices. I would recommend that
these intervals be extended, at minimum, back to the 7 year interval proposed in Draft 2 - if not
longer. Table 1-4 (a, b, c, e) - Station dc supply using any type of battery I recommend that the
maintenance activity to "Verify: Station dc supply voltage" be clarified to state that the voltage should
be measured at the positive and negative battery terminals. Until you get to page 72 of the
Supplementary Reference, you do not know if this means to check the battery voltage or the bus
voltage. The "Station dc supply" could refer to the entire dc system. It needs to be made clear in the
table that you are referring to the battery. Also, I noticed that there is no longer a requirement to
measure individual cell voltages. I was wondering if you could explain the rationale behind that.
Checking for voltages that are out of specification in individual cells helps to identify weak cells that
may need to be replaced, if corrective action taken on them does not improve their condition.
Individual cell voltage readings, along with ohmic readings, have been an industry standard that I
believe many, if not most, companies adhere to. Table 1-4 (a, b, c, d) I recommend eliminating the 3
month requirement. We have found annual inspections to be sufficient in catching problems early
enough to take corrective action. Page 30 of the Supplementary Reference states that the SDT
believes that routine monthly inspections are the norm. While this may be the case at manned
stations, it is not at unmanned stations. The amount of paperwork that would be required to
demonstrate compliance is overwhelming and would be an immense burden. I have seen your
suggestion in past draft comments of the same nature that if we don't want to do the 3 month
inspections, then we should utilize more advanced monitoring. This is not something that can be
implemented in a short time frame. It would take years to put all of that technology in place, and is
rather cost prohibitive. Furthermore, some of the monitoring technologies that would enable you to
forgo the 3 month requirement do not exist yet (to my knowledge). I recommend keeping with the 18
month requirement. If that seems too long, based on past experience I think a 12 month requirement
would suffice. Table 1-4 (c) I propose keeping the option to evaluate ohmic values to baseline. Table
1-4 (a, b) For the requirement to evaluate the ohmic values to baseline, is a checkbox stating that
you did this sufficient, or would a report/graph/etc listing the actual baseline and current value be
required? Table 1-4 (f) The first attribute is regarding high and low voltage monitoring and alarming
of the battery charger voltage to detect charger overvoltage and charger failure. Would a low voltage
alarm combined with high voltage shutdown (but not a high voltage alarm) meet this requirement?
The high voltage shutdown will shut the charger down in a high voltage condition, and therefore
result in a low voltage alarm, so the outcome is the same.
Individual
John Bee
Exelon
Yes
What kind of component we are talking about in table 1.4(d) “Station DC Supply using Non Battery
Based Energy Storage” for switchyard in nuclear plants?
In response to Exelon’s comments provided to drafts 1, 2, and 3 of PRC-005, the SDT did not explain
why a conflict with an existing regulatory requirement is acceptable. The SDT previously responded
that a conflict does not exist and that the removal of grace periods simply is there to comply with
FERC Order directive 693. In response to draft 3 of PRC-005, the SDT stated that "If several different
regulatory agencies have differing requirements for similar equipment, it seems that the entity must
be compliant with the most stringent of the varying requirements. In the cited case, an entity may
need to perform maintenance more frequently than specified within the requirements to assure that
they are compliant." Again this does not explain why a conflict with an existing regulatory
requirement is acceptable. This response does not answer or address dual regulation by the NRC and
by the FERC. Specifically, the request has not been adequately considered for an allowance for NRClicensed generating units to default to existing Operating License Technical Specification Surveillance
Requirements if there is a maintenance interval that would force shutting down a unit prematurely or
become non-compliant with PRC-005. Therefore, Exelon again requests that the SDT communicate
with the NRC and with the FERC to ensure a conflict of dual regulation is not imposed on a nuclear
generating unit without the necessary evaluation. In addition, the SDT still did not fully evaluate or
address the concern related to the uniqueness of nuclear generating unit refueling outage schedules.
Although Exelon Nuclear agrees with the SDT that the maximum allowed battery capacity testing
intervals of not to exceed 6 calendar years for vented lead acid or NiCad batteries (not to exceed 3
calendar years for VRLA batteries) could be integrated within the plant’s routine 18 month to 2 year
interval refueling outage schedule, the SDT has not considered that nuclear refueling outages may be
extended past the 18 month to 2 year "normal" periodicity. There are some unique factors related to
nuclear generating units that the SDT has not taken into consideration in that these units are typically
online continuously between refueling outages without shutting down for any other required
maintenance. Historically, generating units have at times extended planned refueling outage
shutdown dates days and even weeks due to requests from transmission operations, fuel issues and
electrical demand. Without the grace period exclusion currently allowed by existing maintenance
programs, a nuclear plant will be forced to either extend outage duration to include testing on an
every other refueling outage (i.e., every four years to ensure compliance for a typical boiling water
reactor) or leave the testing on a six year periodicity with the vulnerability of a forced shut down
simply to perform maintenance to meet the six year periodicity or a self report of non-compliance. To
ensure compliance, the nuclear industry will be forced to schedule battery testing on a four year
periodicity to ensure the six year periodicity is met, thus imposing a requirement on nuclear
generating units that would not apply to other types of generating units. The SDT response to this
question in draft 3 is that "(t)he 18-month (and shorter) interval activities are activities that can be
completed without outages – primarily inspection-related activities. An entity may need to perform
maintenance more frequently than specified within the requirements to assure that they are
compliant." Respectfully Exelon requests that the SDT review and evaluate the concern.
Individual
Glen Sutton
AtCO Electric ltd
Table 1-4: ATCO Electric has a number of remote substations that are difficult to access. The
requirement for a 3 calendar month inspection for electrolyte level is too frequent. The requirement
would become achievable if electrolyte level inspections were moved to the 18 calendar months
category, or if the 3 calendar months frequency were increased to 8 calendar months. Table 1-4(b):
for the same reasons, the requirement of a 6 calendar month inspection of individual battery cell/unit
internal ohmic values is too frequent. The requirement would become achievable if battery cell/unit
internal ohmic value inspections were moved to the 18 calendar months category, or if the 6 calendar
months frequency were increased to 14 calendar months. Table 1-4(c): the requirement of a 6
calendar year performance service or modified performance capacity test should be removed. From
our experience, there is no benefit in doing battery load tests. Instead, we apply verification of
battery intercell resistance as a more efficient method of monitoring battery condition, which provides
an 8 to 14 month lead time to replace a battery unit/cell before it goes dead.
Table 1-2: the requirement for a 12 calendar year verification for the channel and essential signals’
performance should be removed. We do not see benefit in the maintenance activities under level 2
(the 12 calendar year requirement) and suggest merging it with level 3 (the “no periodic maintenance
specified” requirement). The ‘loss of function’ alarm, will be considered as a countable event to fall
under requirement R3 and dealt as maintenance correctable issue. Table 1-5: the requirement of 6
calendar year verification for electrical operation of electromechanical lockout and/or tripping auxiliary
devices should be revisited, considering that: • It is not feasible to exercise a lockout relay during
maintenance due to high risk to the in-service facility, as well as the complexity of lockout relay
connections and protection schemes. Instead, we propose a DC ring test, which verifies the continuity
of control circuitry and eliminates the risk impact of lockout or auxiliary tripping device operations. •
The interval is too frequent. The requirement would become achievable if the 6 calendar year
frequency were increased to 12 calendar years, to be in line with microprocessor relay maintenance
frequency
Individual
Claudiu Cadar
GDS Associates
Yes
Yes
No
• Suggest clarification of the VSL for R2. It appears that R2 Lower VSL is also contained in the R2
High VSL. • If the maintenance is completed prior to the maximum interval, would it then reset the
clock? Or should it read that maintenance should be done at least once per quarter, etc. • The plan
should split into generation time horizons and transmission time horizons since these can be
significantly different
Yes
The standard should include a footnote indicating this document as reference
A. Requirement R1 • Suggest changing the language in R1.2 to read “Identify which maintenance
method such as the time-based, performance-based (detailed in PRC-005 Attachment A), or a
combination of the two would be appropriate to be used for each type of Protection System
component. Based upon their own constructive type, all batteries associated with the station DC
supply shall be included in a time-based maintenance program consistent with Table 1-4(a) through
Table 1-4(f)” • Suggest changing the language for the first paragraph in R1.3 to read “Establish the
occurrences associated with the time-based maintenance programs up to but no less than the time
intervals specified in Table 1-1 through Table 1-5, and Table 2. Consequently, include all applicable
monitoring attributes and related maintenance activities characteristic to each type of Protection
System component specified in Table 1-1 through Table 1-5, and Table 2” • Suggest adding a subrequirement such as R1.5 to read “Include documentation of maintenance, testing interval and their
basis and a summary of testing procedures” B. Requirement R3 • The redline version of the standard
is misleading. Requirement R3 is crossed out and then replacing requirement R7 which is also crossed
out. • The wording “[…] initiates resolution of any identified maintenance correctable issues” it is
vague. What a responsible entity should do to become compliant with this requirement? We also
believe that is not sufficient to just “initiate resolution”; the standard should call for corrective actions
to be performed within the maintenance time interval. • The “identified maintenance correctable
issues” may not be a proper choice. The name of the new term suggests that is about issues that can
be corrected during maintenance, while the definition from the clean version explains otherwise?! C.
Additional requirement • Suggest adding a requirement to read “The Transmission Owner, Generator
Owner, and Distribution Provider shall provide documentation of its PSMP and implementation to the
appropriate Regional Reliability Organizations on request (within 45 calendar days).” • Add measure
for the evidence on documenting the PSMP from the additional requirement D. General comments and
notes • If you own electro-mechanical relays and microprocessor based relays is there a need to keep
two different logs for these? • On table 1-4 the generator CTs should be tested earlier than the
suggested 12 years due to exposure of continuous mechanical stress • Clarify table 1-5 to address
verification tests on different circuits. Suggest that the Table 1-5 to read “Complete a terminal test of
unmonitored circuitry” instead of the “Unmonitored control circuitry associated with protective
functions” • In what instances (what extent) would the standard allow using the real time breaker
operation to be considered maintenance as applicable to different types of relays involved in the real
time event? This is briefly emphasized under TBM at paragraph 5.1 from the supplementary reference
document?
Group
ISO/RTO Standards Review Committee
Albert DiCaprio
The SRC disagrees with the change to the term under 4.2.1. “Protection Systems designed to provide
protection for BES elements.” We support keeping the previous version’s wording of 4.2.1. “Protection
Systems applied on, or designed to provide protection for the BES.” The revised wording expands the
fundamental purpose of the NERC PRC-005 standard from being focused on ensuring relays intended
to protect the reliability of the BES are maintained to a standard whose intent is to ensure all BES
facilities have relay maintenance programs. Although we do not disagree with maintaining all relays,
regardless of what their intended purposes are, it should not be the purpose of a NERC standard to
police all protection schemes beyond those needed for interconnected reliability. There are numerous
protective relays employed on facilities interconnected to the BES but their purpose may be for
operating preference or service/equipment quality purposes such as reclosing schemes and
transformer sudden pressure relays. We believe the NERC PRC-005 standard should be focused on
maintenance of those protective relays which are needed to ensure that the loss of a single element
does not cause cascading effects on the bulk power system.
Group
Transmission Access Policy Study Group
Cynthia S. Bogorad
The scope of the equipment to which the draft standard applies is over-broad. Specifically, PRC-005-2
should not apply to non-relay equipment for UFLS and UVLS systems. Subjecting UFLS and UVLS
batteries, instrument transformers, DC control circuitry, and communications to the requirements of
PRC-005-2 would drastically increase the scope of equipment covered by the standard, with no
corresponding benefit to reliability, for the following reasons. In contrast to transmission and
generation protection systems and SPSs, for which there are typically two protection systems per
facility and therefore per fault, UFLS and UVLS deal with widespread events. For any under-voltage or
under-frequency event, there are literally hundreds of UFLS/UVLS relays to respond. It is therefore far
less critical if one UFLS or UVLS relay fails to operate properly. Furthermore, transmission is typically
not radial (in fact, radials to load are excluded from the BES). But distribution circuits, where UFLS
and UVLS systems are located, are usually radial. Testing some of the non-relay equipment to which
the draft standard applies would require blacking out the customers served by that radial. In other
words, the draft standard would require entities to definitely cause blackouts in an attempt to prevent
very unlikely potential blackouts. This is plainly not justified from a harm/benefit perspective. Finally,
many of the types of non-relay equipment to which the standard would apply are in effect tested by
faults. Specifically, faults happen on distribution circuits (where UFLS and UVLS systems are located)
more frequently than on transmission circuits, due to such things as animal contacts and car
accidents. Any such fault is in fact a test of the all the equipment that is involved in clearing the fault.
There is no need to require separate tests of that equipment, any more than we would require tests of
a phone line that is used on an everyday basis; you already know that the phone works.
Individual
Gerry Schmitt
BGE
Yes
No comments.
Yes
No comments.
Yes
No comments.
Yes
The supplementary reference on page 30, under the question beginning “Our maintenance plan
requires…” states that an entity is “out of compliance” if maintenance occurs at a time longer than
that specified in the entity’s plan, even if that maintenance occurred at less than the maximum
interval in PRC-005-2. But then on page 35, under the question, “How do I achieve a grace period
without being out of compliance” provides an example of scheduling maintenance at four year
intervals in order to manage scheduling complexities and assure completion in less in less than the
maximum time of six calendar years. This is conflicting advice. The FAQ /supplementary reference
should be revised so that it does imply that an entity is out-of-compliance by performing maintenance
more frequently than required. Avoiding compliance risk is one reason to do this, but there are other
valid motives not directly related to reliable protection system performance. Testing of PT’s and CT’s
(12 year max) is non invasive and convenient to schedule at the same time as relays (6 year max)
just to keep procedures consistent and reduce program administration. Testing of ties to other TOs or
GOs may have to be scheduled more frequently than preferred in order to synchronize schedules.
No comments.
Group
FirstEnergy
Sam Ciccone
Yes
No
Although we agree with the timeframes being afforded to achieve compliance, we suggest the
following changes: 1. During the last comment period, we suggested changes to the wording
regarding retirement of existing standards on page 2. We do no see a response to these comments.
Therefore, we would like to reiterate that the four existing standards are to be retired upon the
effective date of the new standard and not upon regulatory approval. 2. In 4a of the plan, since the
timeframe for 30% completion is 3 calendar years, we suggest a change to three calendar years for
the parenthetical phrase “(or, for generating plants with scheduled outage intervals exceeding two
calendar years, at the conclusion of the first succeeding maintenance outage)”. Change “two” to
“three”. 3. We suggest the implementation plan be included within the body of the standard. It is very
burdensome for entities to have to look for the implementation plan and we believe that a “one-stop
shopping” approach would alleviate this burden.
Yes
Yes
We do not agree with the following wording on page 37 of the reference document: (1) “If your PSMP
(plan) requires more activities then you must perform and document to this higher standard.” and (2)
“If your PSMP (plan) requires activities more often than the Tables maximum then you must perform
and document those activities to your more stringent standard.” We continue to believe that the
auditor is required to audit to the standard. If the standard requires maintenance intervals every 6
years, this is what the auditor should verify. This was also verified in the recent NERC Workshop at
which it was confirmed that “auditors must audit to the standard”. To this end, we also suggest
changes to Requirement R3 as explained in our comments in Question 5.
FE offers the following additional comments and suggestions: We do not agree with the wording of
requirement R3. The entity is only required to meet the minimum maintenance intervals of the
standard as outlined in Tables 1 and 2. We offer a scenario where an entity states that they will go
above the standard and maintain relays on a 4 year cycle. The standard, in meeting an adequate level
of reliability, sates that this activity must be performed every 6 years. If the entity happened to miss
the 4 year timeframe, deciding from a business standpoint to delay the maintenance to the 5th year,
an auditor can find the entity non-compliant per the guidance and wording of the requirements in this
standard. However, the entity still exceeded an adequate level of reliability by performing the
maintenance within 5 years. This scenario would be very unfortunate to the entity that has essentially
done their part in providing reliability to the bulk power system, yet they would be punished for not
meeting their more stringent timeframes. This standard’s guidance and requirements sends an
adverse message to industry. It essentially punishes an entity for going above and beyond the
standard except on a few rare occasions. If this were to happen, that entity, and possibly others,
would not see the value in going above a standard. It would make entities meet the bare minimum
requirements, essentially reducing overall system reliability. Therefore, we suggest the following
wording for requirement R3: “R3. Each Transmission Owner, Generator Owner, and Distribution
Provider shall implement its PSMP to ensure adherence to the minimum requirements as outlined in
Tables 1 and 2, and initiate resolution of any identified maintenance correctable issues.”
Individual
Michael Moltane
ITC
Yes
The re-structured tables are easier to use.
Yes
Yes
No
We agree with the combination of the two. One document with the FAQ’s grouped with the
supplemental topics makes it easier to review the whole topic.
For Battery System: - Table 1-4(a) o The maximum maintenance interval for the majority of the
battery maintenance is listed at “18 calendar months”. The current ITC Standard is “once per calendar
year and a calendar year is defined as a twelve-month period beginning January 1st and ending
December 31st “. ITC would like the maximum maintenance interval at “once per calendar year” -
Table 1-4(b) o VRLA (Valve Regulated Lead Acid) batteries have an additional inspection at 6 calendar
months that includes inspecting the condition of all individual units by measuring the battery cell/unit
internal ohmic values. This is in addition to the “18 calendar months” inspection. ITC would like to be
consistent with the VLA (Vented Lead Acid) batteries and have only one internal ohmic value
inspection once per calendar year. For Battery System: - Table 1-4(a) o The maximum maintenance
interval for the majority of the battery maintenance is listed at “18 calendar months”. The current ITC
Standard is “once per calendar year and a calendar year is defined as a twelve-month period
beginning January 1st and ending December 31st “. ITC would like the maximum maintenance
interval at “once per calendar year” - Table 1-4(b) o VRLA (Valve Regulated Lead Acid) batteries have
an additional inspection at 6 calendar months that includes inspecting the condition of all individual
units by measuring the battery cell/unit internal ohmic values. This is in addition to the “18 calendar
months” inspection. ITC would like to be consistent with the VLA (Vented Lead Acid) batteries and
have only one internal ohmic value inspection once per calendar year. Auxiliary Relays: • ITC does
not agree with the 6 year interval for Aux relays in the trip circuit. Although they are EM relays they
are simple and have very few moving parts. We believe the maintenance period for auxiliary relays
should be 12 years and they should be in conjunction with the control circuit. We recognize that Draft
4 only includes auxiliary relays that are directly in the trip path. That is an improvement in Draft 4. In
general, auxiliary relays are very reliable; only certain relay types have been proven to be
problematic. A known relay type (HEA) has been proven to be problematic if not exercised frequently.
The standard should not require a 6 year interval period for all other auxiliary relays. We believe
problematic relays should be addressed through use of a NERC Alert process. Don’t cut down the tree
for a bad apple.
Individual
Bill Middaugh
Tri-State G&T
On Table 1-2, page 11: The standard describes the following component attributes, “Any unmonitored
communications system necessary for correct operation of protective functions, and not having all the
monitoring attributes of a category below.” How does this apply to redundant communication
systems? If the primary communications channel fails the protective relay automatically fails over to
the back-up channel and continues to function properly. Are redundant communication channels
excluded from this component attribute and associated interval? Please clarify the term correct
operation and how it applies to redundant communication systems.
The draft standard requires the PSMP to include maintenance and testing intervals for Station DC
supply associated with protective functions (including batteries, battery chargers, and non-batterybased dc supply). Does this requirement include DC systems (batteries not included in station
batteries) used by communication systems necessary for the correct operation of protective
functions?
On Page 19, Table 1-5, the standard requires that monitored electromechanical lockouts be
maintained every 6 years. Why is there inconsistency in the interval between the monitored lockouts
and monitored relays?
M1 - Why is the document necessary to be “current or updated?” Eliminate “or updated.” R1 VSL Second item in Severe VSL is not addressed in any lower VSL. Should there also be a comparable
violation in Lower and Moderate? R2 VSL – Keep the comment about the redundancy in Lower VSL
and High VSL for clarifying the difference between the two.
Individual
Don Schmit
Nebraska Public Power District
No
Comments: The restructured tables are indeed an improvement; however the tables still need some
work for clarity: Table 1-5: Unmonitored control circuitry has a maintenance activity of “Verify all
paths of the control and trip circuits.” The wording of “control and trip circuits” leads to circuit
verification of more than just trip circuits. In fact multiple circuits would have to verified, such as
station house load transfer schemes. Providing documentation to an auditor to prove all paths have
been tested will be difficult and is considered excessive. The paperwork required to prove compliance
is extremely excessive for this requirement and doesn’t provide a benefit to reliability. Table 1-5:
Table 1-5 requires trip checking every six calendar years for trip coils and electromechanical lockout
and/or tripping auxiliary devices. Every six years is excessive, when sutiable monitoring is used. We
recommend verification of these components be completed at the same frequency as the associated
relay testing when monitoring is used. For electromechanical, no more than every 6 calendar years,
for microprocessor, no more than 12 calendar years. Table 2: The interrelationship between Tables 11 through 1-5 and Table 2 is ambiguous. Tables 1-1 through 1-5 “component attributes” columns
references Table 2 in many cases as the criteria for maximum interval. However, each table entry has
a maximum maintenance interval listed as well. There are a few instances where the “trump” interval
is not clear. Table 1-5 is a good example. Table 2 states that monitored devices (1-1 through 1-5) not
having monitored alarm paths shall be tested every 12 years. However, Table 1-5 states that DC
circuits with monitored continuity shall have no periodic maintenance. We suspect that Table 2
attributes needs further clarification to eliminate the confusion, both Table 2 attributes at first glance
appear to say the same thing. However, after study it appears to address “detection” monitoring
versus continuous (control center type) monitoring. We believe further distinguishing clarifications are
needed to make it evident and clear.
Group
Western Area Power Administration
Brandy A. Dunn
Yes
Yes
Yes
Yes
Can the SDT add a better definition or clarification of “Calendar Year” as it pertains to PRC-005-2 and
provide examples or parameters of Compliance with the Standard requirements and tables? Calendar
Year is explained in various details within Pages 35-Pages 37 of the Supplementary Reference and
FAQ. This important attribute of a TBM or TBM/CBM combination program is not easily found in the
Table of Contents or section sub-headings.
Please explain or clarify the term “mitigating devices” used in Table 1-5 Control Circuitry, Page 19.
This term is not well defined in the industry and not easily understood as “interrupting device” or
“circuit breaker.”
Group
Luminant
David Youngblood
Yes
No comments
Yes
No comments
Yes
No comments
Yes
The document was valuable in understanding PRC-005-2 by providing clarification using practical
protective relay system examples. Below are two comments for further improvement. 1. It would be
beneficial if the document could provide additional information for relaying in the high-voltage
switchyard (transmission owned) - power plant (generation owned) interface. While Figures 1 and 2
are typical generation and transmission relay diagrams, it would be helpful if protective relays
typically used in the interface also be included. For example, a transmission bus differential would
remove a generator from service by tripping the generator lockout. 2. Figures 1 and 2 refer to a
“Figure 1 and 2 Legend” table which provides additional information on qualifications for relay
components. Should a footnote be used to point toward Reference 1 (Protective System Maintenance:
A Technical Reference) located in Section 16?
The red-lined version did not agree with the clean copy. In reading the "red lined" document it
appears that R3 was intended to be "Each Transmission Owner, Generation Owner, and distribution
Provider shall implement and follow its PSPM and initiate resolution of any identified maintenance
correctable issues."
Group
NextEra Energy
Silvia Parada Mitchell
Yes
Yes
Yes
No
Thank you for your diligent efforts in writing the draft standard. The draft standard and associated
documents are well written and we believe, after approval, will be instrumental to improving the
reliability of the BES. We have the following specific comments: a. The maximum maintenance
interval of unmonitored Vented Lead-Acid (VLA) batteries should be changed from 3 calendar months
to 12 calendar months. Today’s lead-calcium and lead-selenium-low antimony batteries do not have
rapid water loss as compared to the legacy lead-antimony batteries. FPL’s operating experience has
shown that electrolyte in today’s VLA cells do not require watering within a 12-month interval. In fact,
battery manufacturers now recommend watering intervals of 2 to 3 years for some new batteries. b.
The maximum maintenance interval to verify that unmonitored communications systems are
functional should be changed from 3 calendar months to 12 calendar months. FPL’s operating
experience has shown that power line carrier (PLC) failures are primarily due to PLC protective
devices (MOVs, gas tubes & spark gaps). Automated testing such as PLC check-back schemes cannot
test for failed PLC protective devices. We believe a 12 calendar month functional test is sufficient
because of FPL’s operating experience. FPL’s operating experience has shown that power line carrier
(PLC) failures are primarily due to PLC protective devices (MOVs, gas tubes & spark gaps). c. We
believe the data retention requirements for R2 and R3 should be documentation for the two most
recent maintenance activities. d. Regarding Maintenance Correctable Issue (page2) where it states:
“..such that it cannot be restored to functional order during performance of the initial on-site activity”.
This terminology is vague: Particularly” initial on-site activity”. Not sure what “functional order”
means? The suggestion is to change to “..such that the deficiency cannot be restored to meet
applicable acceptance criteria during the performance of the scheduled maintenance activity”. e.
Regarding Maintenance Correctable Issue (page 2) and “R4” on Page 5, the suggestion is an entirely
new “Maintenance Correctable” definition especially: “Therefore this issue requires followup corrective
action”. Regarding this new definition: Why is it here? Is its purpose to ask us to do something with
these issues if we discover them? Do issues identified as “Maint. Correctable” need to be tracked and
reported in some manner? The referenced term “Maint. Correctable” is only used in PRC-005-2 in
“R4” (page 5). The suggestion is to provide clarification. Is this “maintenance cotrrectable
terminology implying that NERC PRC005-2 is opening up a new requirement for tracking and
reporting resolution of “Maint Correctable” issues? The suggestion is to change to: “This issue includes
any activity requiring further follow-up corrective action to restore operability outside of the applicable
maint activity”. f. Regarding Countable Event (Page 3), the suggestion is an entirely new “Countable
Event” definition. Why is this new term and definition “countable event” included in PRC-005-2 ?
Note: In the PRC005-2 text ”countable event” is actually only referred to in PRC-005-2 in Attachment
A under “Performance Based Programs” (not referred to in time based programs section). The
recommendation is that the PRC-005-2 version explicitly clarify the definition of “countable event” to
clearly indicate that this term is applicable ONLY to “Performance Based Programs”. g. Regarding
Countable Event (page 3), where the text says “Any failure of a component which requires repair or
replacement, any condition discovered during the verification activities in Tables 1-1/1-5 which
requires corrective action…..”, in the definition for “countable event” what does “corrective action”
mean? PRC005-2 is unclear. Does the term “countable event” have any ties to “Maint Correctable”
issues. The suggestion is to Consider changing wording from “corrective action” to “which requires >
7 days to correct” and clarify whether or not ”countable event” has any correlation to “Maint
Correctable”events as discussed on page 2 and in R4? If so please provide language clarifying this
correlation.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
No
We commented on this before and we will comment again. The time periods for FERC-jurisdictional
entities and non-jurisdictional entities should have at least a 3-month difference to allow some time
for FERC approval after BoT adoption in an attempt to more or less put the effective dates of the two
groups of entities in the same general time frame. The implementation plan as presented will always
result in an effective date for the non-jurisdictional entities to be at least some months (the time
between BoT adoption and FERC approval) earlier than their jurisdictional counterparts.
No
(1) We do not agree with the High VRF for R3 which asks for implementing the maintenance plan (and
initiate corrective measures) whose development and content requirements (R1 and R2) themselves
have a Medium VRF. Failure to develop a maintenance program with the attributes specified in R1,
and stipulation of the maintenance intervals or performance criteria as required in R2, will render R3
not executable. Hence, we suggest that the VRF for R3 be changed to Medium. (2) The Severe VSL
for R2 is improper. First, the reference to R3 is incorrect. Second, the first condition that says: “Failed
to establish the entire technical justification described within R3 for the initial use of the performancebased PSMP” introduces a requirement not stipulated in R2 itself. We suggest to remove this
condition. If the SDT feels strongly that the technical justification (we’re not sure what exactly it is)
needs to be established for the initial use of the performance-based PSMP, then R2 should be revised
to capture this requirement.
Individual
Martin Kaufman
ExxonMobil Research and Engineering
No
No
No
Yes
The SDT should provide notes that reference the sources used for developing the maximum
maintenance intervals utilized in the time-based program, and provide a technical explanation as to
why they have not provided a tolerance band for use with the time-based program. What is the
increase in risk owned by an entity when a protective device is tested at the 6 year and 30 day mark
instead of the 6 year mark?
PRC-005-2 is a highly prescriptive standard that prevents small entities from establishing a risk-based
approach to protective system maintenance that is commonly used in other industry sectors and
forces the small entity to utilize the time-based program. Many registered entities do not have a
population size of 60 for each type of protective device. However, they do possess historical records
that can be used to calculate the mean time between failures for each equipment type that
adequately reflects the service conditions in which the equipment is installed. The SDT should
consider allowing registered entities to utilize historical records in their supporting documentation for
defining a performance based program. Additionally, by restricting populations by manufacturer
model, as referenced in PRC-005-2 Attachment A, the Standard Drafting Team is bordering on anticompetitive behavior as those entities that utilize performance-based programs may be discouraged
to utilize alternative suppliers because utilization of a time-based maintenance program on the
alternative supplier’s equipment may present a cost-benefit analysis hurdle that the supplier of the
equipment is not able to overcome. Lastly, the SDT has chosen not to provide a tolerance band for
the maximum maintenance intervals it defines in its time-base program. Given that the SDT has not
provided sound technical justification (i.e. a study, industry recommended practice, etc.), the SDT
should reconsider its stance on providing a tolerance band on the time intervals specified in the timebased program. What is the increase in risk owned by an entity when a protective device is tested at
the 6 year and 30 day mark instead of the 6 year mark?
Individual
Gary Kruempel
MidAmerican Energy Company
Yes
Yes
In the background section of the implementation plan in item two it states “...it is unrealistic for those
entities to be immediately in compliance with the new intervals.” Recent compliance application
notices indicate that auditors are requiring entities to include proof of compliance to maintenance
intervals by providing the most recent and prior maintenance dates. The implementation document
could be improved by providing clarity to what is expected with regard to when an entity is expected
to provide evidence of maintenance interval compliance given the quoted item above. As an example
in the section the implementation plan for a 6 year interval item it states: “ The entity shall be at
least 30% compliant on the first day of the first calendar quarter 3 years following applicable
regulatory approval..” In keeping with the previously quoted “reasonableness” criteria it would seem
that 30% compliant would mean only one test action would be needed to be completed by the
indicated deadline and the next one would be required no later than 6 years from that first test. It is
recommended that the implementation plan document be improved to clarify this issue. In addition, it
would seem appropriate to allow entities that decide to implement PRC-005-2 requirements before
the standard becomes effective to count the maintenance they do before the effective date in the
implementation plan schedule and in the testing interval compliance.
Yes
No
Requirement R3 of the standard discusses resolution of “identified maintenance correctable issues”.
M3 requires evidence of “resolution of Maintenance Correctable Issues”. The definition of Maintenance
Correctable Issue in the standard includes “during performance of the initial on-site activity”. The
“initial on-site activity” seems to imply that the corrective steps that need to be tracked are those
resulting from the periodic testing that is done for compliance with the standard. It is not clear if the
SDT meant to require that records be kept of any required maintenance that is done as a result of a
discovered problem or failure that is not identified during the periodic testing.
Individual
Alice Ireland
Xcel Energy
Yes
Regarding the last row of Table 1-4(f): it seems very inconsistent to require a formal trending
program for a manual 6 month(VRLA)/18 month (VLA) internal ohmic reading but to require no
gathering and analysis of data as an alarm for a ohmic value for each cell/unit is available. If just a
raw ohmic value is an adequate predictor of cell life, than why require a trending program for the
manual reading if all that is needed to determine adequacy of remaining cell life is just a simple
acceptance criteria (i.e. - alarm setpoint) against which you need to compare your measured data? In
theory these are very gradual and predictable changes in ohmic readings over the entire life of the
battery, such that the benefit of real time knowledge of exactly when a threshold is reached via alarm
is minimal rather than having to wait until the next manual reading to ascertain that the threshold
limit has been reached.
Yes
Yes
Yes
1) On page 65, paragraph 4, of the “Supplemental reference and FAQ” document, it states: “… the
type of test equipment used to establish the baseline must be used for any future trending of the cells
internal ohmic measurements because of variances in test equipment and the type of ohmic
measurement used by different manufacturer’s equipment.” While we understand the importance of
creating a baseline, it is not feasible to expect the test equipment be the same as the manufacturer’s
test equipment or even the same test equipment over the life of the battery. The expected life of a
battery may be in excess of 20 years and it is not feasible to expect that the type of test equipment
will not change during this period. 2) A FAQ to clarify in scope protection systems for variable energy
resource facilities (wind, solar, etc) would be very helpful. Does paragraph 4.2.5.3 “Facilities” imply
that the only protection system associated with a wind farm that is considered in scope for PRC-005-2
is that for the aggregating transformer? If other protection systems associated with a wind farm are
in scope, please clarify which systems would be in scope for PRC-005-2. For example, a typical wind
farm in our system might have 30-33, 1.5MVA windmills connected to one 34.5 KV collecting feeder
circuit for a total of roughly 50 MVA per collecting feeder. 4 of these 50 MVA collecting feeders are
tied via circuit breakers to a low side 34.5 KV bus which in turn is connected via a low side breaker to
aggregating step up transformer which then connects to the BES transmission system. Obviously per
paragraph 4.2.5.3, the protection system for the aggregating step up transformer is in scope. What
about the protection system for the transformer low side 34.5 KV breaker – serving 200 MVA of
aggregate generation? What about the protection system of each individual 34.5 KV aggregating
feeder – 50 MVA of aggregate generation? What about the “protection system” for each individual 1.5
MVA windmill? An FAQ on this topic would be very helpful.
1) Regarding “Facilities” paragraph 4.2.5, we are in agreement with the elimination from scope of
system connected station service transformers for those plants that are normally fed from a generator
connected station service transformers. However, in the cases where a plant does not have a
generator connected station service transformer such that it is normally fed from a system connected
station service transformer, is it still the drafting team’s intent to exclude the protection systems for
these system connected auxiliary transformers from scope even when the loss of the normal (system
connected) station service transformer will result in a trip of a BES generating facility? If the end
result of the trip of the primary station service transformer is a trip of a BES generating facility, it
would be more consistent to include the protection system for that transformer as in scope – whether
it be connected to the system or to the generator. 2) We recommend the SDT consider an interval of
12 calendar years for the component in row 3, of Table 1-5 on page 19 of the standard. The
maximum maintenance interval for “Electromechanical lockout and/or tripping devices which are
directly in a trip path from the protective relay to the interrupting device trip coil” should be
consistent with the “Unmonitored control circuit” interval which is 12 calendar years. In order to test
the lockout relays, it may be necessary to take a bus outage (due to lack of redundancy and
associated stability issues with delayed clearing). Increasing the frequency of bus outages (with
associated lines or transformers) will also increase the amount of time that the BES is in a less intact
system configuration. Increasing the time the BES is in a less intact system configuration also
increases the probability of a low frequency, high impact event occurring. Therefore, the Maximum
Maintenance Interval should be 12 years for lockout relays. We believe that, as written, the testing of
“each” trip coil and the proposed maintenance interval for lockout testing will result in the increased
amount of time that the BES is in a less intact system configuration. We hope that the SDT will
consider these changes.
Consideration of Comments on the 4th draft of the standard for Protection System
Maintenance and Testing — Project 2007-17
Consideration of Comments on the 4th Draft of Protection System Maintenance and
Testing — Project 2007-17
The Protection System Maintenance and Testing Drafting Team thanks all commenters who
submitted comments on the 4th draft of the Protection System Maintenance standard, its
implementation plan, and the associated reference document. The standard and associated
documents were posted for a 30-day public comment period from April 13, 2011 through
May 13, 2011. Stakeholders were asked to provide feedback on the standard and
associated documents through a special electronic comment form. There were 55 sets of
comments, including comments from more than 176 people from approximately 103
companies representing 10 of the 10 Industry Segments as shown in the table on the
following pages.
All comments submitted may be reviewed in their original format on the standard’s project
page:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
In addition, a successive ballot of the standard was conducted from May 3-13, 2011, and a
non-binding poll of the Violation Risk Factors and Violation Severity Levels was conducted
from May 3-16, 2011 and comments from the ballot and poll have been included in this
report.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is
a NERC Reliability Standards Appeals Process. 1
Summary Consideration of all Comments Received:
Purpose:
The SDT modified the Purpose to state, “To document and implement programs for the
maintenance of all Protection Systems affecting the reliability of the Bulk Electric System
(BES) so that these Protection Systems are kept in working order” in response to previous
Quality Review comments.
Applicability:
Several comments were offered, suggesting that PRC-005-2 needs to be consistent with the
interpretation in Project 2009-17, now implemented as PRC-005-1a, and the SDT modified
Applicability 4.2.1 for better consistency with the interpretation 4.2.1 as shown below:
4.2.1. Protection Systems that are installed for the purpose of detecting faults on BES Elements
(lines, buses, transformers, etc.).
Requirement R1:
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
1
Consideration of Comments on the 4th draft of the standard for Protection System
Maintenance and Testing — Project 2007-17
Requirement R1 was modified as shown below for improved specificity, based on
stakeholder comments:
R1.
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems identified in
Section 4.2.
Tables
Most commenters seemed to agree in general that the restructured tables added clarity, and
some commenters offered assorted suggestions for further improvement. Minor clarifying
changes were made to the Tables themselves, and additional discussion was added to the
“Supplementary Reference and FAQ” to address various comments.
Implementation Plan
Some commenters noted that for entities not subject to regulatory approvals, the
implementation plan should be longer so that all entities have sufficient time for
implementation. The team did modify the Implementation Plan to provide for a lengthened
implementation period for R1 and the less-than-1-calendar-year activities in R2 and R3 to
allow entities not subject to regulatory approvals of 9 additional months following BOT
approvals, and, for the remaining activities, of 12 additional months following BOT
approvals, to be more consistent with the expected Regulatory Approval timelines.
Additionally, all “calendar year” implementation periods were revised to “months” for
additional clarity.
VLSs:
VSLs for Requirement R1
•
Phased VSLs were added to address R1 Part 1.1, which was previously addressed only
as a “Severe” VSL.
•
A reference was added within the R1 VSL to Part 1.3.
•
R1 High VSL was revised to add a reference to Table 2.
VSLs for Requirement R2
•
One element of the R2 VSL was made binary (Severe), rather than “phased” (in two
steps), in response to several comments.
•
Many commenters pointed out an error (which was corrected by the SDT) within the VSL
for R2, where the Lower and High VSLs contained identical text.
VSLs for Requirement R3
•
The R3 VSLs were revised to replace “complete” with “implement and follow” for
consistency with the Requirement.
•
Other minor editorial changes were made throughout the VSLs in response to
comments.
Supplementary Reference and FAQ
•
The commenters were generally supportive of the reference document.
2
Consideration of Comments on the 4th draft of the standard for Protection System
Maintenance and Testing — Project 2007-17
•
Several questions regarding the enforceability of this document were posed, and the
SDT explained that the document is a supporting reference and not enforceable – only
standard requirements are enforceable.
•
A variety of suggestions were offered regarding additional information for the document,
which largely resulted in modifications to the Supplementary Reference document. One
specific suggestion of note (resulting in additional discussion within the document)
requested a FAQ regarding “Calendar Year”.
•
Several commenters posed questions regarding “grace periods” and “PSMPs established
by entities that are more stringent than the requirements within the standard”. No
additional changes were made due to these questions. If an entity develops a PSMP that
includes time intervals that are more stringent than those in the standard, the entity will
be audited against the intervals in its PSMP.
Definitions:
•
Several comments were offered regarding Maintenance Correctable Issues, and resulted
in modifying this definition to be “…such that the deficiency cannot be corrected during
the performance of the maintenance activity …”
Unresolved Minority Views:
•
Many comments were offered objecting to the 3-calendar-month intervals for station dc
supply and communications systems, and suggesting that a 3-calendar-month interval
requires entities to schedule these activities for 2-calendar-months in order to assure
compliance. The SDT did not modify the standard in response to these comments, and
responded that the intervals were appropriate, and that entities should be able to assure
compliance on a 3-calendar-month schedule by using program oversight. The
“Supplementary Reference and FAQ” document was augmented with additional
explanatory text.
•
Several commenters were concerned that an entity has to be “perfect” in order to be
compliant; the SDT responded that NERC Standards currently allow no provision for any
degree of non-performance relative to the requirements.
•
Several commenters continued to insist that “grace periods” should be allowed. The
SDT continued to respond that grace periods would not be measurable.
•
Several comments were offered questioning various aspects of Applicability 4.2.5.4
(generation auxiliary transformers). No changes were made in response to these
comments, and responses were offered illustrating why these transformers are included.
•
Many comments were offered, questioning the propriety of including distribution system
Protection Systems, almost all related to UFLS/UVLS. The SDT explained that these
Protection Systems are appropriate to be included for consistency with legacy standards
PRC-008, PRC-011, and PRC-017, and noted that their inclusion is consistent with
Section 202 of the NERC Rules of Procedure.
•
Several comments were offered, objecting to the 6-calendar-year interval for lockout
and auxiliary relays. The SDT declined to adopt the requested changes, and noted that
these “electromechanical” devices with “moving parts” share failure mechanisms with
electromechanical protective relays and that the intervals should be identical.
3
Consideration of Comments on the 4th draft of the standard for Protection System
Maintenance and Testing — Project 2007-17
Index to Questions, Comments, and Responses
1.
The SDT has restructured the Table for Station DC Supply, separating it into six subtables individually addressing the various different technologies. Do you agree that the
restructured tables provide more clarity? If not, please provide specific suggestions for
improvement. ................................................................................................... 18
2.
The SDT has modified the Implementation Periods within the Implementation Plan. Do
you agree with the changes? If not, please provide specific suggestions for
improvement. ................................................................................................... 39
3.
The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do you
agree with the changes? If not, please provide specific suggestions for improvement. 47
4.
The SDT has incorporated the FAQ document into the “Supplementary Reference”
document and has provided the combined document as support for the Requirements
within the standard. Do you have any specific suggestions for further improvements? 53
5.
If you have any other comments on this Standard that you have not already provided
in response to the prior questions, please provide them here. ................................. 64
4
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Guy Zito
Additional Member
Northeast Power Coordinating Council
Additional Organization
2
3
4
5
6
7
8
9
10
X
Region Segment Selection
1. Alan Adamson
New York State Reliablity Council, LLC
NPCC 10
2. Gregory Campoli
New York Independent System Operator
NPCC 2
3. Kurtis Chong
Independent Electricity System Operator
NPCC 2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7. Brian Evans-Mongeon Utility Services
NPCC 8
8. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
9. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
10. Kathleen Goodman
ISO - New England
NPCC 2
11. Chantel Haswell
FPL Group, Inc.
NPCC 5
12. David Kiguel
Hydro One Networks Inc.
NPCC 1
13. Michael R. Lombardi
Northeast Utilities
NPCC 1
14. Randy MacDonald
New Brunswick Power Transmission
NPCC 1
5
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
15. Bruce Metruck
New York Power Authority
NPCC 6
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
19. Saurabh Saksena
National Grid
NPCC 1
20. Michael Schiavone
National Grid
NPCC 1
21. Wayne Sipperly
New York Power Authority
NPCC 5
22. Donald Weaver
New Brunswick System Operator
NPCC 1
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Group
Marie Knox
Additional Member
MISO Standards Collaborators
Additional Organization
NIPSCO
RFC
6
2. Gary Carlson
Michigan Public Power Agency RFC
3
3.
Additional Member
Mike Garton
Electric Market Policy
Additional Organization
Dominion Resources Services, Inc. SERC
3
2. Michael Crowley
Dominion Virginia Power
1
3. Louis Slade
Group
SERC
Dominion Resources Services, Inc. RFC
Terry L. Blackwell
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
Region Segment Selection
1. Michael Gildea
4.
3
Region Segment Selection
1. Joe O'Brien
Group
2
6
Santee Cooper
Additional Member Additional Organization Region Segment Selection
1. S. T. Abrams
Santee Cooper
SERC
1
2. Glenn Stephens
Santee Cooper
SERC
1
3. Rene Free
Santee Cooper
SERC
1
4. Kevin Bevins
Santee Cooper
SERC
1
5. Bridgett Coffman
Santee Cooper
SERC
1
6
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
BPA, Transmission, SPC Technical Svcs
WECC 1
2. Jason Burt
BPA, Transmission, RAS and Data Systems
WECC 1
3. Robert France
BPA, Transmission, PSC Technical Svcs
WECC 1
4. Mason Bibles
BPA, Transmission, Sub Maint and HV Engineering WECC 1
5. Deanna Phillips
BPA, Transmission, FERC Compliance
Group
Jonathan Hayes
Additional Member
SPP reliability standard development Team
Additional Organization
Oklahoma Gas and Electric
SPP
1, 3, 5
Grand Rvier Dam Authority
SPP
1, 3, 5
3. James Hutchinson
Oklahoma Gas and Electric
SPP
1, 3, 5
4. Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5
5. Rick Bartlett
Independence Power & Light
SPP
1, 3, 5
6. Sean Simpson
Board of Public Utilities, City of McPherson SPP
1, 3, 5
7. Mark Wurm
Board of Public Utilities, City of McPherson SPP
1, 3, 5
8. Joe Border
Board of Public Utilities, City of McPherson SPP
1, 3, 5
9. Michelle Corley
CLECO
1, 3, 5, 6
David Thorne
5
X
6
7
8
9
10
X
X
Region Segment Selection
2. Edwin Averill
Group
X
4
WECC 1
1. David Reilly
7.
X
3
Region Segment Selection
1. Dean Bender
6.
2
SPP
Pepco Holdings Inc
X
X
Additional Member Additional Organization Region Segment Selection
1. Carlton Bradshaw
8.
Group
Additional Member
Atlantic Electric
Dave Davidson
Additional Organization
1
Tennessee Valley Authority
X
X
Region Segment Selection
1. David Thompson
River Operations Engineering SERC
NA
2. Frank Cuzzort
Nuclear Power Engineering
NA
SERC
7
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Robert Brown
Nuclear Power Engineering
SERC
NA
4. Robert Mares
Fossil Power Engineering
SERC
NA
5. Paul Barlett
Transmission O&M Support
SERC
NA
6. Pat Caldwell
Transmission O&M Support
SERC
NA
7. Rusty Hardison
Transmission O&M Support
SERC
NA
8. Jerry Findley
Communications/SCADA
SERC
NA
Jose Landeros
Imperial Irrigation District
9.
Group
2
3
X
X
X
X
4
X
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Epifanio Martinez
WECC
2. Fernando Gutierrez
WECC
3. Gerardo Landeros
WECC
4. Tony Allegranza
10.
Group
Additional Member
WECC
Ron Sporseen
PNGC Comment Group
Additional Organization
X
Region Segment Selection
1. Bud Tracy
Blachly-Lane Electric Cooperative
WECC 3
2. Dave Markham
Central Electric Cooperative
WECC 3
3. Roman Gillen
Consumer's Power Inc.
WECC 3
4. Roger Meader
Coos-Curry Electric Cooperative
WECC 3
5. Dave Hagen
Clearwater Electric Cooperative
WECC 3
6. Dave Sabala
Douglas Electric Cooperative
WECC 3
7. Bryan Case
Fall River Electric Cooperative
WECC 3
8. Rick Crinklaw
Lane Electric Cooperative
WECC 3
9. Michael Henry
Lincoln Electric Cooperative
WECC 3
10. Richard Reynolds
Lost River Electric Cooperative
WECC 3
11. Jon Shelby
Northern Lights Electric Cooperative WECC 3
12. Ray Ellis
Okanogan Electric Cooperative
WECC 3
13. Aleka Scott
PNGC Power
WECC 4
8
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
14. Heber Carpenter
Raft River Electric Cooperative
WECC 3
15. Ken Dizes
Salmon River Electric Cooperative
WECC 3
16. Steve Eldrige
Umatilla Electric Cooperative
WECC 3
17. Marc Farmer
West Oregon Electric Cooperative
WECC 3
18. Margaret Ryan
PNGC Power
WECC 8
19. Stuart Sloan
Consumer's Power Inc.
WECC 1
20. Rick Paschal
PNGC Power
WECC 3
11.
Group
Additional Member
Additional Organization
Omaha Public Utility District
MRO
1, 3, 5, 6
American Transmission Company
MRO
1
3. Tom Webb
Wisconsin Public Service Corporation MRO
3, 4, 5, 6
4. Jodi Jenson
Western Area Power Administration
MRO
1, 6
5. Ken Goldsmith
Alliant Energy
MRO
4
6. Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
7. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
8. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
9. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
10. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
11. Scott Nickels
Rochester Public Utilties
MRO
4
12. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
13. Richard Burt
Minnkota Power Cooperative, Inc.
MRO
1, 3, 5, 6
Daniel Herring
4
5
6
7
8
9
10
X
Region Segment Selection
2. Chuck Lawrence
Group
3
MRO's NERC Standards Review
Subcommittee
Carol Gerou
1. Mahmood Safi
12.
2
The Detroit Edison Company
X
X
X
Additional Member Additional Organization Region Segment Selection
1. David A Szulczewski Engineering
RFC
3, 4, 5
2. Steven P Kerkmaz
RFC
3, 4, 5
Engineering
9
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Nicole M Syc
13.
Group
Engineering
Albert DiCaprio
RFC
2
3
4
5
6
7
8
9
10
3, 4, 5
ISO/RTO Standards Review Committee
X
Additional Member Additional Organization Region Segment Selection
1. Terry Bilke
MISO
RFC
2
2. Patrick Brown
PJM
RFC
2
3. Greg Campoli
ISO-NY
NPCC
2
4. Mike Falvo
IESO
NPCC
2
5. Matt Goldberg
ISO-NE
NPCC
2
6. Kathleen Goodman ISO-NE
NPCC
2
7. Ben Li
IESO
NPCC
2
8. Steve Myers
ERCOT
ERCOT 2
9. Bill Phillips
MISO
RFC
10. Mark Thompson
AESO
WECC 2
11. Don Weaver
NBSO
NPCC
2
12. Mark Westendorf
MISO
RFC
2
SPP
SPP
2
13. Charles Yeung
14.
Group
Sam Ciccone
2
FirstEnergy
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
2. Jim Kinney
FE
RFC
1
3. Brian Orians
FE
RFC
5
4. Ken Dresner
FE
RFC
5
5. Bill Duge
FE
RFC
5
6. Craig Boyle
FE
RFC
1
7. Mark Pavlick
FE
RFC
1, 3, 4, 5, 6
8. Lenny Lee
FE
RFC
1
9. J. Chmura
FE
RFC
1
10
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10. Rusty Loy
FE
RFC
5
11. Hugh Conley
FE
RFC
1
FE
RFC
1
12. Frank Hartley
15.
Individual
Cynthia S. Bogorad
Transmission Access Policy Study Group
X
16.
Individual
Brandy A. Dunn
Western Area Power Administration
X
17.
Individual
David Youngblood
Luminant
18.
Individual
Silvia Parada Mitchell
NextEra Energy
19.
Individual
David Youngblood
Luminant
20.
Individual
Jim Eckelkamp
Progress Energy
21.
Individual
Steve Rueckert
Western Electricity Coordinating Council
Individual
Janet Smith, Regulatory
Affairs Supervisor
Arizona Public Service Company
23.
Individual
Robert W. Kenyon
NERC - EA & I
24.
Individual
Daniel Duff
Liberty Electric Power LLC
25.
Individual
Russ Schneider
FHEC
26.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
27.
Individual
Beth Young
Tampa Electric Company
22.
2
3
X
4
X
5
X
6
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
28.
Individual
Joe O'Brien
NIPSCO
X
29.
Individual
Linda Jacobson
Farmington Electric Utility System
30.
Individual
Greg Rowland
Duke Energy
31.
Individual
Steve Alexanderson
Central Lincoln
32.
Individual
Bob Thomas
Illinois Municipal Electric Agency
33.
Individual
Joe Petaski
Manitoba Hydro
34.
Individual
Mike Hancock
Shermco Industries
35.
Individual
Michael Crowley
Dominion Virginia Power
X
36.
Individual
Edward J Davis
Entergy Services
37.
Individual
Thad Ness
38.
Individual
39.
2
3
4
X
5
6
X
X
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
American Electric Power
X
X
X
X
Jose H Escamilla
CPS Energy
X
Individual
Melissa Kurtz
US Army Corps of Engineers
X
40.
Individual
Kenneth A. Goldsmith
Alliant Energy
41.
Individual
Kirit Shah
Ameren
42.
Individual
Rex Roehl
Indeck Energy Services
43.
Individual
Kevin Luke
Georgia Transmission Corporation
X
X
X
X
X
X
X
X
12
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
44.
Individual
Andrew Z Pusztai
American Transmission Company, LLC
X
45.
Individual
John Bee
Exelon
X
46.
Individual
Glen Sutton
AtCO Electric ltd
X
47.
Individual
Claudiu Cadar
GDS Associates
X
48.
Individual
Gerry Schmitt
BGE
X
49.
Individual
Michael Moltane
ITC
X
50.
Individual
Bill Middaugh
Tri-State G&T
X
51.
Individual
Don Schmit
Nebraska Public Power District
X
52.
Individual
Michael Falvo
Independent Electricity System Operator
53.
Individual
Martin Kaufman
ExxonMobil Research and Engineering
X
54.
Individual
Gary Kruempel
MidAmerican Energy Company
X
X
X
55.
Individual
Alice Ireland
Xcel Energy
X
X
X
X
X
X
X
6
7
8
9
10
X
X
X
X
13
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
The following balloters submitted comments either with a comment form or with their ballot:
Balloter
Edward P. Cox
Brock Ondayko
Kenneth Goldsmith
Kirit S. Shah
Paul B. Johnson
Company
AEP Marketing
AEP Service Corp.
Alliant Energy Corp. Services, Inc.
Ameren Services
American Electric Power
6
7
8
9
10
11
Jason Shaver
Robert D Smith
John Bussman
Joseph S. Stonecipher
Donald S. Watkins
Francis J. Halpin
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Beaches Energy Services
Bonneville Power Administration
Bonneville Power Administration
1
1
1
1
1
5
12
13
14
15
16
17
William Mitchell Chamberlain
Steve Alexanderson
Matt Culverhouse
Linda R. Jacobson
Gregg R Griffin
Paul Morland
California Energy Commission
Central Lincoln PUD
City of Bartow, Florida
City of Farmington
City of Green Cove Springs
Colorado Springs Utilities
9
3
3
3
3
1
18
19
20
21
22
23
Christopher L de Graffenried
Peter T Yost
Wilket (Jack) Ng
Nickesha P Carrol
Brenda Powell
Amir Y Hammad
Consolidated Edison Co. of New York
Consolidated Edison Co. of New York
Consolidated Edison Co. of New York
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Constellation Power Source Generation, Inc.
1
3
5
6
6
5
24
25
26
David A. Lapinski
David Frank Ronk
James B Lewis
Consumers Energy
Consumers Energy
Consumers Energy
3
4
5
1
2
3
4
5
Segment
6
5
4
1
1
14
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
27
28
29
Kenneth Parker
Joel T Plessinger
Terri F Benoit
Entegra Power Group, LLC
Entergy
Entergy Services, Inc.
5
3
6
30
31
32
33
34
35
Robert Martinko
Kevin Querry
Kenneth Dresner
Mark S Travaglianti
Dennis Minton
Frank Gaffney
FirstEnergy Energy Delivery
FirstEnergy Solutions
FirstEnergy Solutions
FirstEnergy Solutions
Florida Keys Electric Cooperative Assoc.
Florida Municipal Power Agency
1
3
5
6
1
4
36
37
38
39
40
41
David Schumann
Richard L. Montgomery
Thomas E Washburn
Luther E. Fair
Claudiu Cadar
Guy Andrews
Florida Municipal Power Agency
Florida Municipal Power Agency
Florida Municipal Power Pool
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia System Operations Corporation
5
6
6
1
1
4
42
43
44
45
46
47
Gordon Pietsch
Gwen Frazier
Ronald D. Schellberg
Bob C. Thomas
Rex A Roehl
Michael Moltane
1
3
1
4
5
1
48
49
50
51
52
Garry Baker
Stan T. Rzad
Larry E Watt
Mace Hunter
Paul Shipps
Great River Energy
Gulf Power
Idaho Power Company
Illinois Municipal Electric Agency
Indeck Energy Services, Inc.
International Transmission Company
Holdings Corp
JEA
Keys Energy Services
Lakeland Electric
Lakeland Electric
Lakeland Electric
53
54
55
56
Daniel Duff
Brad Jones
Mike Laney
Joseph G. DePoorter
Liberty Electric Power LLC
Luminant Energy
Luminant Generation Company LLC
Madison Gas and Electric Co.
5
6
5
4
3
1
1
3
6
15
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
57
58
59
Joe D Petaski
Greg C. Parent
Mark Aikens
Manitoba Hydro
Manitoba Hydro
Manitoba Hydro
1
3
5
60
61
62
63
64
65
Daniel Prowse
Jason L. Marshall
John S Bos
Saurabh Saksena
Arnold J. Schuff
Gerald Mannarino
Manitoba Hydro
Midwest ISO, Inc.
Muscatine Power & Water
National Grid
New York Power Authority
New York Power Authority
6
2
3
1
1
5
66
67
68
69
70
71
Guy V. Zito
William SeDoris
Joseph O'Brien
John Canavan
Douglas Hohlbaugh
Mark Ringhausen
Northeast Power Coordinating Council, Inc.
Northern Indiana Public Service Co.
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Edison Company
Old Dominion Electric Coop.
10
3
6
1
4
4
72
73
74
75
76
77
Margaret Ryan
Sandra L. Shaffer
Tom Bowe
John C. Collins
Terry L Baker
Carol Ballantine
Pacific Northwest Generating Cooperative
PacifiCorp
PJM Interconnection, L.L.C.
Platte River Power Authority
Platte River Power Authority
Platte River Power Authority
8
5
2
1
3
6
78
79
80
David Thorne
Jerzy A Slusarz
Henry E. LuBean
1
5
4
81
82
Steven Grega
Greg Lange
Potomac Electric Power Co.
PSEG Power LLC
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County
83
84
85
86
Terry L. Blackwell
Lewis P Pierce
Suzanne Ritter
Pawel Krupa
Santee
Santee
Santee
Seattle
1
5
6
1
Cooper
Cooper
Cooper
City Light
5
3
16
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
87
88
89
Dana Wheelock
Hao Li
Michael J. Haynes
Seattle City Light
Seattle City Light
Seattle City Light
3
4
5
90
91
92
93
94
95
Dennis Sismaet
Horace Williamson
William D Shultz
Scott M. Helyer
Larry Akens
George T. Ballew
Seattle City Light
Southern Company
Southern Company Generation
Tenaska, Inc.
Tennessee Valley Authority
Tennessee Valley Authority
6
1
5
5
1
5
96
97
98
99
100
101
Marjorie S. Parsons
Keith V Carman
Janelle Marriott
Barry Ingold
John Tolo
Melissa Kurtz
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tri-State G & T Association, Inc.
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
U.S. Army Corps of Engineers
6
1
3
5
1
5
102
103
104
105
106
107
Martin Bauer P.E.
Ric Campbell
Louise McCarren
Linda Horn
James R. Keller
Anthony Jankowski
U.S. Bureau of Reclamation
Utah Public Service Commission
Western Electricity Coordinating Council
Wisconsin Electric Power Co.
Wisconsin Electric Power Marketing
Wisconsin Energy Corp.
5
9
10
5
3
4
108
109
James A Ziebarth
Kristina M. Loudermilk
Y-W Electric Association, Inc.
4
8
17
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
1. The SDT has restructured the Table for Station DC Supply, separating it into six sub-tables individually
addressing the various different technologies. Do you agree that the restructured tables provide more clarity?
If not, please provide specific suggestions for improvement.
Summary Consideration: Most commenters seemed to agree in general that the restructured tables added clarity, and some
commenters offered assorted suggestions for further improvement. Minor clarifying changes were made to the Tables
themselves, and additional discussion was added to the “Supplementary Reference and FAQ” to address various comments.
A number of commenters continued to object to the “3 Calendar Month” maintenance intervals, and the SDT chose not to
modify the standard. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type
activities of unmonitored battery systems and suggestions to extend the maintenance intervals to 6 or 18 months were not
adopted.
Some comments suggested extending the interval to 4 months. Additional discussion (including an example) regarding this
item was added to Section 7.1 of the “Supplementary Reference and FAQ”. As explained in the reference, a calendar month
begins on the first day of a new month following the month in which the activity was performed. Thus every “3 Calendar
Months” means to add 3 months from the last time the activity was performed.
Specific changes made to the tables in response to comments:
Tables 1-1 and 1-3 – References to Table 2 were corrected.
Table 1-4(a) and Table 1-4(d) – Modified header to clarify, “Protection System Station dc supply”
Table 1-4(b) and Table 1-4(c) - Modified header and component attributes to clarify, “Protection System Station dc supply”
Table 1-4(e) - Modified header and component attributes to clarify, “Protection System Station dc supply” and replaced,
“distribution breakers” with “non-BES interrupting devices”.
Table 1-4(f) - Modified header to clarify, “Protection System Station dc supply”, modified the seventh table entry for clarity, and
added eighth table entry.
Table 1-5 – Added “Associated with Protective Functions” to header
Organization
Tri-State G & T Association, Inc.
Yes or No
Ballot
Question 1 Comment
On Table 1-2, page 11: The standard describes the following component attributes, “Any unmonitored
18
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
(3) (5)
Comment –
Affirmative
communications system necessary for correct operation of protective functions, and not having all the
monitoring attributes of a category below.” How does this apply to redundant communication systems? If the
primary communications channel fails the protective relay automatically fails over to the back-up channel and
continues to function properly. Are redundant communication channels excluded from this component
attribute and associated interval? Also, if a relay is set to operate in a manner typical when communication is
not used for protection (i.e. defaulting to step-distance functions with a loss of communication), is the
defaulted operation of the relay considered “correct operation” thereby excluding the communication as
necessary for its correct operation?
Please clarify the term correct operation and how it applies to redundant communication systems and/or the
performance of the relay in the absence of communication.
Response: Thank you for your comments. If communication-assisted protection is provided as described in the Applicability of PRC-005-2, it must be tested in
accordance with the intervals and activities described in the standard. Redundant equipment and/or channels do not relieve the entity of the responsibility to
maintain all equipment as required. An entity is entitled to use any monitoring present on the communications system to adjust its maintenance as established
within Table 1-2, and, if sufficient component populations are present and the entity wishes to address the additional included requirements, performance-based
maintenance is also available.
Correct operation of the protective function means that if the communications system is part of the protection system and loss of it causes the system to fail to
meet the schemes protection requirements it has failed. In the example you provide, loss of communications would result in time delay clearing depending on
location of the fault. If time delay clearing will be sufficient for your system clearing time requirements, then high speed clearing is not required and the Comm.
System would not need to be installed. If it is installed, you must meet the PRC-005 requirements. Redundant communications schemes are installed where high
speed clearing is required to meet planning criteria. The second scheme is in place to prevent the line from being removed from service if the primary scheme
must be maintained or fails. If redundant schemes are in place, both must meet the PRC-005 standard.
Tri-State G&T
On Table 1-2, page 11: The standard describes the following component attributes, “Any unmonitored
communications system necessary for correct operation of protective functions, and not having all the
monitoring attributes of a category below.” How does this apply to redundant communication systems? If the
primary communications channel fails the protective relay automatically fails over to the back-up channel and
continues to function properly. Are redundant communication channels excluded from this component
attribute and associated interval? Please clarify the term correct operation and how it applies to redundant
communication systems.
Response: Thank you for your comments. If communication-assisted protection is provided as described in the Applicability of PRC-005-2, it must be tested in
accordance with the intervals and activities described in the standard. Redundant equipment and/or channels do not relieve the entity of the responsibility to
maintain all equipment as required. An entity is entitled to use any monitoring present on the communications system to adjust its maintenance as established
19
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
within Table 1-2, and, if sufficient component populations are present and the entity wishes to address the additional included requirements, performance-based
maintenance is also available.
Correct operation of the protective function means that if the communications system is part of the protection system and loss of it causes the system to fail to
meet the schemes protection requirements it has failed. In the example you provide, loss of communications would result in time delay clearing depending on
location of the fault. If time delay clearing will be sufficient for your system clearing time requirements, then high speed clearing is not required and the Comm.
System would not need to be installed. If it is installed, you must meet the PRC-005 requirements. Redundant communications schemes are installed where high
speed clearing is required to meet planning criteria. The second scheme is in place to prevent the line from being removed from service if the primary scheme
must be maintained or fails. If redundant schemes are in place, both must meet the PRC-005 standard.
Consumers Energy (4)
Ballot
Comment Negative
Relating to Table 1-3, The SDT has advised that the voltage and current inputs must be checked at each
individual relay. This may not be difficult if the relays are microprocessor relays (where internal metering may
be used), but for the predominant population of electromechanical relays (particularly for current signals), this
requirement will necessitate repeated operation of test switches and associated insertion of meters. Such
activities will not only be very difficult and time consuming, but will actually be dangerous because of the
dangers of accidentally opening current circuits during testing. It should be sufficient to verify the integrity of
the series string of protective relays, etc during maintenance activities, as all devices within the series string
will be receiving the same values.
Response: Thank you for your comments. Entities can choose how to best manage their risk. If online testing is deemed too risky, offline tests such as, but not
limited to, secondary injection, CT excitation test and PT turns ratio tests can be compared to baseline data and be used in conjunction with CT and PT secondary
wiring insulation verification tests to adequately “verify the current and voltage circuit inputs from the voltage and current sensing devices to the protective relays”.
Tri-State G & T Association, Inc.
(3) (5)
Ballot
Comment Affirmative
The draft standard requires the PSMP to include maintenance and testing intervals for Station DC supply
associated with protective functions (including batteries, battery chargers, and non-battery-based dc supply).
Does this requirement include DC systems (batteries not included in station batteries) used by communication
systems necessary for the correct operation of protective functions?
Response: Thank you for your comments. No, an independent DC Supply related only to communication equipment is not considered to be “station dc supply”.
The periodic functional observation and testing of the communications equipment is included, but there are no requirements for the independent dc supply.
Wisconsin Electric Power Co. (5)
Wisconsin Electric Power
Ballot
Comment Negative
(1) The maximum maintenance intervals listed in various PRC-005-2 tables are described as “calendar years”
which is an undefined term. Since maintenance intervals are critical to this standard, this term should be
either clearly defined or explained in the standard. For example, if a component was last tested on
6/1/2005; does that component need to be tested by 6/1/2011 or 12/31/2011 to satisfy its 6 calendar year
20
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Marketing (3)
Wisconsin Energy Corp. (4)
Question 1 Comment
maximum maintenance interval?
2) Clarification and/or direction is desired on the testing of protection systems that contain components owned
by various entities. For example, in the instance of non-vertical integrated utilities where a distribution
provider has a Protection System that directly trips a transmission owner’s circuit breaker(s), how would
the distribution provider verify that the trip coil is able to operate the circuit breaker?
(3) Maximum testing intervals are defined. Does this imply that there are no minimum testing intervals? In
other words, is the maintenance cycle reset anytime maintenance is performed?
(4) Requirement R1.1.2 states that” “All batteries associated with the station dc supply component type of a
Protection System shall be included in a time-based program as described in Table 1-4.” Yet, in Table 1-4
under Component Attributes it refers to “…not having monitoring attributes of Table 1-4(f).” Suggest this
statement be made more clear by adding “All batteries associated with the station dc supply component
type of a Protection System shall be included in a time-based program as described in Table 1-4., unless
the dc supply has the monitoring attributes listed in Table 1-4(f).”
(5) Suggest the inspection Maximum Maintenance Interval for inspection of batteries be 4 months instead of 3
months to allow for workforce constraints that may preclude an inspection being performed within a 3
month window. Every 3 months has been found to be more than adequate to observe changing
conditions that affect batteries, therefore we feel 4 months would still be sufficient.
(6) In Tables 1-4 (a), (b), (c) – What is your interpretation of battery continuity? In other words, what
measurements or indications would be acceptable to affirm an acceptable condition? Table 1-4(b) VRLA
batteries, Maximum Maintenance Interval 18 Calendar Months, Maintenance Activities, Verify: Battery
terminal connection resistance, Verify: Battery intercell or unit-to-unit connection resistance - comment:
Add the following qualifier to these resistance checks: "If battery posts are not readily accessible or too
small to allow a good connection, follow the manufacturer's recommendation(s)."
Response: Thank you for your comments.
1. A “calendar year” refers to the years on the Julian calendar commonly used, and should be regarded as referring to a numbered year, comprising the months of
January through December. For example, 2010 is one calendar year; 2011 is another. A component, with a 6-year interval, which was last tested in 2005, would
next have to be tested by the end of 2011.
2. The standard does not prescribe “how” an entity must meet the requirements, only that the requirements must be met. However, all entities listed in the
Applicability are “owner entities”, and the SDT believes that the owner of the component should be responsible for its maintenance. However, it may be necessary
to have records relating to specific activities from the associated entity in order to demonstrate compliance to an auditor.
3. No minimum intervals are provided. To the degree that any maintenance includes all required activities, that maintenance can be recorded as addressing the
21
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
standard and re-setting the interval.
4. A “time-based” program includes extended intervals for those activities that can be effectively performed by condition monitoring. However, this requirement
excludes an entity from utilizing performance-based maintenance per R3 and Attachment A.
5. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities. The SDT believes that an entity may schedule
activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the intervals should be extended.
The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. See Section 7.1 of the
“PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about “calendar month”
6. In Section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT gives its interpretation of battery continuity and lists
several examples of measurements or indications that would be acceptable to affirm an acceptable condition and contains a discussion of connection resistance.
Your comment concerning the inaccessibility of posts or being too small would fit more appropriately as a qualifier there than in the in the standard itself.
Tennessee Valley Authority (1)
(5) (6)
Ballot
Comment Negative
In Table 1-4(a), the requirement to perform battery cell internal ohmic measurements every 18 months for
vented lead-acid batteries is excessive, and no technical justification is provided for an 18-month interval. A 3year internal ohmic test frequency is adequate to prove battery integrity. IEEE 450 does not provide a
recommended interval for internal ohmic measurements. For standard capacity testing, the recommended
interval is no greater than 25% of expected battery life. Our normal battery life is 20+ years, so the
recommended capacity test interval would be about 5 years. EPRI also recommends capacity testing at 5
year intervals. There is no justification for performing internal ohmic measurements every 18 months (which
equals every 7.5% interval of the expected battery life). We feel the standard should set the interval for
battery internal cell ohmic testing at 3 years.
Response: Thank you for your comments. The Maintenance Activity of evaluating the measured cell/unit internal ohmic values to station battery baseline is an
optional activity to verify that the station battery can perform as designed. An owner who desires not to take internal ohmic measurements on a Vented Lead-Acid
(VLA) battery can elect to verify that the station battery can perform as designed by conducting a performance, service, or modified performance capacity test of
the entire battery bank without ever having to perform any internal ohmic measurement on the battery. The maximum maintenance interval for performing this
capacity test on a VLA battery bank is 6 Calendar Years. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” - that
was posted for review with PRC-005-2 - the SDT answered several Frequently Asked Questions which explain why the 18 month Maximum Maintenance Interval
is justified rather than the 3 year frequency that is assumed by some to be adequate.
Great River Energy (1)
Ballot
Comment Affirmative
1. Table 1-4(b) VRLA Batteries---both” 6 Calendar Months” in the table should be changed to 12 months. This
would avoid being in violation if we miss a bank during a “6 month maintenance cycle”
2. Table 1-4(c) Nickel-Cadmium Batteries under the Maintenance Activities column for the 6 Calendar Years-- This maintenance activity should be optional if 18 Calendar Month Activities are completed. Or increase
load test to 10 years.
22
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments.
1. In the IEEE recommended Practice for Maintenance, Testing and Replacement of VRLA batteries (IEEE SDT 1188) a quarterly inspection should include
“Cell/unit internal ohmic values.” Based on this recommendation the SDT believes that extending the Maximum Maintenance Interval of 6 Calendar Months in
Table 1-4(b) to 12 months as suggested would be too excessive. The 6 Calendar Months for this maintenance activity will allow an entity to avoid being in
violation if they miss a bank by a few days during the quarterly maintenance cycle.
2. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT answered a Frequently Asked Question explaining
why the 6 Calendar Year maintenance activity cannot be optional if the 18 Calendar Month Activity of Table 1-4(c) is performed. The SDT also in the
Supplemental Reference & FAQ document justifies why the 6 Calendar Year Maximum Maintenance interval for performing the Maintenance Activity in Table 14(c) can not be extended to 10 years as suggested.
AtCO Electric ltd
Table 1-4: ATCO Electric has a number of remote substations that are difficult to access.
1. The requirement for a 3 calendar month inspection for electrolyte level is too frequent. The requirement
would become achievable if electrolyte level inspections were moved to the 18 calendar months category,
or if the 3 calendar months frequency were increased to 8 calendar months.
2. Table 1-4(b): for the same reasons, the requirement of a 6 calendar month inspection of individual battery
cell/unit internal ohmic values is too frequent. The requirement would become achievable if battery cell/unit
internal ohmic value inspections were moved to the 18 calendar months category, or if the 6 calendar
months frequency were increased to 14 calendar months.
3. Table 1-4(c): the requirement of a 6 calendar year performance service or modified performance capacity
test should be removed. From our experience, there is no benefit in doing battery load tests. Instead, we
apply verification of battery intercell resistance as a more efficient method of monitoring battery condition,
which provides an 8 to 14 month lead time to replace a battery unit/cell before it goes dead.
Response: Thank you for your comments.
1. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval. If adequate program oversight is exercised, and disagrees that the intervals should be
extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about “calendar month”.
2. In the IEEE recommended Practice for Maintenance, Testing and Replacement of VRLA batteries (IEEE SDT 1188) a quarterly inspection should include
“Cell/unit internal ohmic values.” Based on this recommendation the SDT believes that extending the Maximum Maintenance Interval of 6 Calendar Months in
Table 1-4(b) to the 18 calendar months category as suggested would be excessive and the SDT notes that this verification may be possible via monitoring
methods.”(See Table 1-4(f), component attribute row “Any lead acid battery based …”). The 6 Calendar Months for this maintenance activity will allow an entity to
avoid being in violation if they miss a bank by a few days during the quarterly maintenance cycle.
23
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
3. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT answered a Frequently Asked Question explaining
why the 6 Calendar Year maintenance activity cannot be optional if the 18 Calendar Month Activity of Table 1-4(c) is performed. The SDT also in the
Supplemental Reference & FAQ document justifies why the 6 Calendar Year Maximum Maintenance interval for performing the Maintenance Activity in Table 14(c) can not be removed as suggested.
Kristina M. Loudermilk (8)
Ballot
Comment Affirmative
1) In Table 1-4(b) under the Component Attributes, the sentence begins with Station dc supply; while the
other 1-4 tables begin with Protection System Station dc. I propose to make it consistent with the other
tables.
2) Table 1-4(e) mentions Maximum intervals and references another table. Is there an easier way in the
Standard to send the same information without having them flip pages? As another example in every
Component Attribute in Table 1-4(f) we mention (See Table 2). Could it be possible to make that a note,
instead of placing it under each attribute? It seems overwhelming when looking at these and for each one
that is read, flip over to Table 2. I feel like some of these references give the feel of a scavenger hunt. I am
not sure if anything can be done, but thought I would mention it.
Response: Thank you for your comments.
1.The Tables have been modified to use “Protection System Station dc supply”
2. In this regard, the SDT has tried several methods of presentation for this information. Of all methods reviewed, including the one you suggest, the SDT has
determined that the method currently represented in the Tables represents the best compromise.
Consumers Energy (4)
Ballot
Comment Negative
Relative to the 18-month activity to measure battery terminal connection resistance in Table 1-4, measuring
the battery terminal connection resistance for all terminals of the battery is an involved process that may force
the battery (and thus the system) out-of-service, or alternatively the use of a temporary battery, for the
duration of the activity. We suggest that a 6-year interval for this involved and invasive activity is appropriate
and adequate. We also suggest that it should alternatively be sufficient to instead re-torque all battery
terminal connections at the same interval.
Response: Thank you for your comments. In IEEE Standards 450, 1188, and 1106 for vented lead-acid (VLA), valve-regulated lead-acid (VRLA) and nickelcadmium (NiCd) batteries respectively state that a “yearly inspection” should include “Cell-to-cell and terminal connection resistance”, “Cell-to-cell and detail
resistance of entire battery”, and “Condition and resistance of cable connections.” Based on these IEEE recommendations the SDT believes that the Maximum
Maintenance Interval of 18 Calendar Months for this Maintenance activity will allow an entity to avoid being in violation if they miss a bank by a few weeks during
the yearly maintenance cycle.
In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” - that was posted for review with PRC-005-2 - the SDT explains
what hazards can result from high connection resistance. Also in the Supplementary Reference the SDT references where in the IEEE Standards entities can find
excellent information and examples of performing this non-intrusive Maintenance Activity. The SDT respectively disagrees with the premise that the activity to
24
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
measure battery terminal connection resistance in Table 1-4 is “an involved process that may force the battery (and thus the system) out-of-service, or
alternatively the use of a temporary battery, for the duration of the activity.” Members of the SDT are familiar with numerous Transmission Owners, Generator
Owners and Distribution Providers in NERC who yearly perform this benign maintenance activity on their battery systems while the Protection Systems that the
station batteries support are in service.
Ameren Services (1)
Ballot
Comment Affirmative
Clarify p17 Table 1-4(e) interval meaning. We think this means we need to verify the Station dc supply voltage
on 12 calendar year interval if unmonitored, or no periodic maintenance if monitored as stated.
Response: Thank you for your comments. You are correct in your interpretation for Protection System dc supply used only for distribution breakers that are
associated with UFLS, UVLS, or SPS, as stated in Table 1-4(e).
Old Dominion Electric Coop. (4)
Ballot
Comment Affirmative
ODEC believes the standard is very close to being ready for approval.
1. In the Attachment A for the battery testing, you exempt the UFLS and UVLS equipment in tables and then
include SPS batteries in the table with UFLS and UVLS. Either SPS should be associated with UFLS and
UVLS and you need to add it to the previous tables or fix table 1(f).
2. Also, consider going to 4 calendar months instead of 3 calendar months for the battery maintenance
requirements.
Response: Thank you for your comments.
1. Special Protection Systems are often a far more complex system which may comprise a combination of “transmission”, distribution, and generation
components, and are often installed to prevent serious system problems. Therefore, the requirements for SPS equipment maintenance align with that for other
generic Protection Systems. It is also notable that the legacy PRC-017-1 includes batteries within the list of components to be addressed. However, if the breaker
is a distribution breaker that is associated with SPS but is not otherwise associated with generic Protection Systems, the extended interval in Table 1.4(e) applies.
2. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month.”
Associated Electric Cooperative,
Inc. (1)
Ballot
Comment Negative
AECI appreciates the effort by the drafting team. However, the 90 day inspections for batteries and
communications circuits should be extended to 120 days to allow for a 30 grace period. Schedules would be
set for every 90 days as what is required in this revision.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
25
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
unmonitored components. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program
oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary
Reference & FAQ” for a discussion about “calendar month”
Manitoba Hydro (1) (3) (5) (6)
Ballot
Comment Negative
1. Battery Check Interval Manitoba Hydro maintains our position that the 3 month battery check interval
should be extended to 6 months. The 3 month interval is too frequent based on our experience and while
IEEE SDT 450 (which seems to be the basis for table 1-4) does recommend intervals, it also states that
users should evaluate these recommendations against their own operating experience. With the 3 month
battery check frequency and no allowance for a grace period, there may be a negative impact on reliability
caused by diverting resources away from projects that are critical to reliability to meet this maintenance
interval.
2. Conductance Measurements Conductance measurement should be listed in Table 1-4 as an acceptable
measurement method.
Response: Thank you for your comments.
1. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval if adequate program oversight is exercised, and disagrees that the intervals should be
extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about “calendar month”.
2. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT answered a Frequently Asked Question explaining
what cell/unit internal ohmic measurements are. Conductance by definition is an ohmic measurement and although not spelled out in the standard is listed in
Table 1-4 because it is an ohmic measurement.
Georgia Transmission
Corporation
No
We need clarification on the UFLS or UVLS system Station DC Supply test. We trip the high side device (nonBES asset) for each of our distribution stations UFLS or UVLS schemes, not the individual distribution
breakers. It is hard to distinguish what maintenance interval and maintenance activities we should engage for
Station DC Supply test. Since the device is not a distribution breaker as mentioned in the Table 1-4 (a-f) we
would be conservative and choose to perform maintenance at all our distribution stations with UFLS or UVLS
schemes as per Table 1-4(a). Reading the statements in the Supplementary Reference and FAQ, we notice
our devices perform similar functions as the distribution breakers. Reference pg 60 of Supp. Ref. and FAQ
paragraph 4. Since tripping the high side device of a distribution transformer still constitutes a distributed
system would our system meat the exclusion criteria although it is not a distribution breaker, would this meet
the same requirements and exempt the station from Table 1-4(a) and require only maintenance for DC
systems as per Table 1-4(e)? Please clarify. We recommend changing the term distribution breaker to
distribution asset interruption device or non-BES equipment interruption device.
26
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. Table 1-4 (e) has been modified in consideration of your comment to improve clarity (“non-BES interrupting devices “).
If the cited distribution transformer is not a BES element, the Protection Systems for that distribution transformer are not included per the Applicability (4.2.1) as
modified.
PNGC Comment Group
No
We agree the changes to the tables have added clarity, but disagree with the maintenance intervals for DC
supply. Comments:
PNGC’s comment group views the Maximum Maintenance Interval for station DC Power Supply (Table 14a/b/c/d) to be unnecessarily onerous and restrictive to many smaller-rural entities, in the west and probably
throughout the US, and this prevents us from being able to support PRC-005-2 as written. We make these
comments with the understanding that others have made similar comments in the past but we feel strongly
that this is an important issue worthy of further review by the SDT. We believe a quarterly inspection
schedule can be met while at the same time allowing entities the flexibility they need. IEEE 1188-2005
suggests a quarterly inspection schedule for lead acid batteries and we believe the standard interval for
verifying and inspecting dc supply should be 3 months with a maximum interval of 6 months. This meets the
quarterly threshold and gives some flexibility to account for unusual conditions. There are substations in
Pacific Northwest rural areas that can be inaccessible during long periods of time during the winter, potentially
exposing an entity to sanction if weather conditions prevent access to equipment for an extended period of
time. Additionally, due to a smaller workforces and greater distances between equipment subject to PRC005, small-rural entities face obstacles that large entities may not have. The three month maximum interval
assumes ideal conditions and resource access and is not realistic. We thank the SDT for considering our
comments.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended.
Arizona Public Service Company
No
Although considerable clarity was achieved in the structuring of the table for the different types of
technologies associated with the DC supply, there is issue on the maximum allowable intervals. The standard
remains too prescriptive in the intervals and maintenance activities. As an example it is believed the intent of
the interval for verifying voltages and inspecting electrolyte levels and unintentional grounds level would be
every 3 months. However, for the entity to ensure compliance and not incur a violation it would have to have
a shorter interval, probably every 2 months just to ensure compliance and not incur a violation. The 3 month
interval is in question based on programs that have been in service for many years where four months have
been proven as reliable for operation, an even shorter period than 3 or 4 months is not only a burden but an
unnecessary expense without a benefit of increase reliability of the Bulk Electric System.
27
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”.
Southern Company Generation
(5)
Ballot
Comment Affirmative
The restructured Table for Station DC supply does clarify what is being required for each type of dc system,
yet the Station DC Supply requirements, however, are excessively prescriptive in comparison to the other
Protection System component types.
Response: Thank you for your comments. The SDT recognizes that Table 1-4 with its tables a through f is considerably larger than any of the tables for the other
four Protection System components. However the SDT does not agree that the maintenance activities of Tables 1-4 (a –f) for the station dc supply are
“excessively prescriptive.” As pointed out in Section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the station battery
which is part of the station dc supply is unique from any other Protection System component in that it is a perishable product which requires several prescribed
maintenance activities to monitor and maintain its ability to perform as designed for its life cycle.
Indeck Energy Services
No
The tables are limited to a few battery technologies and will be out of date in short order with the many types
of advanced batteries already on the market. The testing requirements should be performance based as
opposed to prescriptive.
Response: Thank you for your comments. While the SDT agrees that there are a few advanced batteries and new station dc supplies which have non battery
based energy storage devices in them on the market, the SDT disagrees that the testing requirements for batteries used in station dc supplies should be
performance based as opposed to prescriptive. FERC Order 693 and the approved SAR assign the SDT to develop a standard with maximum allowable intervals
and minimum maintenance activities. Please note that the Standard specifically addresses requirements for non-battery based energy storage devices within
Table 1-4(d). According to the NERC Reliability Standard Development Process, NERC Reliability Standards must be reviewed at least once every five years,
and any changes related to new technologies can be addressed within that process.
Tampa Electric Company
No
If during a UF operation there were ever any breakers that did not trip properly, there may be enough that do
trip to return things to balance. There is more room for error with UFLS than with BES. The standard does
make some allowance for differences between UFLS equipment and BES equipment. For example the DC
source testing requirement for UFLS is to just test the battery voltage when the control circuit is tested. It is
not necessary that the breaker be tripped for UFLS testing every six years as is the case for BES. However,
every 12 years all unmonitored control circuitry must be tested, which may include tripping the breaker.
Response: Thank you for your comments. Table 1-5 does not require tripping of the breaker for UFLS/UVLS.
Tri-State G & T Association, Inc.
Ballot
On Page 19, Table 1-5, the standard requires that electromechanical lockout control circuits be maintained
28
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
(3) (5)
Comment Affirmative
every 6 years and protective function unmonitored control circuits be maintained every 12 years. Why is there
inconsistency in the interval between the electromechanical lockout and protective function control circuits?
Response: Thank you for your comments. The circuit itself is 12-years, but the interval for electromechanical devices such as auxiliary or lockout relays remains at
6 years, as these devices contain “moving parts” which must be periodically exercised to remain reliable.
Constellation Energy
Commodities Group (6)
Ballot
Comment Negative
As with previous revisions of this standard, the maintenance intervals and activities described in Table 1-1
through Table 1-5 are too prescriptive.
Constellation Power Source
Generation, Inc. (5)
Ballot
Comment Negative
CPG believes, as with previous revisions of this standard, that the maintenance intervals and activities
described in Table 1-1 through Table 1-5 are too prescriptive.
Response: Thank you for your comments. The SDT is not prescribing or suggesting what methods an entity employs within their program. The intervals remain as
prescribed within the standard and are designed to be clear and effective to support reliability of the BES.
Alliant Energy Corp. Services,
Inc. (4)
Ballot
Comment Negative
Table 1-5 (Component Type – Control Circuitry) Item 4 – “Unmonitored control circuitry associated with
protective functions” require a 12 calendar year maximum maintenance interval. We believe UFLS and UVLS
control circuitry should be exempted from this requirement. It would take multiple failures to have any impact,
and the impact on the BES would be minimal.
Response: Thank you for your comments. The SDT disagrees; however, the requirements related to interrupting devices used only for UFLS/UVLS are less
detailed than those for other Protection Systems because of the reason cited in your comment.
Consumers Energy (4)
Ballot
Comment Negative
Relative to Table 1-5, the activities will likely require that system components be removed from service to
complete those activities. In the case of system elements that do not have redundant protection systems
(such as those related to lower-voltage systems within the BES), it may not be possible to do so with outaging
customers for the duration of the maintenance activity. The standard must exempt these components from the
activities of Table 1-5 if the activity would result in deenergizing customers.
Response: Thank you for your comments. The intervals and activities specified are believed by the SDT to be technically effective. It is left to the entity to
determine how to align these requirements with requirements of other regulations and with operational concerns. Entities should be able to complete the activities
within the shorter intervals without outages.
American Transmission
Ballot
1. ATC recognizes the substantial efforts and improvements to PRC-005-2 that have been made and
29
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
Company, LLC (1)
Comment Negative
appreciate the dedicated work of the SDT. ATC appreciates the removal of Requirement R1.5 and R4 and
other clarifications from draft 3.
2. ATC’s remaining concerns to PRC-005-2 are with the definition and timelines established in Table 1-5. ATC
is recommending a negative ballot since, as written, the testing of “each” trip coil and the proposed
maintenance interval for lockout testing will result in the increased amount of time that the BES is in a less
intact system configuration. Note: Additional Comments to overall Standard also submitted.
Response: Thank you for your comments.
1. Thank you for your support.
2. The lockout relays and trip coils contain “moving parts” which must be periodically exercised to remain reliable. Operational results, if desired by an entity,
MAY be used to meet maintenance requirements to the degree that they verify, etc, the relevant performance. Whether their use is effective for a specific entity is
left to the entity to determine.
Wisconsin Electric Power Co. (5)
Ballot
Comment Negative
Wisconsin Electric Power
Marketing (3)
Clarification is required in Table 1-5 as to what trip and control paths should be tested. Specifically, should
non-protection paths, such as local control switches, that are not part of the Protection System, but operate
Protection System Component, be tested?
In Table 1-5, the maintenance activity for unmonitored control circuitry associated with protective functions is
to “verify all paths of the control and trip circuits”. We recommend that only the protection system paths of the
control and trip circuits require verification by PRC-005-2.
Wisconsin Energy Corp. (4)
Response: Thank you for your comments. The SDT believes that Protection Systems that protect BES elements should be included. This position is consistent
with the currently-approved PRC-005-1 and consistent with the SAR for Project 2007-17. The header section of Table 1-5 has been modified to clarify that only
the control circuitry associated with protective functions is being addressed.
Kristina M. Loudermilk (8)
Ballot
Comment Affirmative
In table 1-5 is it necessary to mention the second and last item in the table. If there is nothing to do, then why
have it as an attribute making it mandatory to keep track of, well, nothing. If those items do need to stay, then
could we reorganize the table so where it is in ascending order from Maximum maintenance intervals, like the
other tables?
Response: Thank you for your comments. The SDT believes that inclusion of these two items add clarity. The Table entry for trip coils associated only with
UVLS/UVLS has been left in the original position to relate it directly to the companion activities for other applications.
30
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Nebraska Public Power District
Yes or No
No
Question 1 Comment
The restructured tables are indeed an improvement; however the tables still need some work for clarity:
1. Table 1-5:
Unmonitored control circuitry has a maintenance activity of “Verify all paths of the control and
trip circuits.”
The wording of “control and trip circuits” leads to circuit verification of more than just trip circuits. In fact
multiple circuits would have to verified, such as station house load transfer schemes. Providing
documentation to an auditor to prove all paths have been tested will be difficult and is considered
excessive. The paperwork required to prove compliance is extremely excessive for this requirement and
doesn’t provide a benefit to reliability.
2. Table 1-5: Table 1-5 requires trip checking every six calendar years for trip coils and electromechanical
lockout and/or tripping auxiliary devices. Every six years is excessive, when suitable monitoring is used.
We recommend verification of these components be completed at the same frequency as the associated
relay testing when monitoring is used. For electromechanical, no more than every 6 calendar years, for
microprocessor, no more than 12 calendar years.
Response: Thank you for your comments.
1. The header section of Table 1-5 has been revised to clarify that it applies to “Control Circuitry Associated with Protective Functions”, and the SDT believes that
this revision addresses your concerns.
2. The electromechanical devices such as auxiliary or lockout relays remains at 6 years, as these devices contain “moving parts” which must be periodically
exercised to remain reliable.
Consolidated Edison Co. of New
York (1) (3) (5)
Ballot
Comment Affirmative
1. We recommend increasing the Table 2 reporting window from 24-hours to 72-hours for facilities not
continuously manned in order to accommodate discovery and reporting of failed alarms at these facilities
which may occur over a long (3-day) holiday weekend.
Consolidated Edison Co. of New
York (6)
Ballot
Comment Affirmative
1. We recommend increasing the Table 2 reporting window from 24-hours to 72-hours for facilities not
continuously manned in order to accommodate discovery and reporting of failed alarms at these facilities
which may occur over a long (3-day) holiday weekend.
2. We recommend that the drafting team recognize that a “fail safe” or “self-reporting” alarm design serves as
an acceptable alternative to periodic testing. This “fail safe” or “self-reporting” alarm design is equivalent to
continuous testing the alarm. When the alarm circuit fails the alarm is set to “alarm on” and automatically
notifies the control center, initiating a corrective action.
Response: Thank you for your comments.
31
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
1. The SDT believes that the monitoring and reporting will be generally done by automatic reporting methods such as SCADA and previously removed a reference
to “automatic reporting” specifically to address those cases where the facility is manned.
2. The application discussed seems to the SDT to be an effective method of “monitoring the monitoring circuit”. (See Table 2, last row with heading “Alarm Path
with monitoring.”)
Nebraska Public Power District
No
1. Table 2: The interrelationship between Tables 1-1 through 1-5 and Table 2 is ambiguous. Tables 1-1
through 1-5 “component attributes” columns references Table 2 in many cases as the criteria for maximum
interval. However, each table entry has a maximum maintenance interval listed as well. There are a few
instances where the “trump” interval is not clear. Table 1-5 is a good example.
2. Table 2 states that monitored devices (1-1 through 1-5) not having monitored alarm paths shall be tested
every 12 years. However, Table 1-5 states that DC circuits with monitored continuity shall have no periodic
maintenance. We suspect that Table 2 attributes needs further clarification to eliminate the confusion, both
Table 2 attributes at first glance appear to say the same thing. However, after study it appears to address
“detection” monitoring versus continuous (control center type) monitoring. We believe further distinguishing
clarifications are needed to make it evident and clear.
Response: Thank you for your comments.
1. The SDT believes that the activities and intervals, as they relate to whatever monitoring attributes are present, are clear. Table 2 is specifically labeled to
address whatever maintenance is necessary to the monitoring and alarming equipment itself. The references to Table 2 have been corrected where necessary.
2. Table 1 is related to the component itself, and Table 2 relates to maintenance of the monitoring and alarming if relevant. If the monitoring specified is present,
no periodic maintenance of the control circuitry itself is needed. However, as indicated in Table 2, maintenance (or monitoring) is required to assure that the
monitoring on the control circuitry is operational.
ExxonMobil Research and
Engineering
No
Ameren
Yes
Please carry the grid across in Table 1-4(f) to show the Maintenance Activities that go with the Component
Attribute.
Response: Thank you for your comments. The grid in Table 1-4(f) is drawn as the SDT intended, to show “No periodic maintenance specified” for all table entries.
The activity listed is the activity that is being accomplished by the monitoring mechanism.
Tennessee Valley Authority
Yes
However, The requirement to perform battery cell internal ohmic measurements every 18 months for vented
lead-acid batteries is excessive, and no technical justification is provided for an 18-month interval. A 3-year
32
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
internal ohmic test frequency is adequate to prove battery integrity. EEE 450 does not provide a
recommended interval for internal ohmic measurements. For standard capacity testing, the recommended
interval is no greater than 25% of expected battery life. Our normal battery life is 20+ years, so the
recommended capacity test interval would be about 5 years. EPRI also recommends capacity testing at 5
year intervals. There is no justification for performing internal ohmic measurements every 18 months (which
equals every 7.5% interval of the expected battery life). Recommendation: Set the interval for battery internal
cell ohmic testing at 3 years.
Response: Thank you for your comments. The Maintenance Activity of evaluating the measured cell/unit internal ohmic values to station battery baseline is an
optional activity to verify that the station battery can perform as designed. An owner who desires not to take internal ohmic measurements on a Vented Lead-Acid
(VLA) battery can elect to verify that the station battery can perform as designed by conducting a performance, service, or modified performance capacity test of
the entire battery bank without ever having to perform any internal ohmic measurement on the battery. The maximum maintenance interval for performing this
capacity test on a VLA battery bank is 6 Calendar Years. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” - that
was posted for review with PRC-005-2 - the SDT answered several Frequently Asked Questions which explain why the 18 month Maximum Maintenance Interval
is justified rather than the 3 year frequency that is assumed by some to be adequate.
Exelon
Yes
What kind of component we are talking about in table 1.4(d) “Station DC Supply using Non Battery Based
Energy Storage” for switchyard in nuclear plants?
Response: Thank you for your comments. An example of a “station dc supply” component of this nature would be fuel cells. The SDT is aware that some entities
are beginning to apply non-battery-based dc supplies, but we are unaware whether anyone is using these in switchyards for nuclear plants.
Xcel Energy
Yes
Regarding the last row of Table 1-4(f): it seems very inconsistent to require a formal trending program for a
manual 6 month (VRLA)/18 month (VLA) internal ohmic reading but to require no gathering and analysis of
data as an alarm for a ohmic value for each cell/unit is available. If just a raw ohmic value is an adequate
predictor of cell life, than why require a trending program for the manual reading if all that is needed to
determine adequacy of remaining cell life is just a simple acceptance criteria (i.e. - alarm set point) against
which you need to compare your measured data? In theory these are very gradual and predictable changes
in ohmic readings over the entire life of the battery, such that the benefit of real time knowledge of exactly
when a threshold is reached via alarm is minimal rather than having to wait until the next manual reading to
ascertain that the threshold limit has been reached.
Response: Thank you for your comments. Your comment concerning the last row of Table 1-4(f) being inconsistent with the two distinct maintenance activities for
internal ohmic value measurement found in the unmonitored station dc supply tables 1-4(a) and 1-4(b) was very incisive. As pointed out in section 15.4 of “PRC005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT recognized that there are two maintenance activities in Table 1-4(b) which
appear to be the same, but require a different method of interpretation to complete the required maintenance activity. The Drafting Team has considered your
comment in light of its own discussion in the Supplementary Reference & FAQ document and has divided the last row of Table 1-4(f) into two rows to reflect the
33
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
two distinct maintenance activities required in the unmonitored tables (inspection of the condition of individual VRLA cell/units, and evaluating internal ohmic
measurements to a baseline to verify the station battery can perform as designed).
Duke Energy
Yes
We believe the table could be improved further to aid compliance by adding a footnote to the term “baseline”
in the sub-tables 1-4(a), 1-4(b) and 1-4(f). The following proposed footnote text is taken from page 65 of the
Supplementary and FAQ Reference Document: “Often for older VLRA batteries the owners of the station
batteries have not established a baseline at installation. Also for owners of VLA batteries who want to
establish a maintenance activity which requires trending of measured ohmic values to a baseline, there was
typically no baseline established at installation of the station battery to trend to. To resolve the problem of the
unavailability of baseline internal ohmic measurements for the individual cell/unit of a station battery, all
manufacturers of internal ohmic measurement devices have established libraries of baseline values for VRLA
and VLA batteries using their testing device. Also several of the battery manufacturers have libraries of
baselines for their products that can be used to trend to.”
Response: Thank you for your comments. The addition that you suggest is properly considered application guidance; the SDT has been advised that such
information is not to be included within the standard, and that it is appropriately included in separate reference materials.
Ingleside Cogeneration LP
Yes
1. Ingleside Cogeneration, LP, continues to believe that the six year requirement to verify channel
performance on associated communications equipment will prove to be more detrimental than beneficial on
older relays. Clearly newer technology relays which provide read-outs of signal level or data-error rates will
easily verified, but the tools which measure power levels and error rates on non-monitored communication
links are far more intrusive. After the technician uncouples and re-attaches a fiber optic connection, the
communications channel may be left in worse shape after verification than it was prior to the start of the
test.
2. However, we have found that the remainder of the items in the Tables are logically organized and
correspond effectively with the five components of a Protection System. The maintenance activities and
intervals are technically solid and reasonable. In our opinion, the benefits to proceed outweigh our one
concern with the validation of communications channel performance.
Response: Thank you for your comments.
1. We agree that it is not good practice to disturb fiber connections as you indicate. Draft 4 does not require that. The Entity must perform the activities in the
“Maintenance Activities” column. The SDT does not interpret this as taking anything apart.
2. Thank you.
Manitoba Hydro
Yes
The restructured tables are an improvement, but we suggest that conductance (siemens) should be listed as
34
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 1 Comment
an acceptable measurement in addition to the resistance measurements already included in the tables.
Response: Thank you for your comments. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT answered a
Frequently Asked Question explaining what cell/unit internal ohmic measurements are. Conductance is an ohmic measurement and although not spelled out in
the standard is listed in Table 1-4 because it is an ohmic measurement.
NIPSCO
Yes
Sub-tables are good. A related question: Some devices such as reclosers and circuit breakers may include
batteries within the device itself. Does Table 1-4 apply to such batteries and DC supply? Recloser batteries
do not provide access to intercell connections.
Response: Thank you for your comments. In most instances Table 1-4 does not apply to recloser batteries or batteries within the device because they are not
generally used to provide dc power to Protection Systems designed to provide protection for BES elements. However, these types of devices with self contained
batteries may be used at the distribution level to provide Protection Systems used for underfrequency and undervoltage load-shedding. Maintenance activities
and maximum maintenance intervals for such batteries are found in Table 1-4(e) of the Standard.
MISO Standards Collaborators
Yes
American Transmission
Company, LLC
1. Yes, however, in the “Supplemental reference and FAQ” document on page 65 there are two areas of
concern. Page 65, paragraph 4:” the type of test equipment used to establish the baseline must be used for
any future trending of the cells internal ohmic measurements because of variances in test equipment and
the type of ohmic measurement used by different manufacturer’s equipment.”
While we understand the importance of creating a baseline, it is not feasible to expect the test equipment
be the same as the manufacturer’s test equipment or even the same test equipment over the life of the
battery. The expected life of a battery may be in excess of 20 years and it is not feasible to expect that the
type of equipment will not change during this period.
2. On Page 65, paragraph 6, it states:”all manufacturers of internal ohmic measurement devices have
established libraries of baseline values.” We question the availability of baseline libraries for all
manufacturers considering the variety and longevity of installations.
Response: Thank you for your comments.
1. The “Supplementary Reference and FAQ” concerning types of equipment have been changed per your suggestion to reflect consistent test data as opposed to
exactly the same piece of test equipment.
2. Many manufacturers of “Ohmic” test equipment have established libraries of baseline data. You are correct that test equipment manufacturers may not have
data on every battery in service today. Several manufacturers of batteries (not all) have libraries for some (but perhaps not all) of their products. To achieve
significant results from a trending program one needs to have good baseline data. The “Supplementary Reference and FAQ” document has been revised to reflect
your concern – the word, “all” was changed to “many”.
35
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
Yes
Question 1 Comment
Yes, however, in the “Supplemental reference and FAQ” document on page 65 this is one area of concern.
Page 65, paragraph 4 ”the type of test equipment used to establish the baseline must be used for any future
trending of the cells internal ohmic measurements because of variances in test equipment and the type of
ohmic measurement used by different manufacturer’s equipment”
While we understand the importance of creating a baseline, it’s not feasible to expect the test equipment to be
the same as the manufacturer’s test equipment or even the same test equipment over the life of the battery.
The expected life of a battery may be in excess of 15 years and it is not feasible to expect that the type of test
equipment will not change during this period.
We suggest changing the wording to read that consistent test equipment should be used to provide
consistent/comparable results.
Response: Thank you for your comments. The statements concerning types of equipment have been changed per your suggestion to reflect consistent test data
as opposed to exactly the same piece of test equipment.
The Detroit Edison Company
Yes
Yes, the tables do provide more clarity. It is much easier to understand the requirements now that they are
broken down by technology, and the exclusion of intervals on certain activities based on the individual
monitoring attributes is helpful. I appreciate the thought that went into revising this.
Response: Thank you for your comments.
New York Power Authority (1)
Yes
No comments.
ITC
Yes
The re-structured tables are easier to use.
Response: Thank you for your comments.
Luminant
Yes
No comments.
BGE
Yes
No comments.
Luminant
Yes
No comments
Northeast Power Coordinating
Council
Yes
36
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Electric Market Policy
Yes
Santee Cooper
Yes
Bonneville Power Administration
Yes
SPP reliability standard
development Team
Yes
Pepco Holdings Inc
Yes
Imperial Irrigation District
Yes
FirstEnergy
Yes
Western Area Power
Administration
Yes
NextEra Energy
Yes
Liberty Electric Power LLC
Yes
FHEC
Yes
Farmington Electric Utility System
Yes
Central Lincoln
Yes
Illinois Municipal Electric Agency
Yes
Shermco Industries
Yes
Dominion Virginia Power
Yes
Question 1 Comment
37
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
American Electric Power
Yes
CPS Energy
Yes
US Army Corps of Engineers
Yes
Alliant Energy
Yes
GDS Associates
Yes
Independent Electricity System
Operator
Yes
MidAmerican Energy Company
Yes
Question 1 Comment
38
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
2. The SDT has modified the Implementation Periods within the Implementation Plan. Do you agree with the
changes? If not, please provide specific suggestions for improvement.
Summary Consideration: Most commenters who responded to this question agreed with the proposed Implementation Plan.
There was no predominant theme in the comments. A few commenters focused on the perceived short time period allowed for
the initial conversion and development of their maintenance program while and other commenters suggested specifying Jan. 1
as an interval marker to ease in calendar year interval determination.
The SDT believes that the time frames in the proposed Implementation Plan are adequate for conversion when considering the
complete time frame that is likely to occur between industry approval vote and regulatory approvals.
The Implementation Plan was modified to provide for a lengthened implementation period for R1 and the less-than-1-calendaryear activities in R2 and R3 to allow entities not subject to regulatory approvals of 9 additional months following BOT approvals,
and, for the remaining activities, of 12 additional months following BOT approvals, to be more consistent with the expected
Regulatory Approval timelines. Additionally, all “calendar year” implementation periods were revised to “months” for additional
clarity.
The team also clarified that during the phase-in of the requirements in PRC-005-2, entities must be prepared to identify
whether each component is being maintained according to PRC-005-2, or according to PRC-005-1, PRC-008-0, PRC-011-0, and
PRC-017-0.
Under Item 4a, the team corrected the reference to generating plant outages to change “two years” to “three years” to align
with the time allocated for becoming 30% compliant (3 years) with maintenance of components subject to a 6 year interval.
Organization
Yes or No
Tri-State G&T
Question 2 Comment
The draft standard requires the PSMP to include maintenance and testing intervals for Station DC supply
associated with protective functions (including batteries, battery chargers, and non-battery-based dc supply).
Does this requirement include DC systems (batteries not included in station batteries) used by communication
systems necessary for the correct operation of protective functions?
Response: Thank you for your comments. This comment does not apply to the Implementation Plan.
Consumers Energy (4)
Ballot
Comment Negative
The implementation period for R1 and R3 for the component types addressed in Tables 1-3 and 1-5 is not
adequate. The requirements may cause entities to identify components very differently than they are currently
doing, and doing so may take several years to complete. The Implementation Plan for R1 and R3 is too
aggressive in that it may not permit entities to complete the identification of discrete components and the
associated maintenance and implement their program as currently proposed. We propose that the
Implementation Plan specifically address the components in Table 1-3 and 1-5 with a minimum of 3 calendar
39
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 2 Comment
years for R1 and 12 calendar years after that for R4.
Response: Thank you for your comments. The SDT believes that the degree of flexibility written in the standard for categorizing (and subcategorizing) is sufficient
for accomplishing the requirements within the time frames given in the Implementation Plan. For example, the voltage and current sensing devices may be
individually identified or identified by group (associated with a relay). Examples of different ways to group the dc control circuitry discrete components include
individual circuits, individual lockout devices, component protected, by control panel, or by station. The method chosen for the representation will impact the
amount of time required to transform a maintenance program.
Ameren Services (1)
Ballot
Comment Affirmative
PSMP Implement Date should commence at the beginning of a Calendar year (i.e., January 1st ). This is the
most practical way to transition assets from our existing PRC-005-1 plans
Response: Thank you for your comments. The SDT believes that the proposed Implementation Plan intervals are long enough to provide an entity the amount of
time it will take to transition to the new intervals. Considering the additional time between an approved ballot by the industry through the NERC BOT approval and
regulatory agency approval, it is very likely that an entity may have an additional 6-9 months to transition to the new program. The guidance provided to drafting
teams by NERC suggests that standards should be effective at the beginning of a calendar quarter, rather than a calendar year.
Independent Electricity System
Operator
No
We commented on this before and we will comment again. The time periods for FERC-jurisdictional entities
and non-jurisdictional entities should have at least a 3-month difference to allow some time for FERC
approval after BoT adoption in an attempt to more or less put the effective dates of the two groups of entities
in the same general time frame. The implementation plan as presented will always result in an effective date
for the non-jurisdictional entities to be at least some months (the time between BoT adoption and FERC
approval) earlier than their jurisdictional counterparts.
Response: Thank you for your comments. The Implementation Plan was modified to provide for a lengthened implementation period for R1 and the less-than-1calendar-year activities in R2 and R3 to allow entities not subject to regulatory approvals of 9 additional months following BOT approvals, and, for the remaining
activities, of 12 additional months following BOT approvals, to be more consistent with the expected Regulatory Approval timelines.
NIPSCO
No
This new standard’s calibration intervals outlined here will require additional staff at our organization. In order
to get people hired and trained the implementation plan should allow more time for the phase-in period. From
experience, calibration should have been de-emphasized since more concerns are discovered during full
tests.
Response: Thank you for your comments. The SDT believes that the proposed Implementation Plan intervals are long enough to provide an entity the amount of
time it will take to transition to the new intervals. Considering the additional time between an approved ballot by the industry through the NERC BOT approval and
regulatory agency approval, it is very likely that an entity may have an additional 6-9 months to transition to the new program.
40
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Tampa Electric Company
Yes or No
No
Question 2 Comment
The new maintenance plan has to be completed in 1 year.
1. Would that mean it is required to identify and list every element that requires testing in a database within
the first year? This will be a time intensive effort that probably that would be difficult to complete in a year
with current personnel.
2. After 1 year, would entities be required to start implementing the plan depending on the maintenance
intervals of the equipment? Qualified people would have to be in place to start the work, again this would
be difficult to accomplish with current personnel.
Response: Thank you for your comments.
1. No. Please read R1 carefully to determine what’s necessary to be implemented. There is no requirement to have a database – just to have a PSMP that
identifies the component “types” and for each component type, the associated type of maintenance program, associated maintenance activities, maintenance
intervals, and, for component types that use monitoring to extend the intervals, the appropriate monitoring attributes. There is no requirement to identify and
list every element.
2. Yes. The implementation of the plan must proceed as indicated.
Indeck Energy Services
No
The last part of the implementation plan is vague, if not undefined. The implementation should “follow the
previous maintenance intervals until all maintenance is transitioned to the new intervals.”
Response: Thank you for your comments. The SDT presumes that your comment is related to the last paragraph of the General Consideration section of the
proposed Implementation Plan. The entity should follow the previous maintenance intervals for any specific components until that component is addressed by
PRC-005-2. As the transition is occurring, the entity should adjust its maintenance and testing schedule so that it is able to demonstrate that the required % of
components meet the maintenance intervals given in the PRC-005-2 tables at each of the % compliant milestones given in this Implementation Plan.
American Electric Power
No
On page 2 of the implementation plan, it is indicated that PRC-005-1, PRC-008-0, PRC-011-0 and PRC-017-0
shall be retired and that entities will be required to identify which components will be addressed under PRC005-1 or PRC-005-2. There is no wording to cover those components that are still being addressed under
PRC-008-0, PRC-011-0 or PRC-017-0 during the implementation period.
Response: Thank you for your comments. As noted in the “General Considerations”, the entity should follow the previous maintenance intervals for any specific
components until that component is addressed by PRC-005-2. As the transition is occurring, the entity should adjust its maintenance and testing schedule so that
they are able to demonstrate that the required % of components meet the maintenance intervals given in the PRC-005-2 tables at each of the % compliant
milestones given in this Implementation Plan. The team also clarified that during the phase-in of the requirements in PRC-005-2, entities must be prepared to
identify whether each component is being maintained according to PRC-005-2 or according to PRC-005-1, PRC-008-0, PRC-011-0, or PRC-017-0.
41
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Bonneville Power Administration
Yes or No
Question 2 Comment
No
Many of the maintenance intervals in the standard are given in the terms calendar years or calendar months.
There is no description of these terms in the NERC Glossary. My Webster's dictionary defines calendar year
as the period that begins on January 1 and ends on December 31. There is no definition in my dictionary of
calendar month. Is the intent of the term calendar year in the standard that maintenance intervals start on
January 1 and end on December 31? This would make all maintenance due on December 31, and December
would be a very busy time. Does this mean that if I do maintenance on something with a maximum interval of
six calendar years in June of 2011 that it will be due again on January 1 of 2017 instead of June 1 of 2017?
We believe that the drafting team intends for maintenance to be due after a given number of years that begins
to elapse immediately after the previous maintenance is completed so that in the previous example the
maintenance would be due on June 1, 2017. Please remove the word calendar from the maximum
maintenance intervals to remove this confusion.
Response: Thank you for your comments. The intent of the term calendar year is to indicate that the maintenance is due sometime during a particular calendar
year (Jan-Dec). If you perform maintenance in June 2011 and have a 6 calendar year interval, then the same maintenance is again due sometime in 2017 (2011
+ 6). The NERC Compliance Application Notice CAN-0010, posted 19 Apr 2011, supports this compliance guideline. An interval of one calendar year means that
the activity or event must be conducted at least once within each calendar year.
FHEC
No
Can't locate the implementation plan in the posted materials.
Response: Thank you for your comments. The implementation plan was provided as a separate document within the posting and is available in the Standards
Under Development section of the NERC website under Project 2007-17:
http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html
FirstEnergy
No
Although we agree with the timeframes being afforded to achieve compliance, we suggest the following
changes:
1. During the last comment period, we suggested changes to the wording regarding retirement of existing
standards on page 2. We do no see a response to these comments. Therefore, we would like to reiterate that
the four existing standards are to be retired upon the effective date of the new standard and not upon
regulatory approval.
2. In 4a of the plan, since the timeframe for 30% completion is 3 calendar years, we suggest a change to
three calendar years for the parenthetical phrase “(or, for generating plants with scheduled outage intervals
exceeding two calendar years, at the conclusion of the first succeeding maintenance outage)”. Change ”two”
to “three”
3. We suggest the implementation plan be included within the body of the standard. It is very burdensome for
42
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 2 Comment
entities to have to look for the implementation plan and we believe that a “one-stop shopping” approach would
alleviate this burden.
Response: Thank you for your comments.
1. The Effective Date within the Standard was stated as it is based on verbal advice of NERC Compliance – several drafts ago.
2. The Implementation Plan has been modified as you suggested.
3. The Implementation Plan is provided separately in accordance with instructions from the NERC Standards Department and Standards Committee. Further, at
the end of all transition periods, it is not needed in the standard.
ExxonMobil Research and
Engineering
No
Ameren
Yes
While we agree with the Implementation Periods, it would be best to alter R2 and R3 implementation such
that components with maximum allowable intervals of 1 year or longer align with a true calendar year (i.e.
begin with January 1).
Response: Thank you for your comments. The SDT believes that the proposed Implementation Plan intervals are long enough to provide an entity the amount of
time it will take to transition to the new intervals. Considering the additional time between an approved ballot by the industry through the NERC BOT approval and
regulatory agency approval, it is very likely that an entity may have an additional 6-9 months to transition to the new program. The guidance provided to drafting
teams by NERC suggests that standards should be effective at the beginning of a calendar quarter, rather than a calendar year.
MidAmerican Energy Company
Yes
1. In the background section of the implementation plan in item two it states “...it is unrealistic for those
entities to be immediately in compliance with the new intervals.” Recent compliance application notices
indicate that auditors are requiring entities to include proof of compliance to maintenance intervals by
providing the most recent and prior maintenance dates. The implementation document could be improved by
providing clarity to what is expected with regard to when an entity is expected to provide evidence of
maintenance interval compliance given the quoted item above. As an example in the section the
implementation plan for a 6 year interval item it states: “The entity shall be at least 30% compliant on the first
day of the first calendar quarter 3 years following applicable regulatory approval..”
In keeping with the previously quoted “reasonableness” criteria it would seem that 30% compliant would mean
only one test action would be needed to be completed by the indicated deadline and the next one would be
required no later than 6 years from that first test. It is recommended that the implementation plan document
be improved to clarify this issue.
2. In addition, it would seem appropriate to allow entities that decide to implement PRC-005-2 requirements
43
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 2 Comment
before the standard becomes effective to count the maintenance they do before the effective date in the
implementation plan schedule and in the testing interval compliance.
Response: Thank you for your comments.
1. The Implementation Plan establishes that an entity must follow its current plan until the new standard is implemented for any specific component. Therefore,
an entity should have documentation that it has maintained any given component according to its current program until it is addressed in the revised program
(including all relevant activities addressed in PRC-005-2). An entity should adjust it‘s maintenance and testing schedule so that it is able to demonstrate that the
required % of components meet the maintenance intervals given in the PRC-005-2 tables at each of the % compliant milestones given in the Implementation
Plan. The team also clarified that during the phase-in of the requirements in PRC-005-2, entities must be prepared to identify whether each component is being
maintained according to PRC-005-2 or according to PRC-005-1, PRC-008-0, PRC-011-0, or PRC-017-0.
2. If entities begin to implement the PRC-005-2 activities before the effective date, it seems to the SDT that this entity will find that they it has fully implemented
PRC-005-2 sooner, and will thus have attained a stable sustainable program that much sooner.
New York Power Authority (1)
Ballot
Comment Affirmative
2. The SDT has modified the Implementation Periods within the Implementation Plan.. Do you agree with the
changes? If not, please provide specific suggestions for improvement.
X0 Yes 0 No Comments:
Luminant
Yes
No comments.
BGE
Yes
No comments.
Luminant
Yes
No comments
Northeast Power Coordinating
Council
Yes
MISO Standards Collaborators
Yes
Electric Market Policy
Yes
Santee Cooper
Yes
44
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
SPP reliability standard
development Team
Yes
Pepco Holdings Inc
Yes
Tennessee Valley Authority
Yes
Imperial Irrigation District
Yes
PNGC Comment Group
Yes
MRO's NERC Standards Review
Subcommittee
Yes
The Detroit Edison Company
Yes
Western Area Power
Administration
Yes
NextEra Energy
Yes
Arizona Public Service Company
Yes
Liberty Electric Power LLC
Yes
Ingleside Cogeneration LP
Yes
Farmington Electric Utility System
Yes
Duke Energy
Yes
Central Lincoln
Yes
Illinois Municipal Electric Agency
Yes
Question 2 Comment
45
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Manitoba Hydro
Yes
Shermco Industries
Yes
Dominion Virginia Power
Yes
CPS Energy
Yes
US Army Corps of Engineers
Yes
Alliant Energy
Yes
Georgia Transmission
Corporation
Yes
American Transmission
Company, LLC
Yes
GDS Associates
Yes
ITC
Yes
Xcel Energy
Yes
Question 2 Comment
46
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
3. The SDT has modified the VSLs, VRFs and Time Horizons with this posting. Do you agree with the changes? If
not, please provide specific suggestions for improvement.
Summary Consideration: Many commenters pointed out an error (which was corrected by the SDT) within the VSL for R2,
where the Lower and High VSLs contained identical text.
Many comments were offered on the VRFs that demonstrated unfamiliarity with the relationship between VSLs and VRFs.
Violation Risk Factors identify the reliability-related risk associated with non-compliance; VSLs are applied after a finding of
non-compliance to identify the degree of non-compliance.
Many duplicate comments were offered on the content of the standard which were not relevant to the VRFs, VSLs, or Time
Horizons and these were answered elsewhere in this document
VSLs for R1:
•
Phased VSLs were added to address R1 Part 1.1, which was previously addressed only as a “Severe” VSL.
•
A reference was added within the R1 VSL to Part 1.3.
•
R1 High VSL was revised to add a reference to Table 2.
VSLs for R2:
•
One element of the R2 VSL was made binary (Severe), rather than “phased” (in two steps), in response to several
comments.
VSLs for R3:
•
The R3 VSLs were revised to replace “complete” with “implement and follow” for consistency with the Requirement.
Other minor editorial changes were made throughout the VSLs in response to comments.
Organization
Tri-State G&T
Yes or No
Question 3 Comment
On Page 19, Table 1-5, the standard requires that monitored electromechanical lockouts be
maintained every 6 years. Why is there inconsistency in the interval between the monitored lockouts
and monitored relays?
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to your comments on the standard provided elsewhere in this report.
47
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
SPP reliability standard
development Team
Yes or No
Question 3 Comment
No
1. If the maintenance is done prior to the maximum interval would it then reset the clock. Or should
it read that maintenance and testing should be done at least once per quarter etc.
2. We would like to see the plan split up into generation time horizons and transmission time
horizons, these can be significantly different.
Response: Thank you for your comments.
1. Provided that all required maintenance activities are done, the activity for that interval is taken care of, and the clock is reset.
2. The options for the Time Horizons are “Long-term Planning” (a planning horizon of one year or longer), “Operations Planning” (operating and
resource plans from day-ahead up to and including seasonal), “Same Day Operations” (actions required within the timeframe of a day, but not realtime), “Real-time Operations” (actions required within one hour or less to preserve the reliability of the bulk electric system), and “Operations
Assessment” (follow-up evaluations and reporting of real time operations). All of the requirements are properly assigned a Time Horizon of “Long
Term Planning”. There is no provision for different Time Horizon between entity types.
Indeck Energy Services
No
1. The VSL’s for R1 should combine the ones for Lower, Moderate and High VSL into Lower VSL.
The Severe VSL should be moved to the Moderate VSL. Because R1 is administrative, it
shouldn’t have High or Severe VSL’s.
2. The R2 High VSL (3 yrs) is more stringent than the Severe VSL (5 yrs).
3. The R3 VSL’s need to have combined numbers of components or percentages because small
generators may only have 25 relays or 1 battery and would be categorized as High or Severe VSL
with a few components affected. The percentage could apply to RE’s with more than 250
components included in the PSMP.
4. The Medium VRF for R1 should be Low VRF because R1 is administrative. Only the performance
of the maintenance has anything more than Low VRF.
5. The Medium VRF for R2 is OK.
6. Having a High VRF for R3 is without basis. R3 should have Medium VRF.
Response: Thank you for your comments.
1. R1 is not administrative – it is foundational to developing the program. The VSLs as established conform to the NERC Violation Severity Level
Guidelines.
2. The SDT disagrees. R2 “High” reflects a failure to return the “Countable Events” to an acceptable level in three years. R2 “Severe” reflects even
worse performance, in that the entity has failed to return the “Countable Events” to an acceptable level in an even longer period – five years.
48
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
3. The SDT disagrees. A smaller entity will have less to maintain in accordance with the standard, and thus the percentages are still appropriate.
4. R1 is not administrative – it is foundational to developing the program, and not having a program could “directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric system” as established in the criteria
for a Medium VRF, even if the devices are being maintained to some degree. Without having an established program, the remaining requirements are
far less meaningful.
5. Thank you.
6. The SDT believes that failure to maintain Protection Systems could “place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures” as established in the criteria for a High VRF. This concern is borne out by observations relating to several disturbances over the last
several years. Also, a High VRF for R3 is consistent with the PRC-005-1 VRF for the corresponding requirement (R2).
FRCC (10)
Non-binding
Poll
Comment
The VSL's need additional work. Here are some of the issues I see:
1. For R1, the High VSL has a condition that states "Failed to include all maintenance activities or
intervals relevant for the identified monitoring attributes specified in Tables 1-1 through 1-5. (Part
1.4)" This condition is really a combination of what is required in Part 1.3 AND Part 1.4. How would
the compliance enforcement determine an appropriate VSL if the registered entity only did not do
Part 1.3 (maintenance activities)? These should be separated.
2. Also the Severe VSL is also identified for failure to specify three or more component types. I
believe it is more appropriate to have three in High VSL and leave the Severe VSL for 4 or more.
3. For R2, the Lower VSL lists item 1) as "Failed to reduce countable events to less than 4% within
three years." This is also the same condition that is identified for the High VSL. It is also the same
condition that is listed as item 2) for the Severe VSL. In Lower and Severe, the items are
separated by OR so they are each distinct. So, which VSL should the compliance enforcement
authority use?
4. Also for R2, Lower VSL is indicated for failure to document for countable events for 5% or less of
components. Then you jump to Severe VSL for over 5%. That seems like a very huge jump. The
Moderate and High VSLs should be used to make a more gradual difference.
5. Finally, for R2, the Lower VSL is indicated if a segment has 54-59 components and a Severe is
more than 54 components. In reading Attachment A, it states that a segment MUST contain at
least sixty (60) individual components. This would appear to me to be all or nothing. I would
suggest that the only VSL for this would be a Severe if it did not have 60 or more.
Response: Thank you for your comments.
49
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
1. The SDT disagrees. For the assessment of compliance to R1, Part 1.3 and Part 1.4 work together in the fashion identified in the VSL.
2. The SDT disagrees, and believes that failure to address three or more component types (out of a total of five) indeed reflects a Severe violation of the
requirement.
3. Thank you for catching this. The High VSL has been modified from three years to four years. Where elements of the VSL are separated by “or”, the
compliance enforcement authority should use each of them as appropriate.
4. The SDT disagrees. The documentation of countable events is so fundamental to a performance-based maintenance program that the SDT has
assigned a Lower VSL to minor transgressions, with all other transgressions being regarded as a Severe VSL.
5. The SDT has modified the R2 VSL for the segment population to be binary as you suggested.
Tri-State G & T Association,
Inc. (3) (5)
Ballot
Comment
1. On Page 7, R2 Violation Severity Levels, “Entity has Protection System elements in a
performance-based PSMP but has failed to reduce countable events to less than 4% within three
years” is shown as both a Lower VSL and a High VSL. What differentiates the two VSLs?
2. R1 VSL - Second item in Severe VSL is not addressed in any lower VSL. Should there also be a
comparable violation in Lower and Moderate?
Response: Thank you for your comments.
1. Thank you for catching this. The High VSL has been modified from three years to four years.
2. VSLs have been added to Moderate and High to address lesser violations.
Tri-State G & T Association
Inc. (3)
Non-binding
Poll
Comment
1. Comment 1: On Page 7, R2 Violation Severity Levels, “Entity has Protection System elements in a
performance-based PSMP but has failed to reduce countable events to less than 4% within three
years” is shown as both a Lower VSL and a High VSL. What differentiates the two VSLs?
2. Comment 2: R1 VSL - Second item in Severe VSL is not addressed in any lower VSL. Should
there also be a comparable violation in Lower and Moderate?
Response: Thank you for your comments.
1. Thank you for catching this. The High VSL has been modified from three years to four years.
2. VSLs have been added to Moderate and High to address lesser violations.
Tri-State G & T Association
Inc. (5)
Non-binding
Poll
1: On Table 1-2, page 11: The standard describes the following component attributes, “Any
unmonitored communications system necessary for correct operation of protective functions, and
50
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Comment
Question 3 Comment
not having all the monitoring attributes of a category below.” How does this apply to redundant
communication systems? If the primary communications channel fails the protective relay
automatically fails over to the back-up channel and continues to function properly. Are redundant
communication channels excluded from this component attribute and associated interval? Also, if
a relay is set to operate in a manner typical when communication is not used for protection (i.e.
defaulting to step-distance functions with a loss of communication), is the defaulted operation of
the relay considered “correct operation” thereby excluding the communication as necessary for its
correct operation? Please clarify the term correct operation and how it applies to redundant
communication systems and/or the performance of the relay in the absence of communication.
2: The draft standard requires the PSMP to include maintenance and testing intervals for Station DC
supply associated with protective functions (including batteries, battery chargers, and non-batterybased dc supply). Does this requirement include DC systems (batteries not included in station
batteries) used by communication systems necessary for the correct operation of protective
functions?
3: On Page 19, Table 1-5, the standard requires that electromechanical lockout control circuits be
maintained every 6 years and protective function unmonitored control circuits be maintained every
12 years. Why is there inconsistency in the interval between the electromechanical lockout and
protective function control circuits?
4: On Page 7, R2 Violation Severity Levels, “Entity has Protection System elements in a
performance-based PSMP but has failed to reduce countable events to less than 4% within three
years” is shown as both a Lower VSL and a High VSL. What differentiates the two VSLs?
Response: Thank you for your comments.
1. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
2. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
3. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
4. Thank you for catching this. The High VSL has been modified from three years to four years.
Farmington Electric Utility
System
No
VSL on R2: Lower criteria item 1; the wording is identical High VSL. FEUS recommends keeping the
criteria in the Lower VSL.
51
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
City of Farmington (3)
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
Alliant Energy Corp. Services,
Inc. (4)
Non-binding
Poll
Comment
The Lower and High VSL for Requirement 2 have the same description. The Lower VSL has other
possible items, but there is a conflict where an entity could argue for both a Lower and High VSL.
That needs to be clarified.
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
GDS Associates
No
1. Suggest clarification of the VSL for R2. It appears that R2 Lower VSL is also contained in the R2
High VSL.
2. If the maintenance is completed prior to the maximum interval, would it then reset the clock? Or
should it read that maintenance should be done at least once per quarter?
3. The plan should split into generation time horizons and transmission time horizons since these
can be significantly different
Response: Thank you for your comments.
1. Thank you for catching this. The High VSL has been modified from three years to four years.
2. Yes – it would reset the clock, provided that all required activities are completed during the performance of the maintenance.
3. The SDT disagrees. The options for the Time Horizons are “Long-term Planning” (a planning horizon of one year or longer), “Operations Planning”
(operating and resource plans from day-ahead up to and including seasonal), “Same Day Operations” (actions required within the timeframe of a
day, but not real-time), “Real-time Operations” (actions required within one hour or less to preserve the reliability of the bulk electric system), and
“Operations Assessment” (follow-up evaluations and reporting of real time operations). All of the requirements are properly assigned a Time Horizon
of “Long Term Planning”. There is no provision for different Time Horizon between entity types.
Alabama Power Company (3)
Georgia Power Company (3)
Non-binding
Poll
Comment
But only if the clean version on Page 7 under Violation Severity Levels R2/High VSL match the
redline dated 4/12/2011. Entity has Protection System elements in a performance-based PSMP but
has failed to reduce countable events to less than 4% within four years.
Gulf Power (3)
Mississippi Power (3)
Response: Thank you for your comments. The clean version represents the content desired for the Standard. The red-line is affected by peculiarities of
52
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
the red-lining tool within Microsoft Word.
Tampa Electric Company
No
VSL is severe for more than 4% Countable Events on R2. It does not seem feasible.
Response: Thank you for your comments. R2, by reference to Attachment A, requires that entities using performance-based maintenance reduce
Countable Events to less than 4% within three years. The R2 Severe VSL reflects failure to do so within five years.
Manitoba Hydro
No
1. VSL for Requirement 2:-Needs to use consistent terminology. The standard requirements refer to
components and component types, not elements.
2. The violation “Entity has Protection System elements in a performance-based PSMP but has failed
to reduce countable events to less than 4% within three years” appears in both the Lower VSL
column and the High VSL column. The violation cannot be both Lower and High. VSL for
Requirement R3: -Suggested wording “completed its scheduled program”.
Manitoba Hydro (1) (3) (5) (6)
Non-binding
Poll
Comment
Manitoba Hydro is voting negative for the following reasons:
1. VSL for Requirement 2: -Needs to use consistent terminology. The standard requirements refer to
components and component types, not elements.
2. The violation “Entity has Protection System elements in a performance-based PSMP but has failed
to reduce countable events to less than 4% within three years” appears in both the Lower VSL
column and the High VSL column. The violation cannot be both Lower and High.
3. VSL for Requirement R3: -Suggested wording “completed its scheduled program”.
Response: Thank you for your comments.
The term, “element” is not used in any of the VSLs.
2. Thank you for catching this. The High VSL has been modified from three years to four years.
3. The SDT disagrees; the VSL address failure to complete the scheduled program. The suggested change does not reflect this.
Duke Energy
No
Duke Energy
Non-binding
Poll
Typographical error - the High VSL for R2 has been incorrectly changed to “within three years” from
“within four years”. This is now the same as the Lower VSL.
There is a typographical error on the High VSL for R2. It has been incorrectly changed to “within three
years” from “within four years”. This is now the same as the Lower VSL.
53
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
Comment
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
Kristina M. Loudermilk
Non-binding
Poll
Comment
1. In VSL R2 I find it confusing for the Lower VSL and High VSL. In the Lower VSL for R2 #1 is
mentioned, but again mentioned in High VSL. IS there an easier way to make that flow?
2. Also I found that I have forgotten a comment for the Standard itself.... In Attachment A, #5 is
mentioned twice. I understand as to why, so I think, but in the "To Maintain" #5 says that one has to
use the prior year's data. It matches the exact form of "how to establish the performance based
PSMP". I find this confusing. So does this mean that testing will be once a year for parts of the
segment. I did not get that same understanding from the support documents. Is there way to reword
one of the #5's to show case a difference. Or is this on purpose? I just found it confusing.
Response: Thank you for your comments.
1. The High VSL has been modified from three years to four years.
2. The “first” #5 applies to establishing the performance-based program; the “second” one – now modified to be #4 in the second section, applies to
maintaining the performance-based program on a continuing basis.
Alliant Energy
No
The LOW and HIGH VSL for R2 are the same. There are additional possibilities for the LOW, but it is
possible to be in both the LOW and HIGH VSL at the same time. We recommend removing #1 in the
LOW VSL category to resolve the issue.
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
The Detroit Edison Company
No
R2 - It appears that the Lower VSL point 1) and High VSL are identical.
Response: Thank you for your comments. Thank you for catching this. The High VSL has been modified from three years to four years.
Consolidated Edison Co. of
New York (1) (3) (5) (6)
Ballot
Comment Affirmative
Clarification is needed to assure that the industry more fully understands how the percentage of
“maintenance correctable issues” will be computed in the R3 VSL.
Consolidated Edison Co. of
New York (1) (5) (6)
Non-binding
Poll
1: Clarification is needed to assure that the industry more fully understands how the percentage of
“maintenance correctable issues” will be computed in the R3 VSL.
54
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
Comment
2: We recommend increasing the Table 2 reporting window from 24-hours to 72-hours for facilities not
continuously manned in order to accommodate discovery and reporting of failed alarms at these
facilities which may occur over a long (3-day) holiday weekend.
3: We recommend that the drafting team recognize that a “fail safe” or “self-reporting” alarm design
serves as an acceptable alternative to periodic testing. This “fail safe” or “self-reporting” alarm
design is equivalent to continuous testing the alarm. When the alarm circuit fails the alarm is set to
“alarm on” and automatically notifies the control center, initiating a corrective action.
Response: Thank you for your comments.
1. The SDT believes that this is clear; if an entity has 20 maintenance-correctable issues and has failed to initiate resolution of one, it has failed to initiate
resolution of 5% of the maintenance-correctable issues.
2. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
3. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our response to your comments on the
standard provided elsewhere in this report.
Independent Electricity System
Operator
Independent Electricity System
Operator (2)
No
Non-binding
Poll
Comment
(1) We do not agree with the High VRF for R3 which asks for implementing the maintenance plan
(and initiate corrective measures) whose development and content requirements (R1 and R2)
themselves have a Medium VRF. Failure to develop a maintenance program with the attributes
specified in R1, and stipulation of the maintenance intervals or performance criteria as required in
R2, will render R3 not executable. Hence, we suggest that the VRF for R3 be changed to Medium.
(2) The Severe VSL for R2 is improper. First, the reference to R3 is incorrect. Second, the first
condition that says: “Failed to establish the entire technical justification described within R3 for the
initial use of the performance-based PSMP” introduces a requirement not stipulated in R2 itself.
We suggest to remove this condition. If the SDT feels strongly that the technical justification (we’re
not sure what exactly it is) needs to be established for the initial use of the performance-based
PSMP, then R2 should be revised to capture this requirement.
Response: Thank you for your comments.
1. The SDT believes that failure to maintain Protection Systems could “place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures” as established in the criteria for a High VRF. This concern is borne out by observations relating to several disturbances over the last
several years. However, even if the program is not fully documented per R1 and R2, devices may still be maintained; thus the reduced VRF for these
requirements. Also, the R3 “High” VRF is consistent with the VRF assigned to the similar PRC-005-1 requirement (R2).
55
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
2. The Severe VSL for R2 has been corrected to refer to R2. The remainder of the Severe VSL for R2 is correct, in that R2 itself specifies that the
procedure in Attachment A must be used, both to establish and maintain a performance-based maintenance program. The definition of maintenance
correctable issue has been revised to be clearer.
Tennessee Valley Authority
No
TVA has 590 Pilot Relay (Carrier Blocking) Terminals that are tested twice a year. After an extensive
study of carrier failures over a 5-year period, it was determined that we were not having any failures
that could have been prevented by a functional test. In January 2008, we reduced our frequency
from 4 times per year to 2 times per year. The failure rate has remained about the same since that
change.
As PRC 005-2 currently states, the PM frequency would be 3 months. Allowing for a one-month
grace period would actually require the interval to be set at 2 months. Therefore, the interval we used
prior to 2008 (4 times per year) still would not make TVA compliant with the stated 3 month
interval.TVA Power Control Systems is in the process of developing extensive PM tests for carrier
terminals to complement the existing PM program. This PM would record signal levels, reflected
power, line losses, and other pertinent data. It is my position that this PM will improve reliability more
than increasing the frequency of the functional test.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to your comments on the standard provided elsewhere in this report.
American Electric Power
No
This standard encompasses a very broad range of component types and functionality. It also
encompasses broad segments of the BES. The proposed VSLs and VRFs place the same level of
severity or priority on facilities that serve local load with that of an EHV facility. The percentages
indicated in the VSLs seem to be too strict based upon the vast quantity of elements in scope and
broad range of application.
Response: Thank you for your comments. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without
being in violation. The NERC VRF Guidelines establish the criteria for assigning VRFs and do not provide for multiple VRFs for a single requirement,
and the percentages (where used) assigned within the VSLs conform to the criteria established within the NERC VSL guidelines.
FHEC
No
For Distribution Provider level equipment there should be no High or Severe VSLs
Response: Thank you for your comments. The SDT disagrees; the VSLs are intended to address the degree to which an entity fails to comply with each
requirement, and the nature of the entity has no bearing on this determination.
56
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Pepco Holdings Inc
Yes or No
No
Question 3 Comment
1. Are the bullet items listed for the R2 Severe Violation Severity Level , Item 5 an "and" or an "or"?
5) Failed to:
• Annually update the list of components,
• Perform maintenance on the greater of 5% of the segment population or 3 components,
• Annually analyze the program activities and results for each segment.
2. The wording of the R3 Lower Violation Severity Level seems to imply that an entity that fails to
complete 0% (i.e., completes 100%) of its maintenance correctable issues is non-compliant. Entity
has failed to complete scheduled program on 5% or less of total Protection System components.
OR Entity has failed to initiate resolution on 5% or less of identified maintenance correctable
issues.
The following re-phrasing is suggested: Entity has failed to complete scheduled program on
greater than 0%, but no more than 5% of total Protection System components. OR Entity has
failed to initiate resolution on greater than 0%, but less than or equal to 5% of identified
maintenance correctable issues.
Response: Thank you for your comments.
1. The VSL has been modified to separate these items with “or”.
2. The SDT disagrees; this description conforms to the guidance in the NERC VSL Guidelines, and VSLs only apply if there is a failure to comply with
the relevant requirement.
Liberty Electric Power LLC (5)
Non-binding
Poll
Comment
The use of percentages, without accounting for the size of the entity, unfairly burdens small IPPs.
Response: Thank you for your comments. The SDT disagrees. A smaller entity will have less to maintain in accordance with the standard, and thus the
percentages are still appropriate.
Liberty Electric Power LLC
No
See comments at end.
Response: Thank you for your comments. Please see our response to your other comments.
57
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
ExxonMobil Research and
Engineering
Consumers Energy (5)
Yes or No
Question 3 Comment
No
Non-binding
Poll
Comment
see comment on R3
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to your comments on the standard provided elsewhere in this report.
New York Power Authority (1)
Yes
No comments.
Luminant
Yes
No comments.
BGE
Yes
No comments.
Luminant
Yes
No comments
Northeast Power Coordinating
Council
Yes
MISO Standards Collaborators
Yes
Santee Cooper
Yes
Imperial Irrigation District
Yes
PNGC Comment Group
Yes
MRO's NERC Standards
Review Subcommittee
Yes
FirstEnergy
Yes
58
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Western Area Power
Administration
Yes
NextEra Energy
Yes
Ingleside Cogeneration LP
Yes
Central Lincoln
Yes
Shermco Industries
Yes
CPS Energy
Yes
US Army Corps of Engineers
Yes
Ameren
Yes
Georgia Transmission
Corporation
Yes
ITC
Yes
MidAmerican Energy
Company
Yes
Xcel Energy
Yes
NIPSCO
Northern Indiana Public
Service Co. (3)
Question 3 Comment
no comments at this time
Non-binding
Poll
Comment
One of our concerns is that, while the present standard is 2 pages and is the most highly violated and
fined standard, the new proposed standard is 22 pages, the implementation plan is 4 pages and the
Supplemental FAQ document is 87 pages.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
59
Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
response to NIPSC’s comments on the standard provided elsewhere in this report.
Public Utility District No. 2 of
Grant County
Non-binding
Poll
Comment
GCPD has made it a practical practice of not voting affirmative for VRF and VSL until the standard is
edited to our satisfaction and can vote affirmative on the standard.
Response: Thank you for your comments. Please see the revisions made to the standard and the drafting team’s responses to the comments.
Florida Municipal Power
Agency (4) (5)
FMPP (6)
Non-binding
Poll
Comment
· Section 4.2.1 states that the Standard is applicable to “Protections Systems designed to provide
protection BES Elements.” Section 15.1 of the Supplementary Reference Document defines the
scope as those “devices that receive the input signal from the current and voltage sensing devices
and are used to isolate a faulted element of the BES.” These two statements are not exactly
equivalent, and in fact, are in conflict with the Interpretation of PRC-004-1 and PRC-005-1 for Y-W
Electric and Tri-State, Approved by the Board of Trustees on February 17, 2011. Section 4.2.1 should
be changed to “Any Protection System that is installed for the purpose of detecting faults on
transmission elements (lines, buses, transformers, etc.) identified as being included in the Bulk
Electric System (BES) and trips an interrupting device that interrupts current supplied directly from
the BES.”
· Examples #1, #2 and #3 in Section 7.1 of the Supplementary Reference all indicate that it is a
requirement to “verify all paths of control and trip circuits” every 12 years. As stated, there would be
circuits included in the testing requirement that the SDT did not mean to include in the scope of the
Standard (e.g., SCADA closing circuit.) The statements in the illustrative examples should be
changed to “verify all paths in the control circuitry associated with protective functions through the trip
coil(s) of the circuit breakers or other interrupting devices” to be in line with the definition of a
Protection System.
· Section 15.5 of the Supplementary Reference Document states: “It was the intent of this Standard to
require that a test be made of any communications-assisted trip scheme regardless of the vintage of
the technology. The essential element is that the tripping (or blocking) occurs locally when the remote
action has been asserted; or that the tripping (or blocking) occurs remotely when the local action is
asserted”. The SDT should reword this statement recognizing that tests performed on communication
systems may not be performed at the same time an entity chooses to perform trip tests on the
associated breaker(s). The notion of “overlapping” can be applied, for instance, by taking an outage
on one relay set in a fully redundant system, initiating a trip signal from the remote end and observing
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
the trip signal locally. All remaining portions in the local communication-assisted trip paths can then
be tested when the local line panel is taken out of service for maintenance.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to the same comments on the proposed standard provided elsewhere in this report.
Seattle City Light (5)
Non-binding
Poll
Comment
Pursuant to the negative ballot relating to the Standard. Both votes will be affirmed if the comments
are addressed.
Response: Thank you for your comments. Please see the drafting team’s responses to the comments offered by Seattle on the proposed standard.
Seattle City Light (6)
Non-binding
Poll
Comment
Seattle City Light (SCL) commends the Standard Drafting Team (SDT) for the many improvements in
the latest draft of proposed standard PRC-005-2. The proposed PRC-005-2 standard is an
improvement over the four standards that it will replace. Each draft has been better than that
preceding, and the supporting material is very helpful in understanding the impact and
implementation of the proposed Standard. However, SCL votes NO for this draft because of
1) the inclusion and treatment of electromechanical lockout relays within the scope of draft Standard
and
2) confusion about language between section 4.2 and Requirement 1.
Regarding electromechanical lockout relays, SCL is highly concerned about the reliability risks and
logistical difficulties associated with meeting the requirements proposed for these relays. Lockout
relays operate rarely and are known for reliable service. For many such relays, the proposed
maintenance would require clearance of entire bus sections or even multiple bus sections (such as
for a bus differential lockout relay). In SCL's opinion, the reliability risks posed by such switching and
outages to the Bulk Electric System outweigh the reliability benefits of including lockout relays in the
scope of PRC-005-2. If the SDT deems it necessary to include electromechnical lockout relays within
PRC-005-2, SCL recommends that a difference be made between the maintenance activities
specified for monitored and unmonitored types. The draft Standard describes the requirements for
"electromechanical lockout and/or tripping auxiliary devices" in Table 1-5 (p.19) and assigns a 6-year
maximum maintenance interval, the same as for other unmonitored relays. Modern electromechanical
lockout relays may be specified with a built-in self-monitoring trip-coil alarm. SCL believes the
maintenance requirements for electromechanical lockout relays with such an alarm should be similar
to those for other alarmed or monitored relays.
As such we recommend that a new entry be added to Table 1-5 for monitored electromechanical
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Organization
Yes or No
Question 3 Comment
lockout relays, as follows:
• Component Attributes: Electromechanical lockout and/or tripping auxiliary devices which are directly
in a trip path from the protective relay to the interrupting device trip coil AND include built-in selfmonitoring trip-coil alarm
• Maximum Maintenance Interval: 12 calendar years
• Maintenance Activities: Verify electrical operation of electromechanical trip and auxiliary devices.
Verify that the alarm path conveys alarm signals to a location where corrective action can be initiated.
Regarding confusion over language, section 4.2 section identifies five types of Facilities that the
standard is applicable to, whereas Requirement 1 indicates that applicable entities need to establish
a Protection System Maintenance Program (PSMP) for the Protection Systems designed to provide
protection for BES Element(s) (Part 4.2.1 of Section 4.2). As such, it is not clear if PRC-005-2 applies
to five Facilities or to certain Protection Systems. SCL believes the intent is to have a PSMP for all
Protection Systems identified in "Part A, Section 4.2 - Facilities" and that the language of
Requirement 1 may cause confusion or be misleading. We suggest changing the language of
Requirement 1 from:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for
BES Element(s). to: • Each Transmission Owner, Generator Owner, and Distribution Provider shall
establish a Protection System Maintenance Program (PSMP) for its Facilities identified in Part A,
Section 4.2.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to the same comments on the proposed standard provided elsewhere in this report.
Beaches Energy Services (1)
Non-binding
Poll
Comment
We believe that there is an unnecessary expansion of the scope of equipment covered by this
standard into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes
batteries, instrument transformers, DC control circuitry and communications in addition to the relays
for BES protection systems. PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether
non-relay components are included in those standards. The new PRC-005-2 includes these non-relay
components into UFLS and UVLS. The problem is, for UFLS and UVLS, these non-relay components
are mostly distribution class equipment; hence, the result of this version 2 standard will be inclusion
of most distribution class protection system components into PRC-005-2. This is a huge expansion of
the scope of equipment covered by the standard with negligible benefit to BES reliability. We agree
wholeheartedly with the inclusion of non-relay components for BES Protection Systems. It is critical
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
that BES Protection Systems work and clear the fault (e.g., on > 100 kV Facilities). However, UFLS
and UVLS are quite different. For an event requiring UFLS and UVLS operation, there are many, e.g.,
hundreds and possibly thousands of relays, that operate to shed load automatically and if a small
percentage of those do not operate as expected, the impact is minimal. So, it is not important for BES
reliability to include non-relay components of UFLS and UVLS in the PRC-005-2 standard. In
addition, testing of protection systems on distribution circuits is difficult for distribution circuits that are
radial in nature. For instance, testing trip coils of distribution breakers will likely result in service
interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault
current on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing
customer service quality for an infinitesimal increase in BES reliability. In addition, non-relay
protection components operate much more frequently on distribution circuits than on Transmission
Facilities due to more frequent failures due to trees, animals
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to the same comments on the proposed standard provided elsewhere in this report.
City of Green Cove Springs (3)
Non-binding
Poll
Comment
GCS believes that there is an unnecessary expansion of the scope of equipment covered by this
standard into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes
batteries, instrument transformers, DC control circuitry and communications in addition to the relays
for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are
included in those standards. The new PRC-005-2 includes these non-relay components into UFLS
and UVLS. The problem is, for UFLS and UVLS, these non-relay components are mostly distribution
class equipment; hence, the result of this version 2 standard will be inclusion of most distribution
class protection system components into PRC-005-2. This is a huge expansion of the scope of
equipment covered by the standard with negligible benefit to BES reliability. GCS agrees
wholeheartedly with the inclusion of non-relay components for BES Protection Systems. It is critical
that BES Protection Systems work and clear the fault (e.g., on > 100 kV Facilities). However, UFLS
and UVLS are quite different. For an event requiring UFLS and UVLS operation, there are many, e.g.,
hundreds and possibly thousands of relays, that operate to shed load automatically and if a small
percentage of those do not operate as expected, the impact is minimal. So, it is not important for BES
reliability to include non-relay components of UFLS and UVLS in the PRC-005-2 standard. In
addition, testing of protection systems on distribution circuits is difficult for distribution circuits that are
radial in nature. For instance, testing trip coils of a distribution breakers will likely results in service
interruption to customers on that distribution circuit in order to test the breaker or to perform break-
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
before-make switching on the distribution system often required to manage maximum available fault
current on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing
customer service quality for an infinitesimal increase in BES reliability. In addition, non-relay
protection components operate much more frequently on distribution circuits than on transmission
Facilities due to more frequent failures due to trees, animals, lightning, traffic accidents, etc., and
have much less of a need for testing since they are operationally tested.
As another comment, station service transformers are not BES Elements and should not be part of
the Applicability - they are radial serving only load.
Response: Thank you for your comments. These comments are not relative to the non-binding poll of the VRFs and VSLs for PRC-005. Please see our
response to the same comments on the proposed standard provided elsewhere in this report.
ReliabilityFirst
Non-binding
Poll
Comment
ReliabilityFirst agrees with the VRFs but votes negative on the VSLs for the following reasons:
1.
2.
3.
VSL for R1
a. Part 1.3 is not mentioned in the VSLs
b. The VSLs should start off with the phrase “The responsible entities PSMP…”
c. For the VSLs dealing with Part 1.2, the term “or a combination” should be added as one of the
methods for maintenance.
d. The last VSL under the Severe category should reference Part 1.2
e. The VSLs for Part 1.1 should be gradated similar to Part 1.2 (e.g. what VSL does an entity
fall under if they failed to address two component types included in the definition of ‘Protection
System’?)
VSL for R2
a. To be consistent with Requirement 2, the VSLs should start off with the phrase “The
responsible entity uses performance-based maintenance intervals in its PSMP, but…”
b. The first VSL under the “Lower” category is a duplicate of the VSL under the “High” category
c. The third VSL under the “Lower” category has language stating “or containing different
manufacturers.” Neither R2 nor Attachment A mentions this language. This is a violation of the
FERC Guideline 3: “Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement”
d. Recommend that the VSL regarding entities that “maintained a segment with less than X
amount of components” should be a binary “Severe” VSL
VSL for R3
a. The VSLs should start off with the phrase “The responsible entity…”
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 3 Comment
b. R3 does not require an entity to “…complete scheduled program…” This is a violation of the
FERC Guideline 3: “Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement”
c. The “implement and follow its PSMP” language in R3 is not mentioned in the VSLs for R3.
Recommend including this language in the VSLs for R3
Response: Thank you for your comments.
1.
a. Part 1.3 has been added to the R1 High VSL.
b. The R1 Lower, Medium, and Higher VSLs have been modified as you suggest.
c. The R1 Lower, Medium, and Severe VSLs have been modified as you suggest.
d. The R1 Severe VSL has been modified as you suggest
e. The R1 Moderate and High VSLs have been modified to add graduated VSLs for part 1.1.
2.
a. The R2 VSLs have been modified as you suggest.
b. Thank you for catching this. The High VSL has been modified from three years to four years.
c. This portion of the R2 Lower VSL has been removed, making the VSL for this portion of R2 binary (with only a Severe VSL).
d. The VSL for R2 has been modified as you suggest.
3.
a. The R3 VSLs have been modified as you suggest.
b. The R3 VSLs have been modified by replacing “complete” with “implement and follow” in consideration of your comment.
c. The R3 VSLs have been modified by replacing “complete” with “implement and follow” in consideration of your comment.
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
4. The SDT has incorporated the FAQ document into the “Supplementary Reference” document and has provided
the combined document as support for the Requirements within the standard. Do you have any specific
suggestions for further improvements?
Summary Consideration: The commenters were generally supportive of the combination of documents.
Several comments were offered, repeating previous questions regarding the enforceability of this document, and the SDT
repeated previous responses explaining the status of this document as a supporting reference – reference documents have no
enforceability.
A variety of suggestions were offered regarding additional information for the document, which largely resulted in modifications
to the Supplementary Reference document. One specific suggestion of note (resulting in additional discussion within the
document) requested a FAQ regarding “Calendar Year”.
Several commenters posed questions regarding “grace periods” and “PSMPs established by entities that are more stringent than
the requirements within the standard”. No additional changes were made due to these questions, but the SDT further
explained previous guidance on these issues within the responses. Entities are always allowed to implement practices that are
more stringent than those identified in a standard.
Organization
Yes or No
Manitoba Hydro
Question 4 Comment
A red line was not provided making this document difficult to review. We suggest that a redline of this
document be posted.
Response: Thank you for your comments. A red-line was not provided because of overall extensive changes, resulting from merging of the previous
Supplementary Reference Document and FAQ; the entire document would have been red-line. The next posting will include a red-lined document, as well as the
“clean” document.
U.S. Bureau of Reclamation (5)
Ballot
Comment Affirmative
1. The reference material provides a significant insight into the intent of the proposed changes to the
standard. In some cases an interpretation is provided which is not supported by the explicit interpretation of
the standard text. The SDT is encouraged to either attach the reference material to the standard or add
relevant sections to standard as Background. The Background section could reference the Supplemental
Reference & FAQ.
2. The reference material provides more detail indicating that “Voltage & Current Sensing Device circuit input
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 4 Comment
connections to the protection system relays can be verified by (but not limited to) comparison of measured
values on live circuits or by using test currents and voltages on equipment out of service for maintenance. .
. . . . The values should be verified to be as expected, (phase value and phase relationships are both
equally important to verify).” This interpretation is not consistent with the text of the standard and would
suggest that it be incorporated into Table 1-3.
3. When protective equipment is replaced, the reference information indicates that the information associated
with the original equipment must be retained to show compliance with the standard until the performance
with the new equipment can be established. This is not stated in the Measurements and should be added if
the expectation exists.
Response: Thank you for your comments.
1. This standard is not being developed in a “results-based” format. Attaching the extra document as you suggest would make the supporting information within
the FAQ and Supplementary Reference part of the standard, and this would add extensive and unnecessary prescription to the standard. As you suggest the
reference material is listed within the Standard (Section F – Supplemental Reference Document). The next revision will likely resemble your suggestion.
2. Details within the Supplemental Reference Document are provided as examples and should not be construed as limitations or additional requirements. The
intent of the supplementary information is to spur insight into possible means of satisfying requirements and is not intended to promote a single technical method
of accomplishing tasks.
3. M1 states “Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence that it has implemented the Protection System
Maintenance Program and…” Documenting the implementation of the PSMP certainly requires evidence that maintenance was performed at the prescribed
intervals and the data retention requirements state that evidence of the two most recent performances of each distinct maintenance activity be retained. Also,
please see the NERC Compliance Process Bulletin #2011-001 (“Data Retention Requirements”) for similar guidance.
Ameren Services (1)
Ballot
1. Omit retention of maintenance records for replaced equipment. Supplement FAQ 12.1 on page 51 final
Comment –
sentence states that documentation for replaced equipment must be retained to prove the interval of its
Affirmative
maintenance. We oppose this because: the replaced equipment is gone and has no impact on BES reliability;
and such retention clutters the data base and could cause confusion. For example, it could result in saving
lead acid battery load test data beyond the life of its replacement. Since BES Element protection is the
objective, we suggest a compromise of keeping the evidences of last test for the removed equipment and
using that with the equivalent function replacement equipment commissioning or in-service date to prove
interval.
2. In Supplement examples on pp 22-23, replace “Instrumentation transformers” with “Verify that current and
voltage signal values are provided to the protective relays” to be consistent with Table 1-3.
3. Remove “Reverse power relays” from the sample list of generator devices in Supplement p31 because
reverse power relays are applied for mechanical protection of the prime mover, not electrical protection of the
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 4 Comment
generator.
4. Revise Supplement Figure 1 & 2 Legend p83 to align with Draft 4 (a) state “Protective relays designed to
provide protection for BES Element(s)” (b) state “Current and voltage signals provided to the protective
relays”.
5. Please add a Performance-Based maintenance example for control circuitry, and /or voltage and current
sensing.
Response: Thank you for your comments.
1. This cited reference in the Supplementary Reference Document is present to maintain consistent evidence that maintenance was performed within prescribed
intervals. Please see the NERC Compliance Process Bulletin #2011-001 (“Data Retention Requirements”) for similar guidance.
2. Thank you, the change has been made.
3. The commenter is correct that it is the prime mover that is protected by the Reverse Power relay; however the Standard considers relays (such as Reverse
Power relays) that sense voltage and current are within the scope. Furthermore, Part 4.2.5.1 (Applicability) of the Standard includes Protection Systems for
generator Facilities that are part of the BES including Protection Systems that act to trip the generator either directly or via generator lockout or auxiliary tripping
relays.
4. The column marked Component of Protection System closely aligns with the definition of Protection System as approved by the NERC Board of Trustees and is
included within the Standard itself. The next column (“Includes”) is more explanatory in nature and is intended to give insight on the SDT’s intent.
5. Thank you, the requested changes have been made. Additional Q&A (including one for control circuitry and one for voltage and current sensing devices) have
been added to Section 9.2.
National Grid (1)
Ballot
Comment Affirmative
National Grid suggests that FAQ be added:
1. Regarding Table 2 in the standard, Does a fail-safe “form b” contact that is alarmed to a 24/7 operation
center classify as an alarm path with monitoring?
2. Please add a clarification as part of the FAQ document that defines whether the control circuitry and trip
coil of a non-BES breaker, tripped via a BES protection component, must be tested per Table 1.5.
Response: Thank you for your comments.
1. Thank you, the change has been made. An additional Q&A has been added to Section 15.6.1.
2. Thank you, the change has been made. An additional Q&A has been added to Section 15.3.1.
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
New York Power Authority (1)
Ballot
Comment Affirmative
Question 4 Comment
Comments: We suggest that FAQ be added:
1. Regarding Table 2 in the standard, Does a fail-safe “form b” contact that is alarmed to a 24/7 operation
center classify as an alarm path with monitoring?
2. Please add a clarification as part of the FAQ document that defines whether the control circuitry and trip
coil of a non-BES breaker, tripped via a BES protection component, must be tested per Table 1.5.
Response: Thank you for your comments.
1. Thank you, the change has been made. An additional Q&A has been added to Section 15.6.1.
2. Thank you, the change has been made. An additional Q&A has been added to Section 15.3.1.
Muscatine Power & Water (3)
Ballot
Comment Affirmative
In the “Supplemental Reference and FAQ” document on page 65 there is one area of concern.
In paragraph 4 “…the type of test equipment used to establish the baseline must be used for any future
trending of the cells internal ohmic measurements because of variances in test equipment and the type of
ohmic measurement used by different manufacturer’s equipment.”
While MP&W understands the importance of creating a valid baseline, it is disingenuous to expect the test
equipment to be the same as the manufacturer’s test equipment. For that matter, it would be highly unlikely
the same test equipment would be used over the life of the battery. The expected life of a battery may be in
excess of 15 years in most cases and it would not be probable to expect that the type of test equipment is not
going to change during this period. MP&W suggests changing the wording to read that CONSISTENT test
equipment should be used to provide consistent/comparable results.
Response: Thank you for your comments, the change has been made. The statements concerning types of equipment have been changed per your suggestion to
reflect consistent test data as opposed to exactly the same piece of test equipment.
Florida Municipal Power Agency
(4) (5) (6)
Florida Municipal Power Pool (6)
Ballot
Comment Negative
1. Examples #1, #2 and #3 in Section 7.1 of the Supplementary Reference all indicate that it is a requirement
to “verify all paths of control and trip circuits” every 12 years. As stated, there would be circuits included in
the testing requirement that the SDT did not mean to include in the scope of the Standard (e.g., SCADA
closing circuit.) The statements in the illustrative examples should be changed to “verify all paths in the
control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other
interrupting devices” to be in line with the definition of a Protection System.
2. Section 15.5 of the Supplementary Reference Document states: “It was the intent of this Standard to
require that a test be made of any communications-assisted trip scheme regardless of the vintage of the
technology. The essential element is that the tripping (or blocking) occurs locally when the remote action
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
Question 4 Comment
has been asserted; or that the tripping (or blocking) occurs remotely when the local action is asserted”. The
SDT should reword this statement recognizing that tests performed on communication systems may not be
performed at the same time an entity chooses to perform trip tests on the associated breaker(s). The notion
of “overlapping” can be applied, for instance, by taking an outage on one relay set in a fully redundant
system, initiating a trip signal from the remote end and observing the trip signal locally. All remaining
portions in the local communication-assisted trip paths can then be tested when the local line panel is taken
out of service for maintenance.
Response: Thank you for your comments.
1. Thank you, the change has been made.
2. Thank you, the change has been made.
ITC
No
We agree with the combination of the two. One document with the FAQ’s grouped with the supplemental
topics makes it easier to review the whole topic.
Response: Thank you for your comments.
Central Lincoln
No
The first FAQ under 2.3.1 is incorrect, referencing a FERC informational filing. Included in the filing was a
WECC test that was never approved by the WECC board and is not being used. Using this document as
suggested will get WECC entities into trouble.
Response: Thank you for your comments. There are presently regional differences allowed that may cease to exist once the BES is redefined. The SDT for the
BES Definition (Project 2010-17) is charged with developing a continent-wide BES definition; however, this FERC informational filing is on the public record, and
was part of the basis for FERC Order 743.
Tampa Electric Company
No
Tampa Electric requests further differentiation between BES protection elements and UFLS equipment.
Response: Thank you for your comments. UFLS equipment is presently covered under PRC-008. PRC-005-2 will cover all Protection Systems components
including components used for UFLS. The Standard addresses UFLS and UVLS to the degree that they are installed per NERC Standards, even though entities
may choose to install them on distribution systems. This is an intentional difference between UFLS/UVLS and the remainder of the Protection Systems addressed
within the Standard, because of the distributed nature of UFLS/UVLS and because these devices are usually tripping non-BES system elements.
Electric Market Policy
No
Santee Cooper
No
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
Yes or No
SPP reliability standard
development Team
No
Tennessee Valley Authority
No
Imperial Irrigation District
No
MRO's NERC Standards Review
Subcommittee
No
The Detroit Edison Company
No
NextEra Energy
No
Western Electricity Coordinating
Council
No
Ingleside Cogeneration LP
No
Farmington Electric Utility System
No
Illinois Municipal Electric Agency
No
Shermco Industries
No
Dominion Virginia Power
No
American Electric Power
No
CPS Energy
No
Indeck Energy Services
No
MidAmerican Energy Company
No
Question 4 Comment
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
Organization
NIPSCO
Yes or No
Yes
Question 4 Comment
We used the FAQ Supplemental Reference while reviewing this draft standard and found it useful.
Response: Thank you for your comments.
FirstEnergy
Yes
1. We do not agree with the following wording on page 37 of the reference document: (1) “If your PSMP (plan)
requires more activities then you must perform and document to this higher standard.” and (2) “If your
PSMP (plan) requires activities more often than the Tables maximum then you must perform and document
those activities to your more stringent standard.”
2. We continue to believe that the auditor is required to audit to the standard. If the standard requires
maintenance intervals every 6 years, this is what the auditor should verify. This was also verified in the
recent NERC Workshop at which it was confirmed that “auditors must audit to the standard”.
To this end, we also suggest changes to Requirement R3 as explained in our comments in Question 5.
Response: Thank you for your comments.
1. The SDT respectfully disagrees with the commenter. R1 of the Standard states that “… shall establish a Protection System Maintenance Program (PSMP)…,
and R3 states that “… shall implement and follow its (PSMP)…” Therefore, if an entity has a more stringent PSMP then they must follow their own PSMP. An
example of this might be a case that has an entity with Performance Based Maintenance; this entity could find time intervals between maintenance activities that
are more frequent than are laid out in the Tables. This entity must follow their PSMP. Another example might be an entity that requires CT Saturation tests every
10 years; this is a more stringent requirement than is contained within the minimum maintenance activities of the Standard. Neither the SDT nor any auditor has
any idea why an entity may require more stringent requirements of themselves than the Standard requirements. Even under the present PRC-005-1 an auditor
audits to the entity’s PSMP; a case in point is if an entity PSMP requires relay testing with simulated fault values of voltage and current every year then they are
audited to that requirement (even though PRC-005-1 specifically does not require any particular relay testing and certainly has no time intervals stated). Please
note that FERC Order 693 directs NERC to establish maximum allowable intervals not minimum intervals, and the entity’s program must, at a minimum, conform
to those intervals.
2. The SDT has set no requirements that an entity have a more stringent PSMP than the minimum requirements set out in the Standard, only that any PSMP meet
the minimums laid out within the Standard. But, should an entity have a PSMP that is more stringent then, according to R3, they must maintain to their own more
stringent PSMP.
BGE
Yes
1. The supplementary reference on page 30, under the question beginning “Our maintenance plan requires”
states that an entity is “out of compliance” if maintenance occurs at a time longer than that specified in the
entity’s plan, even if that maintenance occurred at less than the maximum interval in PRC-005-2. But then
on page 35, under the question, “How do I achieve a grace period without being out of compliance”
provides an example of scheduling maintenance at four year intervals in order to manage scheduling
complexities and assure completion in less in less than the maximum time of six calendar years. This is
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Question 4 Comment
conflicting advice. The FAQ /supplementary reference should be revised so that it does imply that an entity
is out-of-compliance by performing maintenance more frequently than required. Avoiding compliance risk is
one reason to do this, but there are other valid motives not directly related to reliable protection system
performance.
2. Testing of PT’s and CT’s (12 year max) is non invasive and convenient to schedule at the same time as
relays (6 year max) just to keep procedures consistent and reduce program administration. Testing of ties
to other TOs or GOs may have to be scheduled more frequently than preferred in order to synchronize
schedules.
Response: Thank you for your comments.
1. There is no conflict, the first commenter-cited PSMP example has language that has no grace-period built in, and the second commenter-cited PSMP example
has language with a built-in grace period. Both cited examples are measurable to a time limit between testing activities.
2. Your observations are correct; an entity may choose to perform activities more often than is specified in the Standard. For that matter, an entity may choose to
perform activities more often than their own PSMP; the entity simply cannot exceed their own PSMP intervals which in turn cannot exceed the intervals in the
Standard.
Pepco Holdings Inc
Yes
The Supplementary Reference and FAQ should be an attachment to the standard (Appendix A) and not just
referenced. If not attached it will not be readily accessible to those that will be using the standard.
Response: Thank you for your comments. The Supplementary Reference and FAQ is referenced in Section F of the standard (which was on Page 9 of the clean
version of the recent posting), in accordance with the Standards Development Process, and will be posted with the standard as “Reference Materials”.
GDS Associates
Yes
The standard should include a footnote indicating this document as reference
Response: Thank you for your comments. This document is addressed within the Standard as a reference document by listing it in Section F (which was on Page
9 of the clean version of the recent posting), in accordance with the Standards Development Process.
ExxonMobil Research and
Engineering
Yes
The SDT should provide notes that reference the sources used for developing the maximum maintenance
intervals utilized in the time-based program, and provide a technical explanation as to why they have not
provided a tolerance band for use with the time-based program. What is the increase in risk owned by an
entity when a protective device is tested at the 6 year and 30 day mark instead of the 6 year mark?
Response: Thank you for your comments. The SDT was tasked to create a standard with maximum time intervals between maintenance activities. Thus the task,
in and of itself, sets the limit as absolute. Where the intervals were set at six years (or any interval for that matter), there was no assessment of risk beyond the
time interval chosen as the absolute. The question always would arise as “Why not an additional thirty days after that?” The reference material cites methodology
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Question 4 Comment
to determine initial time intervals. The SDT took further care to try to align the initial maintenance intervals with common maintenance schedules like plant outages
and other published guidelines. Please note that the Tables refer to “Calendar Year” for the intervals referenced in the comment; the noted concern would only be
relevant if the entity actually completes the activity at the very end of the calendar year.
US Army Corps of Engineers
Yes
1. The reference material provides a significant insight into the intent of the proposed changes to the
standard. In some cases an interpretation is provided which is not supported by the explicit interpretation of
the standard text. The SDT is encouraged to either attach the reference material to the standard or add
relevant sections to standard as Background. The Background section could reference the Supplemental
Reference & FAQ.
2. The reference material provides more detail indicating that “Voltage & Current Sensing Device circuit input
connections to the protection system relays can be verified by (but not limited to) comparison of measured
values on live circuits or by using test currents and voltages on equipment out of service for maintenance. .
. . . . The values should be verified to be as expected, (phase value and phase relationships are both
equally important to verify).”
This interpretation is not consistent with the text of the standard and would suggest that it be
incorporated into Table 1-3.
Response: Thank you for your comments.
1. This standard is not being developed in a “results-based” format. As you suggest the reference material is listed within the Standard (Section F – Supplemental
Reference Document). The next revision will likely resemble your suggestion.
2. Details within the Supplemental Reference Document are provided as examples and should not be construed as limitations or additional requirements. The
intent of the supplementary information is to spur insight into possible means of satisfying requirements and is not intended to promote a single technical method
of accomplishing tasks.
Luminant
Yes
The document was valuable in understanding PRC-005-2 by providing clarification using practical protective
relay system examples. Below are two comments for further improvement.
1. It would be beneficial if the document could provide additional information for relaying in the high-voltage
switchyard (transmission owned) - power plant (generation owned) interface. While Figures 1 and 2 are
typical generation and transmission relay diagrams, it would be helpful if protective relays typically used in
the interface also be included. For example, a transmission bus differential would remove a generator from
service by tripping the generator lockout.
2. Figures 1 and 2 refer to a “Figure 1 and 2 Legend” table which provides additional information on
qualifications for relay components. Should a footnote be used to point toward Reference 1 (Protective
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Question 4 Comment
System Maintenance: A Technical Reference) located in Section 16?
Response: Thank you for your comments.
1. There are so many variations possible that it is impractical to try to capture all configurations on a single picture or in a single document. However, for the cited
example - a transmission bus Protection System would be included. All five of the Protection System component types would fall within the Standard including the
trip paths and the electrical test requirements of the generator lockout device.
2. Thank you, a link has been provided to the references.
MISO Standards Collaborators
Yes
The additional documentation seems to be quite large, and the additional content seems to go far beyond
what is necessary for the PRC-005-2 standard. We recommend the SDT lessen the amount of content
provided in the “Supplementary Reference” document.
Response: Thank you for your comments. Details within the Supplemental Reference Document are provided as examples and should not be construed as
limitations or additional requirements. The intent of the supplementary information is to spur insight into possible means of satisfying requirements and is not
intended to promote a single technical method of accomplishing tasks.
Northeast Power Coordinating
Council
Yes
Suggest that to FAQ be added:
1. Regarding Table 2 in the standard, does a fail-safe “form” contact that is alarmed to a 24/7 operation
center qualify as an alarm path with monitoring?
2. Add a clarification as part of the FAQ document that defines whether the control circuitry and trip coil of a
non-BES breaker, tripped via a BES protection component, must be tested as per Table 1.5.
Response: Thank you for your comments.
1. Thank you, the change has been made. An additional Q&A has been added to Section 15.6.1.
2. Thank you, the change has been made. An additional Q&A has been added to Section 15.3.1.
Georgia Transmission
Corporation
Yes
See comments for item 1 and continue clarification where we could include high side or distributed
interrupting devices, exchange nomenclature removing distribution breaker and adding distributed interrupting
device or non-BES equipment.
Response: Thank you for your comments. Circuit interrupting devices that only participate in a UFLS or UVLS scheme are excluded from the tripping requirement,
but not from the circuit test requirements. The “non-BES equipment interruption device” phrase has been inserted as suggested.
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PNGC Comment Group
Yes or No
Yes
Question 4 Comment
Section 9.2 (copied below) indicates that small entities can utilize Performance-Based PSMP if they
aggregate with other entities. Does this section indicate that only a parent entity with individually owned
components can aggregate, or can independent entities under a G&T aggregate? In other words, individual
DP/LSE/TOs with different audits. Can they aggregate under a common PSMP for performance based
maintenance?
9.2 Frequently Asked Questions: I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity? Multiple asset owning entities may aggregate their individually
owned populations of individual Protection System components to create a segment that crosses ownership
boundaries. All entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance intervals and
criteria), for which the multiple owners are individually responsible with respect to the requirements of the
Standard. The requirements established for performance-based maintenance must be met for the overall
aggregated program on an ongoing basis. The aggregated population should reflect all factors that affect
consistent performance across the population, including any relevant environmental factors such as
geography, power-plant vs. substation, and weather conditions.
Response: Thank you for your comments.
Two entities in such a shared program must have populations of components that can be aggregated and the PSMP for those components are the same between
the two entities. Thus the combined entities can show total populations, total numbers of components tested and total failures found. The combined entities would
thus be forced to follow the same intervals, test procedures and statistical analysis. There would have to be cooperation between entities but in the end the
outcome would be the same as if the PBM process were applied to a single entity. There is no inherent advantage or disadvantage to multiple entities cooperating
in such a manner. The SDT intends that small entities with small populations of equipment have the same access to PBM as the larger entities.
FHEC
Yes
It is unclear what compliance obligations may be created or clarified with the FAQ. It is a good explanatory
document and a helpful reference, but the Standard should speak for itself as it relates to what it takes to
achieve compliance.
Response: Thank you for your comments. The Standard is the only “mandatory and enforceable” document. Details within the Supplemental Reference
Document are provided as examples and should not be construed as limitations or additional requirements. The SDT intends that it be posted as a Reference
Document, accompanying the standard. As established in SDT Guidelines, the Standard is to be a terse statement of requirements, etc, and is not to include
explanatory information like that included in the Supplementary Reference Document. The Supplementary Reference FAQ will be revised in the course of the
revision process of the standard.
Western Area Power
Yes
Can the SDT add a better definition or clarification of ”Calendar Year” as it pertains to PRC-005-2 and provide
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Question 4 Comment
examples or parameters of Compliance with the Standard requirements and tables? Calendar Year is
explained in various details within Pages 35-Pages 37 of the Supplementary Reference and FAQ. This
important attribute of a TBM or TBM/CBM combination program is not easily found in the Table of Contents or
section sub-headings.
Response: Thank you for your comments. Per your suggestion, a “What is a Calendar Year?” Q&A has been added to the front end of Section 7.1.
Duke Energy
Yes
Along the lines of what we have suggested in our comment to Question #1 above, we believe it would make
compliance more certain if selected language from the Supplementary reference could be incorporated into
the standard, either directly in requirements, or in footnotes.
Response: Thank you for your comments. The addition that you suggest is properly considered application guidance; the SDT has been advised that this
information is not to be included within the standard, and that it is appropriately included in separate reference materials.
Ameren
Yes
1. Comments: Supplement FAQ 12.1 on page 51 final sentence states that documentation for replaced
equipment must be retained to prove the interval of its maintenance. We oppose this because: the
replaced equipment is gone and has no impact on BES reliability; and such retention clutters the data base
and could cause confusion. For example, it could result in saving lead acid battery load test data beyond
the life of its replacement. Since BES Element protection is the objective, we suggest a compromise of
keeping the evidences of last test for the removed equipment and using that with the equivalent function
replacement equipment commissioning or in-service date to prove interval.
2. Clarify p17 Table 1-4(e) interval meaning. We think this means we need to verify the Station dc supply
voltage on 12 calendar year interval if unmonitored, or no periodic maintenance if monitored as stated.
3. In Supplement examples on pp 22-23, replace “Instrumentation transformers” with “Verify that current and
voltage signal values are provided to the protective relays” to be consistent with Table 1-3.
4. Remove “Reverse power relays” from the sample list of generator devices in Supplement p31 because
reverse power relays are applied for mechanical protection of the prime mover, not electrical protection of
the generator.
5. Revise Supplement Figure 1 & 2 Legend p83 to align with Draft 4 (a) state “Protective relays designed to
provide protection for BES Element(s)”. (b) state “Current and voltage signals provided to the protective
relays”
6. Please add a Performance-Based maintenance example for control circuitry, and /or voltage and current
sensing.
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Question 4 Comment
Response: Thank you for your comments.
1. This cited reference in the proposed Standard is present to maintain consistent evidence that maintenance was performed within prescribed intervals.
2. The SDT agrees.
3. Thank you, the change has been made
4. The commenter is correct that it is the prime mover that is protected by the Reverse Power relay, however the Standard considers relays (such as Reverse
Power relays) that sense voltage and current as within the scope. Furthermore, Part 4.2.5.1 of the Standard states that Protection Systems for generator Facilities
that are part of the BES including Protection Systems that act to trip the generator either directly or via generator lockout or auxiliary tripping relays
5. The column marked Component of Protection System closely aligns with the definition of Protection System as approved by the NERC Board of Trustees and is
included within the Standard itself. The next column (“Includes”) is more explanatory in nature and is intended to give insight on the SDT intent
6. Thank you, the changes have been made. Additional Q&A have been added to Section 9.2.
Xcel Energy
Yes
1) On page 65, paragraph 4, of the ”Supplemental reference and FAQ” document, it states:”the type of test
equipment used to establish the baseline must be used for any future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement used by
different manufacturer’s equipment.” While we understand the importance of creating a baseline, it is not
feasible to expect the test equipment be the same as the manufacturer’s test equipment or even the same
test equipment over the life of the battery. The expected life of a battery may be in excess of 20 years
and it is not feasible to expect that the type of test equipment will not change during this period.2) A FAQ
to clarify in scope protection systems for variable energy resource facilities (wind, solar, etc) would be
very helpful.
2) Does paragraph 4.2.5.3 “Facilities” imply that the only protection system associated with a wind farm that
is considered in scope for PRC-005-2 is that for the aggregating transformer? If other protection systems
associated with a wind farm are in scope, please clarify which systems would be in scope for PRC-005-2.
For example, a typical wind farm in our system might have 30-33, 1.5MVA windmills connected to one
34.5 KV collecting feeder circuit for a total of roughly 50 MVA per collecting feeder. 4 of these 50 MVA
collecting feeders are tied via circuit breakers to a low side 34.5 KV bus which in turn is connected via a
low side breaker to aggregating step up transformer which then connects to the BES transmission
system. Obviously per paragraph 4.2.5.3, the protection system for the aggregating step up transformer
is in scope. What about the protection system for the transformer low side 34.5 KV breaker - serving 200
MVA of aggregate generation? What about the protection system of each individual 34.5 KV aggregating
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feeder - 50 MVA of aggregate generation? What about the”protection system” for each individual 1.5
MVA windmill? An FAQ on this topic would be very helpful.
Response: Thank you for your comments.
1. Thank you for your suggestion; the paragraph cited has been changed.
2. Clause 4.2.5.3 states specifically that the Protection Systems on the aggregating transformer are included. The SDT has not specifically included other
equipment, but, depending on what, specifically, is defined to be BES for these facilities, either within current Regional definitions or within the emerging NERC
definition, other equipment may be drawn in.
Alliant Energy
Yes
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Consideration of Comments on the 4th draft of the standard for Protection System Maintenance and Testing — Project 2007-17
5. If you have any other comments on this Standard that you have not already provided in response to the prior
questions, please provide them here.
Summary Consideration: Several commenters were concerned that an entity has to be “perfect” in order to be compliant;
the SDT responded that NERC Standards currently allow no provision for any degree of non-performance relative to the
requirements.
Several commenters continued to insist that “grace periods” should be allowed. The SDT continued to respond that grace
periods would not be measurable.
Several comments were offered, suggesting that PRC-005-2 needs to be consistent with the interpretation in Project 2009-17,
now implemented as PRC-005-1a, and the SDT modified Applicability 4.2.1 for better consistency with the interpretation 4.2.1
(Protection Systems that are installed for the purpose of detecting faults on BES Elements (lines, buses, transformers, etc).
Many comments were offered objecting to the 3-calendar-month intervals for station dc supply and communications systems,
and suggesting that a 3-calendar-month interval requires entities to schedule these activities for 2-calendar-months in order to
assure compliance. The SDT did not modify the standard in response to these comments, and responded that the intervals
were appropriate, and that entities should be able to assure compliance on a 3-calendar-month schedule by using program
oversight. The “Supplementary Reference and FAQ” document was augmented with additional explanatory text.
Several comments were offered questioning various aspects of Applicability 4.2.5.4 (generation auxiliary transformers). No
changes were made in response to these comments, and responses were offered illustrating why these transformers are
included.
Many (essentially identical) comments were offered, questioning the propriety of including distribution system Protection
Systems, almost all related to UFLS/UVLS. The SDT explained that these Protection Systems are appropriate to be included for
consistency with legacy standards PRC-008, PRC-011, and PRC-017, and noted that their inclusion is consistent with Section
202 of the NERC Rules of Procedure.
Several comments were offered, objecting to the 6-calendar-year interval for lockout and auxiliary relays. The SDT declined to
adopt the requested changes, and noted that these “electromechanical” devices with “moving parts” share failure mechanisms
with electromechanical protective relays and that the intervals should be identical.
Several comments were offered regarding Maintenance Correctable Issues, and resulted in modifying this definition to be
“…such that the deficiency cannot be corrected during the performance of the maintenance activity …”
Assorted additional comments were offered by individual commenters (most of them similar to comments on previous
postings), which resulted in responses similar to those offered during previous posting periods.
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Question 5 Comment
Consolidated Edison Co. of New
York (1) (3) (5)
Ballot
Comment Affirmative
We recommend that the drafting team recognize that a “fail safe” or “self-reporting” alarm design serves as an
acceptable alternative to periodic testing. This “fail safe” or “self-reporting” alarm design is equivalent to
continuous testing the alarm. When the alarm circuit fails the alarm is set to “alarm on” and automatically
notifies the control center, initiating a corrective action.
Response: Thank you for your comments. The application discussed seems to the SDT to be an effective method of “monitoring the monitoring circuit”. (See Table
2, last row with heading “Alarm Path with monitoring.”)
Ameren Services (1)
Ballot
Comment Affirmative
(1) Need some tolerance – require 99% of components to meet R3. Measure M3 on page 5 should apply to
99% of the components. “Each … shall have evidence that it has implemented the Protection System
Maintenance Program for 99% of its components and initiated….” PRC-005-2 unrealistically mandates
perfection without providing technical justification. A basic premise of engineering is to allow for reasonable
tolerances, even Six Sigma allows for defects. Requiring perfection may well harm reliability in that valuable
resources will be distracted from other duties.
(2) Define BES perimeter in accordance with Project 2009-17 Interpretation. Facilities Section 4.2.1 “or
designed to provide protection for the BES” needs to be clarified so that it incorporates the latest Project
2009-17 interpretation. The industry has deliberated and reached a conclusion that provides a meaningful
and appropriate border for the transmission Protection System; this needs to be acknowledged in PRC005-2 and carried forward. The BOT adopted this 2/17/2011.
(3) Battery inspection every 4 months is sufficient. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for an
interval that might extend past three calendar months due to storms and outages must set a target interval
of two months thereby increasing the number of inspections each year by half again. This is unnecessarily
frequent. We suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar
months.
Response: Thank you for your comments.
1. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation.
2. The referenced interpretation relates to a quasi-definition of “transmission Protection System”, and in the context of the approved PRC-004-1 and PRC-005-1,
presents a consistent context for this term. However, the interpretation was constrained to not introducing any requirements or applicability not already included
within the approved standards. PRC-005-2 does not use this term, and expands upon the applicability in the interpretation to address what seems to the SDT to
be an appropriate applicability for PRC-005-2. The applicability of the interpretation to PRC-004-1 is not affected by PRC-005-2.
3. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
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Question 5 Comment
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the activity was performed.
Xcel Energy
1) Regarding “Facilities” paragraph 4.2.5, we are in agreement with the elimination from scope of system
connected station service transformers for those plants that are normally fed from a generator connected
station service transformers. However, in the cases where a plant does not have a generator connected
station service transformer such that it is normally fed from a system connected station service transformer,
is it still the drafting team’s intent to exclude the protection systems for these system connected auxiliary
transformers from scope even when the loss of the normal (system connected) station service transformer
will result in a trip of a BES generating facility? If the end result of the trip of the primary station service
transformer is a trip of a BES generating facility, it would be more consistent to include the protection
system for that transformer as in scope - whether it be connected to the system or to the generator.
2) We recommend the SDT consider an interval of 12 calendar years for the component in row 3, of Table 1-5
on page 19 of the standard. The maximum maintenance interval for “Electromechanical lockout and/or
tripping devices which are directly in a trip path from the protective relay to the interrupting device trip coil”
should be consistent with the “Unmonitored control circuit” interval which is 12 calendar years. In order to
test the lockout relays, it may be necessary to take a bus outage (due to lack of redundancy and associated
stability issues with delayed clearing). Increasing the frequency of bus outages (with associated lines or
transformers) will also increase the amount of time that the BES is in a less intact system configuration.
Increasing the time the BES is in a less intact system configuration also increases the probability of a low
frequency, high impact event occurring. Therefore, the Maximum Maintenance Interval should be 12 years
for lockout relays. We believe that, as written, the testing of “each” trip coil and the proposed maintenance
interval for lockout testing will result in the increased amount of time that the BES is in a less intact system
configuration. We hope that the SDT will consider these changes.
Response: Thank you for your comments.
1. The SDT does not intend that the system-connected station auxiliary transformers be included in the Applicability. The generator-connected station service
transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
2. The SDT believes that electromechanical devices share performance attributes (and failure modes) with electromechanical relays and need to be tested at
similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
Northeast Power Coordinating
Council, Inc. (10)
Ballot
Comment -
A concern exists that an entity with a very strict PSMP with intervals that are much shorter than neighboring
entities or the standard will rewrite their PSMP and loosen their requirements to allow postponed maintenance
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Affirmative
Question 5 Comment
up the maximum specified in the standard. This standard, as written penalizes non-adherence to more
stringent and better PSMPs and may inadvertently driving entities to the least common denominator. I am
hopeful that Phase 2 will address this issue.
Response: Thank you for your comments. The Standard is defining maximum allowable intervals and minimum acceptable activities for a PSMP. Entities are
empowered to develop PSMPs that exceed these requirements if they determine such a PSMP to be necessary.
GDS Associates
Requirement R1
1.
Suggest changing the language in R1.2 to read “Identify which maintenance method such as the timebased, performance-based (detailed in PRC-005 Attachment A), or a combination of the two would be
appropriate to be used for each type of Protection System component. Based upon their own constructive
type, all batteries associated with the station DC supply shall be included in a time-based maintenance
program consistent with Table 1-4(a) through Table 1-4(f)”
2. Suggest changing the language for the first paragraph in R1.3 to read “Establish the occurrences
associated with the time-based maintenance programs up to but no less than the time intervals specified
in Table 1-1 through Table 1-5, and Table 2. Consequently, include all applicable monitoring attributes
and related maintenance activities characteristic to each type of Protection System component specified
in Table 1-1 through Table 1-5, and Table 2”
3. Suggest adding a sub-requirement such as R1.5 to read “Include documentation of maintenance, testing
interval and their basis and a summary of testing procedures”
Requirement R3
4. The redline version of the standard is misleading. Requirement R3 is crossed out and then replacing
requirement R7 which is also crossed out.
5. The wording “initiates resolution of any identified maintenance correctable issues” it is vague. What a
responsible entity should do to become compliant with this requirement? We also believe that is not
sufficient to just “initiate resolution”; the standard should call for corrective actions to be performed within
the maintenance time interval.
6.
The “identified maintenance correctable issues” may not be a proper choice. The name of the new term
suggests that is about issues that can be corrected during maintenance, while the definition from the
clean version explains otherwise?
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Additional requirement
7. Suggest adding a requirement to read “The Transmission Owner, Generator Owner, and Distribution
Provider shall provide documentation of its PSMP and implementation to the appropriate Regional
Reliability Organizations on request (within 45 calendar days).”
8. Add measure for the evidence on documenting the PSMP from the additional requirement
General comments and notes
9. If you own electro-mechanical relays and microprocessor based relays is there a need to keep two
different logs for these?
10. On table 1-4 the generator CTs should be tested earlier than the suggested 12 years due to exposure of
continuous mechanical stress
11. Clarify table 1-5 to address verification tests on different circuits. Suggest that the Table 1-5 to read
“Complete a terminal test of unmonitored circuitry” instead of the “Unmonitored control circuitry
associated with protective functions”
12. In what instances (what extent) would the standard allow using the real time breaker operation to be
considered maintenance as applicable to different types of relays involved in the real time event? This is
briefly emphasized under TBM at paragraph 5.1 from the supplementary reference document?
Response: Thank you for your comments.
1. It is not enough for an entity to determine if time-based, performance-based, or a combination of the two would be “appropriate”; the entity must specify which
method is being used, so that it is clear to both the entity and an auditor if R2 and Attachment A apply.
2. The SDT has considered your comment and has determined that the text currently within the requirement is appropriate.
3. The requirement that you suggest is identical to one of the most troublesome requirements from the approved PRC-005-1. By providing Tables 1-1 through 1-5,
as well as Table 2, the SDT is establishing maximum allowable intervals as well as minimum required activities, and thus replacing this PRC-005-1 requirement
with a more prescriptive one. If an entity chooses to extend the intervals and alter the activities by using monitoring, or to apply performance-based maintenance
per R2 and Attachment A, the additional requirements related to those choices effectively establish a requirement such as you suggest.
4. The red-lining tools in Microsoft Word can sometimes be misleading, but the red-line is provided in an effort to illustrate the changes made to the document. We
recommend that the entity use the “clean” version in order to see the final resulting text.
5. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even
several years) to complete effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with
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Question 5 Comment
other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these
more extended activities to “correct the maintenance correctable issue”; therefore, the SDT has opted to require only that the entity initiate correction of
maintenance correctable issues within PRC-005-2 and rely on the operating focus on the degraded system to ensure that they are completed. The associated
measure provides examples of relevant documentation. The definition of maintenance correctable issue has been revised to be clearer.
6. The phrase from the entire sentence states “initiate resolution of any identified maintenance correctable issues”. This is to ensure follow-up for items which
cannot be corrected during maintenance. The definition of maintenance correctable issue has been revised to be clearer.
7. No direct BES reliability purpose is supported by “on request documentation of a program”; this has value only for monitoring compliance. Additionally,
Compliance Enforcement Authorities are empowered by the NERC Rules of Procedure to request information demonstrating compliance at any time.
8. No additional measure is necessary, as the suggested requirement is unnecessary.
9. The SDT is not specifying how the maintenance records are maintained relative to the Standard. It is up to the entity to determine how to best document the
detailed implementation of their program.
10. Instrument transformers are addressed in Table 1-3, not Table 1-4. Entities are allowed to maintain components more frequently than required within the
Standard if they feel it necessary.
11. The SDT does not believe that the suggested text adds clarity to the standard. Please see Section 15.3 of the Supplementary Reference Document for
additional discussion.
12. The SDT suggests that observed in-service performance may be usable for any activities that are clearly verified by the in-service performance.
Liberty Electric Power LLC
Apologies to the drafting team for submitting this with the ballot, repeated here to insure the comments are
captured and addressed. While the SDT has done a very good job at responding to the most objectionable
parts of the previous version, there are still a number of issues which makes the standard problematic.
1. The standard introduces the term "initiate resolution". This is an interpretable term, and has the potential for
an auditor and an entity to disagree on an action. Would issuing a work order be considered "initiating
resolution"? What if the WO had a completion date many years into the future? I would suggest adding the
term to the list of definitions which will remain with the standard, and defining it as "performing any task
associated with conducting maintenance activities, including but not limited to issuing purchase orders,
soliciting bids, scheduling tasks, issuing work requests, and performing studies".
2. Some clarity is needed to differentiate system connected and generator connected station service
transformers. A statement that a station service transformer connected radially to the generator bus is
considered a system connected transformer if the transformer cannot be used for service unless connected
to the BES.
3. The "bookends" issue, brought up in the prior round of comments, still exists. Although the SDT rightly
notes a CAN has been issued regarding bookends, the CAN covers the documentation for system
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components that entities were required to self-certify to on June 18, 2007. PRC-005-2 adds additional
components to the protection system scheme which were not part of that certification, and has the potential
to put entities into violation space due to a lack of records for those components. The SDT should add to
M3 a statement that entities may demonstrate compliance with the standard by demonstrating that required
activities took place twice within the maximum maintenance interval -starting from the effective date of the
standard - for all components not listed in PRC-005-1.
Response: Thank you for your comments.
1. The SDT believes that issuing a work order would satisfy this requirement. M3 presents several examples of relevant evidence. The SDT has considered that,
while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even several years) to complete
effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with other standards. The SDT
is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these more extended activities to
“correct the maintenance correctable issue”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues and
rely on the operating focus on the degraded system to ensure that they are completed. The definition of maintenance correctable issue has been revised to be
clearer.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
3. The Implementation Plan specifies that entities may implement PRC-005-2 incrementally throughout the intervals specified, and that they shall follow their
existing program for components not yet implemented. The SDT believes that the “bookends” issue to which you refer is therefore addressed. Also, please see
Compliance Process Bulletin 2011-001 for a discussion about data retention.
Central Lincoln
As we stated two ballots ago, we continue to believe that IEEE battery standard quarterly maintenance was
never intended to be performed at a maximum interval of three months. Instead, three months is a target
value that might be extended due to emergency. We continue to support a maximum interval of four months
for these activities.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the
activity was performed.
Tampa Electric Company
1. As written PRC-005-2 would have a very significant impact on Tampa Electric Company with very little
reliability benefit. For the testing of the DC control circuits Tampa Electric would need to remove from
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service each BES element (circuit, bus, transformer, breaker) and perform an R&C checkout somewhat
equivalent to what Tampa Electric does for new construction. That process would have to be repeated no
less often than every six years. The testing of DC control circuits to the level described / required in the
proposed standard in an energized station is a very risky proposition. Even though an element can be
taken out of service for testing, the DC control circuits are often interconnected for functions such as
breaker failure, bus and transformer lockouts etc. It is very easy to accidentally trip other in service
equipment while doing this testing. Another concern is getting outages on equipment to perform the
proposed testing.
2. Tampa Electric believes that there is an unnecessary expansion of the scope of equipment covered by the
proposed PRC-005-2 standard into the distribution system related to UVLS and UFLS. Currently, PRC-0051 includes batteries, instrument transformers, DC control circuitry and communications in addition to the
relays for BES protection systems. PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether
non-relay components are included in those standards. The proposed PRC-005-2 includes the non-relay
components into UFLS and UVLS. The problem is, for UFLS and UVLS, the non-relay components are
mostly distribution class equipment; hence, the result of this version 2 standard will be inclusion of most
distribution class protection system components into PRC-005-2. This is a huge expansion of the scope of
equipment covered by the proposed standard with negligible benefit to BES reliability.
3. In addition, testing of protection systems on distribution circuits is difficult for distribution circuits that are
radial in nature. In addition, non-relay protection components operate much more frequently on distribution
circuits than on transmission Facilities due to more frequent failures due to trees, animals, lightning, traffic
accidents, etc., and have much less of a need for testing since they are operationally tested.
4. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
5. Tampa Electric’s Energy Supply Department has the following comment / question regarding Data
Retention: For Requirement R3 R2 and Requirement R4R3, the Transmission Owner, Generator Owner,
and Distribution Provider shall each keep documentation of the two most recent performances of each
distinct maintenance activity for the Protection System components, or all performances of each distinct
maintenance activity for the Protection System component since or to the previous scheduled audit date,
whichever is longer. If all of the data which the proposed PRC-005-2 standard requires to be collected is
not be available or kept for the prescribed period of time, how does a registered entity comply with the
required data retention?
Response: Thank you for your comments.
1. Entities must employ processes and training on how to best manage risk . Not performing DC control circuit verification of protection functions is a risk to the
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reliability of the BES.
2. Section 202 of the NERC Rules of Procedure define “Reliability standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition. The SDT notes that several Table entries for
components that are used only for UFLS or UVLS involve fewer activities and/or longer intervals than for other similar components for generic Protection Systems.
3. The requirements related to UFLS and UVLS, which are commonly applied on non-BES equipment, are less involved than those for other Protection System
equipment in recognition of the observations by the commenter.
4. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
5. The stated data retention period is consistent with what auditors are expecting (per the SDT’s experience), and is also consistent with Compliance Process
Bulletins 2011-001 and 2009-05. The entity is urged to assure that data is retained as specified within the Standard.
American Transmission
Company, LLC
1. Change the text of Standard PRC-005-2 - Protection System Maintenance Table 1-5 on page 19, Row 1,
Column 3 to:
”Verify that a trip coil is able to operate the circuit breaker, interrupting device, or mitigating device.”
Or alternately, ”Electrically operate each interrupting device every 6 years”
Trip coils are designed to be energized no longer than the breaker opening time (3-5 cycles). They are
robust devices that will successfully operate the breaker for 5,000-10,000 electrical operations. The most
likely source of trip coil failure is the breaker operating mechanism binding, thereby preventing the breaker
auxiliary stack from opening and keeping the trip coil energized for too long of a time period. Therefore,
trip coil failure is a function of the breaker mechanism failure. Exercising the breakers and circuit switchers
is an excellent practice. We would encourage language that would suggest this task be done every 2
years, not to exceed 3 years. Exercising the interrupting devices would help eliminate mechanism binding,
reducing the chance that the trip coils are energized too long. The language as currently written in table 1-5
row 1 will also have the unintentional effect of changing an entities existing interrupting device maintenance
interval (essentially driving interrupting device testing to a less than 6 year cycle).
2. Change the text of Standard PRC-005-2 -Protection System Maintenance Table 1-5 on page 19, Row 3,
Column 2 to:
“12 calendar years”
The maximum maintenance interval for “Electromechanical lockout and/or tripping devices which are
directly in a trip path from the protective relay to the interrupting device trip coil” should be consistent with
the “Unmonitored control circuit” interval which is 12 calendar years. In order to test the lockout relays, it
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may be necessary to take a bus outage (due to lack of redundancy and associated stability issues with
delayed clearing). Increasing the frequency of bus outages (with associated lines or transformers) will also
increase the amount of time that the BES is in a less intact system configuration. Increasing the time the
BES is in a less intact system configuration also increases the probability of a low frequency, high impact
event occurring. Therefore, the Maximum Maintenance Interval should be 12 years for lockout relays.ATC
recognizes the substantial efforts and improvements to PRC-005-2 that have been made and appreciate
the dedicated work of the SDT. We appreciate the removal of Requirement R1.5 and R4 and other
clarifications from draft 3.
3. ATC’s remaining concern for PRC-005-2 is with definition and timelines established in Table 1-5. ATC
believes that, as written, the testing of “each” trip coil and the proposed maintenance interval for lockout
testing will result in the increased amount of time that the BES is in a less intact system configuration. ATC
hopes that the SDT will consider these changes.
Response: Thank you for your comments.
1. The SDT considers it important to verify that each breaker trip coil has indeed operated within the established intervals. While breakers may be operated much
more frequently at times (and allow the entity to document these operations to address this activity), other breakers may not be called on to operate for many
years.
2. The SDT believes that electromechanical devices share performance attributes (and failure modes) with electromechanical relays and need to be tested at
similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
3. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.
Tri-State G & T Association, Inc.
(3)
Ballot
Comment Affirmative
1: Section A.4.2. They are referencing Protection Systems as if they are Facilities in the Applicability section.
Facilities are BES Elements, but Protection Systems are not. That needs to be modified somehow. Perhaps
the drafting team needs to add another category under Applicability entitled “Protection Systems” and then
list which types are included.
2: Maintenance Correctable Issue - This definition seems to be more of a Maintenance Non-Correctable Issue
since it can only be resolved by follow-up corrective action. Suggest changing the term.
3: Change Definitions as indicated below:
Segment - Protection System components that are identical or share common elements. Consistent
performance is expected across the entire population of a Segment. A Segment must contain at least sixty
(60) individual components in order to be considered for inclusion in a performance-based PSMP
Component -An individual piece of equipment included in the definition of a Protection System., Entities are
allowed some latitude to designate their own definitions of a Component. An example of where the entity
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has some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three-phase set of such devices or
a single device as a single Component.
4: M1 - Why is the document necessary to be “current or updated?” Eliminate “or updated.”
5: The Applicability section needs to be changed, regardless of whether it has been discussed before.
Protection Systems are not Facilities.
Response: Thank you for your comments.
1. The standard template allows for two separate sections within Applicability, “Entities” and “Facilities”. The listing under Facilities is describing the applicable
facilities to which the Protection Systems are applied, clarified further to indicate that only the Protection Systems on those Facilities are relevant.
2. The definition of maintenance correctable issue has been revised to be clearer. Please see Section 4.1 of the Supplementary Reference Document for
additional discussion. The revised definition is:
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
3. The SDT does not believe that your suggested changes add clarity.
4. M1 has been modified as you suggest.
5. The standard template allows for two separate sections within Applicability, “Entities” and “Facilities”. The listing under Facilities is describing the applicable
Facilities to which the Protection Systems are applied, clarified further to indicate that only the Protection Systems on those Facilities are relevant.
Progress Energy
Comments on Draft Standard
1. Table 1-1, 2nd row, 2nd bullet: The comment “(see Table 2)” does not apply to this bullet, but applies to the
first bullet.
2. Table 1-3, 2nd row: Need to add “(See Table 2).”
Comments on Implementation Plan
1. Section 3a states that “The entity shall be at least 30% compliant on the first day of the first calendar
quarter 2 calendar years following applicable regulatory approval”
If regulatory approval occurs on January 31, 2012, does this mean that the entity has until December
31, 2014 to be 30% compliant? It might be beneficial to provide an example explaining “calendar year.”
Comments on Supplementary Reference
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1. Table of Contents does not list Section 15.4
2. Page 54, last paragraph, last sentence: “advances that are may be coming”
3. Page 65, 5th paragraph: VLRA should be VRLA
4. Page 67, 4th paragraph, 4th sentence: “typically looking for on the plates”
5. Page 69, 4th paragraph, last sentence: “Grounds because to of the possible”
6. Page 69, 5th paragraph, 2nd sentence: “For example, to do I need”
7. Page 70 5th paragraph, 5th sentence: “A manufacturer of”
8. Page 70 5th paragraph, 6th sentence: “by a third manufacturer’s equipment”
9. Page 71, first line: “(impedance, conductance, and resistance)”
Response: Thank you for your comments.
Draft Standard Comments
1. The Table has been modified as you suggest.
2. The Table has been modified as you suggest.
Implementation Plan Comments
1. The Implementation Plan has been modified for clarity. For the cited example with regulatory approval on January 31, 2012, the entity must be 30% compliant
on the first day of the first calendar quarter 24 months following regulatory approvals. Hence, the entity must be 30% compliant on April 1, 2014.
Supplemental Reference Document Comments
1. Changed per your suggestion.
2. Changed per your suggestion.
3. Changed per your suggestion.
4. Changed per your suggestion.
5. Changed per your suggestion.
6. Changed per your suggestion.
7. Changed per your suggestion.
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8. Changed per your suggestion.
9 Changed per your suggestion.
Dominion Virginia Power
Comments: IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not
maximums. An entity wishing to avoid non-compliance for an interval that might extend past three calendar
months must implement a policy of two months with one month of grace period thereby increasing the number
of inspections each year by half again. This is unnecessarily frequent. We suggest changing the maximum
interval for battery inspections to 4 calendar months. For consistency, Dominion suggests that all battery
maintenance intervals expressed as 3 calendar months be changed to 4 calendar months.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the
activity was performed.
Santee Cooper
Comments:
1. Santee Cooper does not agree with the expansion of the UFLS and UVLS requirements to include the dc
supply. We understand that, in the previous consideration of comments, it is stated that “For UFLS and
UVLS, the maintenance activities related to station dc supply and control circuitry are somewhat
constrained relative to similar activities for Protection Systems in general.” In the table, the requirement for
dc supply for UFLS is to verify the station dc supply voltage when the control circuits are verified, which
could be 6 or 12 years. It seems like the restraint shown in the requirement, if an indication of the level of
need for the verification, is of a much longer timeframe than what would actually happen in the typical
operation of a distribution system. Therefore, proof of this verification seems to be of minimal value
compared to the extra documentation required due to this now being an auditable maintenance activity.
2. We also agree that maintenance activities with fast intervals, especially the 3 month ones, should be
adjusted to 4 months to allow for the actual interval the entities use to be 3 months. Having the
requirement at 3 months forces the utilities to schedule even faster (such as every month or 2 months) to
ensure compliance.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure define “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
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2. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the activity was performed.
The Detroit Edison Company
1. Countable Event - This definition should be clarified. As it stands, it appears that if a technician were to
adjust the settings on an electromechanical relay - even if it were not outside of the entity's acceptable
tolerance - it would need to be classified as a countable event. I would recommend that the definition be
limited to repairing or replacing a failed component during the maintenance activity. These activities would
address conditions that would potentially cause a Protection System misoperation (either a failure to trip or
an unintentional trip). Routine maintenance activities to bring component test values back within tolerance
should be excluded from the definition of a Countable Event. These activities are performed to keep the
protection systems performance at its most ideal state. In addition, the definition as stated appears to
classify battery maintenance activities such as cleaning corrosion, adding water, or applying an equalize
charge, as countable events. If this is the intent, I disagree. These are activities that are expected to occur
on a regular, routine basis due to the chemical properties of the battery (as described at length in the
Supplementary Reference). As such, they should also not be classified as countable events.
2. Table 1-1 and Table 1-5 Based on experience with DECo equipment, a 6 year interval for testing monitored
relays and performing tests on the breaker trip coil is substantially shorter than required. Currently, the
interval for both is 10 years. This interval lines up both with the Transmission Owner's interval for relay
maintenance as well as the maintenance interval for the associated current interrupting devices. I would
recommend that these intervals be extended, at minimum, back to the 7 year interval proposed in Draft 2 if not longer.
3. Table 1-4 (a, b, c, e) - Station dc supply using any type of battery recommend that the maintenance activity
to "Verify: Station dc supply voltage" be clarified to state that the voltage should be measured at the
positive and negative battery terminals. Until you get to page 72 of the Supplementary Reference, you do
not know if this means to check the battery voltage or the bus voltage. The "Station dc supply" could refer
to the entire dc system. It needs to be made clear in the table that you are referring to the battery.
4. Also, I noticed that there is no longer a requirement to measure individual cell voltages. I was wondering if
you could explain the rationale behind that. Checking for voltages that are out of specification in individual
cells helps to identify weak cells that may need to be replaced, if corrective action taken on them does not
improve their condition. Individual cell voltage readings, along with ohmic readings, have been an industry
standard that I believe many, if not most, companies adhere to.
5. Table 1-4 (a, b, c, d)I recommend eliminating the 3 month requirement. We have found annual inspections
to be sufficient in catching problems early enough to take corrective action. Page 30 of the Supplementary
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Reference states that the SDT believes that routine monthly inspections are the norm. While this may be
the case at manned stations, it is not at unmanned stations. The amount of paperwork that would be
required to demonstrate compliance is overwhelming and would be an immense burden. I have seen your
suggestion in past draft comments of the same nature that if we don't want to do the 3 month inspections,
then we should utilize more advanced monitoring. This is not something that can be implemented in a short
time frame. It would take years to put all of that technology in place, and is rather cost prohibitive.
Furthermore, some of the monitoring technologies that would enable you to forgo the 3 month requirement
do not exist yet (to my knowledge). I recommend keeping with the 18 month requirement. If that seems
too long, based on past experience I think a 12 month requirement would suffice.
6. Table 1-4 (c) I propose keeping the option to evaluate ohmic values to baseline.
7. Table 1-4 (a, b) For the requirement to evaluate the ohmic values to baseline, is a checkbox stating that
you did this sufficient, or would a report/graph/etc listing the actual baseline and current value be required?
8. Table 1-4 (f) The first attribute is regarding high and low voltage monitoring and alarming of the battery
charger voltage to detect charger overvoltage and charger failure. Would a low voltage alarm combined
with high voltage shutdown (but not a high voltage alarm) meet this requirement? The high voltage
shutdown will shut the charger down in a high voltage condition, and therefore result in a low voltage alarm,
so the outcome is the same.
Response: Thank you for your comments.
1.”Tweaking the settings” on a component that is not outside tolerances is not a Countable Event, which is partially defined as “A component which has failed and
requires repair or replacement, any condition discovered during the verification maintenance activities in Tables 1-1 through 1-5 which requires corrective action
…”. However, as described in Clause 9.2 (Question 4) of the Supplementary Reference Document, a device which is outside tolerances should be considered to
have experienced a “calibration failure” and thus has experienced a countable event.
2. If an entity’s experience is that these components require less-frequent maintenance, a performance-based program in accordance with R2 and Attachment A is
an option. The intervals were revised after Draft 3 such that the various intervals are multiples of each other, such that entities may establish a systematic PSMP.
3. Your observation that in section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT stated that “verification of dc
supply voltage is simply an observation of battery voltage” is correct, but the SDT does not agree that the location where voltage should be measured (verified) be
contained in PRC-005-2 or the Supplementary Reference document. Due to the variances in topography of dc control circuitry for Protection Systems, a single
location for verification of dc supply voltage cannot be specified and must be determined by the Protection System owner.
4. As you correctly stated taking Individual cell voltage readings has been a standard that many companies adhere to. However, this maintenance activity was
removed from the standard because it was a “how to requirement”.
5. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
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intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the activity was performed.
6. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” the SDT explains why in Table 1-4 (c) (Station dc supply
using NiCad batteries) the option to evaluate ohmic values to baseline is not available.
7. The SDT believes that just providing “a checkbox stating that you did this” is sufficient proof. Section 15.4 of “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” provides additional discussion on this topic. However, the SDT is unable to fully predict what evidence may be required by the
Compliance Enforcement Authority to demonstrate compliance.
8. “A low voltage alarm combined with high voltage shutdown (but not a high voltage alarm)” would only partially meet the requirement. To ensure that the
automatic shutdown of the battery charger for high voltage conditions is achieved, a high voltage alarm must be a component attribute of the monitoring system in
order.
Florida Keys Electric Cooperative
Assoc. (1)
Ballot
Comment Negative
Extreme unreasonableness and undue hardships on entities, specifically smaller entities. Just one example is
"battery inspections". What is an inspection - simply visual or cell readings? Some entities may have to assign
full time battery maintenance duties. Can SCADA monitor DC voltage trends?
Response: Thank you for your comments. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” – that was provided
for review and comment with PRC-005-2 – details what should be inspected for visual battery cells. The SDT disagrees that the PRC-005-2 with its accompanying
Table 1 imposes “extreme unreasonableness and undue hardships on entities, specifically smaller entities” to maintain a reliable Protection Systems. Monitoring
the dc voltages via SCADA is an option.
FirstEnergy
FE offers the following additional comments and suggestions:
We do not agree with the wording of requirement R3. The entity is only required to meet the minimum
maintenance intervals of the standard as outlined in Tables 1 and 2. We offer a scenario where an entity
states that they will go above the standard and maintain relays on a 4 year cycle. The standard, in meeting an
adequate level of reliability, sates that this activity must be performed every 6 years. If the entity happened to
miss the 4 year timeframe, deciding from a business standpoint to delay the maintenance to the 5th year, an
auditor can find the entity non-compliant per the guidance and wording of the requirements in this standard.
However, the entity still exceeded an adequate level of reliability by performing the maintenance within 5
years. This scenario would be very unfortunate to the entity that has essentially done their part in providing
reliability to the bulk power system, yet they would be punished for not meeting their more stringent
timeframes. This standard’s guidance and requirements sends an adverse message to industry. It essentially
punishes an entity for going above and beyond the standard except on a few rare occasions. If this were to
happen, that entity, and possibly others, would not see the value in going above a standard. It would make
entities meet the bare minimum requirements, essentially reducing overall system reliability. Therefore, we
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suggest the following wording for requirement R3:
“R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP to
ensure adherence to the minimum requirements as outlined in Tables 1 and 2, and initiate resolution of any
identified maintenance correctable issues.”
Response: Thank you for your comments. The Standard requires an entity to implement a PSMP that meets the minimum requirements to the standard. An entity
may choose to implement a program that exceeds the requirements.
City of Farmington (3)
Ballot
Comment Affirmative
FEUS would like to thank the Drafting Team. The proposed PRC-005-2 standard is an improvement over the
four standards that it will replace.
However, section 4.2 identifies five types of protection systems that the standard is applicable to, but the
language of Requirement 1 indicates that applicable entities need to establish a Protection System
Maintenance Program (PSMP) for the Protection Systems designed to provide protection for BES Element(s)
(Part 4.2.1 of Section 4.2). We believe the intent is to have a PSMP for all Protection Systems identified in
Section 4.2 and that the language of Requirement 1 may cause confusion or be misleading. We suggest
changing the language of Requirement 1 from: Each Transmission Owner, Generator Owner, and Distribution
Provider shall establish a Protection System Maintenance Program (PSMP) for its Protection Systems
designed to provide protection for BES Element(s). to: Each Transmission Owner, Generator Owner, and
Distribution Provider shall establish a Protection System Maintenance Program (PSMP) for its Protection
Systems identified in Section 4.2.
Response: Thank you for your comments. R1 has been modified as you suggest.
FirstEnergy Energy Delivery
FirstEnergy Solutions
Ballot
Comment Affirmative
FirstEnergy appreciates the efforts of the drafting team and supports PRC-005-2. We would also like the team
to address our comments and suggestions submitted through the separate comment period.
Ohio Edison Company
(1) (3) (4) (5) (6)
Response: Thank you for your comments. Please see our responses to your comments submitted with the Formal Comments.
ITC
1. For Battery System:- Table 1-4(a)o The maximum maintenance interval for the majority of the battery
maintenance is listed at “18 calendar months”. The current ITC Standard is”once per calendar year and a
calendar year is defined as a twelve-month period beginning January 1st and ending December 31st “.
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ITC would like the maximum maintenance interval at “once per calendar year”
2. Table 1-4(b)
o VRLA (Valve Regulated Lead Acid) batteries have an additional inspection at 6 calendar months that
includes inspecting the condition of all individual units by measuring the battery cell/unit internal ohmic
values. This is in addition to the “18 calendar months” inspection. ITC would like to be consistent with the
VLA (Vented Lead Acid) batteries and have only one internal ohmic value inspection once per calendar
year.
3. For Battery System:- Table 1-4(a)
o The maximum maintenance interval for the majority of the battery maintenance is listed at “18 calendar
months”. The current ITC Standard is “once per calendar year and a calendar year is defined as a twelvemonth period beginning January 1st and ending December 31st “. ITC would like the maximum
maintenance interval at “once per calendar year”
4. Table 1-4(b) VRLA (Valve Regulated Lead Acid) batteries have an additional inspection at 6 calendar
months that includes inspecting the condition of all individual units by measuring the battery cell/unit
internal ohmic values. This is in addition to the ”18 calendar months” inspection. ITC would like to be
consistent with the VLA (Vented Lead Acid) batteries and have only one internal ohmic value inspection
once per calendar year.
5. Auxiliary Relays:
ITC does not agree with the 6 year interval for Aux relays in the trip circuit. Although they are EM relays
they are simple and have very few moving parts. We believe the maintenance period for auxiliary relays
should be 12 years and they should be in conjunction with the control circuit. We recognize that Draft 4 only
includes auxiliary relays that are directly in the trip path. That is an improvement in Draft 4. In general,
auxiliary relays are very reliable; only certain relay types have been proven to be problematic. A known
relay type (HEA) has been proven to be problematic if not exercised frequently. The standard should not
require a 6 year interval period for all other auxiliary relays. We believe problematic relays should be
addressed through use of a NERC Alert process. Don’t cut down the tree for a bad apple.
Response: Thank you for your comments.
1. In choosing the 18 calendar month interval for the maximum maintenance interval for the maintenance activities of table 1-4(a) the SDT was aware that the
majority of these activities are recommended to be performed in IEEE 450 “Recommended Practice for Maintenance, Testing, and Replacement of Vented LeadAcid Batteries for Stationary Applications “at the Yearly inspection. The SDT does not agree that “once per calendar year” would be a more appropriate interval
for these activities but notes that entities may choose to perform required activities more frequently than the maximum intervals expressed in the Tables.
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Question 5 Comment
2. In section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” – that was provided for review and comment with PRC-005-2
explaining why the for VRLA battery systems (Table 1-4(b)) the maximum maintenance intervals and maintenance activities cannot be consistent with the intervals
and activities of VLA battery systems (Table 1-4(a)).
3. In choosing the 18 calendar month interval for the maximum maintenance interval for the maintenance activities of table 1-4(a) the SDT was aware that the
majority of these activities are recommended to be performed in IEEE 450 “Recommended Practice for Maintenance, Testing, and Replacement of Vented LeadAcid Batteries for Stationary Applications “at the Yearly inspection. However, the SDT has considered that IEEE 450 presents these activities as recommended
activities in a vacuum, without considering other activities that are being performed at the 3-calendar-month interval and has established the 18-calendar-month
interval to comport to the most aggressive intervals being used in common practice. The SDT does not agree that “once per calendar year” would be a more
appropriate interval for these activities but notes that entities may choose to perform required activities more frequently than the maximum intervals expressed in
the Tables.
4. Section 15.4 of “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” (question – “What are cell/unit internal ohmic measurements “–
that was provided for review and comment with PRC-005-2 – explains why the for VRLA battery systems (Table 1-4(b)) the maximum maintenance intervals and
maintenance activities cannot be consistent with the intervals and activities of VLA battery systems (Table 1-4(a)).
5. The SDT believes that electromechanical devices share performance attributes (and failure modes) with electromechanical relays and need to be tested at
similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices supports those intervals. If an
entities’ experience is that these components require less-frequent maintenance, a performance-based program in accordance with R3 and Attachment A is an
option.
Manitoba Hydro
Manitoba Hydro (1) (3) (5) (6)
-Grace periods Grace periods should be permitted on the maintenance time intervals. While we understand
that grace periods can be built into a PSMP, maintenance decisions that compromise reliability may still have
to be made just to meet the specified time
Ballot
Comment Negative
Manitoba Hydro is voting negative for the following reasons:
-Grace periods Grace periods should be permitted on the maintenance time intervals. While we understand
that grace periods can be built into a PSMP, maintenance decisions that compromise reliability may still have
to be made just to meet the specified time intervals and avoid penalty. An example of this would be removing
a hydraulic generator from service at a time of low reserve to meet a maintenance interval and avoid noncompliance (removing an asset in a time of constraint). Grace periods are also required in the case of
extreme weather conditions. Such conditions may make it unsafe to perform maintenance within the
maintenance interval or may create a risk to reliability if the equipment being maintained is removed from
service during these conditions. Utilities need to retain a reasonable amount of discretion and flexibility to
make maintenance decisions that are best for reliability without risking non-compliance.
Response: Thank you for your comments. “Grace Periods” within the standard are not measurable, and would probably lead to persistently increasing intervals.
However, an entity may establish an internal program with grace-period allowance, as long as the entire program (including grace periods) does not exceed the
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Question 5 Comment
intervals within the standard.
Georgia System Operations
Corporation (3)
Ballot
Comment
GSOC supports comments submitted by Georgia Transmission Corporation
Response: Thank you for your comments. Please see the SDT response to the comments submitted by Georgia Transmission Corporation.
Electric Market Policy
IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not maximums.
An entity wishing to avoid non-compliance for an interval that might extend past three calendar months must
implement a policy of two months with one month of grace period thereby increasing the number of
inspections each year by half again. This is unnecessarily frequent. We suggest changing the maximum
interval for battery inspections to 4 calendar months. For consistency, Dominion suggests that all battery
maintenance intervals expressed as 3 calendar months be changed to 4 calendar months.
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the
activity was performed.
Alliant Energy Corp. Services,
Inc. (4)
Ballot
Comment Negative
1. If PRC-005-2 is going to incorporate PRC-008 (UFLS) and PRC-011 (UVLS) the Purpose needs to be
revised to include Distribution Protection Systems designed to protect the BES.
2. We do not believe a distribution relaying system, designed to protect the distribution assets, that may open
a transmission element (ie; breaker failure) should be considered part of the BES Protection System. R1
should add the following sentence “Distribution Protection Systems intended solely for the protection of
distribution assets are not included as a BES Protection System, even if they may open a BES Element.”
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure define “Reliability standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition. UFLS and UVLS are described in the Applicability
as being included within the Protection System addressed within the standard if they are applied per other NERC Standards.
2. Section 202 of the NERC Rules of Procedure define “Reliability standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirement, as written, supports this.
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Exelon
Yes or No
Question 5 Comment
1. In response to Exelon’s comments provided to drafts 1, 2, and 3 of PRC-005, the SDT did not explain why
a conflict with an existing regulatory requirement is acceptable. The SDT previously responded that a
conflict does not exist and that the removal of grace periods simply is there to comply with FERC Order
directive 693. In response to draft 3 of PRC-005, the SDT stated that "If several different regulatory
agencies have differing requirements for similar equipment, it seems that the entity must be compliant with
the most stringent of the varying requirements. In the cited case, an entity may need to perform
maintenance more frequently than specified within the requirements to assure that they are compliant."
Again this does not explain why a conflict with an existing regulatory requirement is acceptable. This
response does not answer or address dual regulation by the NRC and by the FERC. Specifically, the
request has not been adequately considered for an allowance for NRC-licensed generating units to default
to existing Operating License Technical Specification Surveillance Requirements if there is a maintenance
interval that would force shutting down a unit prematurely or become non-compliant with PRC-005.
Therefore, Exelon again requests that the SDT communicate with the NRC and with the FERC to ensure a
conflict of dual regulation is not imposed on a nuclear generating unit without the necessary evaluation. In
addition, the SDT still did not fully evaluate or address the concern related to the uniqueness of nuclear
generating unit refueling outage schedules.
2. Although Exelon Nuclear agrees with the SDT that the maximum allowed battery capacity testing intervals
of not to exceed 6 calendar years for vented lead acid or NiCad batteries (not to exceed 3 calendar years
for VRLA batteries) could be integrated within the plant’s routine 18 month to 2 year interval refueling
outage schedule, the SDT has not considered that nuclear refueling outages may be extended past the 18
month to 2 year "normal" periodicity. There are some unique factors related to nuclear generating units that
the SDT has not taken into consideration in that these units are typically online continuously between
refueling outages without shutting down for any other required maintenance. Historically, generating units
have at times extended planned refueling outage shutdown dates days and even weeks due to requests
from transmission operations, fuel issues and electrical demand. Without the grace period exclusion
currently allowed by existing maintenance programs, a nuclear plant will be forced to either extend outage
duration to include testing on an every other refueling outage (i.e., every four years to ensure compliance
for a typical boiling water reactor) or leave the testing on a six year periodicity with the vulnerability of a
forced shut down simply to perform maintenance to meet the six year periodicity or a self report of noncompliance. To ensure compliance, the nuclear industry will be forced to schedule battery testing on a four
year periodicity to ensure the six year periodicity is met, thus imposing a requirement on nuclear generating
units that would not apply to other types of generating units. The SDT response to this question in draft 3 is
that "(t)he 18-month (and shorter) interval activities are activities that can be completed without outages primarily inspection-related activities. An entity may need to perform maintenance more frequently than
specified within the requirements to assure that they are compliant." Respectfully Exelon requests that the
SDT review and evaluate the concern.
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Question 5 Comment
Response: Thank you for your comments.
1. It appears that the SDT’s response was mis-understood. The SDT intended that the response be understood as” in order to be compliant with all requirements,
regardless of the different agencies imposing those requirements, the entity will likely have to be compliant with the most stringent of the requirements”.
Regarding PRC-005-2, an entity must be compliant with the included requirements, even if they are more stringent than other regulatory requirements.
2. The SDT believes that the activities addressed in the comment can be integrated with the 18-24 month plant refueling outage. This may result in the activities
being performed more frequently than specified.
Entergy (3)
Entergy Services, Inc. (6)
Ballot
Comment Negative
In Section 4.2, ‘Facilities’ add the following subsection 4.2.6: Protection Systems for generating units in
extended forced outage or in inactive reserve status are excluded from the requirements of this standard.
However, the required maintenance and testing of the Protection Systems at these units must be completed
prior to connecting the units to the Bulk Electric System (BES). Reason for the above comment: The above
units are not connected to the BES and therefore do not affect the reliability of the BES. However, to ensure
the reliability of the BES, required maintenance and testing of the Protection Systems at these units must be
completed prior to connecting them to the BES.
Response: Thank you for your comments. Please refer to Compliance Application Notice CAN-0011, footnote 5, which states, “The registered entity’s Protection
System maintenance and testing program is only applicable for Protection System devices in service …” The SDT believes that this guidance will remain durable
for PRC-005-2.
Entergy Services
In Section 4.2, “Facilities” add the following subsection 4.2.6: Protection Systems for generating units in
extended forced outage or in inactive reserve status are excluded from the requirements of this standard.
However, the required maintenance and testing of the Protection Systems at these units must be completed
prior to connecting the units to the Bulk Electric System (BES).
Reason for the above comment: The above units are not connected to the BES and therefore do not affect
the reliability of the BES. However, to ensure the reliability of the BES, required maintenance and testing of
the Protection Systems at these units must be completed prior to connecting them to the BES.
Response: Thank you for your comments. Please refer to Compliance Application Notice CAN-0011, footnote 5, which states, “The registered entity’s Protection
System maintenance and testing program is only applicable for Protection System devices in service …” The SDT believes that this guidance will remain durable
for PRC-005-2.
MRO's NERC Standards Review
Subcommittee
In the checkbox for Requirement R3 please change the wording to read, “Maintenance Correctable Issue Failure of a component to operate within design parameters such that it cannot be restored to functional order
by repair or calibration during performance of the initiating on-site activity. Therefore this issue requires follow-
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Question 5 Comment
up corrective action.”
Response: Thank you for your comments. The definition of maintenance correctable issue has been revised to be clearer:
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
Bonneville Power Administration
1. In the header of Tables 1-1, 1-2, 1-3, and 1-5 there is a note that says "Table requirements apply to all
components of Protection Systems except as noted." Since each table only applies to the specific
component type shown in the header, we do not understand what this note means. The definition given for
component only makes the note more confusing. Please clarify the note.
2. Additionally, BPA is voting no during this round due to an issue with the Applicability Section and Section
4.2. Once this issue is clarified, BPA would be in support of a yes vote.
Issue: Section 4.2 Facilities lists 5 separate items that the standard is applicable for (4.2.1. - 4.2.5).
However Requirement 1 uses language that only addresses one of the items (4.2.1). There is no language
contained anywhere within any of the requirements in PRC-005-2 that apply to the types of protection
systems described in Applicability Sections 4.2.2 - 4.2.5. Therefore, it could be argued that this leaves it
open to interpretation as to whether UFLS/UVLS/SPS are addressed by R1.In the NOPR (¶ 105), FERC
states that “the Requirements within a standard define what an entity must do to be compliant” Further, in
Order 693 (¶ 253) FERC explicitly states that “compliance will in all cases be measured by determining
whether a party met or failed to meet the Requirement”. Given this, then from a compliance perspective,
the actual applicability of the standard appears to not be as broad as intended. We ask that this issue be
resolved by modifying the language in R1 in a manner that explicitly encompasses all types of protection
systems to which it is intended to be applied.
Response: Thank you for your comments.
1. In Table 1-1, for example, this note means that all activities apply to all protective relay components unless specifically differentiated within individual table
entries. Because Tables 1-1, 1-2, and 1-3 do not include any additional differentiation within the table, the note was removed from these tables in consideration of
your comment.
2. The R1 requirement has been revised in consideration of your comments.
JEA (3)
Ballot
Comment Negative
JEA maintains testing of lockout relays will have major reliability impact to the JEA system.
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Question 5 Comment
Response: Thank you for your comments. The SDT believes that electromechanical devices share performance attributes (and failure modes) with
electromechanical relays and need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of
these devices supports those intervals.
Tri-State G&T
1. M1 - Why is the document necessary to be “current or updated?” Eliminate “or updated.”
2. R1 VSL - Second item in Severe VSL is not addressed in any lower VSL. Should there also be a
comparable violation in Lower and Moderate?
3. R2 VSL - Keep the comment about the redundancy in Lower VSL and High VSL for clarifying the difference
between the two.
Response: Thank you for your comments.
1. M1 has been revised as suggested and the phrase, “or updated” has been removed
2. The VSL for R1 has been revised to add phased VSLs for Moderate and High related to this item.
3. The High VSL has been modified from three years to four years.
Ameren
1. Measure M3 on page 5 should apply to 99% of the components. “Each __shall have evidence that it has
implemented the Protection System Maintenance Program for 99% of its components and initiate” PRC005-2 unrealistically mandates perfection without providing technical justification. A basic premise of
engineering is to allow for reasonable tolerances, even Six Sigma allows for defects. Requiring perfection
may well harm reliability in that valuable resources will be distracted from other duties.
2. Define BES perimeter in accordance with Project 2009-17 Interpretation. Facilities Section 4.2.1 “or
designed to provide protection for the BES” needs to be clarified so that it incorporates the latest Project
2009-17 interpretation. The industry has deliberated and reached a conclusion that provides a meaningful
and appropriate border for the transmission Protection System; this needs to be acknowledged in PRC005-2 and carried forward. The BOT adopted this 2/17/2011.
3. Battery inspection every 4 months is sufficient. IEEE battery maintenance standards call for quarterly
inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for an
interval that might extend past three calendar months due to storms and outages must set a target interval
of two months thereby increasing the number of inspections each year by half again. This is unnecessarily
frequent. We suggest changing the maximum interval for battery inspections to 4 calendar months. For
consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar
months.
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Yes or No
Question 5 Comment
Response: Thank you for your comments.
1. The NERC criteria for VSLs do not currently permit them to allow some level of non-performance without being in violation.
2. The referenced interpretation relates to a quasi-definition of “transmission Protection System”, and in the context of the approved PRC-004-1 and PRC-005-1,
presents a consistent context for this term. However, the interpretation was constrained to not introduce any requirements or applicability not already included
within the approved standards. PRC-005-2 does not use this term, and expands upon the applicability in the interpretation to address what seems to the SDT to
be an appropriate applicability for PRC-005-2. The applicability of the interpretation to PRC-004 is not affected by PRC-005-2.
3. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of unmonitored battery systems. The SDT believes
that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate program oversight is exercised, and disagrees that the
intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about
“calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the activity was performed.
Madison Gas and Electric Co. (4)
Ballot
Comment Affirmative
MGE is voting affirmative with the following recommendation to the definition of Maintenance Correctable
Issue. Maintenance Correctable Issue - Failure of a component to operate within design parameters such that
it cannot be restored to functional order by repair or calibration during performance of the "initiating" on-site
activity. Therefore this issue requires follow-up corrective action. The removal of the word “initial” will cause
less confusion because the industry does not understand if this is initial (commissioning) or is initial used as
when a component requires repair. Recommend “initiating” replace “initial”.
Response: Thank you for your comments. The definition of maintenance correctable issue has been revised to be clearer:
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
Arizona Public Service Company
NERC continues to be too prescriptive in the standard. For example, Table 1-4(a) requires battery
verifications and inspection every three months. We have been performing similar tests every four months for
over a decade, with no adverse consequences. Although FERC Order 693 directs NERC to establish
maximum allowable intervals, the maximum interval must be “appropriate to the type of protection system and
its impact on the reliability of the Bulk-Power System.” (Order 693 at 1475)The Standard Drafting Team
(SDT) has not demonstrated a mechanism that connects the maximum maintenance interval with its impact
on the reliability of the Bulk-Power System. An example can be found on the bottom of page 18 and the top
of page 19 of the Consideration of Comments on Protection System Maintenance [Project 2007-17] for draft
3. Although the commenting organization provided a concrete example of successful maintenance under a
longer interval, the Standards Drafting Team commented that it “believes that 18-months is the proper interval
for this activity.” (Emphasis added) An organization cannot challenge the SDT’s beliefs, only facts. The basis
for each maximum maintenance interval, with appropriate linkage to its impact on the reliability of the Bulk-
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Question 5 Comment
Power System, needs to be published and voted upon so that factual based proposals to modify the
maximum interval can be rationally challenged.
Response: Thank you for your comments. The basis for the intervals established within the standard is described throughout the Supplementary Reference
document.
Northern Indiana Public Service
Co. (3)
Ballot
Comment Negative
One of our concerns is that, while the present standard is 2 pages and is the most highly violated and fined
standard, the new proposed standard is 22 pages, the implementation plan is 4 pages and the Supplemental
FAQ document is 87 pages.
Response: Thank you for your comments. The SDT has established maximum allowable intervals in accordance with FERC Order 693. Additionally, the SDT has
addressed many of the common program-related causes of observed violations, and has provided the Supplementary Reference and FAQ to assist entities in
implementing their program.
PJM Interconnection, L.L.C. (2)
Ballot
Comment Negative
PJM has a general problem with how this current draft defines "protection system". The issue is that PJM
believes the standard should only apply to Protection relays that are designed to protect the BES. It should
not apply to relays that protect the asset itself.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements as written directly support this definition.
Western Area Power
Administration
Please explain or clarify the term “mitigating devices” used in Table 1-5 Control Circuitry, Page 19. This term
is not well defined in the industry and not easily understood as “interrupting device” or “circuit breaker.”
Response: Thank you for your comments. This term is primarily focused on Special Protection Systems, where they may perform some activity other than
“interrupt” to address their design objectives.
Shermco Industries
1. Please provide clarification on "Communications" in regards to the following: If our customers are
utilizing Schweitzer SEL311 relays and utilizing the fiber for transfer trip, is this considered a
communications circuit? Our experiences in regards to testing these devices that have transfer trips out
into a main substation that could affect a main ring tie or open a major 138kV loop, are that the T&D
utilities will not allow us to perform these tests and trip their breakers. Therefore, what is required to
satisfy testing?
2. In regards to Function / Trip testing, if we have a sudden pressure device, this is considered an auxiliary
relay and the sudden pressure relay itself is not required to be tested. However, the trip path is required
to be tested for DC tripping, if it directly trips the breaker feeding the BES, on the DC Control verification
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Question 5 Comment
testing. Please clarify if this is correct.
Response: Thank you for your comments.
1. The fiber you indicate is a relay communications circuit. The SEL311 monitors the condition of the fiber. It will provide an alarm on loss of communications. If
this alarm is not monitored then the entity will be required to check it every 3 months and verify it is still operational. If the communications alarm is brought back
to the control center, and the error rate or pilot signal is verified continuously, the interval will be 12 years.
2. Yes, this is correct.
ExxonMobil Research and
Engineering
1. PRC-005-2 is a highly prescriptive standard that prevents small entities from establishing a risk-based
approach to protective system maintenance that is commonly used in other industry sectors and forces
the small entity to utilize the time-based program. Many registered entities do not have a population size
of 60 for each type of protective device. However, they do possess historical records that can be used to
calculate the mean time between failures for each equipment type that adequately reflects the service
conditions in which the equipment is installed. The SDT should consider allowing registered entities to
utilize historical records in their supporting documentation for defining a performance based program.
2. Additionally, by restricting populations by manufacturer model, as referenced in PRC-005-2 Attachment
A, the Standard Drafting Team is bordering on anti-competitive behavior as those entities that utilize
performance-based programs may be discouraged to utilize alternative suppliers because utilization of a
time-based maintenance program on the alternative supplier’s equipment may present a cost-benefit
analysis hurdle that the supplier of the equipment is not able to overcome.
3. Lastly, the SDT has chosen not to provide a tolerance band for the maximum maintenance intervals it
defines in its time-base program. Given that the SDT has not provided sound technical justification (i.e. a
study, industry recommended practice, etc.), the SDT should reconsider its stance on providing a
tolerance band on the time intervals specified in the time-based program. What is the increase in risk
owned by an entity when a protective device is tested at the 6 year and 30 day mark instead of the 6 year
mark?
Response: Thank you for your comments.
1. If the historical records fully address the criteria in Attachment A, they would be useful in establishing the basis for a performance-based maintenance program.
If the population is not in accordance with the definition of segment in Attachment A, the SDT does not believe that the entity has a statistically-significant sample
on which to base a PBM.
2. In order to properly apply a performance-based maintenance program, the components within a segment must be such that they will exhibit similar behavior.
Similarly-functioning components from different manufacturers will likely not satisfy this criterion. If an entity does not have sufficient component populations to
apply performance-based maintenance, they must revert to time-based maintenance per the Tables or find another entity with whom they can aggregate
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Question 5 Comment
components within a performance-based maintenance program. Please see Section 9 of the Supplementary Reference Document for a discussion regarding
aggregating components between entities within a performance-based maintenance program.
3. There may be minimal additional risk for missing the required interval by only a small amount. However, “grace periods” within the standard are not
measurable, and would probably lead to persistently increasing intervals. However, an entity may establish an internal program with grace-period allowance, as
long as the entire program (including grace periods) does not exceed the intervals within the standard. Also, this concern is only a practical one if an entity is
persistently maintaining its Protection System components at the very end of each maximum allowable interval.
Luminant
The red-lined version did not appear to agree with the clean copy. In reading the "red lined" document it
appears that R3 was intended to be "Each Transmission Owner, Generation Owner, and distribution Provider
shall implement and follow its PSPM and initiate resolution of any identified maintenance correctable issues."
Response: Thank you for your comments. The red-lining tools in Microsoft Word can sometimes be misleading, but the red-line is provided in an effort to illustrate
the changes made to the document. We recommend that the entity use the “clean” version in order to see the final resulting text.
MidAmerican Energy Company
Requirement R3 of the standard discusses resolution of “identified maintenance correctable issues”. M3
requires evidence of “resolution of Maintenance Correctable Issues”. The definition of Maintenance
Correctable Issue in the standard includes “during performance of the initial on-site activity”. The “initial onsite activity” seems to imply that the corrective steps that need to be tracked are those resulting from the
periodic testing that is done for compliance with the standard. It is not clear if the SDT meant to require that
records be kept of any required maintenance that is done as a result of a discovered problem or failure that is
not identified during the periodic testing.
Response: Thank you for your comments. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may
take an extended period (perhaps even several years) to complete effectively, during which time the degraded system must be reported and reflected within the
operation of the BES in accordance with other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete”
during the scheduled interval for these more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of
maintenance correctable issues and rely on the operating focus on the degraded system to ensure that they are completed. The definition of maintenance
correctable issue has been revised, though, to be clearer.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
Consumers Energy (5)
Ballot
Comment Negative
While most of the changes are quite good, I believe R3 may not be what was intended. R3 concludes with
"initiate resolution of any identified maintenance correctable issues." My copy of Webster's Dictonary defines
initiate as "to set going : start". Thus to meet R3, I need never order a replacement component I just need to
write a purchase order (it's the start of the process). If rewiring is needed, I only need to write a maintenance
order, rather than sending out an electrician with tools and wire. I believe reliability would be better served to
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require resolution of the problem rather than just starting a process to begin work.
Response: Thank you for your comments. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may
take an extended period (perhaps even several years) to complete effectively, during which time the degraded system must be reported and reflected within the
operation of the BES in accordance with other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete”
during the scheduled interval for these more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of
maintenance correctable issues and rely on the operating focus on the degraded system to ensure that they are completed.
Constellation Energy
Commodities Group (6)
Ballot
Comment Negative
Constellation Power Source
Generation, Inc. (5)
1. R3 is vague and can be easily interpreted in a variety of ways. For example, “initiate resolution” may mean
closing a work order on a correctable issue or it may mean simply to create a work order with the intent of
closing it out. The difference is not just in compliance evidence but it potentially allows an auditor to
interpret the requirement to state that closed work orders should be completed in a timely manner.
2. Lastly, the technical man power and compliance documentation needed to implement a performance based
protection system maintenance program are so onerous that it is highly unlikely that any entity would use
it.”
Response: Thank you for your comments.
1. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even
several years) to complete effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance
with other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for
these more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues
and rely on the operating focus on the degraded system to ensure that they are completed. The definition of maintenance correctable issue has been revised
to be clearer.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
2. The SDT understands that the requirements to establish and operate a performance-based PSMP may be beyond what many entities will wish to pursue.
However, these are provided for the use of those entities who wish to make use of the analytical resources to optimize their field maintenance.
MISO Standards Collaborators
1. R3 speaks of a Maintenance Correctable Issue and implementing your Protection System Maintenance
Program (PSMP). In the definition of Maintenance Correctable Issue, it states "...of the initial on-site
activity". The intent seems to be that during any maintenance activity, and something is found not working
properly, you should repair it. Some may look at the word "initial" as during the commissioning of a facility.
We recommend the SDT delete the word "initial" to cause less confusion.
2. We recommend the SDT change the text of Standard PRC-005-2 - Protection System Maintenance Table
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1-5 on page 19, Row 1, Column 3 to “Verify that each a trip coil is able to operate the circuit breaker,
interrupting device, or mitigating device.”
Or alternately,
“Electrically operate each interrupting device every 6 years.”
Trip coils are designed to be energized no longer than the breaker opening time (3-5 cycles). They are
robust devices that will successfully operate the breaker for 5,000-10,000 electrical operations. The most
likely source of trip coil failure is the breaker operating mechanism binding, thereby preventing the breaker
auxiliary stack from opening and keeping the trip coil energized for too long of a time period. Therefore,
trip coil failure is a function of the breaker mechanism failure. Exercising the breakers and circuit switchers
is an excellent practice. We would encourage language that would suggest this task be done every 2
years, not to exceed 3 years. Exercising the interrupting devices would help eliminate mechanism binding,
reducing the chance that the trip coils are energized too long. The language as currently written in Table 15, Row 1, will also have the unintentional effect of changing an entities existing interrupting device
maintenance interval (essentially driving interrupting device testing to a less than 6 year cycle).
3. We recommend the SDT change the text of Standard PRC-005-2 - Protection System Maintenance Table
1-5 on page 19, Row 3, Column 2 to
“12 calendar years”.
The maximum maintenance interval for “Electromechanical lockout and/or tripping devices which are
directly in a trip path from the protective relay to the interrupting device trip coil” should be consistent with
the “Unmonitored control circuit” interval which is 12 calendar years.
4. In order to test the lockout relays, it may be necessary to take a bus outage (due to lack of redundancy and
associated stability issues with delayed clearing). Increasing the frequency of bus outages (with
associated lines or transformers) will also increase the amount of time that the BES is in a less intact
system configuration. Increasing the time the BES is in a less intact system configuration also increases
the probability of a low frequency, high impact event occurring. Therefore, the Maximum Maintenance
Interval should be 12 years for lockout relays.
5. We recognize the substantial efforts and improvements to PRC-005-2 that have been made and appreciate
the dedicated work of the SDT. We appreciate the removal of Requirement R1.5 and R4 and other
clarifications from draft 3.
6. Our remaining concern for PRC-005-2 is with definition and timelines established in Table 1-5. We believe
that, as written, the testing of “each” trip coil and the proposed maintenance interval for lockout testing will
result in the increased amount of time that the BES is in a less intact system configuration. We hope that
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the SDT will consider these changes.
Response: Thank you for your comments.
1. The word, “initial” is intended to emphasize that an identified concern becomes a Maintenance Correctable Issue when the entity is not able to immediately
resolve it, and must return to correct the problem. The definition of maintenance correctable issue has been revised to be clearer.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
2. The SDT considers it important to verify each breaker trip coil will indeed operate within the established intervals. While breakers may be operated much more
frequently at times (and allow the entity to document these operation to address this activity), other breakers may not be called on to operate for many years.
3. The SDT believes that electromechanical devices contain moving parts and share performance attributes (and failure modes) with electromechanical relays and
need to be tested at similar intervals. Performance-Based maintenance is an option to increase the intervals if the performance of these devices supports those
intervals.
4. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.
5. Thank you.
6. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.
NERC - EA & I
Recommend entities be explicitly required to document the Relay Maintenance Program in one document.
Many entities presently maintain their Protection Maintenance Program in several documents, such as one for
relays, one for batteries, etc. This complicates compliance review and contributes to non-compliance since
personnel in different departments writing these have different levels of understanding of NERC standards.
Separate documents also allow inconsistencies to slip in. Recommend Requirement 1 to changed to the
following to address this problem. "Each Transmission Owner, Generator Owner, and Distribution Provider
shall establish a Protection System Maintenance Program (PSMP), RECORDED AND UPDATED AS A
SINGLE DOCUMNET for its Protection Systems designed to provide protection for BES Element(s). "
Response: Thank you for your comments. The SDT believes that, because of the diversity of different entities and their business arrangements that such a
requirement could serve to decrease the quality of an entity’s PSMP, particularly for a vertically-integrated entity that includes several of the specified Applicable
Entities. For example, the Generator Owner and Transmission Owner are likely to have significant differences for very good reasons.
Florida Municipal Power Agency
(4) (5) (6)
Ballot
Comment Negative
1. Section 4.2.1 states that the Standard is applicable to “Protections Systems designed to provide protection
BES Elements.” Section 15.1 of the Supplementary Reference Document defines the scope as those
“devices that receive the input signal from the current and voltage sensing devices and are used to isolate a
faulted element of the BES.” These two statements are not exactly equivalent, and in fact, are in conflict
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Florida Municipal Power Pool (6)
Question 5 Comment
with the Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State, Approved by the Board
of Trustees on February 17, 2011.
2. Section 4.2.1 should be changed to “Any Protection System that is installed for the purpose of detecting
faults on transmission elements (lines, buses, transformers, etc.) identified as being included in the Bulk
Electric System (BES) and trips an interrupting device that interrupts current supplied directly from the
BES.”
Response: Thank you for your comments.
1. The referenced interpretation relates to a quasi-definition of “transmission Protection System”, and in the context of the approved PRC-004-1 and PRC-005-1,
presents a consistent context for this term. However, the interpretation was constrained to not introduce any requirements or applicability not already included
within the approved standards. PRC-005-2 does not use this term, and expands upon the applicability in the interpretation to address what seems to the SDT to
be an appropriate applicability for PRC-005-2. The applicability of the interpretation to PRC-004 is not affected by PRC-005-2.
2. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements as written directly support this definition.
US Army Corps of Engineers
1. Section 4.2.5.4 - please clarify generator connected station service transformer. We believe this to mean a
station service transformer with no breaker between the transformer and the generator bus.
2. R3 - the term 'initiate resolution' is vague and needs to be further defined. Does this mean putting in a
work order or is further action required.
3. Data Retention: The proposed standard clarifies that two of the most recent records of maintenance are to
be retained to demonstrate compliance with the prescribed maintenance intervals. When equipment is
replaced, the reference information indicates that the information associated with the original equipment
must be retained to show compliance with the standard until the performance with the new equipment can
be established. This is not explicitly stated in the requirements and warrants a comment.
Response: Thank you for your comments.
1. The commenter is correct.
2. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even
several years) to complete effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with
other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these
more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues and rely on
the operating focus on the degraded system to ensure that they are completed. The definition of maintenance correctable issue has been revised to be clearer.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
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performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
3. The data retention section is stated to describe what an entity must do to demonstrate compliance to an auditor on a persistent basis. The additional
clarification in the Supplemental Reference Document is provided to share the experiences of SDT members with other entities, and to suggest a possible
effective practice.
Public Utility District No. 1 of
Lewis County (5)
Ballot
Comment Negative
Standard does not recognize the affects and great burdens to smaller utilities that have limited staff and great
distance to travel out west. Generally, our facilities to not affect the BES. We believe that the battery testing
requirements are overkill. The intervals for testing should be placed at minimum of 2 or 3 years
Response: Thank you for your comments. The activities involved in the 3-calendar-month maintenance intervals all relate to inspection-type activities of
unmonitored battery systems. The SDT believes that an entity may schedule activities for a 3-calendar-month interval without a “grace period” if adequate
program oversight is exercised, and disagrees that the intervals should be extended. See Section 7.1 of the “PRC-005-2 Protection System Maintenance
Supplementary Reference & FAQ” for a discussion about “calendar month”. Basically every “3 Calendar Months” means to add 3 months from the last time the
activity was performed.
As for the other shorter-duration activities, the SDT believes that all of these activities, at the specified intervals, are necessary to assure reliability. From the
experience of the SDT members, and as supported by various IEEE Standards, it seems clear that delaying the battery maintenance activities to 2-3 years would
be detrimental to the reliability of the BES.
AtCO Electric ltd
1. Table 1-2: the requirement for 12 calendar year verification for the channel and essential signals’
performance should be removed. We do not see benefit in the maintenance activities under level 2 (the 12
calendar year requirement) and suggest merging it with level 3 (the “no periodic maintenance specified”
requirement). The “loss of function” alarm, will be considered as a countable event to fall under requirement
R3 and dealt as maintenance correctable issue.
2. Table 1-5: the requirement of 6 calendar year verification for electrical operation of electromechanical
lockout and/or tripping auxiliary devices should be revisited, considering that: ” It is not feasible to exercise
a lockout relay during maintenance due to high risk to the in-service facility, as well as the complexity of
lockout relay connections and protection schemes. Instead, we propose a DC ring test, which verifies the
continuity of control circuitry and eliminates the risk impact of lockout or auxiliary tripping device
operations.” The interval is too frequent. The requirement would become achievable if the 6 calendar year
frequency were increased to 12 calendar years, to be in line with microprocessor relay maintenance
frequency
Response: Thank you for your comments.
1. Though a channel with continuous alarming may not be in an alarm state during a quiescent state, the alarm function alone does not identify if the channel will
fail during fault conditions. Fault noise level and, fault location impact a channels’ noise immunity margin. The activities are specified are to ensure reliable
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performance of the communication channel.
2. The SDT believes that performing these maintenance activities will benefit the reliability of the BES.The SDT believes that electromechanical devices with
moving parts share performance attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals. Performance-Based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
CPS Energy
1. Table 1-5 The new standard requires that every 6 years it is verified that “each trip coil is able to operate
the breaker,”. The supplementary reference states that this requirement can be met by tracking real-time
fault-clearing operations on the circuit breakers. With transmission breakers typically having dual trip coils,
how can tracking real-time operations meet this requirement? Would a breaker operations where relays in
both the primary and secondary trip coils indicated operation be sufficient or would some type of trip coil
monitoring that showed coil energization be needed?
2. Additionally, regarding the verification of all trip paths of the trip circuit. If a microprocessor relay is used to
trip a breaker, and two contacts are paralleled on the relay through a single test switch for breaker tripping,
would it be necessary to verify each contact independently or could an assertion of both contacts through
the test switch be adequate? In this instance, the functionality of each contact would be fully identical.
3. Table 1-2A 3-month inspection is required for communications equipment that does not have “continuous
monitoring or periodic automated testing for the presence of the channel function, and alarming for loss of
function” has to be verified that the communication equipment is “functional” with a 3-month site visit.
Would a carrier on-off system, that did not perform periodic check back testing, but did have an alarm
contact (loss of power, failure, etc.) that was monitored through SCADA would need to have a 3-month
inspection? According to the supplemental reference, this inspection should be to verify that the equipment
is “operable through a cursory inspection and site visit”. It sounds as if this cursory inspection and site visit
would accomplish the same as the alarm contact. It does not appear that end-end functional testing of the
blocking signal is required by what is provided in the supplemental reference. Is this correct?
4. Table 1-3 - The maintenance activity for the 12 calendar year testing should include a little more specificity.
It should have something stating the values provided to the relay are accurate. I know that this discussed
in the supplemental reference, but requirement in Table1-3 sounds as if any relay that measured for loss of
signal, such as a loss-of-potential function, would be sufficient when the purpose to verify that the signal not
only gets to the relay but also has some accuracy as needed by the application of the relay.
Response: Thank you for your comments.
1. If you are able to independently track both trip coils via real-time operations tracking, you could use this tracking to address this activity. If not, you will likely
need to perform focused maintenance activities.
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2. This would be adequate.
3. This is not correct. As you indicate, the 3 month check for unmonitored relay channels is to verify that the channel is functional. For a guard signal, a visual
inspection will indicate if a guard or pilot signal is being received. A blocking channel can only be verified by either a checkback test or an end to end signal check.
A visual check that the equipment is not failed does not indicate that the channel medium or auxiliary devices are still intact. We will revise the supplementary
reference to clear this up (See Section 15.5.1, question “What is needed for the 3-month inspection of communications-assisted trip scheme equipment?”).
4. If the voltage and current signals are measured by the relay and verified to be correct, this would satisfy the required activity in the Table. Please note that, in
the definition of Protection System Maintenance Program, “verify” means, “determine that the component is functioning correctly”.
NextEra Energy
Thank you for your diligent efforts in writing the draft standard. The draft standard and associated documents
are well written and we believe, after approval, will be instrumental to improving the reliability of the BES. We
have the following specific comments:
a. The maximum maintenance interval of unmonitored Vented Lead-Acid (VLA) batteries should be changed
from 3 calendar months to 12 calendar months. Today’s lead-calcium and lead-selenium-low antimony
batteries do not have rapid water loss as compared to the legacy lead-antimony batteries. FPL’s operating
experience has shown that electrolyte in today’s VLA cells do not require watering within a 12-month
interval. In fact, battery manufacturers now recommend watering intervals of 2 to 3 years for some new
batteries.
b. The maximum maintenance interval to verify that unmonitored communications systems are functional
should be changed from 3 calendar months to 12 calendar months. FPL’s operating experience has shown
that power line carrier (PLC) failures are primarily due to PLC protective devices (MOVs, gas tubes & spark
gaps). Automated testing such as PLC check-back schemes cannot test for failed PLC protective devices.
We believe a 12 calendar month functional test is sufficient because of FPL’s operating experience. FPL’s
operating experience has shown that power line carrier (PLC) failures are primarily due to PLC protective
devices (MOVs, gas tubes & spark gaps).
c. We believe the data retention requirements for R2 and R3 should be documentation for the two most recent
maintenance activities.
d. Regarding Maintenance Correctable Issue (page2) where it states: “.such that it cannot be restored to
functional order during performance of the initial on-site activity”. This terminology is vague: Particularly
“initial on-site activity”. Not sure what “functional order” means? The suggestion is to change to “..such that
the deficiency cannot be restored to meet applicable acceptance criteria during the performance of the
scheduled maintenance activity”.
e. Regarding Maintenance Correctable Issue (page 2) and R4 on Page 5, the suggestion is an entirely new
“Maintenance Correctable” definition especially: “Therefore this issue requires followup corrective action”.
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Regarding this new definition: Why is it here? Is its purpose to ask us to do something with these issues if
we discover them? Do issues identified as “Maint. Correctable” need to be tracked and reported in some
manner? The referenced term “Maint. Correctable” is only used in PRC-005-2 in R4 (page 5). The
suggestion is to provide clarification. Is this maintenance correctable terminology implying that NERC
PRC005-2 is opening up a new requirement for tracking and reporting resolution of “Maint Correctable”
issues? The suggestion is to change to:
This issue includes any activity requiring further follow-up corrective action to restore operability outside
of the applicable maint activity
f. Regarding Countable Event (Page 3), the suggestion is an entirely new “Countable Event” definition. Why
is this new term and definition “countable event” included in PRC-005-2 ? Note: In the PRC005-2 text
“countable event” is actually only referred to in PRC-005-2 in Attachment A under “Performance Based
Programs” (not referred to in time based programs section). The recommendation is that the PRC-005-2
version explicitly clarify the definition of â ”countable event” to clearly indicate that this term is applicable
ONLY to “Performance Based Programs”.
g. Regarding Countable Event (page 3), where the text says “Any failure of a component which requires
repair or replacement, any condition discovered during the verification activities in Tables 1-1/1-5 which
requires corrective action..”, in the definition for “countable event” what does “corrective action” mean?
PRC005-2 is unclear. Does the term “countable event” have any ties to”Maint Correctable” issues. The
suggestion is to Consider changing wording from “corrective action” to “which requires > 7 days to correct”
and clarify whether or not “countable event” has any correlation to “Maint Correctable” events as discussed
on page 2 and in R4? If so please provide language clarifying this correlation.
Response: Thank you for your comments.
a. This activity is primarily inspection-related, and addresses an inspection of electrolyte levels, dc grounds, and station dc supply voltages. Good practice is that
entities will conduct a visual inspection of the overall battery condition during these activities, although the Standard does not require it. Also, please note that,
while some batteries may reliably go longer between “watering”, this activity is to detect gross failures, rather than specifically to address “watering”. Please see
Section 15.4 of the Supplementary Reference Document for further discussion.
b. A relay communications channel and equipment provide logic for a pilot protective relay system to operate correctly to clear faults instantaneously. Channel
failure would cause the protective system to not operate or to operate incorrectly. An unmonitored channel failure will decrease reliability of that protective system
until its failure is discovered. One year is too long to risk BES protective systems out of service. The three month interval is devised to maintain BES system
reliability. If an entity’s experience suggests that longer intervals are appropriate, they may employ performance-based maintenance per R2 and Attachment A.
The definition of maintenance correctable issue has been revised to be clearer.
c. From SDT members’ experiences, it is clear that auditors will generally wish to monitor compliance all the way back to the previous audit. Please see
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Compliance Application Notice CAN-008 for a discussion about pre-2007 data.
d. The definition has been modified in consideration of your comment.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that the deficiency cannot be corrected during the
performance of the maintenance activity. Therefore this issue requires follow-up corrective action.
e. Yes – the entity is expected to do something in response to an identified Maintenance Correctable Issue, but it is left to the entity to determine the best method
for them to track the initiation of resolution of Maintenance Correctable issues. The definition of maintenance correctable issue has been revised to be clearer..
Please refer to M3 for some sample types of evidence.
f. Countable events are used only within Attachment A.
g. “Countable Event” applies only to performance-based maintenance, and is used solely to determine and evaluate the PBM maintenance intervals. A countable
event may (or may not) be a maintenance correctable issue, depending on whether the deficiency is corrected while performing the maintenance activity or
requires additional follow-up.
U.S. Bureau of Reclamation (5)
Ballot
Comment Affirmative
The application of the PSMP should be explicitly defined in the standard. Currently the PSMP is required to
protect rather than a PSMP to identify the components defined by the standard. The language should be
altered to ensure the PSMP is developed for the component types specified in the standard. The following
language should be considered: "Each Transmission Owner, Generator Owner, and Distribution Provider
shall establish a Protection System Maintenance Program (PSMP) for its Protection Systems identified in
Section 4.2".
Response: Thank you for your comments. R1 has been modified as you suggest.
NIPSCO
1. The present PRC-005 standard is 2 pages while the proposed PRC-005-2 is 22 pages, with an
implementation plan of 4 pages and a supplemental document of 87 pages. The review process appears to
be somewhat daunting especially considering that NERC is trying to simply things with such concepts as
the “traffic ticket” approach.
2. In R3 we’re not sure if there is a time requirement regarding the completion of the resolution process. We
like the use of "calendar year" in requirements which should provide flexibility in getting the work
completed.
3. Another comment for our response concerns Table 1-2, Communications Systems (page 11):The first
maintenance interval is 3 calendar months. Does this mean the same as 1 calendar quarter?1. Example
for 3 calendar months: Maintenance performed on 1/4/11. Next maint due by 4/30/11. Maintenance
performed on 4/12/11. Next maint due by 7/31/11. Maintenance performed on 7/30/11. Next maint due by
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10/31/11. This would yield 3 inspections for 2011. Maintenance performed on 10/12/11. Next maint due
by 1/31/12.2. Example for 1 calendar quarter: Maintenance performed on 1/4/11. Next maint due by
6/30/11. This would yield 4 inspections for 2011 (1 per quarter).
Response: Thank you for your comments.
1. The SDT has established maximum allowable intervals in accordance with FERC Order 693. Additionally, the SDT has addressed many of the common
program-related causes of observed violations, and has provided the Supplementary Reference and FAQ to assist entities in implementing their program. The
“traffic ticket” approach is focused on how the compliance monitor will assess violations, and has no bearing on the Standard itself.
2. The SDT has considered that, while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even
several years) to complete effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with
other standards. The SDT is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these
more extended activities to “correct”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues and rely on
the operating focus on the degraded system to ensure that they are completed.
3. The intervals, “3 calendar months” and “once per calendar quarter” are not synonymous. “Once per calendar quarter” would effectively permit entities to have
six months (less two days) between successive activities, while a “3 calendar month” interval limits an entity to four months (less two days) between activities.
See Section 7.1 of the “PRC-005-2 Protection System Maintenance Supplementary Reference & FAQ” for a discussion about “calendar month” Basically every “3
Calendar Months” means to add 3 months from the last time the activity was performed.
Tenaska, Inc. (5)
Ballot
Comment Negative
1. The biggest concern we have with the proposed standard is the inclusion of 4.2.5.4. As written it is not
clear, but more importantly it is overly broad and provides little, if any, increase to reliability. It needs to be
deleted.
2. In Section 4.2, five types of protection systems are identified as being applicable, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance
Program (PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1
of Section 4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2
and that the language of Requirement 1 may cause confusion or be misleading. We suggest changing the
language of Requirement 1 from:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
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System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Response: Thank you for your comments.
1. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1.
2. R1 of the standard has been modified as you suggest.
Seattle City Light (1) (3) (4)
Ballot
Comment Negative
Seattle City Light (SCL) commends the Standard Drafting Team (SDT) for the many improvements in the
latest draft of proposed standard PRC-005-2. The proposed PRC-005-2 standard is an improvement over the
four standards that it will replace. Each draft has been better than that preceding, and the supporting material
is very helpful in understanding the impact and implementation of the proposed Standard. However, SCL
votes NO for this draft because of
1) the inclusion and treatment of electromechanical lockout relays within the scope of draft Standard and
2) 2) confusion about language between section 4.2 and Requirement 1.
1. Regarding electromechanical lockout relays, SCL is highly concerned about the reliability risks and
logistical difficulties associated with meeting the requirements proposed for these relays. Lockout relays
operate rarely and are known for reliable service. For many such relays, the proposed maintenance would
require clearance of entire bus sections or even multiple bus sections (such as for a bus differential lockout
relay). In SCL's opinion, the reliability risks posed by such switching and outages to the Bulk Electric
System outweigh the reliability benefits of including lockout relays in the scope of PRC-005-2. If the SDT
deems it necessary to include electromechanical lockout relays within PRC-005-2, SCL recommends that a
difference be made between the maintenance activities specified for monitored and unmonitored types. The
draft Standard describes the requirements for "electromechanical lockout and/or tripping auxiliary devices"
in Table 1-5 (p.19) and assigns a 6-year maximum maintenance interval, the same as for other
unmonitored relays. Modern electromechanical lockout relays may be specified with a built-in selfmonitoring trip-coil alarm. SCL believes the maintenance requirements for electromechanical lockout relays
with such an alarm should be similar to those for other alarmed or monitored relays. As such we
recommend that a new entry be added to Table 1-5 for monitored electromechanical lockout relays, as
follows:
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• Component Attributes: Electromechanical lockout and/or tripping auxiliary devices which are directly in a
trip path from the protective relay to the interrupting device trip coil AND include built-in self-monitoring tripcoil alarm
• Maximum Maintenance Interval: 12 calendar years
• Maintenance Activities: Verify electrical operation of electromechanical trip and auxiliary devices. Verify
that the alarm path conveys alarm signals to a location where corrective action can be initiated.
2. We also would like to comment regarding confusion over language in section 4.2.This section identifies
five types of Facilities that the standard is applicable to, whereas Requirement 1 indicates that applicable
entities need to establish a Protection System Maintenance Program (PSMP) for the Protection Systems
designed to provide protection for BES Element(s) (Part 4.2.1 of Section 4.2). As such, it is not clear if
PRC-005-2 applies to five Facilities or to certain Protection Systems. SCL believes the intent is to have a
PSMP for all Protection Systems identified in "Part A, Section 4.2 - Facilities" and that the language of
Requirement 1 may cause confusion or be misleading. We suggest changing the language of Requirement
1 from:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Facilities identified in Part A, Section 4.2.
Response: Thank you for your comments.
1. The SDT believes that performing these maintenance activities will benefit the reliability of the BES. The SDT believes that electromechanical devices having
moving parts share performance attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals. Performance-Based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
2. R1 has been modified as you suggest.
Seattle City Light (5) (6)
Ballot
Comment Negative
Seattle City Light (SCL) commends the Standard Drafting Team (SDT) for the many improvements in the
latest draft of proposed standard PRC-005-2. The proposed PRC-005-2 standard is an improvement over the
four standards that it will replace. Each draft has been better than that preceding, and the supporting material
is very helpful in understanding the impact and implementation of the proposed Standard. However, SCL
votes NO for this draft because of
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1) the inclusion and treatment of electromechanical lockout relays within the scope of draft Standard and
2) confusion about language between section 4.2 and Requirement 1.
1. Regarding electromechanical lockout relays, SCL is highly concerned about the reliability risks and
logistical difficulties associated with meeting the requirements proposed for these relays. Lockout relays
operate rarely and are known for reliable service. For many such relays, the proposed maintenance would
require clearance of entire bus sections or even multiple bus sections (such as for a bus differential lockout
relay). In SCL's opinion, the reliability risks posed by such switching and outages to the Bulk Electric
System outweigh the reliability benefits of including lockout relays in the scope of PRC-005-2. If the SDT
deems it necessary to include electromechanical lockout relays within PRC-005-2, SCL recommends that a
difference be made between the maintenance activities specified for monitored and unmonitored types. The
draft Standard describes the requirements for "electromechanical lockout and/or tripping auxiliary devices"
in Table 1-5 (p.19) and assigns a 6-year maximum maintenance interval, the same as for other
unmonitored relays. Modern electromechanical lockout relays may be specified with a built-in selfmonitoring trip-coil alarm. SCL believes the maintenance requirements for electromechanical lockout relays
with such an alarm should be similar to those for other alarmed or monitored relays. As such we
recommend that a new entry be added to Table 1-5 for monitored electromechanical lockout relays, as
follows:
• Component Attributes: Electromechanical lockout and/or tripping auxiliary devices which are directly in a
trip path from the protective relay to the interrupting device trip coil AND include built-in self-monitoring
trip-coil alarm o Maximum Maintenance Interval: 12 calendar years
• Maintenance Activities: Verify electrical operation of electromechanical trip and auxiliary devices. Verify
that the alarm path conveys alarm signals to a location where corrective action can be initiated.
2. Regarding confusion over language, section 4.2 section identifies five types of Facilities that the standard is
applicable to, whereas Requirement 1 indicates that applicable entities need to establish a Protection
System Maintenance Program (PSMP) for the Protection Systems designed to provide protection for BES
Element(s) (Part 4.2.1 of Section 4.2). As such, it is not clear if PRC-005-2 applies to five Facilities or to
certain Protection Systems. SCL believes the intent is to have a PSMP for all Protection Systems identified
in "Part A, Section 4.2 - Facilities" and that the language of Requirement 1 may cause confusion or be
misleading. We suggest changing the language of Requirement 1 from:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
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•
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Facilities identified in Part A, Section 4.2.
Response: Thank you for your comments.
1. The SDT believes that performing these maintenance activities will benefit the reliability of the BES. The SDT believes that electromechanical devices having
moving parts share performance attributes (and failure modes) with electromechanical relays and need to be tested at similar intervals. Performance-Based
maintenance is an option to increase the intervals if the performance of these devices supports those intervals.
2. R1 has been modified as you suggest.
Colorado Springs Utilities (1)
Ballot
Comment Negative
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. We suggest changing the language of
Requirement 1 from:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Even with this change, the standard is still vague given the fact that there is no clear definition of "BES" or
"Protective relay".
Response: Thank you for your comments. R1 has been modified as you suggest.
Western Electricity Coordinating
Council (10)
Ballot
Comment Affirmative
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. To address the potential for confusion we
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suggest changing the language of Requirement 1 from:
Western Electricity Coordinating
Council
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. We suggest changing the language of
Requirement 1 from:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for
BES Element(s). to:
• Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Response: Thank you for your comments. R1 has been modified as you suggest.
California Energy Commission (9)
Entegra Power Group, LLC
(5)Idaho Power Company (1)
NorthWestern Energy (1)
Platte River Power Authority (1)
Ballot
Comment –
Affirmative
(except for
PUD of
Grant
County Negative
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). We believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. We suggest changing the language of
Requirement 1 from:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems designed to provide protection for BES
Element(s). to:
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•
(3) (6)
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Public Utility District No. 1 of
Douglas County (4)
Public Utility District No. 2 of
Grant County (3)
Utah Public Service Commission
(9)
Response: Thank you for your comments. The Standard has been modified as you suggest.
Tucson Electric Power Co. (1)
Ballot
Comment Negative
The proposed PRC-005-2 standard is an improvement over the four standards that it will replace. However,
section 4.2 identifies five types of protection systems that the standard is applicable to, but the language of
Requirement 1 indicates that applicable entities need to establish a Protection System Maintenance Program
(PSMP) for the Protection Systems designed to provide protection for BES Element(s) (Part 4.2.1 of Section
4.2). I believe the intent is to have a PSMP for all Protection Systems identified in Section 4.2 and that the
language of Requirement 1 may cause confusion or be misleading. Suggest changing the language of
Requirement 1 to:
•
Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection
System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2.
Response: Thank you for your comments. The Standard has been modified as you suggest.
Ingleside Cogeneration LP
The removal of R1.5 and R7 which required Protection System owners to identify and verify calibration
tolerances or equivalent parameters upon conclusion of a maintenance activity was fundamental to Ingleside
Cogeneration’s yes vote. The amount of ambiguity introduced by the requirements and associated
documentation did not serve to improve BES reliability in our view.
Response: Thank you for your comments.
Transmission Access Policy
The scope of the equipment to which the draft standard applies is over-broad.
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Specifically, PRC-005-2 should not apply to non-relay equipment for UFLS and UVLS systems. Subjecting
UFLS and UVLS batteries, instrument transformers, DC control circuitry, and communications to the
requirements of PRC-005-2 would drastically increase the scope of equipment covered by the standard, with
no corresponding benefit to reliability, for the following reasons. In contrast to transmission and generation
protection systems and SPSs, for which there are typically two protection systems per facility and therefore
per fault, UFLS and UVLS deal with widespread events. For any under-voltage or under-frequency event,
there are literally hundreds of UFLS/UVLS relays to respond. It is therefore far less critical if one UFLS or
UVLS relay fails to operate properly.
Furthermore, transmission is typically not radial (in fact, radials to load are excluded from the BES). But
distribution circuits, where UFLS and UVLS systems are located, are usually radial. Testing some of the nonrelay equipment to which the draft standard applies would require blacking out the customers served by that
radial. In other words, the draft standard would require entities to definitely cause blackouts in an attempt to
prevent very unlikely potential blackouts. This is plainly not justified from a harm/benefit perspective.
Finally, many of the types of non-relay equipment to which the standard would apply are in effect tested by
faults. Specifically, faults happen on distribution circuits (where UFLS and UVLS systems are located) more
frequently than on transmission circuits, due to such things as animal contacts and car accidents. Any such
fault is in fact a test of the all the equipment that is involved in clearing the fault. There is no need to require
separate tests of that equipment, any more than we would require tests of a phone line that is used on an
everyday basis; you already know that the phone works.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
Illinois Municipal Electric Agency
The scope of the equipment to which the draft standard applies is still overly broad. Specifically, PRC-005-2
should not apply to non-relay equipment for UFLS and UVLS systems. Subjecting UFLS and UVLS batteries,
instrument transformers, DC control circuitry, and communications to the requirements of PRC-005-2 would
drastically increase the scope of equipment covered by the standard, with no corresponding benefit to
reliability of the BES. This comment/recommendation is provided to address the resource and customer
service interests of a TO and/or DP systems serving distribution load. Illinois Municipal Electric Agency
supports comments submitted by the Transmission Access Policy Study Group.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure define “Reliability standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
ISO/RTO Standards Review
The SRC disagrees with the change to the term under 4.2.1. “Protection Systems designed to provide
protection for BES elements.” We support keeping the previous version’s wording of 4.2.1. “Protection
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Systems applied on, or designed to provide protection for the BES.” The revised wording expands the
fundamental purpose of the NERC PRC-005 standard from being focused on ensuring relays intended to
protect the reliability of the BES are maintained to a standard whose intent is to ensure all BES facilities have
relay maintenance programs. Although we do not disagree with maintaining all relays, regardless of what their
intended purposes are, it should not be the purpose of a NERC standard to police all protection schemes
beyond those needed for interconnected reliability. There are numerous protective relays employed on
facilities interconnected to the BES but their purpose may be for operating preference or service/equipment
quality purposes such as reclosing schemes and transformer sudden pressure relays. We believe the NERC
PRC-005 standard should be focused on maintenance of those protective relays which are needed to ensure
that the loss of a single element does not cause cascading effects on the bulk power system.
Response: Thank you for your comments. Clause 4.2.1 has been modified to improve consistency with the Interpretation that has become part of PRC-005-1a.
Duke Energy
The Standard Drafting Team has done an outstanding job on this standard. We are voting “Affirmative” but
note that implementation questions remain, particularly with regards to classifying component attributes as
“monitored,” “unmonitored,” “internal self diagnosis,” “alarming,” “alarming for excessive error” and “alarming
for excessive performance degradation”. The sheer size of the population of protective relays,
communications systems, voltage and current sensing devices, batteries, and dc supply components means
that the size of the effort required to categorize each individual component could drive us to test and maintain
on the more frequent unmonitored time intervals, simply because of the difficulty in assembling “monitored”
compliance documentation.
Response: Thank you for your comments. The opportunity to use “monitoring” to extend the intervals and reduce the activities, as well as the opportunity to use
performance-based maintenance, is provided for those entities who wish to apply the administrative resources in order to minimize the field maintenance. If
entities choose not to use those opportunities, the SDT believes that the un-monitored intervals and activities will establish an effective PSMP.
Pepco Holdings Inc
There were numerous comments submitted for each of the previous drafts indicating that the 3 month interval
for verifying unmonitored communication systems was much too short. The SDT declined to change the
interval and in their response stated: "The 3 month intervals are for unmonitored equipment and are based on
experience of the relaying industry represented by the SDT, the SPCTF and review of IEEE PSRC work.
Relay communications using power line carrier or leased audio tone circuits are prone to channel failures and
are proven to be less reliable than protective relays." Statistics on the causes of BES protective system
misoperations, however, do not support this assertion. The PJM Relay Subcommittee has been tracking
230kV and above protective system misoperations on the PJM system for many years. For the six year
period from 2002 to 2007, the number of protective system misoperations due to communication system
problems was lower (and in many cases significantly lower) than those caused by defective relays, in every
year but one. Similarly, RFC has conducted an analysis of BES protection system misoperations for 2008
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and 2009, and found the number of misoperations caused by communication system problems to be in line
with the number attributed to relay related problems. If unmonitored protective relays have a 6 year maximum
maintenance/inspection interval, it does not seem reasonable to require the associated communication
system to be inspected 24 times more frequently, particularly when relay failures are statistically more likely to
cause protective system misoperations. As such, a 12 or 18 calendar month interval for inspection of
unmonitored communication systems would seem to be more appropriate. FAQ II 6 B states that the concept
should be that the entity verify that the communication equipment...is operable through a cursory inspection
and site visit. However, unlike FSK schemes where channel integrity can easily be verified by the presence
of a guard signal, ON-OFF carrier schemes would require a check-back or loop-back test be initiated to verify
channel integrity. If the carrier set was not equipped with this feature, verification would require personnel to
be dispatched to each terminal to perform these manual checks. The SDT responded that they still felt the 3
month interval as stated in the standard was appropriate. PHI respectfully requests that the SDT reconsider
this issue and also cite what "specific statistical data" they used to validate that unmonitored communication
systems are 24 times more prone to failure than unmonitored protective relays.
Response: Thank you for your comments.
The SDT believes that relay communications channels are more susceptible to failure from an outside influence than a protective relay. Leased circuits from
communications providers and carrier channels are highly exposed to lightning, automobiles, backhoes, etc. We believe the existing statistics from PJM and RFC
on relay communications system based misoperation causes is due to the present practice of periodic channel verifications being performed. Many utilities
presently use channel monitoring and carrier checkbacks to ensure reliable operation.
Liberty Electric Power LLC (5)
Ballot
Comment Negative
While the SDT has done a very good job at responding to the most objectionable parts of the previous
version, there are still a number of issues which makes the standard problematic.
1. The standard introduces the term "initiate resolution". This is an interpretable term, and has the potential for
an auditor and an entity to disagree on an action. Would issuing a work order be considered "initiating
resolution"? What if the WO had a completion date many years into the future? I would suggest adding the
term to the list of definitions which will remain with the standard, and defining it as "performing any task
associated with conducting maintenance activities, including but not limited to issuing purchase orders,
soliciting bids, scheduling tasks, issuing work requests, and performing studies".
2. Some clarity is needed to differentiate system connected and generator connected station service
transformers. A statement that a station service transformer connected radially to the generator bus is
considered a system connected transformer if the transformer cannot be used for service unless connected
to the BES.
3. The "bookends" issue, brought up in the prior round of comments, still exists. Although the SDT rightly
notes a CAN has been issued regarding bookends, the CAN covers the documentation for system
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components that entities were required to self-certify to on June 18, 2007. PRC-005-2 adds additional
components to the protection system scheme which were not part of that certification, and has the potential
to put entities into violation space due to a lack of records for those components.
4. The SDT should add to M3 a statement that entities may demonstrate compliance with the standard by
demonstrating that required activities took place twice within the maximum maintenance interval -starting
from the effective date of the standard - for all components not listed in PRC-005-1.
Response: Thank you for your comments.
1. The SDT believes that issuing a work order would satisfy this requirement. M3 presents several examples of relevant evidence. The SDT has considered that,
while some maintenance correctable issues may be completed very quickly, others may take an extended period (perhaps even several years) to complete
effectively, during which time the degraded system must be reported and reflected within the operation of the BES in accordance with other standards. The SDT
is concerned that the entity will not be able to record the maintenance activity as “complete” during the scheduled interval for these more extended activities to
“correct the maintenance correctable issue”; therefore, the SDT has opted to require only that the entity initiate correction of maintenance correctable issues and
rely on the operating focus on the degraded system to ensure that they are completed.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
3. The Implementation Plan specifies that entities may implement PRC-005-2 incrementally throughout the intervals specified, and that they shall follow their
existing program for components not yet implemented. The SDT believes that the “bookends” issue to which you refer is therefore addressed.
4. The Standard requires that activities only take place once within the established interval.
SPP reliability standard
development Team
Would like more clarification in table 1-5 to address verification tests on different circuits. Is this an end to end
test or partial test can you test one part of the circuit one way and another a different way? Should table 1-5
read Complete a terminal test of unmonitored circuitry?
Response: Thank you for your comments. The SDT does not believe that the suggested text adds clarity to the standard. Please see Section 15.3 of the
Supplementary Reference Document for additional discussion.
Lakeland Electric (1)
Ballot
Comment Negative
The new PRC-005-2 includes non-relay components into UFLS and UVLS. The problem is, for UFLS and
UVLS, these non-relay components are mostly distribution class equipment; hence, the result of this version 2
standard will be inclusion of most distribution class protection system components into PRC-005-2. This is a
huge expansion of the scope of equipment covered by the standard with negligible benefit to BES reliability.
While Lakeland Electric agrees wholeheartedly with the inclusion of non-relay components for BES Protection
Systems. It is critical that BES Protection Systems work and clear the fault (e.g., on > 100 kV Facilities).
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However, UFLS and UVLS are quite different. For an event requiring UFLS and UVLS operation, there are
many, e.g., hundreds and possibly thousands of relays, that operate to shed load automatically and if a small
percentage of those do not operate as expected, the impact is minimal. So, it is not important for BES
reliability to include non-relay components of UFLS and UVLS in the PRC-005-2 standard.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
City of Bartow, Florida (3)
Ballot
Comment Negative
There is an unnecessary expansion of the scope of equipment covered by this standard into the distribution
system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument transformers, DC
control circuitry and communications in addition to the relays for BES protection systems. PRC-008 (UFLS)
and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included in those standards.
The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The problem is, for UFLS
and UVLS, these non-relay components are mostly distribution class equipment; hence, the result of this
version 2 standard will be inclusion of most distribution class protection system components into PRC-005-2.
This is a huge expansion of the scope of equipment covered by the standard with negligible benefit to BES
reliability. We agree wholeheartedly with the inclusion of non-relay components for BES Protection Systems.
It is critical that BES Protection Systems work and clear the fault (e.g., on > 100 kV Facilities). However,
UFLS and UVLS are quite different. For an event requiring UFLS and UVLS operation, there are many, e.g.,
hundreds and possibly thousands of relays, that operate to shed load automatically and if a small percentage
of those do not operate as expected, the impact is minimal. So, it is not important for BES reliability to include
non-relay components of UFLS and UVLS in the PRC-005-2 standard. In addition, testing of protection
systems on distribution circuits is difficult for distribution circuits that are radial in nature. For instance, testing
trip coils of a distribution breakers will likely results in service interruption to customers on that distribution
circuit in order to test the breaker or to perform break-before-make switching on the distribution system often
required to manage maximum available fault current on the distribution system for worker safety, etc.. Hence,
the standard would be sacrificing customer service quality for an infinitesimal increase in BES reliability. In
addition, non-relay protection components operate much more frequently on distribution circuits than on
transmission Facilities due to more frequent failures due to trees, animals, lightning, traffic accidents, etc., and
have much less of a need for testing since they are operationally tested.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
Lakeland Electric (6)
Ballot
Comment -
Unnecessary expansion of the scope of equipment covered by this standard into the distribution system
related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument transformers, DC control
circuitry and communications in addition to the relays for BES protection systems. PRC-008 (UFLS) and
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Negative
PRC-011 (UVLS) are ambiguous as to whether non-relay components are included in those standards. The
new PRC-005-2 includes these non-relay components into UFLS and UVLS. The problem is, for UFLS and
UVLS, these non-relay components are mostly distribution class equipment; hence, the result of this version 2
standard will be inclusion of most distribution class protection system components into PRC-005-2. This is a
huge expansion of the scope of equipment covered by the standard with negligible benefit to BES reliability.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
Beaches Energy Services (1)
Ballot
Comment Negative
We believe that there is an unnecessary expansion of the scope of equipment covered by this standard into
the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included in
those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment; hence,
the result of this version 2 standard will be inclusion of most distribution class protection system components
into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard with negligible
benefit to BES reliability. We agree wholeheartedly with the inclusion of non-relay components for BES
Protection Systems. It is critical that BES Protection Systems work and clear the fault (e.g., on > 100 kV
Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS and UVLS operation,
there are many, e.g., hundreds and possibly thousands of relays, that operate to shed load automatically and
if a small percentage of those do not operate as expected, the impact is minimal. So, it is not important for
BES reliability to include non-relay components of UFLS and UVLS in the PRC-005-2 standard. In addition,
testing of protection systems on distribution circuits is difficult for distribution circuits that are radial in nature.
For instance, testing trip coils of distribution breakers will likely result in service interruption to customers on
that distribution circuit in order to test the breaker or to perform break-before-make switching on the
distribution system often required to manage maximum available fault current on the distribution system for
worker safety, etc.. Hence, the standard would be sacrificing customer service quality for an infinitesimal
increase in BES reliability. In addition, non-relay protection components operate much more frequently on
distribution circuits than on Transmission Facilities due to more frequent failures due to trees, animals,
lightning, traffic accidents, etc., and have much less of a need for testing since they are operationally tested.
Response: Thank you for your comments. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable
operation of the bulk power system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
Keys Energy Services (1)
Ballot
Comment -
1. KEYS believes that there is an unnecessary expansion of the scope of equipment covered by this standard
into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
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Yes or No
Negative
Question 5 Comment
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included
in those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment;
hence, the result of this version 2 standard will be inclusion of most distribution class protection system
components into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard
with negligible benefit to BES reliability. KEYS agrees wholeheartedly with the inclusion of non-relay
components for BES Protection Systems. It is critical that BES Protection Systems work and clear the fault
(e.g., on > 100 kV Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS
and UVLS operation, there are many, e.g., hundreds and possibly thousands of relays, that operate to shed
load automatically and if a small percentage of those do not operate as expected, the impact is minimal.
So, it is not important for BES reliability to include non-relay components of UFLS and UVLS in the PRC005-2 standard. In addition, testing of protection systems on distribution circuits is difficult for distribution
circuits that are radial in nature. For instance, testing trip coils of a distribution breakers will likely results in
service interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault current
on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing customer service
quality for an infinitesimal increase in BES reliability. In addition, non-relay protection components operate
much more frequently on distribution circuits than on transmission Facilities due to more frequent failures
due to trees, animals, lightning, traffic accidents, etc., and have much less of a need for testing since they
are operationally tested.
2. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
Lakeland Electric (3)
Ballot
Comment Negative
1. LAK believes that there is an unnecessary expansion of the scope of equipment covered by this standard
into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included
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Question 5 Comment
in those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment;
hence, the result of this version 2 standard will be inclusion of most distribution class protection system
components into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard
with negligible benefit to BES reliability. LAK agrees wholeheartedly with the inclusion of non-relay
components for BES Protection Systems. It is critical that BES Protection Systems work and clear the fault
(e.g., on > 100 kV Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS
and UVLS operation, there are many, e.g., hundreds and possibly thousands of relays, that operate to shed
load automatically and if a small percentage of those do not operate as expected, the impact is minimal.
So, it is not important for BES reliability to include non-relay components of UFLS and UVLS in the PRC005-2 standard. In addition, testing of protection systems on distribution circuits is difficult for distribution
circuits that are radial in nature. For instance, testing trip coils of a distribution breakers will likely results in
service interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault current
on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing customer service
quality for an infinitesimal increase in BES reliability. In addition, non-relay protection components operate
much more frequently on distribution circuits than on transmission Facilities due to more frequent failures
due to trees, animals, lightning, traffic accidents, etc., and have much less of a need for testing since they
are operationally tested.
2. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
City of Green Cove Springs (3)
Ballot
Comment Negative
1. GCS believes that there is an unnecessary expansion of the scope of equipment covered by this standard
into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included
in those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment;
131
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hence, the result of this version 2 standard will be inclusion of most distribution class protection system
components into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard
with negligible benefit to BES reliability. GCS agrees wholeheartedly with the inclusion of non-relay
components for BES Protection Systems. It is critical that BES Protection Systems work and clear the fault
(e.g., on > 100 kV Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS
and UVLS operation, there are many, e.g., hundreds and possibly thousands of relays, that operate to shed
load automatically and if a small percentage of those do not operate as expected, the impact is minimal.
So, it is not important for BES reliability to include non-relay components of UFLS and UVLS in the PRC005-2 standard. In addition, testing of protection systems on distribution circuits is difficult for distribution
circuits that are radial in nature. For instance, testing trip coils of a distribution breakers will likely results in
service interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault current
on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing customer service
quality for an infinitesimal increase in BES reliability. In addition, non-relay protection components operate
much more frequently on distribution circuits than on transmission Facilities due to more frequent failures
due to trees, animals, lightning, traffic accidents, etc., and have much less of a need for testing since they
are operationally tested.
2. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
Gainesville Regional Utilities (1)
Ballot
Comment Negative
GRU (GVL) agrees with the following comments provided by the FMPA:
1. FMPA believes that there is an unnecessary expansion of the scope of equipment covered by this standard
into the distribution system related to UVLS and UFLS. Currently, PRC-005-1 includes batteries, instrument
transformers, DC control circuitry and communications in addition to the relays for BES protection systems.
PRC-008 (UFLS) and PRC-011 (UVLS) are ambiguous as to whether non-relay components are included
in those standards. The new PRC-005-2 includes these non-relay components into UFLS and UVLS. The
problem is, for UFLS and UVLS, these non-relay components are mostly distribution class equipment;
hence, the result of this version 2 standard will be inclusion of most distribution class protection system
132
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Question 5 Comment
components into PRC-005-2. This is a huge expansion of the scope of equipment covered by the standard
with negligible benefit to BES reliability. FMPA agrees wholeheartedly with the inclusion of non-relay
components for BES Protection Systems. It is critical that BES Protection Systems work and clear the fault
(e.g., on > 100 kV Facilities). However, UFLS and UVLS are quite different. For an event requiring UFLS
and UVLS operation, there are many, e.g., hundreds and possibly thousands of relays, that operate to shed
load automatically and if a small percentage of those do not operate as expected, the impact is minimal.
So, it is not important for BES reliability to include non-relay components of UFLS and UVLS in the PRC005-2 standard. In addition, testing of protection systems on distribution circuits is difficult for distribution
circuits that are radial in nature. For instance, testing trip coils of a distribution breakers will likely results in
service interruption to customers on that distribution circuit in order to test the breaker or to perform breakbefore-make switching on the distribution system often required to manage maximum available fault current
on the distribution system for worker safety, etc.. Hence, the standard would be sacrificing customer service
quality for an infinitesimal increase in BES reliability. In addition, non-relay protection components operate
much more frequently on distribution circuits than on transmission Facilities due to more frequent failures
due to trees, animals, lightning, traffic accidents, etc., and have much less of a need for testing since they
are operationally tested.
2. As another comment, station service transformers are not BES Elements and should not be part of the
Applicability - they are radial serving only load.
Response: Thank you for your comments.
1. Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power system …” The
requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
2. The generator-connected station service transformers are often connected to the generator bus directly without an interposing breaker; thus, the Protection
Systems on these transformers will trip the generator as discussed in 4.2.5.1. System connected station service transformers were removed from the Applicability
in a previous draft.
Alliant Energy
1. If PRC-005-2 is going to incorporate PRC-008 (UFLS) and PRC-011 (UVLS) the Purpose needs to be
revised to include Distribution Protection Systems designed to protect the BES.
2. We do not believe a distribution relaying system, designed to protect the distribution assets, that may open
a transmission element (ie; breaker failure) should be considered part of the BES Protection System. R1
should add the following sentence “Distribution Protection Systems intended solely for the protection of
distribution assets are not included as a BES Protection System, even if they may open a BES Element.”
3. Table 1-5 (Component Type - Control Circuitry) Item 4 “Unmonitored control circuitry associated with
protective functions” require a 12 calendar year maximum maintenance interval. We believe UFLS and
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UVLS control circuitry should be exempted from this requirement. It would take multiple failures to have
any impact, and the impact on the BES would be minimal.
Response: Thank you for your comments.
1. There is no distinction in the purpose between “Distribution Protection Systems” and “Transmission Protection Systems”. The SDT believes that the
Applicability appropriately describes both the entities and the facilities.
2. The SDT modified Applicability 4.2.1 for better consistency with the interpretation that is reflected in PRC-005-1a, and believes that this change may address
your concern.
3. The Table 1-5 activities for UFLS/UVLS are constrained to those activities that the SDT considers to be appropriate relative to the reliability impact of these
applications. Please see Section 15.3 of the Supplemental Reference Document for additional discussion on this topic.
Y-W Electric Association, Inc. (4)
Ballot
Comment Affirmative
Y-WEA thanks the SDT for its long, hard work on this standard and for its consideration of previous
comments.
Response: Thank you for your comments.
BGE
PNGC Power
No comments.
Thank you for the opportunity to comment on the draft Standard PRC-005-2 – Protection System Maintenance.
We appreciate the work that NERC has put into a new standard to encapsulate and replace the current PRC005, PRC-008, PRC-011 and PRC-017. But, we believe that the draft Standard needs one important revision
before the NERC Board of Trustees should approve it.
Specifically, NERC should revise the draft version of PRC-005-2 so that the beginning of Section 4.2 reads as
follows:
“4.2. Facilities:
Protection Systems that (1) are not facilities used in the local distribution of electricity, (2) are
facilities and control systems necessary for operating an interconnected electric energy
transmission network, and (3) are any of the following:”
This revision is necessary to capture the limits that Congress placed on FERC, NERC, and the Regional Entities
in developing and enforcing mandatory reliability standards. Specifically, Section 215(i) of the Federal Power Act
provides that the Electric Reliability Organization (ERO) “shall have authority to develop and enforce compliance
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with reliability standards for only the Bulk-Power System.” And, Section 215(a)(1) of the statute defines the term
“Bulk-Power System” or “BPS” as: (A) facilities and control systems necessary for operating an interconnected
electric energy transmission network (or any portion thereof); and (B) electric energy from generation facilities
needed to maintain transmission system reliability. The term does not include facilities used in the local
distribution of electric energy.”
With this language, Congress expressly limited FERC, NERC, and the Regional Entities’ jurisdiction with regard
to local distribution facilities as well as those facilities not necessary for operating a transmission network. Given
that these facilities are statutorily excluded from the definition of the BPS, reliability standards may not be
developed or enforced for facilities used in local distribution.
In Order No. 672, FERC adopted the statutory definition of the BPS. In Order No. 743-A, issued earlier this year,
the Commission acknowledged that “Congress has specifically exempted ‘facilities used in the local distribution
of electric energy’” from the BPS definition. FERC also held that to the extent any facility is a facility used in the
local distribution of electric energy, it is exempted from the requirements of Section 215.
In Order No. 743-A, FERC delegated to NERC the task of proposing for FERC approval criteria and a process to
identify the facilities used in local distribution that will be excluded from NERC and FERC regulation. The critical
first step in this process is for NERC to propose criteria for approval by FERC to determine which facilities are
used in local distribution, and are therefore not BPS facilities. The criteria to be developed by NERC must
exclude any facilities that are used in the local distribution of electric energy, because all such facilities are
beyond the scope of the statutory definition of the BPS, which establishes the limit of FERC and NERC
jurisdiction. Accordingly, it is critical that NERC draft the new PRC-005-2 standard to expressly exclude facilities
used in local distribution.
NERC must also expressly exclude from PRC-005-2 those facilities “not necessary for operating an
interconnected electric energy transmission network (or any portion thereof)”. Similar to the local distribution
exclusion, the facilities not necessary for operating a transmission network are not part of the BPS and therefore
must be expressly excluded from the standard.
We understand, but disagree with, the argument that, because the FPA clearly excludes local distribution
facilities and facilities necessary for operating an interconnected electric transmission network from FERC,
NERC, and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in reliability
standards. This approach might be legally accurate, but could lead to significant confusion for entities attempting
to implement the new PRC-005-2 standard. There are numerous examples of Regional Entities, particularly
WECC, attempting to assert jurisdiction over such facilities, and regulated entities face significant uncertainty as
to which facilities they should consider as within jurisdiction. Clarifying FERC, NERC, and Regional Entity
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jurisdiction in the BES definition, even if such clarification is already provided in the FPA, would avoid such
problems under the new PRC-005-2 standard.
Again, we appreciate the work NERC has put in so far on a new Standard. We look forward to working within
the drafting process to help implement our recommended revision.
Response: Thank you for your comments. The SDT has revised R1 to refer to Applicability 4.2. The SDT believes that your comments are otherwise already
reflected in the Standard, and that no further changes are necessary. The Standard currently addresses maintenance of all Protection Systems that are applied
on or to protect BES elements, as well as maintenance of UFLS installed for the BES per PRC-007, UVLS installed on or for the BES per PRC-010, and Special
Protection Systems installed on or for the BES per PRC-012, PRC-013, PRC-014, and PRC-015. Therefore, the Standard is already constrained as you suggest.
Additionally, Section 202 of the NERC Rules of Procedure defines “Reliability Standard” as “a requirement to provide for reliable operation of the bulk power
system …” The requirements regarding maintenance of Protection Systems for UFLS and UVLS directly support this definition.
ReliabilityFirst
Ballot
Comment Affirmative
ReliabilityFirst votes affirmative but offers the following suggestions/comments:
1. R3 should be split into two separate requirements since there are two distinct actions being requested (e.g.
“…shall implement and follow its PSMP” is one requirement and “… shall initiate resolution of any identified
maintenance correctable issues” is the second requirement.
2. There are a number of terms which are defined only for the use of the PRC-005-2 standard which will not be
moved to the Glossary of Terms., and even though I completely agree with this concept, I believe this concept
is not mentioned nor is it allowed per the NERC Standard Processes Manual.
Response: Thank you for your comments.
1. The SDT believes that the two activities are intertwined and should remain within a single requirement.
2. The SDT has been advised by NERC Standards staff that this is acceptable, and has adopted the methodology for doing so as suggested by staff.
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Standard PRC-005-2 — Protection System Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approves SAR for posting on June 5, 2007.
2. The SAR was posted for comment from June 11, 2007–July 10, 2007.
3. The SC approves development of the standard on August 13, 2007.
4. First posting of revised standard on July 24, 2009.
5. Second posting of revised standard on June 11, 2010
6. Third posting of revised standard on November 17, 2010
7. Fourth posting of revised standard on April 13, 2011
Description of Current Draft:
This is the fifth draft of the Standard. This standard merges previous standards PRC-005-1, PRC-008-0,
PRC-011-0, and PRC-017-0. It also addresses FERC comments from Order 693, and addresses
observations from the NERC System Protection and Control Task Force, as presented in NERC SPCTF
Assessment of Standards: PRC-005-1 — Transmission and Generation Protection System Maintenance
and Testing, PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs, PRC011-0 — UVLS System Maintenance and Testing, PRC-017-0 — Special Protection System Maintenance
and Testing.
Future Development Plan:
Anticipated Actions
1. Post for combined 30-day comment and ballot.
Anticipated Date
July 5 – August 4, 2011
2. Conduct successive ballot
July 26 – August 4, 2011
3. Drafting Team Responds to Comments
August 4 – September 6, 2011
Draft 5: June 13, 2011
1
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Protection System (NERC Board of Trustees Approved Definition)
•
•
•
•
•
Protective relays which respond to electrical quantities,
communications systems necessary for correct operation of protective functions,
voltage and current sensing devices providing inputs to protective relays,
station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
The following terms are defined for use only within PRC-005-2, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that
the deficiency cannot be corrected during the performance of the maintenance activity. Therefore this
issue requires follow-up corrective action.
Segment – Protection Systems or components of a consistent design standard, or a particular model or
type from a single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60) individual
components.
Component Type - Any one of the five specific elements of the Protection System definition.
Component – A component is any individual discrete piece of equipment included in a Protection
System, including but not limited to a protective relay or current sensing device. The designation of what
constitutes a control circuit component is very dependent upon how an entity performs and tracks the
testing of the control circuitry. Some entities test their control circuits on a breaker basis whereas others
test their circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
Draft 5: June 13, 2011
2
Standard PRC-005-2 — Protection System Maintenance
their own definitions of control circuit components. Another example of where the entity has some
discretion on determining what constitutes a single component is the voltage and current sensing devices,
where the entity may choose either to designate a full three-phase set of such devices or a single device as
a single component.
Countable Event – A component which has failed and requires repair or replacement, any condition
discovered during the maintenance activities in Tables 1-1 through 1-5 which requires corrective action,
or a Misoperation attributed to hardware failure or calibration failure. Misoperations due to product
design errors, software errors, relay settings different from specified settings, Protection System
component configuration errors, or Protection System application errors are not included in Countable
Events.
Draft 5: June 13, 2011
3
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems affecting the reliability of the Bulk Electric System (BES) so that these Protection
Systems are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via
generator lockout or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for generator-connected station service transformers for
generators that are part of the BES.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems identified in
Section 4.2. Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]
The PSMP shall:
1.1. Address all Protection System component types.
1.2. Identify which maintenance method (time-based,
Draft 5: June 13, 2011
Component Type - Any one of
the five specific elements of the
Protection System definition.
4
Standard PRC-005-2 — Protection System Maintenance
performance-based (per PRC-005 Attachment A), or a combination) is used to address
each Protection System component type. All batteries associated with the station dc
supply component type of a Protection System shall be included in a time-based program
as described in Table 1-4.
1.3. Identify the associated maintenance intervals for time-based programs, to be no less
frequent than the intervals established in Table 1-1 through 1-5 and Table 2.
1.4. Include all applicable monitoring attributes and related maintenance activities applied to
each Protection System component type
consistent with the maintenance intervals
specified in Tables 1-1 through 1-5 and
Table 2.
R2. Each Transmission Owner, Generator Owner,
and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall
follow the procedure established in PRC-005
Attachment A to establish and maintain its
performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations
Planning]
Maintenance Correctable Issue Failure of a component to operate
within design parameters such that the
deficiency cannot be corrected during the
performance of the maintenance activity.
Therefore this issue requires follow-up
corrective action.
R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement and
follow its PSMP and initiate resolution of any identified maintenance correctable issues.
[Violation Risk Factor: High] [Time Horizon: Operations Planning]
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a current
documented Protection System Maintenance Program that addresses all component types of its
Protection Systems, as required by Requirement R1. For each Protection System component
type, the documentation shall include the type of maintenance program applied (time-based,
performance-based, or a combination of these maintenance methods), maintenance activities,
maintenance intervals, and, for component types that use monitoring to extend the intervals, the
appropriate monitoring attributes as specified in Requirement R1, Parts 1.1 through 1.4.
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses a
performance-based maintenance program shall have evidence that its current performancebased maintenance program is in accordance with Requirement R2, which may include but is
not limited to equipment lists, dated maintenance records, and dated analysis records and
results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has implemented the Protection System Maintenance Program and initiated resolution of
identified Maintenance Correctable Issues in accordance with Requirement R3, which may
include but is not limited to dated maintenance records, dated maintenance summaries, dated
check-off lists, dated inspection records, or dated work orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
Draft 5: June 13, 2011
5
Standard PRC-005-2 — Protection System Maintenance
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to demonstrate compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its
current dated Protection System
Component – A component is any individual
Maintenance Program including
discrete piece of equipment included in a
the documentation that specifies
Protection System, including but not limited to
the type of maintenance program
a protective relay or current sensing device.
applied for each Protection
The designation of what constitutes a control
System component type.
circuit component is very dependent upon how
an entity performs and tracks the testing of the
For Requirement R2 and
control circuitry. Some entities test their
Requirement R3, the
control circuits on a breaker basis whereas
Transmission Owner, Generator
others test their circuitry on a local zone of
Owner, and Distribution Provider
protection basis. Thus, entities are allowed
shall each keep documentation of
the latitude to designate their own definitions
the two most recent
of control circuit components. Another
performances of each distinct
example of where the entity has some
maintenance activity for the
discretion on determining what constitutes a
Protection System components,
single component is the voltage and current
or all performances of each
sensing devices, where the entity may choose
distinct maintenance activity for
either to designate a full three-phase set of
the Protection System component
such devices or a single device as a single
since the previous scheduled
component.
audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last periodic audit report and all
requested and submitted subsequent compliance records.
1.4. Additional Compliance Information
None.
Draft 5: June 13, 2011
6
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one component
type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.2)
The responsible entity’s PSMP
failed to address one component
type included in the definition of
‘Protection System’ (Part 1.1)
OR
The responsible entity’s PSMP
failed to specify whether two
component types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.2)
The responsible entity’s PSMP
failed to address two component
types included in the definition of
‘Protection System’ (Part 1.1)
OR
The responsible entity’s PSMP
failed to include station batteries in a
time-based program (Part 1.2)
OR
The responsible entity failed to
include all maintenance activities or
intervals relevant for the identified
monitoring attributes specified in
Tables 1-1 through 1-5 and Table 2.
(Part 1.3 and 1.4)
The responsible entity has not
established a PSMP.
OR
The responsible entity’s PSMP
failed to address three or more
component types included in the
definition of ‘Protection System’
(Part 1.1)
OR
The responsible entity failed to
specify whether three or more
component types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.2).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but has:
1) Failed to reduce countable
events to less than 4% within
three years
OR
Failed to annually document
2)
program activities, results,
maintenance dates, or countable
events for 5% or less of
components in any individual
segment
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but has failed
to reduce countable events to less
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but has:
1) Failed to establish the entire
technical justification
described within R2 for the
initial use of the performancebased PSMP
OR
2) Failed to reduce countable
events to less than 4% within
five years
OR
3) Failed to annually document
program activities, results,
maintenance dates, or countable
Draft 5: June 13, 2011
7
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
events for over 5% of
components in any individual
segment
OR
4) Maintained a segment with less
than 60 components
OR
5) Failed to:
• Annually update the list of
components,
OR
• Perform maintenance on the
greater of 5% of the segment
population or 3 components,
OR
• Annually analyze the program
activities and results for each
segment.
R3
The responsible entity has failed to
implement and follow scheduled
program on 5% or less of total
Protection System components.
OR
The responsible entity has failed to
initiate resolution on 5% or less of
identified maintenance correctable
issues.
Draft 5: June 13, 2011
The responsible entity has failed to
implement and follow scheduled
program on greater than 5%, but no
more than 10% of total Protection
System components
OR
The responsible entity has failed to
initiate resolution on greater than
5%, but less than or equal to 10% of
identified maintenance correctable
issues.
The responsible entity has failed to
implement and follow scheduled
program on greater than 10%, but no
more than 15% of total Protection
System components
OR
The responsible entity has failed to
initiate resolution on greater than
10%, but less than or equal to 15%
of identified.
8
The responsible entity has failed to
implement and follow scheduled
program on greater than 15% of
total Protection System components
OR
The responsible entity has failed to
initiate resolution on greater than
15% of identified maintenance
correctable issues.
Standard PRC-005-2 – Protection System Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — February
2011.
Version History
Version
Date
Action
2
TBD
Complete revision, absorbing maintenance
requirements from PRC-005-1, PRC-008-0,
PRC-011-0, PRC-017
Draft 5: June 13, 2011
Change Tracking
Complete revision
9
Standard PRC-005-2 – Protection System Maintenance
Table 1-1
Component Type - Protective Relay
Component Attributes
Maximum
Maintenance
Interval 1
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
• Test and, if necessary calibrate
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
• Verify acceptable measurement of power system input values.
Verify:
Monitored microprocessor protective relay with the following:
• Settings are as specified.
• Internal self diagnosis and alarming (see Table 2).
• Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
12 calendar
years
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values.
• Alarming for power supply failure (see Table 2).
1
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
Draft 5: June 13, 2011
10
Standard PRC-005-2 – Protection System Maintenance
Monitored microprocessor protective relay with preceding row attributes
and the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive
error. (See Table 2)
• Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure. (See Table 2)
12 calendar
years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Alarming for change of settings. (See Table 2)
Table 1-2
Component Type - Communications Systems
Component Attributes
Maximum
Maintenance
Interval
3 calendar
months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function. (See Table 2)
Draft 5: June 13, 2011
6 calendar
years
12 calendar
years
Maintenance Activities
Verify that the communications system is functional.
Verify that the channel meets performance criteria pertinent to
the communications technology applied (e.g signal level,
reflected power, or data error rate).
Verify essential signals to and from other Protection System
components.
Verify that the channel meets performance criteria pertinent to
the communications technology applied (e.g signal level,
reflected power, or data error rate).
Verify essential signals to and from other Protection System
components.
11
Standard PRC-005-2 – Protection System Maintenance
Any communications system with continuous monitoring or periodic
automated testing for the performance of the channel using criteria pertinent
to the communications technology applied (e.g. signal level, reflected power,
or data error rate, and alarming for excessive performance degradation). (See
Table 2)
No periodic
maintenance
specified
None.
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value as measured by the microprocessor relay to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Draft 5: June 13, 2011
Maximum
Maintenance
Interval
Maintenance Activities
12 calendar years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
12
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
18 Calendar
Months
Protection System Station dc supply for distribution breakers
for UFLS or UVLS are excluded (see Table 1-4(e)).
18 Calendar
Months
-or6 Calendar Years
Draft 5: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
• Physical condition of battery rack
Verify that the station battery can perform as designed by evaluating
the measured cell/unit internal ohmic values to station battery baseline.
-orVerify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the
entire battery bank.
13
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Months
-or3 Calendar Years
Draft 5: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
• Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Physical condition of battery rack
Verify that the station battery can perform as designed by evaluating
the measured cell/unit internal ohmic values to station battery baseline.
-orVerify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the
entire battery bank
14
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Years
Draft 5: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells.
• Physical condition of battery rack
Verify that the station battery can perform as designed by conducting a
performance service, or modified performance capacity test of the
entire battery bank.
15
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Protection System Station dc supply for distribution breakers
for UFLS, UVLS and SPS are excluded (see Table 1-4(e)).
6 Calendar Years
Draft 5: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
Condition of non-battery based dc supply
Verify that the dc supply can perform as designed when ac power is not
present.
16
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Device
Component Attributes
Any Protection System dc supply for tripping only non-BES
interrupting devices as part of a UFLS, UVLS or SPS system
and not having monitoring attributes of Table 1-4(f).
Draft 5: June 13, 2011
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify:
• Station dc supply voltage
17
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure. (See Table 2)
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2)
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2)
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2)
No periodic verification of float voltage of battery charger is
required
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2)
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2)
Any lead acid battery based station dc supply with internal
ohmic value monitoring, and evaluating present values relative
to baseline internal ohmic values for every cell/unit (See Table
2)
Any Valve Regulated Lead-Acid (VRLA) station battery with
monitoring and alarming of each cell/unit internal Ohmic
value. (See Table 2)
Draft 5: June 13, 2011
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
No periodic verification of the intercell and terminal
connection resistance is required.
.No periodic measurement and evaluation relative to baseline
of battery cell/unit internal ohmic values is required to verify
the station battery can perform as designed
.
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA battery is required.
18
Standard PRC-005-2 – Protection System Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Note: Table requirements apply to all Control Circuitry components of Protection Systems, UVLS and UFLS Systems, and SPSs except as
noted.
Component Attributes
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (excluding UFLS or UVLS systems).
Trip coils of circuit breakers and interrupting devices in UFLS or UVLS
systems.
Maximum
Maintenance
Interval
6 calendar
years
No periodic
maintenance
specified
Maintenance Activities
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
None.
Electromechanical lockout and/or tripping auxiliary devices which are directly
in a trip path from the protective relay to the interrupting device trip coil.
6 calendar
years
Verify electrical operation of electromechanical trip and
auxiliary devices.
Unmonitored control circuitry associated with protective functions.
12 calendar
years
Verify all paths of the control and trip circuits.
Control circuitry whose continuity and energization or ability to operate are
monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Draft 5: June 13, 2011
19
Standard PRC-005-2 – Protection System Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance activities are
subject to the following maintenance requirements
Maximum
Component Attributes
Maintenance
Maintenance Activities
Interval
Any alarm path through which alarms in Tables 1-1 through 1-5 are conveyed
from the alarm origin to the location where corrective action can be initiated,
and not having all the attributes of the “Alarm Path with monitoring” category
below.
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of DETECTION to a location where
corrective action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 5: June 13, 2011
No periodic
maintenance
specified
No periodic maintenance specified.
20
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
components included in each designated
segment of the Protection System
component population, with a minimum
segment population of 60 components.
Segment – Protection Systems or components
of a consistent design standard, or a
particular model or type from a single
manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
segment. A segment must contain at least
sixty (60) individual components.
2. Maintain the components in each segment
according to the time-based maximum
allowable intervals established in Tables
1-1 through 1-5 until results of
maintenance activities for the segment are
available for a minimum of 30 individual components of the segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events
for each included component.
Countable Event – A component which has failed
4. Analyze the maintenance program
activities and results for each segment to
determine the overall performance of the
segment and develop maintenance
intervals.
and requires repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5 which requires corrective
action, or a Misoperation attributed to hardware
failure or calibration failure. Misoperations due
to product design errors, software errors, relay
settings different from specified settings,
Protection System component configuration
errors, or Protection System application errors
are not included in Countable Events.
5. Determine the maximum allowable
maintenance interval for each segment
such that the segment experiences
countable events on no more than 4% of
the components within the segment, for
the greater of either the last 30
components maintained or all components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
Draft 5: June 13, 2011
21
Standard PRC-005-2 – Protection System Maintenance
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
5. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
Draft 5: June 13, 2011
22
Standard PRC-005-2 — Protection System Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approves SAR for posting on June 5, 2007.
2. The SAR was posted for comment from June 11, 2007–July 10, 2007.
3. The SC approves development of the standard on August 13, 2007.
4. First posting of revised standard on July 24, 2009.
5. Second posting of revised standard on June 11, 2010
6. Third posting of revised standard on November 17, 2010
7. Fourth posting of revised standard on April 13, 2011
Description of Current Draft:
This is the fourifth draft of the Standard. This standard merges previous standards PRC-005-1, PRC-0080, PRC-011-0, and PRC-017-0. It also addresses FERC comments from Order 693, and addresses
observations from the NERC System Protection and Control Task Force, as presented in NERC SPCTF
Assessment of Standards: PRC-005-1 — Transmission and Generation Protection System Maintenance
and Testing, PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs, PRC011-0 — UVLS System Maintenance and Testing, PRC-017-0 — Special Protection System Maintenance
and Testing.
Future Development Plan:
Anticipated Actions
1. Post for combined 30-day comment and ballot.
Anticipated Date
1-April 12July 5 – August 4, 2011
2. Conduct successive ballot
May 2 – May 12July 26 – August 4,
2011
May 16 – June 3August 4 –
September 6, 2011
3. Drafting Team Responds to Comments
Draft 4
PRC-005-2 – April 125: June 13, 2011
1
Standard PRC-005-2 — Protection System Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Restore — Return malfunctioning components to proper operation.
Protection System (NERC Board of Trustees Approved Definition)
•
•
•
•
•
Protective relays which respond to electrical quantities,
communications systems necessary for correct operation of protective functions,
voltage and current sensing devices providing inputs to protective relays,
station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
The following terms are defined for use only within PRC-005-2, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Maintenance Correctable Issue – Failure of a component to operate within design parameters such that
itthe deficiency cannot be restored to functional order by repair or calibrationcorrected during the
performance of the initial on-sitemaintenance activity. Therefore this issue requires follow-up corrective
action.
Segment – Protection Systems or components of a consistent design standard, or a particular model or
type from a single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60) individual
components.
Component Type - Any one of the five specific elements of the Protection System definition.
Component – A component is any individual discrete piece of equipment included in a Protection
System, including but not limited to a protective relay or current sensing device. The designation of what
constitutes a control circuit component is very dependent upon how an entity performs and tracks the
Draft 4
PRC-005-2 – April 125: June 13, 2011
2
Standard PRC-005-2 — Protection System Maintenance
testing of the control circuitry. Some entities test their control circuits on a breaker basis whereas others
test their circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit components. Another example of where the entity has some
discretion on determining what constitutes a single component is the voltage and current sensing devices,
where the entity may choose either to designate a full three-phase set of such devices or a single device as
a single component.
Countable Event – A component which has failed and requires repair or replacement, any condition
discovered during the verificationmaintenance activities in Tables 1-1 through 1-5 which requires
corrective action, or a Misoperation attributed to hardware failure or calibration failure. Misoperations
due to product design errors, software errors, relay settings different from specified settings, Protection
System component configuration errors, or Protection System application errors are not included in
Countable Events.
Draft 4
PRC-005-2 – April 125: June 13, 2011
3
Standard PRC-005-2 — Protection System Maintenance
A. Introduction
1.
Title:
Protection System Maintenance
2.
Number:
PRC-005-2
3.
Purpose:
To ensure all transmissiondocument and generationimplement programs for the
maintenance of all Protection Systems affecting the reliability of the Bulk Electric System
(BES) are maintainedso that these Protection Systems are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owners
4.1.2
Generator Owners
4.1.3
Distribution Providers
4.2. Facilities:
4.2.1
Protection Systems designed to provide protectionthat are installed for the
purpose of detecting faults on BES Element(s).Elements (lines, buses,
transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via
generator lockout or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for generator-connected station service transformers for
generators that are part of the BES.
5.
(Proposed) Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems designed to
provide protection for BES Element(s). The PSMP shall: [identified in Section 4.2. Violation
Risk Factor: Medium] [Time Horizon: Long Term Planning]
The PSMP shall:
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PRC-005-2 – April 125: June 13, 2011
4
Standard PRC-005-2 — Protection System Maintenance
1.1. Address all Protection System component types.
1.2. Identify which maintenance method (time-based, performance-based (per PRC-005
Attachment A), or a combination) is used to address each Protection System component
type. All batteries associated with the station dc supply component type of a Protection
System shall be included in a time-based program as described in Table 1-4.
1.3. Identify the associated maintenance intervals for time-based programs, to be no less
frequent than the intervals established in
Table 1-1 through 1-5 and Table 2.
1.4. Include all applicable monitoring attributes
and related maintenance activities applied
to each Protection System component type
consistent with the maintenance intervals
specified in Tables 1-1 through 1-5 and
Table 2.
R2. Each Transmission Owner, Generator Owner,
Maintenance Correctable Issue Failure of a component to operate
within design parameters such that the
deficiency cannot be corrected during the
performance of the maintenance activity.
Therefore this issue requires follow-up
corrective action.
and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall
follow the procedure established in PRC-005
Attachment A to establish and maintain its
performance-based intervals. [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement and
follow its PSMP and initiate resolution of any identified maintenance correctable issues.
[Violation Risk Factor: High] [Time Horizon: Operations Planning]
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a current or
updated documented Protection System Maintenance Program that addresses all component
types of its Protection Systems, as required by Requirement R1. For each Protection System
component type, the documentation shall include the type of maintenance program applied
(time-based, performance-based, or a combination of these maintenance methods),
maintenance activities, maintenance intervals, and, for component types that use monitoring to
extend the intervals, the appropriate monitoring attributes as specified in Requirement R1,
Parts 1.1 through 1.4.
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses a
performance-based maintenance program shall have evidence that its current performancebased maintenance program is in accordance with Requirement R2, which may include but is
not limited to equipment lists, dated maintenance records, and dated analysis records and
results that its current performance-based maintenance program is in accordance with
Requirement R2.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
which may include but not limited to dated maintenance records, dated maintenance
summaries, dated check-off lists, dated inspection records, or
dated work orders as evidence that it has implemented the
Component Type - Any one of
Protection System Maintenance Program and initiated
the five specific elements of the
resolution of identified Maintenance Correctable Issues in
Protection System definition.
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PRC-005-2 – April 125: June 13, 2011
5
Standard PRC-005-2 — Protection System Maintenance
accordance with Requirement R3., which may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Transmission Owner,
Generator Owner, and
Distribution Provider shall each
keep data or evidence to
demonstrate compliance as
identified below unless directed
by its Compliance Enforcement
Authority to retain specific
evidence for a longer period of
time as part of an investigation.
For Requirement R1, the
Transmission Owner, Generator
Owner, and Distribution Provider
shall each keep its current dated
Protection System Maintenance
Program including the
documentation that specifies the
type of maintenance program
applied for each Protection
System component type.
Component – A component is any individual
discrete piece of equipment included in a
Protection System, including but not limited to
a protective relay or current sensing device.
The designation of what constitutes a control
circuit component is very dependent upon how
an entity performs and tracks the testing of the
control circuitry. Some entities test their
control circuits on a breaker basis whereas
others test their circuitry on a local zone of
protection basis. Thus, entities are allowed
the latitude to designate their own definitions
of control circuit components. Another
example of where the entity has some
discretion on determining what constitutes a
single component is the voltage and current
sensing devices, where the entity may choose
either to designate a full three-phase set of
such devices or a single device as a single
component.
For Requirement R2 and Requirement R3, the Transmission Owner, Generator Owner,
and Distribution Provider shall each keep documentation of the two most recent
performances of each distinct maintenance activity for the Protection System
components, or all performances of each distinct maintenance activity for the Protection
System component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last periodic audit report and all
requested and submitted subsequent compliance records.
Draft 4
PRC-005-2 – April 125: June 13, 2011
6
Standard PRC-005-2 — Protection System Maintenance
1.4. Additional Compliance Information
None.
Draft 4
PRC-005-2 – April 125: June 13, 2011
7
Standard PRC-005-2 — Protection System Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one component
type is being addressed by timebased or performance-based
maintenance., or a combination of
both. (Part 1.2)
The responsible entity’s PSMP
failed to address one component
type included in the definition of
‘Protection System’ (Part 1.1)
OR
The responsible entity’s PSMP
failed to specify whether two
component types are being
addressed by time-based or
performance-based maintenance., or
a combination of both. (Part 1.2)
The responsible entity’s PSMP
failed to address two component
types included in the definition of
‘Protection System’ (Part 1.1)
OR
The responsible entity’s PSMP
failed to include station batteries in a
time-based program (Part 1.2)
OR
The responsible entity failed to
include all maintenance activities or
intervals relevant for the identified
monitoring attributes specified in
Tables 1-1 through 1-5 and Table 2.
(Part 1.3 and 1.4)
The responsible entity has not
established a PSMP.
OR
The responsible entity’s PSMP
failed to address three or more
component types included in the
definition of ‘Protection System’
(Part 1.1)
OR
The responsible entity failed to
specify whether three or more
component types are being
addressed by time-based or
performance-based maintenance.,
or a combination of both. (Part 1.2).
R2
Entity has Protection System
elements in aThe responsible entity
uses performance-based maintenance
intervals in its PSMP but has:
1) Failed to reduce countable
events to less than 4% within
three years
OR
Failed to annually document
2)
program activities, results,
maintenance dates, or countable
events for 5% or less of
components in any individual
segment
OR
3) Maintained a segment with 54-59
NA
Entity has Protection System
elements in aThe responsible entity
uses performance-based
maintenance intervals in its PSMP
but has failed to reduce countable
events to less than 4% within four
years.
Entity has Protection System
components in aThe responsible
entity uses performance-based
maintenance intervals in its PSMP
but has:
1) Failed to establish the entire
technical justification
described within R3 and
Attachment AR2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce countable
events to less than 4% within
five years
OR
Draft 4
PRC-005-2 – April 125: June 13, 2011
8
Standard PRC-005-2 — Protection System Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
components or containing
different manufacturers.
R3
Draft 4
The responsible entity has failed to
completeimplement and follow
scheduled program on 5% or less of
total Protection System components.
OR
The responsible entity has failed to
initiate resolution on 5% or less of
identified maintenance correctable
issues.
PRC-005-2 – April 125: June 13, 2011
Severe VSL
3) Failed to annually document
program activities, results,
maintenance dates, or countable
events for over 5% of
components in any individual
segment
OR
4) Maintained a segment with less
than 5460 components
OR
5) Failed to:
• Annually update the list of
components,
OR
• Perform maintenance on the
greater of 5% of the segment
population or 3 components,
OR
• Annually analyze the program
activities and results for each
segment.
The responsible entity has failed to
completeimplement and follow
scheduled program on greater than
5%, but no more than 10% of total
Protection System components
OR
The responsible entity has failed to
initiate resolution on greater than
5%, but less than or equal to 10% of
identified maintenance correctable
issues.
The responsible entity has failed to
completeimplement and follow
scheduled program on greater than
10%, but no more than 15% of total
Protection System components
OR
The responsible entity has failed to
initiate resolution on greater than
10%, but less than or equal to 15%
of identified.
9
The responsible entity has failed to
completeimplement and follow
scheduled program on greater than
15% of total Protection System
components
OR
The responsible entity has failed to
initiate resolution on greater than
15% of identified maintenance
correctable issues.
Standard PRC-005-2 – Protection System Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — February
2011.
Version History
Version
Date
Action
2
TBD
Complete revision, absorbing maintenance
requirements from PRC-005-1, PRC-008-0,
PRC-011-0, PRC-017
Draft 3: November 17, 20105: June 13, 2011
Change Tracking
Complete revision
10
Standard PRC-005-2 – Protection System Maintenance
Table 1-1
Component Type - Protective Relay
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval 1
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
• Test and, if necessary calibrate
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
• Verify acceptable measurement of power system input values.
Verify:
Monitored microprocessor protective relay with the following:
• Settings are as specified.
• Internal self diagnosis and alarming. (see Table 2).
• Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics (see Table
2)..
12 calendar
years
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values.
• Alarming for power supply failure (see Table 2).
1
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
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11
Standard PRC-005-2 – Protection System Maintenance
Monitored microprocessor protective relay with preceding row attributes
and the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive
error. (See Table 2)
• Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure. (See Table 2)
12 calendar
years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Alarming for change of settings. (See Table 2)
Table 1-2
Component Type - Communications Systems
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
3 calendar
months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function. (See Table 2)
Draft 3: November 17, 20105: June 13, 2011
6 calendar
years
12 calendar
years
Maintenance Activities
Verify that the communications system is functional.
Verify that the channel meets performance criteria pertinent to
the communications technology applied (e.g signal level,
reflected power, or data error rate).
Verify essential signals to and from other Protection System
components.
Verify that the channel meets performance criteria pertinent to
the communications technology applied (e.g signal level,
reflected power, or data error rate).
Verify essential signals to and from other Protection System
components.
12
Standard PRC-005-2 – Protection System Maintenance
Any communications system with continuous monitoring or periodic
automated testing for the performance of the channel using criteria pertinent
to the communications technology applied (e.g. signal level, reflected power,
or data error rate, and alarming for excessive performance degradation). (See
Table 2)
No periodic
maintenance
specified
None.
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Note: Table requirements apply to all components of Protection Systems, UVLS and UFLS Systems, and SPSs except as noted.
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value as measured by the microprocessor relay to an
independent ac measurement source, with alarming for unacceptable
error or failure. (see Table 2).
Draft 3: November 17, 20105: June 13, 2011
Maximum
Maintenance
Interval
Maintenance Activities
12 calendar years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
13
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(a)
Component Type -– Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Protection System Station dc supply withusing Vented LeadAcid (VLA) batteries not having monitoring attributes of
Table 1-4(f).
18 Calendar
Months
Protection System Station dc supply for distribution breakers
for UFLS or UVLS are excluded (see Table 1-4(e)).
18 Calendar
Months
-or6 Calendar Years
Draft 3: November 17, 20105: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
• Physical condition of battery rack
Verify that the station battery can perform as designed by evaluating
the measured cell/unit internal ohmic values to station battery baseline.
-orVerify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the
entire battery bank.
14
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(b)
Component Type -– Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Months
-or3 Calendar Years
Draft 3: November 17, 20105: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
• Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Physical condition of battery rack
Verify that the station battery can perform as designed by evaluating
the measured cell/unit internal ohmic values to station battery baseline.
-orVerify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the
entire battery bank
15
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(c)
Component Type -– Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Station dc supply for distribution breakers for UFLS or UVLS
are excluded (see Table 1-4(e)).
18 Calendar
Months
6 Calendar Years
Draft 3: November 17, 20105: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells.
• Physical condition of battery rack
Verify that the station battery can perform as designed by conducting a
performance service, or modified performance capacity test of the
entire battery bank.
16
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(d)
Component Type -– Protection System Station dc Supply Using Non Battery Based Energy Storage
Component Attributes
Maximum
Maintenance
Interval
3 Calendar Months
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Protection System Station dc supply for distribution breakers
for UFLS or, UVLS and SPS are excluded (see Table 1-4(e)).
6 Calendar Years
Draft 3: November 17, 20105: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
Condition of non-battery based dc supply
Verify that the dc supply can perform as designed when ac power is not
present.
17
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(e)
Component Type -– Protection System Station dc Supply for Distribution Breakersnon-BES Interrupting Device
Component Attributes
Maximum
Maintenance
Interval
Any Protection System dc supply for tripping only distribution
breakersnon-BES interrupting devices as part of a UFLS or,
UVLS system, or SPS system and not having monitoring
attributes of Table 1-4(f).
When control
circuits are verified
(See Table 1-5)
Draft 3: November 17, 20105: June 13, 2011
Maintenance Activities
Verify:
• Station dc supply voltage
18
Standard PRC-005-2 – Protection System Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure. (See Table 2)
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2)
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2)
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply. (See Table 2)
No periodic verification of float voltage of battery charger is
required
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2)
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2)
Any lead acid battery based station dc supply with internal
ohmic value monitoring, and alarming of internal
Ohmicevaluating present values of every cell (if available for
measurement) or each unit and alarming when any cell/unit
deviates by an unacceptable value from therelative to baseline
internal ohmic value. values for every cell/unit (See Table 2)
Any Valve Regulated Lead-Acid (VRLA) station battery with
monitoring and alarming of each cell/unit internal Ohmic
value. (See Table 2)
Draft 3: November 17, 20105: June 13, 2011
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
No periodic verification of the intercell and terminal
connection resistance is required.
.No periodic measurement and comparisonevaluation relative
to baseline of battery cell/unit internal ohmic values for
VRLA batteries and VLA batteries where the cells are not
visible areis required. to verify the station battery can perform
as designed
.
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA battery is required.
19
Standard PRC-005-2 – Protection System Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Note: Table requirements apply to all Control Circuitry components of Protection Systems, UVLS and UFLS Systems, and SPSs except as
noted.
Component Attributes
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (excluding UFLS or UVLS systems).
Trip coils of circuit breakers and interrupting devices in UFLS or UVLS
systems.
Maximum
Maintenance
Interval
6 calendar
years
No periodic
maintenance
specified
Maintenance Activities
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
None.
Electromechanical lockout and/or tripping auxiliary devices which are directly
in a trip path from the protective relay to the interrupting device trip coil.
6 calendar
years
Verify electrical operation of electromechanical trip and
auxiliary devices.
Unmonitored control circuitry associated with protective functions.
12 calendar
years
Verify all paths of the control and trip circuits.
Control circuitry whose continuity and energization or ability to operate are
monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
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20
Standard PRC-005-2 – Protection System Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance activities are
subject to the following maintenance requirements
Maximum
Component Attributes
Maintenance
Maintenance Activities
Interval
Any alarm path through which alarms in Tables 1-1 through 1-5 are conveyed
from the alarm origin to the location where corrective action can be initiated,
and not having all the attributes of the “Alarm Path with monitoring” category
below.
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of DETECTION to a location where
corrective action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 3: November 17, 20105: June 13, 2011
No periodic
maintenance
specified
No periodic maintenance specified.
21
Standard PRC-005-2 – Protection System Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
components included in each designated
segment of the Protection System
component population, with a minimum
segment population of 60 components.
Segment – Protection Systems or components
of a consistent design standard, or a
particular model or type from a single
manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
segment. A segment must contain at least
sixty (60) individual components.
2. Maintain the components in each segment
according to the time-based maximum
allowable intervals established in Tables
1-1through1 through 1-5 until results of
maintenance activities for the segment are
available for a minimum of 30 individual components of the segment.
3. Document the maintenance program activities and results for each segment, including
maintenance dates and countable events
for each included component.
Countable Event – A component which has failed
4. Analyze the maintenance program
activities and results for each segment to
determine the overall performance of the
segment and develop maintenance
intervals.
and requires repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5 which requires corrective
action, or a Misoperation attributed to hardware
failure or calibration failure. Misoperations due
to product design errors, software errors, relay
settings different from specified settings,
Protection System component configuration
errors, or Protection System application errors
are not included in Countable Events.
5. Determine the maximum allowable
maintenance interval for each segment
such that the segment experiences
countable events on no more than 4% of
the components within the segment, for
the greater of either the last 30
components maintained or all components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System components and segments and/or
description if any changes occur within the segment.
2. Perform maintenance on the greater of 5% of the components (addressed in the
performance based PSMP) in each segment or 3 individual components within the
segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
segment to determine the overall performance of the segment.
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22
Standard PRC-005-2 – Protection System Maintenance
4. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
5. Using the prior year’s data, determine the maximum allowable maintenance interval for
each segment such that the segment experiences countable events on no more than 4% of
the components within the segment, for the greater of either the last 30 components
maintained or all components maintained in the previous year.
6. If the components in a Protection System segment maintained through a performancebased PSMP experience 4% or more countable events, develop, document, and
implement an action plan to reduce the countable events to less than 4% of the segment
population within 3 years.
Draft 3: November 17, 20105: June 13, 2011
23
Implementation Plan for PRC-005-02
Standards Involved:
• Approval:
o PRC-005-2 – Protection System Maintenance and Testing
•
Retirements (phased to coincide with each entity’s implementation of PRC-005-2 as specified in
the Implementation Plan for Requirements R1 through R3 later in this document):
o PRC-005-1 – Transmission and Generation Protection System Maintenance and Testing
o PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding
Equipment Maintenance Program
o PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
o PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
• Revised definition of “Protection System”
Background:
The Implementation Plan reflects consideration of the following:
1. The requirements set forth in the proposed standard establish maximum allowable maintenance
intervals for the first time. The established maximum allowable intervals may be shorter than those
currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the proposed
standard, it is unrealistic for those entities to be immediately in compliance with the new intervals.
Further, entities should be allowed to become compliant in such a way as to facilitate a continuing
maintenance program.
3. Entities that have previously been performing maintenance within the newly specified intervals may
not have all the documentation needed to demonstrate compliance with all of the maintenance
activities specified.
4. The Implementation Schedule set forth in this document requires that entities develop their revised
Protection System Maintenance Program within 12 months following applicable regulatory approvals,
or in those jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter twelve months following Board of Trustees adoption.
5. The Implementation Schedule set forth in this document further requires implementation of the
revised Protection System Maintenance Program in roughly equally-distributed steps over the
maintenance intervals prescribed for each respective maintenance activity in order that entities may
implement this standard in a systematic method that facilitates an effective ongoing Protection
System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall follow the protection
system maintenance and testing program it used to perform maintenance and testing to comply with PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 (for the Protection System components identified in
PRC-005-2 Tables 1-1 through 1-5) until that Transmission Owner, Generator Owner or Distribution
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Provider meets initial compliance for maintenance of the same Protection System component, in
accordance with the phasing specified below.
For audits that are conducted during the time period when entities are modifying their existing protection
system maintenance and testing programs to become compliant with the maintenance activities and
intervals specified in PRC-005-2, each responsible entity must be prepared to identify:
•
All of its applicable protection system components.
•
For each component, whether maintenance of that component is being addressed according to
PRC-005-2 or under PRC-005-1, PRC-008-0, PRC-011-0, or PRC-017-0.
•
Evidence that each component has been maintained under the relevant requirements.
Retirement of Existing Standards:
The existing Standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired upon
regulatory approval of PRC-005-2.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 and R3 which use this defined term.
Implementation Plan for Requirement R1:
•
Entities shall be 100% compliant on the first day of the first calendar quarter twelve (12) months
following applicable regulatory approvals, or in those jurisdictions where no regulatory approval
is required, on the first day of the first calendar quarter twenty-one (21) months following Board
of Trustees adoption.
Implementation Plan for Requirements R2 and R3:
1. For Protection System components with maximum allowable intervals of less than 1 year, as
established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 15
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 24 months
following Board of Trustees adoption.
2. For Protection System components with maximum allowable intervals 1 year or more, but 2 years
or less, as established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 36
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 48 months
following Board of Trustees adoption.
3. For Protection System components with maximum allowable intervals of 3 years, as established
in Tables 1-1 through 1-5:
Draft 5: June 13, 2011
2
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 24
months following applicable regulatory approval (or, for generating plants with
scheduled outage intervals exceeding two years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required,
on the first day of the first calendar quarter 36 months following Board of Trustees
adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 36
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 48 months
following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 48
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 60 months
following Board of Trustees adoption.
4. For Protection System components with maximum allowable intervals of 6 years, as established
in Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 36
months following applicable regulatory approval (or, for generating plants with
scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required,
on the first day of the first calendar quarter 48 months following Board of Trustees
adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 60
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 72 months
following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 84
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 96 months
following Board of Trustees adoption.
5. For Protection System components with maximum allowable intervals of 12 years, as established
in Tables 1-1 through 1-5 and Table 2:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 60
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 72 months
following Board of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter
following 108 months following applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter 120
months following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 156
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 168 months
following Board of Trustees adoption.
Draft 5: June 13, 2011
3
Applicability:
This standard applies to the following functional entities:
•
Transmission Owners
•
Generator Owners
•
Distribution Providers
Draft 5: June 13, 2011
4
Implementation Plan for PRC-005-02
Standards Involved:
• Approval:
o PRC-005-2 – Protection System Maintenance and Testing
•
Retirements: (phased to coincide with each entity’s implementation of PRC-005-2 as specified in
the Implementation Plan for Requirements R1 through R3 later in this document):
o PRC-005-1 – Transmission and Generation Protection System Maintenance and Testing
o PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding
Equipment Maintenance Program
o PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
o PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
• Revised definition of “Protection System”
Background:
The Implementation Plan reflects consideration of the following:
1. The requirements set forth in the proposed standard establish maximum allowable maintenance
intervals for the first time. The established maximum allowable intervals may be shorter than those
currently in use by some entities.
2. For entities using longer intervals than the maximum allowable intervals established in the proposed
standard, it is unrealistic for those entities to be immediately in compliance with the new intervals.
Further, entities should be allowed to become compliant in such a way as to facilitate a continuing
maintenance program.
3. Entities that have previously been performing maintenance within the newly specified intervals may
not have all the documentation needed to demonstrate compliance with all of the maintenance
activities specified.
4. The Implementation Schedule set forth in this document requires that entities develop their revised
Protection System Maintenance Program within 12 months following applicable regulatory approvals,
or in those jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter twelve months following Board of Trustees adoption.
5. The Implementation Schedule set forth in this document further requires implementation of the
revised Protection System Maintenance Program in roughly equally-distributed steps over the
maintenance intervals prescribed for each respective maintenance activity in order that entities may
implement this standard in a systematic method that facilitates an effective ongoing Protection
System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall follow the protection
system maintenance and testing program it used to perform maintenance and testing to comply with PRC005-1, PRC-008-0, PRC-011-0, and PRC-017-0 (for the Protection System components identified in
PRC-005-2 Tables 1-1 through 1-5) until that Transmission Owner, Generator Owner or Distribution
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Provider meets initial compliance for maintenance of the same Protection System component, in
accordance with the phasing specified below.
For audits that are conducted during the time period when entities are modifying their existing protection
system maintenance and testing programs to become compliant with the maintenance activities and
intervals specified in PRC-005-2, each responsible entity must be prepared to identify:
•
All of its applicable protection system components.
•
For each component, whether maintenance of that component is still being addressed according to
PRC-005-2 or under PRC-005-1 or is being performed according toPRC-005-2, PRC-008-0,
PRC-011-0, or PRC-017-0.
•
Evidence that each component has been maintained under the relevant requirements.
Retirement of Existing Standards:
The existing Standards PRC-005-1, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired upon
regulatory approval of PRC-005-2.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 and R3 which use this defined term.
Implementation Plan for Requirement R1:
•
Entities shall be 100% compliant on the first day of the first calendar quarter twelve (12) months
following applicable regulatory approvals, or in those jurisdictions where no regulatory approval
is required, on the first day of the first calendar quarter twelvetwenty-one (21) months following
Board of Trustees adoption.
Implementation Plan for Requirements R2 and R3:
1. For Protection System components with maximum allowable intervals of less than 1 year, as
established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 15
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 1524 months
following Board of Trustees adoption.
2. For Protection System components with maximum allowable intervals 1 year or more, but 2 years
or less, as established in Tables 1-1 through 1-5:
a. The entity shall be 100% compliant on the first day of the first calendar quarter 3
calendar years36 months following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 3 calendar years48 months following Board of Trustees adoption.
3. For Protection System components with maximum allowable intervals of 3 years, as established
in Tables 1-1 through 1-5:
Draft 4: April 125: June 13, 2011
2
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 2
calendar years24 months following applicable regulatory approval (or, for generating
plants with scheduled outage intervals exceeding two calendar years, at the conclusion of
the first succeeding maintenance outage), or in those jurisdictions where no regulatory
approval is required, on the first day of the first calendar quarter 2 calendar years36
months following Board of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 3
calendar years following applicable regulatory approval, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter 3 calendar
years following Board of Trustees adoption.
c.b. The entity shall be 100% compliant on the first day of the first calendar quarter 4
calendar years36 months following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 4 calendar years48 months following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 48
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 60 months
following Board of Trustees adoption.
4. For Protection System components with maximum allowable intervals of 6 years, as established
in Tables 1-1 through 1-5:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 3
calendar years36 months following applicable regulatory approval (or, for generating
plants with scheduled outage intervals exceeding two calendarthree years, at the
conclusion of the first succeeding maintenance outage), or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 3 calendar
years48 months following Board of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter 5
calendar years60 months following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 5 calendar years72 months following Board of Trustees adoption.
c. The entity shall be 100% compliant on the first day of the first calendar quarter 7
calendar years84 months following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 7 calendar years96 months following Board of Trustees adoption.
5. For Protection System components with maximum allowable intervals of 12 years, as established
in Tables 1-1 through 1-5 and Table 2:
a. The entity shall be at least 30% compliant on the first day of the first calendar quarter 5
calendar years60 months following applicable regulatory approval, or in those
jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 5 calendar years72 months following Board of Trustees adoption.
b. The entity shall be at least 60% compliant on the first day of the first calendar quarter
following 9 calendar years108 months following applicable regulatory approval, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter 120 months following Board of Trustees adoption.
Draft 4: April 125: June 13, 2011
3
b.c. The entity shall be 100% compliant on the first day of the first calendar quarter 156
months following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 9 calendar
years168 months following Board of Trustees adoption.
c.The entity shall be 100% compliant on the first day of the first calendar quarter 13 calendar
years following applicable regulatory approval, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter 13 calendar
years following Board of Trustees adoption.
Draft 4: April 125: June 13, 2011
4
Applicability:
This standard applies to the following functional entities:
•
Transmission Owners
•
Generator Owners
•
Distribution Providers
Draft 4: April 125: June 13, 2011
5
Project 2007-17 Protection System Maintenance & Testing
New Definition for Approval:
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection System
components are kept in working order and proper operation of malfunctioning components is restored.
A maintenance program for a specific component includes one or more of the following activities:
•
Verify — Determine that the component is functioning correctly.
•
Monitor — Observe the routine in-service operation of the component.
•
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
•
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
•
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
•
Upkeep — Perform routine activities necessary to assure that the component remains in
good working order and implementation of any manufacturer’s hardware and software
service advisories which are relevant to the application of the device.
•
Restore — Return malfunctioning components to proper operation.
PRC-005-2
Protection System
Maintenance
Supplementary Reference & FAQ
Draft
June 2, 2011
Prepared by the
Protection System Maintenance and Testing Standard
Drafting Team
1
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Table of Contents
1.
Introduction and Summary ..................................................................................................... 4
2.
Need for Verifying Protection System Performance .............................................................. 5
2.1 Existing NERC Standards for Protection System Maintenance and Testing ....................... 5
2.2 Protection System Definition ................................................................................................ 6
2.3 Applicability of New Protection System Maintenance Standards ........................................ 6
2.3.1 Frequently Asked Questions: ............................................................................................ 7
2.4 Applicable Relays ................................................................................................................. 8
2.4.1 Frequently Asked Questions: ............................................................................................ 9
3.
Protection Systems Product Generations .............................................................................. 10
4.
Definitions............................................................................................................................. 11
5.
4.1 Frequently Asked Questions: .............................................................................................. 11
Time-Based Maintenance (TBM) Programs ......................................................................... 13
5.1 Maintenance Practices ........................................................................................................ 13
5.1.1 Frequently Asked Questions: .......................................................................................... 15
5.2 Extending Time-Based Maintenance .......................................................................... 16
5.2.1 Frequently Asked Question: ............................................................................................ 17
6.
Condition-Based Maintenance (CBM) Programs ................................................................. 18
6.1 Frequently Asked Questions: .............................................................................................. 19
7. Time-Based Versus Condition-Based Maintenance ............................................................. 20
8.
7.1 Frequently Asked Questions: .............................................................................................. 20
Maximum Allowable Verification Intervals ......................................................................... 25
8.1 Maintenance Tests .............................................................................................................. 25
8.1.1 Table of Maximum Allowable Verification Intervals ..................................................... 25
8.1.2 Additional Notes for Tables 1-1 through 1-5 .................................................................. 27
8.1.3 Frequently Asked Questions: .......................................................................................... 28
8.2 Retention of Records........................................................................................................... 33
8.2.1 Frequently Asked Questions: .......................................................................................... 33
8.3 Basis for Table 1 Intervals .................................................................................................. 35
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .............................. 36
9. Performance-Based Maintenance Process ............................................................................ 38
9.1 Minimum Sample Size........................................................................................................ 39
9.2 Frequently Asked Questions: .............................................................................................. 41
10.
Overlapping the Verification of Sections of the Protection System .................................. 54
10.1 Frequently Asked Question: ............................................................................................. 55
11.
Monitoring by Analysis of Fault Records .......................................................................... 55
Draft 5 June 2, 2011
2
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
11.1 Frequently Asked Question: ............................................................................................. 56
12.
Importance of Relay Settings in Maintenance Programs ................................................... 57
12.1 Frequently Asked Questions: ............................................................................................ 58
13.
Self-Monitoring Capabilities and Limitations ................................................................... 60
13.1 Frequently Asked Question: ............................................................................................. 61
14.
Notification of Protection System Failures ........................................................................ 62
15.
Maintenance Activities ...................................................................................................... 63
15.1 Protective Relays (Table 1-1) ........................................................................................... 63
15.1.1 Frequently Asked Question: .......................................................................................... 64
15.2 Voltage & Current Sensing Devices (Table 1-3) .............................................................. 64
15.2.1 Frequently Asked Questions: ........................................................................................ 65
15.3 Control circuitry associated with protective functions (Table 1-5) .................................. 67
15.3.1 Frequently Asked Questions: ........................................................................................ 68
15.4 Batteries and DC Supplies (Table 1-4) ............................................................................ 69
15.4.1 Frequently Asked Questions: ....................................................................................... 70
15.5 Associated communications equipment (Table 1-2)......................................................... 81
15.5.1 Frequently Asked Questions: ........................................................................................ 82
15.6 Alarms (Table 2) ............................................................................................................... 85
15.6.1 Frequently Asked Question: .......................................................................................... 85
15.7 Examples of Evidence of Compliance .............................................................................. 86
15.7.1 Frequently Asked Questions: ........................................................................................ 86
Yes. ............................................................................................................................................... 87
16. References ............................................................................................................................... 88
Figures ......................................................................................................................................... 89
Figure 1: Typical Transmission System ................................................................................... 89
Figure 2: Typical Generation System ....................................................................................... 90
Appendix B — Protection System Maintenance Standard Drafting Team ............... 95
Draft 5 June 2, 2011
3
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
This supplementary reference to PRC-005-2 is not mandatory and enforceable.
1. Introduction and Summary
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and address various aspects of maintenance and testing of Protection and Control systems.
These standards are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for Protection
Systems, and that these entities must be able to demonstrate they are carrying out such a
program, there are no specifics regarding the technical requirements for Protection System
maintenance programs. Furthermore, FERC Order 693 directed additional modifications
respective to Protection System maintenance programs. PRC-005-2 combines and replaces PRC005, PRC-008, PRC-011 and PRC-017.
Draft 5 June 2, 2011
4
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
2. Need for Verifying Protection System
Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate their
performance until a fault or other power system problem requires that they operate to protect
power system elements, or even the entire Bulk Electric System (BES). Lacking faults, switching
operations or system problems, the Protection Systems may not operate, beyond static operation,
for extended periods. A misoperation - a false operation of a Protection System or a failure of the
Protection System to operate, as designed, when needed - can result in equipment damage,
personnel hazards, and wide area disturbances or unnecessary customer outages. Maintenance or
testing programs are used to determine the performance and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be visited
at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct plausible
age and service related degradation of the Protection System components such that a properly
built and commissioned Protection System will continue to function as designed over its service
life.
Similarly station batteries which are an important part of the station dc supply are not called
upon to provide instantaneous dc power to the Protection System until power is required by the
Protection System to operate circuit breakers or interrupting devices to clear faults or to isolate
equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC Standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC-005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC-005-1 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC-005-2, the definition of Protection System was:
Protective relays, associated communications systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
Draft 5 June 2, 2011
5
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Requirements: The owner shall have a documented maintenance program with test intervals. The
owner must keep records showing that the maintenance was performed at the specified intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
•
Protective relays which respond to electrical quantities,
•
communications systems necessary for correct operation of protective functions,
•
voltage and current sensing devices providing inputs to protective relays,
•
station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
•
control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting faults on BES Elements (lines, buses, transformers,
etc.).”
The drafting team intends that this Standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the element is a BES element then the Protection
System protecting that element should then be included within this Standard. If there is regional
variation to the definition then there will be a corresponding regional variation to the Protection
Systems that fall under this Standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the Standard language should simply be applicable to relays for BES elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions. See
the NERC glossary of terms for the present, in-force, definition. See the applicable regional
reliability organization for any applicable allowed variations.
While this Standard will undergo revisions in the future, this Standard will not attempt to keep
up with revisions to the NERC definition of BES but rather simply make BES Protection
Systems applicable.
Draft 5 June 2, 2011
6
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because
GO’s and TO’s have equipment that is BES equipment. The Standard brings in Distribution
Providers (DP) because depending on the station configuration of a particular substation, there
may be Protection System equipment installed at a non-transmission voltage level (Distribution
Provider equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would
apply to this equipment. An example is underfrequency load-shedding, which is frequently
applied well down into the distribution system to meet PRC-007-0.
As this Standard is intended to replace the existing PRC-005, PRC-008, PRC-011 and PRC-017,
those Standards are used in the construction of this revision of PRC-005-1. Much of the original
intent of those Standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example the original PRC-008 was
constructed quite differently than the original PRC-005. The drafting team agrees with the intent
of this and notes that distributed tripping schemes would have to exhibit multiple failures to trip
before they would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential lock-out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just fault clearing duty and therefore the distribution circuit breakers are
operated at least as frequently as any requirements that might have appeared in this Standard.
Additionally, since this Standard will now replace PRC-011 it will be important to make the
distinction between under-voltage Protection Systems that protect individual loads and
Protection Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had
been applicable under PRC-011 will now be applicable under this revision of PRC-005-1. An
example of an Under-Voltage Load Shedding scheme that is not applicable to this Standard is
one in which the tripping action was intended to prevent low distribution voltage to a specific
load from a transmission system that was intact except for the line that was out of service, as
opposed to preventing a cascading outage or transmission system collapse.
It had been correctly noted that the devices needed for PRC-011 are the very same types of
devices needed in PRC-005.
Thus a Standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems and replace some other Standards at the same time.
2.3.1 Frequently Asked Questions:
What, exactly, is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used
in Reliability Standards, and is not being modified within this draft Standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving only
load with one transmission source are generally not included in this definition.
Draft 5 June 2, 2011
7
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Each Regional Entity implements a definition of the Bulk Electric System that is based on this
NERC definition, in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
Why is Distribution Provider included within the Applicable Entities and as a responsible
entity within several of the requirements? Wouldn’t anyone having relevant facilities be a
Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
We have an Under Voltage Load Shedding (UVLS) system in place that prevents one of our
distribution substations from supplying extremely low voltage in the case of a specific
transmission line outage. The transmission line is part of the BES. Does this mean that our
UVLS system falls within this Standard?
The situation as stated indicates that the tripping action was intended to prevent low distribution
voltage to a specific load from a transmission system that was intact except for the line that was
out of service, as opposed to preventing cascading outage or transmission system collapse.
This Standard is not applicable to this UVLS.
We have a UFLS scheme that sheds the necessary load through distribution-side circuit
breakers and circuit reclosers. Do the trip-test requirements for circuit breakers apply to
our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential lock-out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just fault clearing duty and therefore the distribution circuit breakers are
operated at least as frequently as any requirements that might have appeared in this Standard.
We have a UFLS scheme that, in some locales, sheds the necessary load through non-BES
circuit breakers and occasionally even circuit switchers. Do the trip-test requirements for
circuit breakers apply to our situation?
If your “non-BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements and otherwise would not have been brought into this standard, then the answer is
that there are no trip-test requirements. For these devices that are otherwise non-BES assets,
these tripping schemes would have to exhibit multiple failures to trip before they would prove to
be as significant as (for example) a single failure to trip of a Transmission Protection System Bus
Differential lock-out relay.
2.4 Applicable Relays
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The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this Standard applies are those protective relays that respond to electrical quantities and
provide a trip output to trip coils, dc control circuitry or associated communications equipment.
This definition extends to IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or
trip-free relay) as these devices are tripping relays that respond to the trip signal of the protective
relay that processed the signals from the current and voltage sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration schemes
covered in this Standard?
No. As stated in Requirement R1, this Standard covers protective relays that use measurements
of electrical quantities to determine anomalies and to trip a portion of the BES. Reclosers,
reclosing relays, closing circuits and auto-restoration schemes are used to cause devices to close
as opposed to electrical-measurement relays and their associated circuits that cause circuit
interruption from the BES; such closing devices and schemes are more appropriately covered
under other NERC Standards. There is one notable exception: if a Special Protection System
incorporates automatic closing of breakers, the related closing devices are part of the SPS and
must be tested accordingly.
I use my protective relays only as sources of metered quantities and breaker status for
SCADA and EMS through a substation distributed RTU or data concentrator to the
control center. What are the maintenance requirements for the relays?
This Standard addresses only devices “that are applied on, or are designed to provide protection
for the BES.” Protective relays, providing only the functions mentioned in the question, are not
included.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2-2008 assigns the device number 94 to auxiliary tripping relays. Sudden
pressure relays are assigned device number 63. Sudden pressure relays are excluded from the
Standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded.
My mechanical device does not operate electrically and does not have calibration settings;
what maintenance activities apply?
You must conduct a test(s) to verify the integrity of the trip circuit. This Standard does not cover
circuit breaker maintenance or transformer maintenance. The Standard also does not cover
testing of devices such as sudden pressure relays (63), temperature relays (49), and other relays
which respond to mechanical parameters rather than electrical parameters.
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The Standard specifically mentions auxiliary and lock-out relays; what is an auxiliary
tripping relay?
An auxiliary relay, IEEE Device Number 94, is described in IEEE Standard C37.2-2008 as “A
device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate
tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should
open automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock-out relay, IEEE Device Number 86, is described in IEEE Standard C37.2 as “A device
that trips and maintains the associated equipment or devices inoperative until it is reset by an
operator, either locally or remotely.”
3. Protection Systems Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System, both depends on the technological generation of the relays as well as how long they
have been in service. Unlike many other transmission asset groups, protection and control
systems have seen dramatic technological changes spanning several generations. During the past
20 years, major functional advances are primarily due to the introduction of microprocessor
technology for power system devices such as primary measuring relays, monitoring devices,
control systems, and telecommunications equipment.
Modern microprocessor based relays have six significant traits that impact a maintenance
strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified periodically.
•
Ability to capture fault records showing how the Protection System responded to a fault
in its zone of protection, or to a nearby fault for which it is required not to operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-fault times. The relays can compute values such as MW and
MVAR line flows that are sometimes used for operational purposes such as SCADA.
•
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording, and measurement.
•
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages or from relay front
panel button requests.
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•
Construction from electronic components some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of Battery Chargers, Associated
Communications Equipment, Voltage and Current Measuring Devices and even the control
circuitry (in the form of software-latches replacing lock-out relays, etc).
Any Protection System component can have self-monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which
Protection System components are kept in working order and proper operation of malfunctioning
components is restored. A maintenance program for a specific component includes one or more
of the following activities:
•
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Restore — Return malfunctioning components to proper operation.
4.1 Frequently Asked Questions:
Why does PRC-005-2 not specifically require maintenance and testing procedures as
reflected in the previous Standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2 requires
a documented maintenance program, and is focused on establishing requirements rather than
prescribing methodology to meet those requirements. Between the activities identified in the
tables 1-1 through 1-5 and Table 2 (collectively the “Tables”), and the various components of the
definition established for a “Protection System Maintenance Program”, PRC-005-2 establishes
the activities and time-basis for a Protection System Maintenance Program to a level of detail not
previously required.
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Please clarify what is meant by restore in the definition of maintenance.
The description of “Restore” in the definition of a Protection System Maintenance Program,
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R3 of the Standard does
require that the entity “initiate resolution of any identified maintenance correctable issues”.
Some examples of restoration (or correction of maintenance-correctable issues) include, but are
not limited to, replacement of capacitors in distance relays to bring them to working order;
replacement of relays, or other Protection System components, to bring the Protection System to
working order; upgrade of electromechanical or solid-state protective relays to micro-processor
based relays following the discovery of failed components. Restoration, as used in this context is
not to be confused with Restoration rules as used in system operations. Maintenance activity
necessarily includes both the detection of problems and the repairs needed to eliminate those
problems. This Standard does not identify all of the Protection System problems that must be
detected and eliminated, rather it is the intent of this Standard that an entity determines the
necessary working order for their various devices and keeps them in working order. If an
equipment item is repaired or replaced then the entity can restart the maintenance-time-intervalclock if desired, however the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements; in other words do not discard maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that the
maintenance intervals had been in compliance. For example, a long range plan of upgrades might
lead an entity to ignore required maintenance; retaining the evidence of prior maintenance that
existed before any retirements and upgrades proves compliance with the Standard.
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5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which Protection Systems are maintained or verified
according to a time schedule. The scheduled program often calls for technicians to travel to the
physical site and perform a functional test on Protection System components. However, some
components of a TBM program may be conducted from a remote location - for example, tripping
a circuit breaker by communicating a trip command to a microprocessor relay to determine if the
entire Protection System tripping chain is able to operate the breaker. Similarly, all Protection
System components can have the ability to remotely conduct tests, either on-command or
routinely, the running of these tests can extend the time interval between hands-on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have
been developed from prior experience or manufacturers’ recommendations. The TBM
verification interval is based on a variety of factors, including experience of the particular
asset owner, collective experiences of several asset owners who are members of a country
or regional council, etc. The maintenance intervals are fixed, and may range in number
of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time clock
can be reset for those components.
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•
PBM – Performance-Based Maintenance - intervals are established based on analytical or
historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses
accompanied by adjustments to maintenance intervals are used to justify continued use of
PBM-developed extended intervals when test failures or in-service failures occur
infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from
non-disruptive self monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what parts
are included as part of the self diagnostics. While the term “Condition-BasedMaintenance” (CBM) is no longer used within the Standard itself, it is important to note
that the concepts of CBM are a part of the Standard (in the form of extended time
intervals through status-monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored-basis-time-intervals” existing within the Standard the
explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor based Protection System components that perform continuous selfmonitoring verify correct operation of most components within the device. Selfmonitoring capabilities may include battery continuity, float voltages, unintentional
grounds, the ac signal inputs to a relay, analog measuring circuits, processors and
memory for measurement, protection, and data communications, trip circuit monitoring,
and protection or data communications signals (and many, many more measurements).
For those conditions, failure of a self-monitoring routine generates an alarm and may
inhibit operation to avoid false trips. When internal components, such as critical output
relay contacts, are not equipped with self-monitoring, they can be manually tested. The
method of testing may be local or remote, or through inherent performance of the scheme
during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours or even milliseconds between non-disruptive self monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
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•
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
•
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been
subject to TBM.
•
Region 3: Optimal TBM intervals based on regions 1 and 2.
TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
5.1.1 Frequently Asked Questions:
The Standard seems very complicated, and is difficult to understand. Can it be simplified?
Because the Standard is establishing parameters for condition-based Maintenance (R1) and
Performance-Based Maintenance (R2) in addition to simple time-based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time-based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened time
intervals then it may, as long as the component has the listed monitoring attributes. If an entity
wishes to use historical performance of its Protection System components to perform
Performance-Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the Standard.
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We have an electromechanical (unmonitored) relay that has a trip output to a lockout relay
(unmonitored) which trips our transformer off-line by tripping the transformer’s high-side
and low-side circuit breakers. What testing must be done for this system?
This system is made up of components that are all unmonitored. Assuming a time-based
Protection System maintenance program schedule (as opposed to a Performance-Based
maintenance program), each component must be maintained per the most frequent hands-on
activities listed in the Tables 1-1 through 1-5.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly
established to assure proper functioning of each component of the Protection System, when data
on the reliability of the components is not available other than observations from time-based
maintenance. The following factors may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self monitoring device), then the intervals may be extended or
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manual testing may be eliminated. This is referred to as condition-based maintenance or
CBM. CBM is valid only for precisely the components subject to monitoring. In the case
of microprocessor-based relays, self-monitoring may not include automated diagnostics
of every component within a microprocessor.
•
Previous maintenance history for a group of components of a common type may indicate
that the maintenance intervals can be extended while still achieving the desired level of
performance. This is referred to as Performance-Based Maintenance or PBM. It is also
sometimes referred to as reliability-centered maintenance or RCM, but PBM is used in
this document.
•
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor-based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a fault verifies the trip contact and trip path, but only through
the relays in series that actually operated; one operation of this relay cannot verify correct
calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is not
unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Question:
If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R3) (in essence) state “…shall implement and follow
its PSMP …” if not then actions must be initiated to correct the deviance. The type of corrective
activity is not stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device tested
bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information
available from modern microprocessor-based relays and other intelligent electronic devices
(IEDs) that monitor Protection System elements. These devices generate monitoring information
during normal operation, and the information can be assessed at a convenient location remote
from the substation. The information from these relays and IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
faults and disturbances, metered values, and binary input status reports. Some of these are
available on the device front panel display, but may be available via data communications
ports. Large files of fault information can only be retrieved via data communications.
These results comprise a mass of data that must be further analyzed for evidence of the
operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
1. Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
2. Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems by
incorrect operation before being caught in the next test round. The frequent or continuous
nature of CBM makes the effective verification interval far shorter than any required
TBM maximum interval.
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6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a 24-hour
attended control room. Does this qualify as an extended time interval condition-based
system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels of
monitoring as per Requirement R1.4 of the Standard, is it necessary to provide this
documentation about the device by listing of every component and the specific monitoring
attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible, it
is not necessary. Global statements can be made to document appropriate levels of monitoring
for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are Monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered Monitored and subject to the rows
for monitored equipment of Table 1-4 requirements as all substation dc supply battery
chargers are equipped with dc voltage alarms and ground detection alarms that are sent to the
manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered Monitored
and subject to the rows for monitored equipment of Table 1-4 requirements as all substation
dc supply battery chargers are equipped with dc voltage alarms and ground detection alarms
that are sent to the manned control center. The dc supply battery chargers of Substation X,
Substation Y, and Substation Z are considered Unmonitored and subject to the rows for
unmonitored equipment in Table 1-4 requirements as they are not equipped with ground
detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes, by
global statements of the monitoring attributes of an entire population of component types, or by
some combination of these methods, it should be noted that auditors may request supporting
drawings or other documentation necessary to validate the inclusion of the device(s) within the
appropriate level of monitoring. This supporting background information need not be
maintained within the program document structure but should be retrievable if requested by an
auditor.
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7. Time-Based Versus Condition-Based Maintenance
Time-based and condition-based maintenance programs are both acceptable, if implemented
according to technically sound requirements. Practical programs can employ a combination of
time-based and condition-based maintenance. The Standard requirements introduce the concept
of optionally using condition monitoring as a documented element of a maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability
Standards for the Bulk-Power System, directed NERC to submit a modification to PRC-005-1
that includes a requirement that maintenance and testing of a Protection System must be carried
out within a maximum allowable interval that is appropriate to the type of the Protection System
and its impact on the reliability of the Bulk Power System. Accordingly, this Supplementary
Reference Paper refers to the specific maximum allowable intervals in PRC-005-2. The defined
time limits allow for longer time intervals if the maintained component is monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay between
the moment of a protection failure and time the Protection System owner knows about it, for the
monitored segments of the Protection System. In some cases, the verification is practically
continuous - the time interval between verifications is minutes or seconds. Thus, technically
sound, condition-based verification, meets the verification requirements of the FERC order even
more effectively than the strictly time-based tests of the same system components.
The result is that:
This NERC Standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection Systems to
reduce the need for periodic site visits and invasive testing of components by on-site technicians.
This periodic testing must be conducted within the maximum time intervals specified in Tables
1-1 through 1-5 and Table 2 of PRC-005-2.
7.1 Frequently Asked Questions:
What is a Calendar Year?
Calendar Year - January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval”, the next event would have
to occur on or before December 31, 2010.
Please provide an example of “3 Calendar Months”.
If a maintenance activity is described as being needed every 3 Calendar Months then it is
performed in a (given) month and due again 3 months later. For example a battery bank is
inspected in month number 1 then it is due again in month number 4. And specifically consider
that you perform your battery inspection on January 3, 2010 then it must be inspected again
before the end of April. Another example could be that a 3-month inspection was performed in
January is due in April, but if performed in March (instead of April) would still be due three
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months later therefore the activity is due again June. Basically every “3 Calendar Months” means
to add 3 months from the last time the activity was performed.
Please provide an example of the unmonitored versus other levels of monitoring available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no alarm
output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits must
alert, within 24 hours, a location wherein corrective action can be initiated. This location might
be, but not limited to an Operations Center, Dispatch Office, Maintenance Center or even a
portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any given
scheme, substation or plant; there can also be a combination of monitored and unmonitored
components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
•
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A Vented Lead-Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
•
A circuit breaker with a trip coil and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2 , the
particular components have maximum activity intervals of:
Every 3 calendar months, verify:
Electrolyte level (station dc supply voltage and unintentional ground detection is being
maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
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Battery cell-to-cell resistance (where available to measure)
Every 6 calendar years, perform/verify the following:
Battery performance test (if ohmic tests are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays and auxiliary relays, electrical operation of
electromechanical trip and auxiliary devices
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to proper
functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
•
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A Vented Lead-Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
•
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (“Maximum
Allowable Testing Intervals and Maintenance Activities”) and Table 2 (“Alarming Paths and
Monitoring”), the particular components have maximum activity intervals of:
Every 3 calendar months, verify:
Electrolyte level (Station dc supply voltage and unintentional ground detection is being
maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
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Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Every 6 calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper functioning
of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays and auxiliary relays, electrical operation of
electromechanical trip and auxiliary devices
Battery performance test (if ohmic tests are not opted)
Every 12 calendar years, verify the following:
Verify that current and voltage signal values are provided to the protective relays
Verify that Protection System component monitoring for the battery system signals are
conveyed to a location where corrective action can be initiated
Verify all paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices Example #3: A
combination of monitored and unmonitored components within a given Protection
System might be:
•
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
•
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
•
Vented Lead-Acid battery without any alarms connected to SCADA
(unmonitored)
•
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (“Maximum Allowable
Testing Intervals and Maintenance Activities”) and Table 2 (“Alarming Paths and
Monitoring”), the particular components shall have maximum activity intervals of:
Every 3 calendar months, verify/inspect the following:
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Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Cell condition of all individual battery cells (where visible)
Every 6 calendar years, perform/verify the following:
Battery performance test (if ohmic tests are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays and auxiliary relays, electrical operation of
electromechanical trip and auxiliary devices
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to proper
functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of Protection
System components. Condition-Based Maintenance is a valuable asset to improve reliability.
Can all components in a Protection System be monitored?
No. For some components in a Protection System, monitoring will not be relevant. For example
a battery will always need some kind of inspection.
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We have a 30 year old oil circuit breaker with a red indicating lamp on the substation relay
panel that is illuminated only if there is continuity through the breaker trip coil. There is
no SCADA monitor or relay monitor of this trip coil. The line protection relay package
that trips this circuit breaker is a microprocessor relay that has an integral alarm relay
that will assert on a number of conditions that includes a loss of power to the relay. This
alarm contact connects to our SCADA system and alerts our 24-hour operations center of
relay trouble when the alarm contact closes. This microprocessor relay trips the circuit
breaker only and does not monitor trip coil continuity or other things such as trip current.
Are the components monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years or when a maintenance
correctable issue arises. The control circuitry can be maintained every 12 years. The trip coil(s)
has to be electrically operated at least once every 6 years.
8. Maximum Allowable Verification Intervals
The Maximum Allowable Testing Intervals and Maintenance Activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older Protection
System components require. As explained below, there are some sections of the Protection
System that monitoring or data analysis may not verify. Verifying these sections of the
Protection Systems requires some persistent TBM activity in the maintenance program.
However, some of this TBM can be carried out remotely - for example, exercising a circuit
breaker through the relay tripping circuits using the relay remote control capabilities can be used
to verify function of one tripping path and proper trip coil operation, if there has been no fault or
routine operation to demonstrate performance of relay tripping circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure that
individual components are still operating within acceptable performance parameters - this type of
test is needed for components susceptible to degraded or changing characteristics due to aging
and wear. Full system performance tests may be used to confirm that the total Protection System
functions from measurement of power system values, to properly identifying fault
characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1-1 through 1-5), in the
Standard, specifies maximum allowable verification intervals for various generations of
Protection Systems and categories of equipment that comprise Protection Systems. The right
column indicates maintenance activities required for each category.
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The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications-assisted line Protection System comprising substation
equipment at each terminal and a telecommunications channel for relaying between the two
substations. Figure 2 shows an example of a Generation station layout. The various subsystems
of a Protection System that need to be verified are shown. UFLS, UVLS, and SPS are additional
categories of Table 1 that are not illustrated in these figures. UFLS, UVLS and SPS all use
identical equipment as Protection Systems in the performance of their functions and therefore
have the same maintenance needs.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC-005-2:
• First find the Table associated with your component. The tables are arranged in the order
of mention in the definition of Protection System;
o Table 1-1 is for protective relays,
o Table 1-2 is for the associated communications systems,
o Table 1-3 is for current and voltage sensing devices,
o Table 1-4 is for station dc supply and
o Table 1-5 is for control circuits. There is an additional table,
o Table 2, which brings alarms into the maintenance arena; this was broken out to
simplify the other tables.
•
Next look within that table for your device and its degree of monitoring. The tables have
different hands-on maintenance activities prescribed depending upon the degree to which
you monitor your equipment. Find the maintenance activity that applies to the monitoring
level that you have on your piece of equipment.
•
This Maintenance activity is the minimum maintenance activity that must be
documented.
•
If your PSMP (plan) requires more activities then you must perform and document to this
higher standard.
•
After the maintenance activity is known, check the Maximum Maintenance Interval; this
time is the maximum time allowed between hands-on maintenance activity cycles of this
component.
•
If your PSMP (plan) requires activities more often than the Tables maximum then you
must perform and document those activities to your more stringent standard.
•
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system; this
combination would require hands-on maintenance activity on the relay at least once every
12 years and attention paid to the communications system as often as every 3 months.
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•
An entity does not have to utilize the extended time intervals made available by this use
of condition-based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available on each of the 5 Tables. While the
maintenance activities resulting from this choice would require more maintenance manhours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. These degrees of monitoring, or levels, range from the legacy
unmonitored through a system that is more comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC-005-2.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC-005-2, most notable of which is an entity using performance
based maintenance methodology. (Another reason for having a more stringent plan than is
required could be a regional entity could have more stringent requirements.) Regardless of the
rationale behind an entity’s more stringent plan, it is incumbent upon them to perform the
activities, and perform them at the stated intervals, of the entity’s PSMP. A quality PSMP will
help assure system reliability and adhering to any given PSMP should be the goal.
8.1.2 Additional Notes for Tables 1-1 through 1-5
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified within
the Table interval as other unmonitored relays but may be verified as functional by means
other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the station
battery and charger. Unlike most Protection System components physical inspection of
station batteries for signs of component failure, reduced performance, and degradation
are required to ensure that the station battery is reliable enough to deliver dc power when
required. IEEE Standards 450, 1188, and 1106 for Vented Lead-Acid, Valve-Regulated
Lead-Acid, and Nickel-Cadmium batteries, respectively (which are the most commonly
used substation batteries on the NERC BES) have been developed as an important
reference source of maintenance recommendations. The Protection System owner might
use the applicable IEEE recommended practice which contains information and
recommendations concerning the maintenance, testing and replacement of its substation
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battery. However, the methods prescribed in these IEEE recommendations cannot be
specifically required because they do not apply to all battery applications.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform properly,
it will not affect the integrity of the overall program. Thus these distributed systems have
decreased requirements as compared to other Protection Systems.
6. Voltage & Current Sensing Device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should be
verified to be as expected, (phase value and phase relationships are both equally
important to verify).
7.
“End-to-end test” as used in this Supplementary Reference is any testing procedure that
creates a remote input to the local communications-assisted trip scheme. While this can
be interpreted as a GPS-type functional test it is not limited to testing via GPS. Any
remote scheme manipulation that can cause action at the local trip path can be used to
functionally-test the dc Control Circuitry. A documented real-time trip of any given trip
path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc Control Circuit trip. Or, another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a real-time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure acceptable
measurement of power system input values.
9. Notes 1-8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the Standard is technology and method neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor based relays.
For relay maintenance departments that choose to test microprocessor based relays in the same
manner as electromechanical relays are tested, the testing process sometimes requires that some
specific functions be disabled. Later tests might enable the functions previously disabled but
perhaps still other functions or logic statements were then masked out. It is imperative that, when
the relay is placed into service, the settings in the relay be the settings that were intended to be in
that relay or as the Standard states “…settings are as specified.”
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Many of the microprocessor based relays available today have software tools which provide this
functionality and generate reports for this purpose.
For evidence or documentation of this requirement a simple recorded acknowledgement that the
settings were checked to be as specified is sufficient.
The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would result
in the correct intended operation of the interrupting device. While that is a noble intention, the
measurable proof of such a requirement is immense. The intent is that settings of the component
be as specified at the conclusion of maintenance activities, whether those settings may have
“drifted” since the prior maintenance or whether changes were made as part of the testing
process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection, and thus the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral currents, or
3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring that
phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 requires that a trip test must verify that the auxiliary tripping relay(s) and/or lockout
relay(s) which are directly in a trip path from the protective relay to the interrupting device trip
coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e. annunciation or DME input)
are not required, by this Standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the overall
SPS does not need to have a single end-to-end test. In other words it may be tested in piecemeal
fashion provided all of the pieces are verified.
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What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or relay sensing for Centralized UFLS or
UVLS Systems?
Since components of the SPS, UFLS, or UVLS are the same types of components as those in
Protection Systems then these components should be maintained like similar components used
for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS are
also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example an SPS that trips a remote circuit breaker might be tested
by testing the various parts of the scheme in overlapping segments. Another method is to
document the real-time tripping of an SPS scheme should that occur. Forced trip tests of circuit
breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled outages
for my power plant. Can I extend the maintenance to the next scheduled outage following
the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance intervals
were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance as required due to a major natural disaster
(hurricane, earthquake, etc), how will this affect my compliance with this Standard.
The Sanction Guidelines of the North American Electric Reliability Corporation effective
January 15, 2008 provides that the Compliance Monitor will consider extenuating circumstances
when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance relays, or,
even worse, I am experiencing numerous relay misoperations due to the relays being outof-tolerance?
The established maximum time intervals are mandatory only as a not-to-exceed limitation. The
establishment of a maximum is measurable. But, any entity can choose to test some or all of their
Protection System components more frequently (or, to express it differently, exceed the
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minimum requirements of the Standard). Particularly, if you find that the maximum intervals in
the Standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay Misoperations
is in no one’s best interest. The BES and an entity’s bottom line both suffer.
We believe that the 3-month interval between inspections is unneccessary, why can we not
perform these inspections twice per year?
The standard drafting team believes that routine monthly inspections are the norm. To align
routine station inspections with other important inspections the 3-month interval was chosen. In
lieu of station visits many activities can be accomplished with automated monitoring and
alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3 years; if
we are unable to achieve this schedule but we are able to complete the procedures in less
than the Maximum Time Interval then are we in or out of compliance?
You are out of compliance. You must maintain your equipment to your stated intervals within
your maintenance plan. The protective relays (and any Protection System component) cannot be
tested at intervals that are longer than the maximum allowable interval stated in the Tables and
yet you must conform to your own maintenance plan. Therefore you should design your
maintenance plan such that it is not in conflict with the Minimum Activities and the Maximum
Intervals. You then must maintain your equipment according to your maintenance plan. You will
end up being compliant with both the Standard and your own plan.
Please provide a sample list of devices or systems that must be verified in a generator,
generator step-up transformer, and generator connected station auxiliary transformer to
meet the requirements of this Maintenance Standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay may include but are not necessarily limited to:
•
Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
•
Loss-of-field relays
•
Volts-per-hertz relays
•
Negative sequence overcurrent relays
•
Over voltage and under voltage protection relays
•
Stator-ground relays
•
Communications-based Protection Systems such as transfer-trip systems
•
Generator differential relays
•
Reverse power relays
•
Frequency relays
•
Out-of-step relays
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•
Inadvertent energization protection
•
Breaker failure protection
For generator step up or generator-connected station auxiliary transformers, operation of any of
the following associated protective relays frequently would result in a trip of the generating unit
and, as such, would be included in the program:
•
Transformer differential relays
•
Neutral overcurrent relay
•
Phase overcurrent relays
Relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program even if the loss of the those loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to secondary
unit substation (SUS) or low switchgear transformers and relays protecting other downstream
plant electrical distribution system components are not included in the scope of this program
even if a trip of these devices might eventually result in a trip of the generating unit. For
example, a thermal overcurrent trip on the motor of a coal-conveyor belt could eventually lead to
the tripping of the generator, but it does not cause the trip.
In the case where a plant does not have a generator connected station service transformer
such that it is normally fed from a system connected station service transformer, is it still
the drafting team’s intent to exclude the protection systems for these system connected
auxiliary transformers from scope even when the loss of the normal (system connected)
station service transformer will result in a trip of a BES generating facility?
The SDT does not intend that the system-connected station auxiliary transformers be included in
the Applicability. The generator-connected station service transformers are often connected to
the generator bus directly without an interposing breaker; thus, the Protection Systems on these
transformers will trip the generator as discussed in 4.2.5.1.
What is meant by “verify operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping” one needs to realize that
sometimes there are more Inputs and Outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation and
sometimes even 52a/b contact inputs are needed for a protective relay to correctly operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from the
microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock-out relays (86) and auxiliary tripping relays (94) (used to convey the
tripping current to the trip coils) need to be electrically operated to prove the capability of the
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device to change state. These tests need to be accomplished at least every 6 years, unless PBM
methodology is applied.
The contacts on the 86 or 94 that change state to pass on the trip current to a breaker trip coil
need only be checked every twelve years with the control circuitry.
Other devices in the control circuitry that are used for other protective functions besides tripping
(including, but not limited to, electromechanical breaker fail initiation relays) need only be
verified with the control circuitry every twelve years.
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC-005-2 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for the
Protection System components, or to the previous scheduled (on-site) audit date, whichever is
longer.
This requirement assures that the documentation shows that the interval between maintenance
cycles correctly meets the maintenance interval limits. The requirement is actually alerting the
industry to documentation requirements already implemented by audit teams. Evidence of
compliance bookending the interval shows interval accomplished instead of proving only your
planned interval.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records to
demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested, for routine scheduled tests, every 3 calendar years with a maximum allowed grace period
of an additional 18 months. This entity would be required to maintain its records of maintenance
of its last two routine scheduled tests. Thus its test records would have a latest routine test as
well as its previous routine test. The interval between tests is therefore provable to an auditor as
being within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two test
results proving the last interval. The drafting team contends that this minimizes storage
requirements while still having minimum data available to demonstrate compliance with time
intervals.
Realistically, the Standard is providing advanced notice of audit team documentation requests;
this type of information has already been requested by auditors.
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If an entity prefers to utilize Performance Based Maintenance then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced then the entity can restart the maintenance-time-interval-clock if
desired, however the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements; in other words do not discard maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that the
maintenance intervals had been in compliance. For example, a long range plan of upgrades might
lead an entity to ignore required maintenance; retaining the evidence of prior maintenance that
existed before any retirements and upgrades proves compliance with the Standard.
What does this Maintenance Standard say about commissioning? Is it necessary to have
documentation in your maintenance history of the completion of commission testing?
This Standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the maintenance
activities specified in the Tables of PRC-005-2, verification of the adequacy of initial installation
necessitates the performance of testing and inspections that go well beyond these routine
maintenance activities. For example, commission testing might set baselines for future tests;
perform acceptance tests and/or warranty tests; utilize testing methods that are not generally
done routinely like staged-fault-tests.
However, many of the Protection System attributes which are verified during commission testing
are not subject to age related or service related degradation and need not be re-verified within an
ongoing maintenance program. Example – it is not necessary to re-verify correct terminal strip
wiring on an ongoing basis.
PRC-005-2 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC-005-2 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components such that a properly built and commission tested Protection System will continue to
function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the Standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content and
therefore, it is not necessary to maintain commission testing records within the maintenance
program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC-005-2 would help that entity
prove time interval maximums by setting the initial time clock.
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How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was tested.
Alternatively, an entity may choose to use the date of completion of the commission testing of
the Protection System component and the system was placed into service as the starting point in
determining its first maintenance due dates. Whichever method is chosen, for newly installed
Protection Systems the components should not be placed into service until minimum
maintenance activities have taken place.
It is conceivable that there can be a (substantial) difference in time between the date of testing as
compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non-compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year). However,
if there is a substantial amount of time difference between testing and in-service dates then the
testing date should be followed because it is the degradation of components that is the concern.
While accuracy fluctuations may decrease when components are not energized there are cases
when degradation can take place even though the device is not energized. Minimizing the time
between commissioning tests and in-service dates will help.
If I miss two battery inspections four times out of 100 Protection System components on my
transmission system, does that count as 2 percent or 8 percent when counting Violation
Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its one hundred Protection System
components which would equate to two percent for application to the VSL Table for
Requirement R3.
How do I achieve a “grace period” without being out of compliance?
For the purposes of this example, concentrating on just unmonitored protective relays,– Table 11 specifies a maximum time interval (between the mandated maintenance activities) of 6
calendar years. Your plan must ensure that your unmonitored relays are tested at least once every
6 calendar years. You could, within your PSMP, require that your unmonitored relays be tested
every 4 calendar years with a maximum allowable time extension of 18 calendar months. This
allows an entity to have deadlines set for the auto-generation of work orders but still have the
flexibility in scheduling complex work schedules. This also allows for that 18 calendar months to
act as a buffer, a grace period, in the event of unforeseen events. You will note that this example
of a maintenance plan interval has a planned time of 4 years; it also has a built-in time extension
allowed within the PSMP and yet does not exceed the maximum time interval allowed by the
Standard. So while there are no time extensions allowed beyond the Standard, an entity can still
have substantial flexibility to maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007.
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
IEEE Power System Relaying Committee Working Group I-17 (Transmission Relay System
Performance Comparison). Review of the I-17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the members
to also provide definitively-known data for other entities. The survey represented 470 GW of
peak load, or 64% of the NERC peak load. Maintenance interval averages were compiled by
weighting reported intervals according to the size (based on peak load) of the reporting utility.
Thus, the averages more accurately represent practices for the large populations of Protection
Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of 5 years for
electromechanical or solid state relays, and 7 years for unmonitored microprocessor relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond 7
years, based on favorable experience with the particular products they have installed. To provide
a technical basis for such extension, the SPCTF authors developed a recommendation of 10 years
using the Markov modeling approach from [1] as summarized in Section 8.4. The results of this
modeling depend on the completeness of self-testing or monitoring. Accordingly, this extended
interval is allowed by Table 1 only when such relays are monitored as specified in the attributes
of monitoring contained in Tables 1-1 through 1-5 and Table 2. Monitoring is capable of
reporting Protection System health issues that are likely to affect performance within the 10 year
time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10-year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval actually
degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level. The
industry has experience with self-monitoring microprocessor relays that leads to the Table 1
value for a monitored relay as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
•
Relay Unavailability - the probability that the relay is out of service due to failure or
maintenance activity while the power system element to be protected is in service.
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•
Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a fault occurs, leading to failure to operate for the fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test).
ST = 0 if there is no self-monitoring; ST = 1 for full monitoring. Practical ST values are
estimated to range from .75 to .95. The SPCTF simulation runs used constants in the Markov
model that were the same as those used in [1] with the following exceptions:
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for Relay Unavailability and Abnormal Unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay Mean Time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields no
failure discoveries that approach the negative impact of removing the relays from service and
running the tests.
The PSMT SDT discussed the practical need for “time-interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “timeinterval extension” or “grace periods”. To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time-interval extension while still
following FERC Order 693 the Standard Drafting Team arrived at a 6 year interval for the
electromechanical relay instead of the 5 year interval arrived at by the SPCTF. The PSMT SDT
has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10 year interval was chosen even though there was “…no
significant change in unavailability value over the range of 9, 10, or 11 years. This was true
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even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection System;
thus the maximum allowed interval for these components has been set to12 years. Twelve years
also fits well into the traditional maintenance cycles of both substations and generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum Maintenance
Interval”. The PSMT SDT deemed it necessary to include the term “Calendar” to facilitate
annual maintenance planning, scheduling and implementation. This need is the result of known
occurrences of system requirements that could cause maintenance schedules to be missed by a
few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need to have
schedules be met to the day. An electromechanical protective relay that is maintained in year #1
need not be revisited until 6 years later (year #7). For example: a relay was maintained April 10,
2008; maintenance would need to be completed no later than December 31, 2014.
Though not a requirement of this Standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP the entity should abide
by their chosen language.
9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a Performance-Based Maintenance process may be used to
establish maintenance intervals (PRC-005 Attachment A Criteria for a Performance-Based
Protection System Maintenance Program). A Performance-Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance-Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order to
provide historical justification for intervals other than those established in Table 1. Furthermore,
the asset owner must regularly analyze these records of corrective actions to develop a ranking of
causes. Recurrent problems are to be highlighted, and remedial action plans are to be
documented to mitigate or eliminate recurrent problems.
Entities with Performance-Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and implement
continuous improvement actions. Since no maintenance program can ever guarantee that no
malfunction can possibly occur, documentation of a Performance-Based Maintenance program
would serve the utility well in explaining to regulators and the public a Misoperation leading to a
major system outage event.
A Performance-Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001-2000, Quality management systems
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— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
•
The completeness of the documented maintenance process
•
Organizational knowledge of and adherence to the process
•
Performance metrics and documentation of results
•
Remediation of issues
•
Demonstration of continuous improvement.
In order to opt into a Performance-Based Maintenance (PBM) program the asset owner must first
sort the various Protection System components into population segments. Any population
segment must be comprised of at least 60 individual units; if any asset owner opts for PBM but
does not own 60 units to comprise a population then that asset owner may combine data from
other asset owners until the needed 60 units is aggregated. Each population segment must be
composed of a grouping of Protection Systems or components of a consistent design standard or
particular model or type from a single manufacturer and subjected to similar environmental
factors. For example: One segment cannot be comprised of both GE & Westinghouse electromechanical lock-out relays; likewise, one segment cannot be comprised of 60 GE lock-out
relays, 30 of which are in a dirty environment and the remaining 30 from a clean environment.
This PBM process cannot be applied to batteries but can be applied to all other components of a
Protection System including (but not limited to) specific battery chargers, instrument
transformers, trip coils and/or control circuitry (etc.).
9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling distribution
of the sample mean can be approximated by a normal probability distribution.” The Central
Limit Theorem states: “In selecting simple random samples of size n from a population, the
sampling distribution of the sample mean x can be approximated by a normal probability
distribution as the sample size becomes large.” (Essentials of Statistics for Business and
Economics, Anderson, Sweeney, Williams, 2003)
To use the Central Limit Theorem in statistics, the population size should be large.
references below are supplied to help define what is large.
The
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution of
the sample mean can be approximated by a normal distribution.” (Essentials of
Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation σ, the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics - Picturing the World, Larson, Farber,
2003)
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“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005)
“… the normal is often used as an approximation to the t distribution in a test of a
null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a “Pass/Fail”
format and will be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
Β = bound on the error of distribution (allowable error)
z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
z
n = π(1 − π)
Β
2
Minimum Population Size to use Performance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample of
a vendor’s overall population of manufactured devices. For this reason the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
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the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are recommended
(and required within the Standard):
Minimum Population Size to use Performance-Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance-Based Program = 30.
Once the population segment is defined then maintenance must begin within the intervals as
outlined for the device described in the Tables 1-1 through 1-5. Time intervals can be lengthened
provided the last year’s worth of components tested (or the last 30 units maintained, whichever is
more) had fewer than 4% countable events. It is notable that 4% is specifically chosen because
an entity with a small population (60 units) would have to adjust its time intervals between
maintenance if more than 1 countable event was found to have occurred during the last analysis
period. A smaller percentage would require that entity to adjust the time interval between
maintenance activities if even one unit is found out of tolerance or causes a Misoperation.
The minimum number of units that can be tested in any given year is 5% of the population. Note
that this 5% threshold sets a practical limitation on total length of time between intervals at 20
years.
If at any time the number of countable events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more) then the time period between
manual maintenance activities must be decreased. There is a time limit on reaching the decreased
time at which the countable events is less than 4%; this must be attained within three years.
This additional time period of three years to restore segment performance to <4% countable
events is mandated to keep entities from “gaming the PBM system”. It is believed that this
requirement provides the economic disincentives to discourage asset owners from arbitrarily
pushing the PBM time intervals out to up to 20 years without proper statistical data.
9.2 Frequently Asked Questions:
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I’m a small entity and cannot aggregate a population of Protection System components to
establish a segment required for a Performance-Based Protection System Maintenance
Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect to
the requirements of the Standard. The requirements established for Performance-Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across the
population, including any relevant environmental factors such as geography, power-plant vs.
substation, and weather conditions.
Can an owner go straight to a Performance-Based Maintenance program schedule, if they
have previously gathered records?
Yes. An owner can go to a Performance-Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance-Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner finds
that a gap exists such that they cannot prove that they have collected the data as required for a
Performance-Based Maintenance program then they will need to wait until they can prove
compliance.
When establishing a Performance-Based Maintenance program, can I use test data from
the device manufacturer, or industry survey results, as results to help establish a basis for
my Performance-Based intervals?
No. You must use actual in-service test data for the components in the segment.
What types of misoperations or events are not considered countable events in the
Performance-Based Protection System Maintenance (PBM) Program?
Countable events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re-calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
misoperations during system installation or maintenance activities are not considered countable
events. Examples of excluded human errors include relay setting errors, design errors, wiring
errors, inadvertent tripping of devices during testing or installation, and misapplication of
Protection System components. Examples of misapplication of Protection System components
include wrong CT or PT tap position, protective relay function misapplication, and components
not specified correctly for their installation. Obviously, if one is setting up relevant data about
hardware failures then human failures should be eliminated from the hardware performance
analysis.
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One example of human-error is not pertinent data might be in the area of testing “86” lock-out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into
a performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial sixyear interval they find zero type “X” failures, but human error led to tripping a BES element 100
times; they find 100 type “Y” failures and had an additional 100 human-error caused tripping
incidents. In this example the human-error caused misoperations should not be used to judge the
performance of either type of LOR. Analysis of the data might lead “Entity A” to change time
intervals. Type “X” LOR can be placed into extended time interval testing because of its low
failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
Certain types of Protection System component errors that cause misoperations are not considered
countable events. Examples of excluded component errors include device malfunctions that are
correctable by firmware upgrades and design errors that do not impact protection function.
What are some examples of methods of correcting segment perfomance for PerformanceBased Maintenance?
There are a number of methods that may be useful for correcting segment performance for malperforming segments in a Performance-Based Maintenance system. Some examples are listed
below.
•
The maximum allowable interval, as established by the Performance-Based Maintenance
system, can be decreased. This may, however, be slow to correct the performance of the
segment.
•
Identifiable sub-groups of components within the established segment, which have been
identified to be the mal-performing portion of the segment, can be broken out as an
independent segment for target action. Each resulting segment must satisfy the minimum
population requirements for a Performance-Based Maintenance program in order to
remain within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
Components within the mal-performing segment can be replaced with other components
(electromechanical distance relays with microprocessor relays, for example) to remove
the mal-performing segment.
If I find (and correct) a maintenance-correctable issue as a result of a misoperation
investigation (Re: PRC-004), how does this affect my Performance-Based Maintenance
program?
If you perform maintenance on a Protection System component for any reason (including as part
of a PRC-004 required misoperation investigation/corrective action), the actions performed can
count as a maintenance activity, and, if you desire, “reset the clock” on everything you’ve done.
In a Performance-Based Maintenance program, you also need to record the maintenancecorrectable issue with the relevant component group and use it in the analysis to determine your
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correct Performance-Based Maintenance interval for that component group. Note that “resetting
the clock” should not be construed as interfering with an entity’s routine testing schedule
because the “clock-reset” would actually make for a decreased time interval by the time the next
routine test schedule comes around.
For example a relay scheme, consisting of 4 relays, is tested on 1-1-11 and the PSMP has a time
interval of 3 calendar years with an allowable extension of 1 calendar year. The relay would be
due again for routine testing before the end of the year 2015. This mythical relay scheme has a
misoperation on 6-1-12 that points to one of the four relays as bad. Investigation proves a bad
relay and a new one is tested and installed in place of the original. This replacement relay
actually could be retested before the end of the year 2016 (clock-reset) and not be out of
compliance. This requires tracking maintenance by individual relays and is allowed. However,
many companies schedule maintenance in other ways like by substation or by circuit breaker or
by relay scheme. By these methods of tracking maintenance that “replaced relay” will be retested
before the end of the year 2015. This is also acceptable. In no case was a particular relay tested
beyond the PSMP of 4 years max, nor was the 6 year max of the Standard exceeded. The entity
can reset the clock if they desire or the entity can continue with original schedules and, in effect,
test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from condition
based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their freshness
(charge), but periodic inspection to determine if there are problems associated with their aging
process and testing to see if they are maintaining a charge or can still deliver their rated output as
required.
Besides being perishable, a second unique feature of a battery that is unlike any other Protection
System element is that a battery uses chemicals, metal alloys, plastics, welds, and bonds that
must interact with each other to produce the constant dc source required for Protection Systems,
undisturbed by ac system disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to make
batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation from
the factory to the job site, length of time before a charge is put on the battery, the method of
installation, the voltage level and duration of equalize charges, the float voltage level used, and
the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control of
the Functional Entities that want to use a Performance-Based Protection System Maintenance
(PBM) program. These inherent variances in the aging process of a battery cell make
establishment of a designated segment based on manufacturer and type of battery impossible.
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The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance-changing criteria.
Similarly, Functional Entities that want to establish a condition-based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands-on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a station
dc supply. Inspection of the battery is required on a Maximum Maintenance Interval listed in the
tables due to the aging processes of station batteries. However, higher degrees of monitoring of
a battery can eliminate the requirement for some periodic testing and some inspections (see
Table 1-4).
Please provide an example of the calculations involved in extending maintenance time
intervals using PBM.
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60.
They start out testing all of the relays within the prescribed Table requirements (6 year max) by
testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is greater than
the minimum sample size requirement of 30.
For the sake of example only the following will show 6 failures per year, reality may well have
different numbers of failures every year. PBM requires annual assessment of failures found per
units tested.
After the first year of tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure
rate.
This entity is now allowed to extend the maintenance interval if they choose.
The entity chooses to extend the maintenance interval of this population segment out to 10 years.
This represents a rate of 100 units tested per year; entity selects 100 units to be tested in the
following year.
After that year of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate such that the failure rate is found to be less than 4% per
year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 8 years. This means
that they will now test 125 units per year (1000/8). The entity has just two years left to get the
test rate corrected.
After a year they again find 6 failures out of the 125 units tested. 6/125= 5% failures.
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In response to the 5% failure rate, the entity decreases the testing interval to 7 years. This means
that they will now test 143 units per year (1000/7). The entity has just one year left to get the test
rate corrected.
After a year they again find 6 failures out of the 143 units tested. 6/143= 4.2% failures.
(Note that the entity has tried 5 years and they were under the 4% limit and they tried 7 years and
they were over the 4% limit. They must be back at 4% failures or less in the next year so they
might simply elect to go back to 5 years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to 6 years.
This means that they will now test 167 units per year (1000/6).
After a year they again find 6 failures out of the 167 units tested. 6/167= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by maintaining
the testing interval at 6 years or less. Entity chose 6 year interval and effectively extended their
TBM (5 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing test
rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; this is there to prevent an
entity from “gaming the system”. An entity might arbitrarily extend time intervals from 6 years
to 20 years. In the event that an entity finds a failure rate greater than 4% then the test rate must
be accelerated such that within three years the failure rate must be brought back down to 4% or
less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to
be Tested
(U= P/I)
1
2
3
4
5
1000
1000
1000
1000
1000
200
100
125
143
167
5 yrs
10 yrs
8 yrs
7 yrs
6 yrs
# of
Failures
Found
(F)
6
6
6
6
6
Failure
Rate
(=F/U)
3%
6%
5%
4.2%
3.6%
Decision
to Change
Interval
Yes or No
Yes
Yes
Yes
Yes
No
Interval
Chosen
10 yrs
8 yrs
7 yrs
6 yrs
6 yrs
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Please provide an example of the calculations involved in extending maintenance time
intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of the
trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “Component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three-phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment – Protection Systems or components of a consistent design standard, or a particular
model or type from a single manufacturer that typically share other common elements.
Consistent performance is expected across the entire population of a segment. A segment must
contain at least sixty (60) individual components.
Example:
Entity has 1000 circuit breakers, all of which have two trip coils for a total of 2000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard then this is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V-insulation panel wiring and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago the entity developed their own internal construction crew and now
builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper-sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their Control Circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population, (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the Operations Control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored, therefore the trip paths are continuously
tested and the circuit will alarm when there is a failure; these alarms have to be verified every 12
years for correct operation.
The entity now has 1000 trip coils (and associated trip paths) remaining that they have elected to
count as control circuits. The entity has instituted a process that requires the verification of every
trip path to each trip coil (one unit), including the electrical activation of the trip coil. (The entity
notes that the trip coils will have to be tripped electrically more often than the trip path
verification and is taking care of this activity through other documentation of real-time fault
operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12
year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30.
For the sake of example only the following will show 3 failures per year, reality may well have
different numbers of failures every year. PBM requires annual assessment of failures found per
units tested.
After the first year of tests the entity finds 3 failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval if they choose.
The entity chooses to extend the maintenance interval of this population segment out to 20 years.
This represents a rate of 50 units tested per year; entity selects 50 units to be tested in the
following year.
After that year of testing these 50 units the entity again finds 3 failed units. 3/50= 6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate such that the failure rate is found to be less than 4% per
year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to get
the test rate corrected.
After a year they again find 3 failures out of the 63 units tested. 3/63= 4.76% failures.
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In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to get
the test rate corrected.
After a year they again find 3 failures out of the 72 units tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years and they were under the 4% limit and they tried 14 years
and they were over the 4% limit. They must be back at 4% failures or less in the next year so
they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12 years.
This means that they will now test 84 units per year (1000/12).
After a year they again find 3 failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by maintaining
the testing interval at 12 years or less. Entity chose 12 year interval and effectively extended
their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing test
rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; this is there to prevent an
entity from “gaming the system”. An entity might arbitrarily extend time intervals from 6 years
to 20 years. In the event that an entity finds a failure rate greater than 4% then the test rate must
be accelerated such that within three years the failure rate must be brought back down to 4% or
less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to
be Tested
(U= P/I)
1
2
3
4
5
1000
1000
1000
1000
1000
100
50
63
72
84
10 yrs
20 yrs
16 yrs
14 yrs
12 yrs
# of
Failures
Found
(F)
3
3
3
3
3
Failure
Rate
(=F/U)
3%
6%
4.8%
4.2%
3.6%
Decision
to Change
Interval
Yes or No
Yes
Yes
Yes
Yes
No
Interval
Chosen
20 yrs
16yrs
14 yrs
12 yrs
12 yrs
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Please provide an example of the calculations involved in extending maintenance time
intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays” as
all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific element. This entity calls this set of
protective relays a “Relay Scheme”. Thus this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off-line tests during generator outages whereas a
transmission maintenance group might create a process that utilizes real-time system values
measured at the relays. Under the included definition of “Component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three-phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment – Protection Systems or components of a consistent design standard, or a particular
model or type from a single manufacturer that typically share other common elements.
Consistent performance is expected across the entire population of a segment. A segment must
contain at least sixty (60) individual components.
Example:
Entity has 2000 “Relay Schemes”, all of which have three current signals supplied from bushing
CT’s and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard and this population is greater than
the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1000) are supplied with current signals from ANSI STD C800 bushing
CT’s and voltage signals from PT’s built by ACME Electric MFR CO. All of the relay panels
and cable pulls were built with consistent standards and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built-in
that compare DNP values of voltages and currents (or Watts and VARs) as interpreted by the
MPC relays and alarm for an entity-accepted tolerance level of accuracy. This newer segment of
their “Voltage and Current Sensing” population is different than the original segment, consistent
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(standards, construction and performance expectations) within the new segment and constitutes
the remainder of the entity’s population.
The entity is tracking many thousands of voltage and current signals within 2000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But half
of all of the relay schemes voltage and current signals are monitored, therefore the voltage and
current signals are continuously tested and the circuit will alarm when there is a failure; these
alarms have to be verified every 12 years for correct operation.
The entity now has 1000 relay schemes worth of voltage and current signals remaining that they
have elected to count within their relay schemes designation. The entity has instituted a process
that requires the verification of these voltage and current signals within each relay scheme (one
unit).
(Please note - a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay all the way to the signal source itself. Having many sources of
problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PT’s). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level thus any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal to
be delivered all the way to the relay.)
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30.
For the sake of example only the following will show 3 failures per year, reality may well have
different numbers of failures every year. PBM requires annual assessment of failures found per
units tested.
After the first year of tests the entity finds 3 failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval if they choose.
The entity chooses to extend the maintenance interval of this population segment out to 20 years.
This represents a rate of 50 units tested per year; entity selects 50 units to be tested in the
following year.
After that year of testing these 50 units the entity again finds 3 failed units. 3/50= 6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate such that the failure rate is found to be less than 4% per
year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to get
the test rate corrected.
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After a year they again find 3 failures out of the 63 units tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to get
the test rate corrected.
After a year they again find 3 failures out of the 72 units tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years and they were under the 4% limit and they tried 14 years
and they were over the 4% limit. They must be back at 4% failures or less in the next year so
they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12 years.
This means that they will now test 84 units per year (1000/12).
After a year they again find 3 failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by maintaining
the testing interval at 12 years or less. Entity chose 12 year interval and effectively extended
their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing test
rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; this is there to prevent an
entity from “gaming the system”. An entity might arbitrarily extend time intervals from 6 years
to 20 years. In the event that an entity finds a failure rate greater than 4% then the test rate must
be accelerated such that within three years the failure rate must be brought back down to 4% or
less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to
be Tested
(U= P/I)
1
2
3
4
5
1000
1000
1000
1000
1000
100
50
63
72
84
10 yrs
20 yrs
16 yrs
14 yrs
12 yrs
# of
Failures
Found
(F)
3
3
3
3
3
Failure
Rate
(=F/U)
3%
6%
4.8%
4.2%
3.6%
Decision
to Change
Interval
Yes or No
Yes
Yes
Yes
Yes
No
Interval
Chosen
20 yrs
16yrs
14 yrs
12 yrs
12 yrs
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10. Overlapping the Verification of Sections of the
Protection System
Tables 1-1 through 1-5 require that every Protection System component be periodically verified.
One approach, but not the only method, is to test the entire protection scheme as a unit, from the
secondary windings of voltage and current sources to breaker tripping. For practical ongoing
verification, sections of the Protection System may be tested or monitored individually. The
boundaries of the verified sections must overlap to ensure that there are no gaps in the
verification. See Appendix A of this Supplementary Reference for additional discussion on this
topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection System
may be divided into multiple overlapping sections with a different maintenance methodology for
each section:
•
Time-based maintenance with appropriate maximum verification intervals for
categories of equipment as given in the Tables 1-1 through 1-5;
•
Monitoring as described in Tables 1-1 through 1-5;
•
A Performance-Based Maintenance program as described in Section 9 above or
Attachment A of the Standard;
•
Opportunistic verification using analysis of fault records as described in Section
11
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10.1 Frequently Asked Question:
My system has alarms that are gathered once daily through an auto-polling system; this is
not really a conventional SCADA system but does it meet the Table 1 requirements for
inclusion as a monitored system?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the maintenance-correctable issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the problem,
but rather a location where the action can be initiated.
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve fault event records and oscillographic records by
data communications after a fault. They analyze the data closely if there has been an apparent
misoperation, as NERC Standards require. Some advanced users have commissioned automatic
fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured digital fault
recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time-interval based check on Protection Systems whose operations are analyzed. Even
electromechanical Protection Systems instrumented with DFR channels may achieve some CBM
benefit. The completeness of the verification then depends on the number and variety of faults in
the vicinity of the relay that produce relay response records, and the specific data captured.
A typical fault record will verify particular parts of certain Protection Systems in the vicinity of
the fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external fault records that
completely verify the Protection System.
For example, fault records may verify that the particular relays that tripped are able to trip via the
control circuit path that was specifically used to clear that fault. A relay or DFR record may
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
indicate correct operation of the protection communications channel. Furthermore, other nearby
Protection Systems may verify that they restrain from tripping for a fault just outside their
respective zones of protection. The ensemble of internal fault and nearby external fault event
data can verify major portions of the Protection System, and reset the time clock for the Table 1
testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple faults close to either side
of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection System
that can actually be proven using the PMU or DME data.
If fault record data is used to show that portions or all of a Protection System have been verified
to meet Table 1 requirements, the owner must retain the fault records used, and the maintenance
related conclusions drawn from this data and used to defer Table 1 tests, for at least the retention
time interval given in Section 8.2.
11.1 Frequently Asked Question:
I use my protective relays for fault and disturbance recording, collecting oscillographic
records and event records via communications for fault analysis to meet NERC and DME
requirements. What are the maintenance requirements for the relays?
For relays used only as disturbance monitoring equipment, the NERC Standard PRC-018-1 R3 &
R6 states the maintenance requirements, and is being addressed by a Standards activity that is
revising PRC-002-1 and PRC-018-1. For protective relays “that are designed to provide
protection for the BES,” this Standard applies, even if they also perform DME functions.
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12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single selfmonitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of fault records may or may not
reveal setting problems. To minimize risk of setting errors after commissioning, the user should
enforce strict settings data base management, with reconfirmation (manual or automatic) that the
installed settings are correct whenever maintenance activity might have changed them. For
background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this requirement
is simple. With legacy relays (non-microprocessor protective relays) it is necessary to know the
value of the intended setting in order to test, adjust and calibrate the relay. Proving that the relay
works per specified setting was the de facto procedure. However, with the advanced
microprocessor relays it is possible to change relay settings for the purpose of verifying specific
functions and then neglect to return the settings to the specified values. While there is no specific
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requirement to maintain a settings management process there remains a need to verify that the
settings left in the relay are the intended, specified settings. This need may manifest itself after
any of the following:
•
One or more settings are changed for any reason.
•
A relay fails and is repaired or replaced with another unit.
•
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be installed.
Other entities may rely upon the vigorous testing of the firmware OEM. An entity has the
latitude to install devices and/or programming that they believe will perform to their satisfaction.
If an entity should choose to perform the maintenance activities specified in the Tables following
a firmware upgrade then they may, if they choose, reset the time clock on that set of maintenance
activities so that they would not have to repeat the maintenance on its regularly scheduled cycle.
(However, for simplicity in maintenance schedules, some entities may choose to not reset this
time clock; it is merely a suggested option.)
If I upgrade my old relays then do I have to maintain my previous equipment maintenance
documentation?
If an equipment item is repaired or replaced then the entity can restart the maintenance-activitytime-interval-clock if desired, however the replacement of equipment does not remove any
documentation requirements. The requirements in the Standard are intended to ensure that an
entity has a maintenance plan and that the entity adheres to minimum activities and maximum
time intervals. The documentation requirements are intended to help an entity demonstrate
compliance. For example, saving the dates and records of the last two maintenance activities is
intended to demonstrate compliance with the interval. Therefore, if you upgrade or replace
equipment then you still must maintain the documentation for the previous equipment, thus
demonstrating compliance with the time interval requirement prior to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system rating
changes that merely required taking relays “out-of-service”. What are our responsibilities
when it comes to “out-of-service” devices?
Assuming that your system up-rates, upgrades and overall changes meet any and all other
requirements and standards then the requirements of PRC-005-2 are simple – if the
Protection System component performs a Protection System function then it must be
maintained. If the component no longer performs Protection System functions then it
does not require maintenance activities under the Tables of PRC-005-2. While many
entities might physically remove a component that is no longer needed there is no
requirement in PRC-005-2 to remove such component(s). Obviously, prudence would
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
dictate that an “out-of-service” device is truly made inactive. There are no record
requirements listed in PRC-005-2 for Protection System components not used.
While performing relay testing of a protective device on our Bulk Electric System it was
discovered that the protective device being tested was either broken or out of calibration.
Does this satisfy the relay testing requirement even though the protective device tested bad,
and may be unable to be placed back into service?
Yes, PRC-005-2 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-2
requirement although the protective device may be unable to be returned to service under normal
calibration adjustments. R3 states (the entity must):
R3. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement
and follow its PSMP and initiate resolution of any identified maintenance correctable issues.
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC Standards.
If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R3) (in essence) state “…shall implement and follow
its PSMP and initiate resolution of any identified maintenance correctable issues...” The type of
corrective activity is not stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device tested
bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products for
nearly 20 years. Theoretically, any element that is monitored does not need a periodic manual
test. A problem today is that the community of manufacturers and users has not created clear
documentation of exactly what is and is not monitored. Some unmonitored but critical elements
are buried in installed systems that are described as self-monitoring.
To utilize the extended time intervals allowed by monitoring the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with the
unmonitored intervals established in Table 1.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands-on
maintenance requirement), the manufacturers of the microprocessor-based self-monitoring
components in the Protection System should publish for the user a document or map that shows:
•
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
•
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
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With this information in hand, the user can document monitoring for some or all sections by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
•
Extending the monitoring to include the alarm transmission facilities through
which failures are reported within a given time frame to allocate where action can
be taken to initiate resolution of the alarm attributed to a maintenance correctable
issue, so that failures of monitoring or alarming systems also lead to alarms and
action.
•
Documenting the plans for verification of any unmonitored components according
to the requirements of Table 1.
13.1 Frequently Asked Question:
I can’t figure out how to demonstrate compliance with the requirements for the highest
level of monitoring of Protection Systems. Why does this Maintenance Standard describe a
maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This Standard does
not presume to specify what documentation must be developed; only that it must be documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring; the Standard establishes the necessary requirements for when
such equipment becomes available.
By creating a roadmap for development, this provision makes the Standard technology-neutral.
The Standard Drafting Team wants to avoid the need to revise the Standard in a few years to
accommodate technology advances that may be coming to the industry.
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14. Notification of Protection System Failures
When a failure occurs in a Protection System, power system security may be compromised, and
notification of the failure must be conducted in accordance with relevant NERC Standard(s).
Knowledge of the failure may impact the system operator’s decisions on acceptable loading
conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System owner also encourages the system owner to execute repairs as rapidly as possible. In
some cases, a microprocessor relay or carrier set can be replaced in hours; wiring termination
failures may be repaired in a similar time frame. On the other hand, a component in an
electromechanical or early-generation electronic relay may be difficult to find and may hold up
repair for weeks. In some situations, the owner may have to resort to a temporary protection
panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance but if its battery
maintenance program is lacking then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC-005-2 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore manual intervention to perform
certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and voltage
sensing devices and are used to isolate a faulted element of the BES. Devices that sense thermal,
vibration, seismic, pressure, gas or any other non-electrical inputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor based equipment
in the following ways, the relays should meet the asset owners’ tolerances.
•
Non-microprocessor devices must be tested with voltage and/or current applied to the
device.
•
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
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15.1.1 Frequently Asked Question:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber-optic Hall-effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type of
voltage and current sensing devices included in this Standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these signals
is to know that the expected output from these components actually reaches the protective relay.
Therefore, the proof of the proper operation of these components also demonstrates the integrity
of the wiring (or other medium used to convey the signal) from the current and voltage sensing
device all the way to the protective relay. The following observations apply.
•
There is no specific ratio test, routine test or commissioning test mandated.
•
There is no specific documentation mandated.
•
It is required that the signal be present at the relay.
•
This expectation can be arrived at from any of a number of means; by calculation, by
comparison to other circuits, by commissioning tests, by thorough inspection, or by any
means needed to verify the circuit meets the asset owner’s Protection System
maintenance program.
•
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this therefore tests the CT as well as the wiring from the relay all the back
to the CT.
•
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during load conditions, at the input to the relay.
•
Another example of testing the various voltage and/or current sensing devices is to query
the microprocessor relay for the real-time loading; this can then be compared to other
devices to verify the quantities applied to this relay. Since the input devices have supplied
the proper values to the protective relay then the verification activity has been satisfied.
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Thus event reports (and oscillographs) can be used to verify that the voltage and current
sensing devices are performing satisfactorily.
•
Still another method is to measure total watts and vars around the entire bus; this should
add up to zero watts and zero vars thus proving the voltage and/or current sensing devices
system throughout the bus.
•
Another method for proving the voltage and/or current sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
•
Any other methods that provide documentation that the expected transformer values as
applied to the inputs to the protective relays are acceptable.
15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage and
current sensing devices to the protective relays …” Do we need to perform ratio, polarity
and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all-inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different current
transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional testing
on the panel wiring to ensure that the values arrive at those relays) with the other phases,
and verify that residual currents are within expected bounds
•
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay (such as, but not limited to, a
query to the microprocessor relay), to another protective relay monitoring the same line,
with currents supplied by different CT’s.
•
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi-meters, voltmeter, clamp-on ammeters, etc) and verified
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by calculations and known ratios to be the values expected. For example a single PT on a
100KV bus will have a specific secondary value that when multiplied by the PT ratio
arrives at the expected bus value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that, an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring systems.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test to
verify that the instrument transformer secondary signals are actually making it to the relay and
not being shunted off to ground. For instance, you could use CT excitation tests and PT turns
ratio tests and compare to baseline values to verify that the instrument transformer outputs are
acceptable. However, to conclude that these acceptable transformer instrument output signals
are actually making it to the relay inputs, it also would be necessary to verify the insulation of
the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions as do microprocessor based relays. In order for me to compare the
instrument transformer inputs to these relays to the secondary values of other metered
instrument transformers monitoring the same primary voltage and current signals, it
would be necessary to temporarily connect test equipment like voltmeters and clamp on
ammeters to measure the input signals to the relays. This practice seems very risky and a
plant trip could result if the technician were to make an error while measuring these
current and voltage signals. How can I avoid this risk? Also, what if no other instrument
transformers are available which monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying the
instrument transformer inputs to the relays but is not required by the Standard. Plants can choose
how to best manage their risk. If online testing is deemed too risky, offline tests such as, but not
limited to, CT excitation test and PT turns ratio tests can be compared to baseline data and be
used in conjunction with CT and PT secondary wiring insulation verification tests to adequately
“verify the current and voltage circuit inputs from the voltage and current sensing devices to the
protective relays …” while eliminating the risk of tripping an in service generator or transformer.
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Similarly, this same offline test methodology can be used to verify the relay input voltage and
current signals to relays when there are no other instrument transformers monitoring available
for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the relays. It
includes the wiring (or other signal conveyance) from every trip output to every trip coil. It
includes any device needed for the correct processing of the needed trip signal to the trip coil of
the interrupting device; this requirement is meant to capture inputs and outputs to and from a
protective relay that are necessary for the correct operation of the protective functions. In short,
every trip path must be verified; the method of verification is optional to the asset owner. An
example of testing methods to accomplish this might be to verify, with a volt-meter, the
existence of the proper voltage at the open contacts, the open circuited input circuit and at the
trip coil(s). As every parallel trip path has similar failure modes, each trip path from relay to trip
coil must be verified. Each trip coil must be tested to trip the circuit breaker (or other interrupting
device) at least once. There is a requirement to operate the circuit breaker (or other interrupting
device) at least once every six years as part of the complete functional test. If a suitable
monitoring system is installed that verifies every parallel trip path then the manual-intervention
testing of those parallel trip paths can be eliminated, however the actual operation of the circuit
breaker must still occur at least once every six years. This 6-year tripping requirement can be
completed as easily as tracking the real-time fault-clearing operations on the circuit breaker or
tracking the trip coil(s) operation(s) during circuit breaker routine maintenance actions.
The circuit-interrupting device should not be confused with a motor-operated disconnect. The
intent of this Standard is to require maintenance intervals and activities on Protection Systems
equipment and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground
switch as an interrupting device if this ground switch is utilized in a Protection System and
forces a ground fault to occur that then results in an expected Protection System operation to
clear the forced ground fault. The SDT believes that this is essentially a transferred-tripping
device without the use of communications equipment. If this high-speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years and any electromechanically operated device will have to be tested every 6 years. If the
spring-operated ground switch can be disconnected from the solenoid triggering unit then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
Circuit breakers that participate in a UFLS or UVLS scheme are excluded from the tripping
requirement, but not from the circuit test requirements; however the circuitry must be tested at
least once every 12 years. There are many circuit interrupting devices in the distribution system
that will be operating for any given under-frequency event that requires tripping for that event. A
failure in the tripping-action of a single distributed system circuit breaker (or non-BES
equipment interruption device) will be far less significant than, for example, any single
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Transmission Protection System failure such as a failure of a bus differential lock-out relay.
While many failures of these distributed system circuit breakers (or non-BES equipment
interruption device) could add up to be significant, it is also believed that many circuit breakers
are operated often on just fault clearing duty and therefore these circuit breakers are operated at
least as frequently as any requirements that appear in this Standard.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay
(86) that may exist in any particular trip scheme. If these devices are electromechanical
components then they must be trip tested. The PSMT SDT considers these components to share
some similarities in failure modes as electromechanical protective relays; as such there is a six
year maximum interval between mandated maintenance tasks unless PBM is applied.
Contacts of the 86 or 94 that pass the trip current on to the circuit interrupting device trip coils
will have to be checked as part of the 12 year requirement. Normally-open contacts that are not
used to pass a trip signal and normally-closed contacts do not have to be verified. Verification of
the tripping paths is the requirement.
New technology is also accommodated here; there are some tripping systems that have replaced
the traditional hard-wired trip circuitry with other methods of trip-signal conveyance such as
fiber-optics. It is the intent of the PSMT SDT to include this, and any other, technology that is
used to convey a trip signal from a protective relay to a circuit breaker (or other interrupting
device) within this category of equipment.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval) than
when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual components’ maximum
allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying the
tripping of circuit breakers. What is this telling me about maintenance of circuit breakers?
Requirements in PRC-005-2 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC-005-2 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit path, as established in Table 1-5 “Protection System
Control Circuitry (Trip coils and auxiliary relays)”?
Table 1-5 specifies that each breaker trip coil, auxiliary relay that carries trip current to a
trip coil, and lockout relays that carry trip current to a trip coil must be operated within
the specified time period. The required operations may be via targeted maintenance
activities, or by documented operation of these devices for other purposes such as fault
clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
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Yes. PRC-005-2 includes high-speed grounding switch trip coils within the dc control circuitry
to the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES protection
component, have to be tested per Table 1.5?
An example of an otherwise non-BES circuit breaker that is tripped via a BES protection
component might be (but is not limited to) a 12.5KV circuit breaker feeding (non-black-start)
radial loads but has a trip that originates from an under-frequency (81) relay.
The relay must be verified.
The voltage signal to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit must be verified every 12 years.
The trip coil of the circuit breaker does not have to be individually proven with an electrical trip.
15.4 Batteries and DC Supplies (Table 1-4)
IEEE guidelines were consulted to arrive at the maintenance activities for batteries. The
following guidelines were used: IEEE 450 (for Vented Lead-Acid batteries), IEEE 1188 (for
Valve-Regulated Lead-Acid batteries) and IEEE 1106 (for Nickel-Cadmium batteries).
The currently proposed NERC definition of a Protection System is
•
Protective relays which respond to electrical quantities,
•
Communications systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.”
•
The station battery is not the only component that provides dc power to a Protection
System. In the new definition for Protection System “station batteries” are replaced with
“station dc supply” to make the battery charger and dc producing stored energy devices
(that are not a battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the Standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner to
the two methods recommended in the IEEE standards. Continuity as used in Table 1-4 of the
Standard refers to verifying that there is a continuous current path from the positive terminal of
the station battery set to the negative terminal. Without verifying continuity of a station battery,
there is no way to determine that the station battery is available to supply dc power to the station.
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An open battery string will be an unavailable power source in the event of loss of the battery
charger.
Batteries cannot be a unique population segment of a Performance-Based Maintenance Program
(PBM) because there are too many variables in the electrochemical process to completely isolate
all of the performance-changing criteria necessary for using PBM on battery systems. However,
nothing precludes the use of a PBM process for any other part of a dc supply besides the batteries
themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply as mentioned in the definition of Protective System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers as well as dc systems that do not utilize batteries. This revision
of PRC-005-2 is intended to capture these devices that were not included under the previous
definition. The station direct current (dc) supply normally consists of two components: the
battery charger and the station battery itself. There are also emerging technologies that provide a
source of dc supply that does not include either a battery or charger.
Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays in
the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1-4.
Emerging Technologies - Station dc supplies are currently being developed that use other energy
storage technologies beside the station battery to prevent loss of the station dc supply when ac
power is lost. Maintenance of these station dc supplies will require different kinds of tests and
inspections. Table 1-4 presents maintenance activities and maximum allowable testing intervals
for these new station dc supply technologies. However, because these technologies are relatively
new the maintenance activities for these station dc supplies may change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the Standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner to
the two methods recommended in the IEEE standards. Continuity as used in Table 1-4 of the
Standard refers to verifying that there is a continuous current path from the positive terminal of
the station battery set to the negative terminal. Without verifying continuity of a station battery,
there is no way to determine that the station battery is available to supply dc power to the station.
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An open battery string will be an unavailable power source in the event of loss of the battery
charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity (an
open circuit) in any part of the electrochemical or metallic path the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery must
be capable of supplying dc current, both for continuous dc loads and for tripping breakers and
switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
•
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
harmonics. With the loss of continuity in the battery, the filter provided by the battery is
no longer present.
•
Loss of electrical continuity of the station battery will cause, regardless of the battery
charger’s output current capability, a delayed response in full output current from the
charger. Almost all chargers have an intentional 1 to 2 second delay to switch from a low
substation dc load current to the maximum output of the charger. This delay would cause
the opening of circuit breakers to be delayed which could violate system performance
standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery unless the battery charger is taken out of service. At that time a
break in the continuity of the station battery current path will be revealed because there will be
no voltage on the station dc circuitry. This particular test method, while proving battery
continuity, may not be acceptable to all installations.
Although the Standard prescribes what must be accomplished during the maintenance activity it
does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the only
possible methods, simply a sampling of some methods:
•
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path through
the battery.
•
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of the
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various dc-supplied equipment in the station should be considered before using this
approach.
•
Manufacturers of microprocessor controlled battery chargers have developed methods for
their equipment to periodically (or continuously) test for battery continuity For example,
one manufacturer periodically reduces the float voltage on the battery until current from
the battery to the dc load can be measured to confirm continuity.
•
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
•
Internal ohmic measurements of the cells and units of Lead Acid Batteries (VRLA &
VLA) can detect lack of continuity within the cells of a battery string and when used in
conjunction with resistance measurements of the battery’s external connections can prove
continuity. Also some methods of taking internal ohmic measurements by their very
nature can prove the continuity of a battery string without having to use the results of
resistance measurements of the external connections.
•
Specific Gravity tests can infer continuity because without continuity there could be no
charging occurring and if there is no charging then Specific Gravity will go down below
acceptable levels.
No matter how the electrical continuity of a battery set is verified it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1-4 to insure that the station
dc supply has a path that can provide the required current to the Protection System at all times.
When should I check the station batteries to see if they have sufficient energy to perform as
designed?
The answer to this question depends on the type of battery (Valve-Regulated Lead-Acid, Vented
Lead-Acid, or Nickel-Cadmium), and the maintenance activity chosen.
For example, if you have a Valve-Regulated Lead-Acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline, you
will have to perform verification at a maximum maintenance interval of no greater than every six
months. While this interval might seem to be quite short, keep in mind that the 6 month interval
is consistent with IEEE guidelines for VRLA batteries; this interval provides an accumulation of
data that better shows when a VRLA battery is no longer capable of its design capacity.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every 3 calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when lead
acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are most
indicative of the station batteries ability to perform as designed they should be made upon
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installation of the station battery and the completion of a performance test of the battery’s
capacity.
When internal ohmic measurements are taken, consistent test equipment should be used to
establish the baseline and used for the future trending of the cells internal ohmic measurements
because of variances in test equipment and the type of ohmic measurement used by different
manufacturer’s equipment. Keep in mind that one manufacturer’s “Conductance” test equipment
does not produce similar results as another manufacturer’s “Impedance” test equipment even
though both manufacturers have produced “Ohmic” test equipment.
For all new installations of Valve-Regulated Lead-Acid (VRLA) batteries and Vented Lead-Acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to be
used to determine the ability of the station battery to perform as designed, the establishment of
the baseline as described above should be followed at the time of installation to insure the most
accurate trending of the cell/unit. However, often for older VRLA batteries the owners of the
station batteries have not established a baseline at installation. Also for owners of VLA batteries
who want to establish a maintenance activity which requires trending of measured ohmic values
to a baseline, there was typically no baseline established at installation of the station battery to
trend to.
To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However it is important that when using battery
manufacturer supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment).
Although many manufacturers may have provided base line values which will allow trending of
the internal ohmic measurements over the remaining life of a station battery, these baselines are
not the actual cell/unit measurements for the battery being trended. It is important to have a
baseline tailored to the station battery to more accurately use the tool of ohmic measurement
trending. That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be a
very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged the battery is available to deliver its existing capacity. As a
battery is discharged its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
IEEE Standards 450, 1188, and 1106 for Vented Lead-Acid (VLA), Valve-Regulated Lead-Acid
(VRLA), and Nickel-Cadmium (NiCd) batteries respectively discuss state of charge in great
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detail in their standards or annexes to their standards. The above IEEE standards are excellent
sources for describing how to determine state of charge of the battery system.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged the battery is
available to deliver its existing capacity. As a battery is discharged its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For Vented Lead-Acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the battery
discharges the active electrolyte, sulphuric acid, is consumed and the concentration of the
sulphuric acid in water is reduced. This in turn reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can therefore
be used as an indication of the state of charge of the battery. Hydrometer readings may not tell
the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA battery. If
measured right after charging, you might see high specific gravity readings at the top of the cell,
even though it is much less at the bottom. Conversely if taken shortly after adding water to the
cell the specific gravity readings near the top of the cell will be lower than those at the bottom.
Nickel-Cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and Valve-Regulated Lead-Acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
readings. For these two types of batteries and also for VLA batteries, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by using
the battery charger and taking voltage and current readings during float and equalize (high-rate
charge mode). This method is an effective means of determining when the state of charge is low
and when it is approaching a fully charged condition which gives the assurance that the available
battery capacity will be maximized.
Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery a
very high resistance can cause severe damage. The maintenance requirement to verify battery
terminal connection resistance in Table 1-4 is established to verify that the integrity of all battery
electrical connections is acceptable. This verification includes cell-to-cell (intercell) and external
circuit terminations.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen not to exceed the maximum
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maintenance interval of Table 1-4. Trending of the interval measurements to the baseline
measurements will identify any degradation in the battery connections. When the connection
resistance values exceed the acceptance criteria for the connection, the connection is typically
disassembled, cleaned, reassembled and measurements taken to verify that the measurements are
adequate when compared to the baseline readings.
IEEE Standard 450 for Vented Lead-Acid (VLA) batteries “informative” annex F, and IEEE
Standard 1188 for Valve-Regulated Lead-Acid (VRLA) batteries “informative” annex D provide
excellent information and examples on performing connection resistance measurements using a
microohmmeter and connection detail resistance measurements. Although this information is
contained in standards for lead acid batteries the information contained is applicable to NickelCadmium batteries also.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1-4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to the
electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal color (possible
copper contamination) and abnormal conditions such as cracked grids. The visual inspection
could look for symptoms of hydration that would indicate that the battery has been left in a
completely discharged state for a prolonged period. Besides looking at the plates for signs of
aging, all internal connections such as the bus bar connection to each plate and the connections
to all posts of the battery need to be visually inspected for abnormalities. In a complete visual
inspection for the condition of the cell the cell plates, separators and sediment space of each cell
must be looked at for signs of deterioration. An inspection of the station battery’s cell condition
also includes looking at all terminal posts and cell-to-cell electric connections to ensure they are
corrosion free. The case of the battery containing the cell or cells must be inspected for cracks
and electrolyte leaks through cracks and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1-4 by a Performance-Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval of
Table 1-4.
Why consider the ability of the station battery to perform as designed?
Determining the ability of a station battery to perform as designed is critical in the process of
determining when the station battery must be replaced or when an individual cell or battery unit
must be removed or replaced. For lead acid batteries the ability to perform as designed can be
determined in more than one manner.
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The two acceptable methods for proving that a station lead acid battery can perform as designed
are based on two different philosophies. The first maintenance activity requires tests and
evaluation of the internal ohmic measurements on each of the individual cells/units of the station
battery to determine that each component can perform as designed and therefore the entire
station battery can be verified to perform as designed. The second activity requires a capacity
discharge test of the entire station battery to verify that degradation of one or several components
(cells) in the station battery has not deteriorated to a point where the total capacity of the station
battery system falls below its designed rating.
The first maintenance activity listed in Table 1-4 for verifying that a station battery can perform
as designed uses maximum maintenance intervals for evaluating internal ohmic measurements in
relation to their baseline measurements that are based on industry experience, EPRI technical
reports and application guides, and the IEEE battery standards. By evaluating the internal ohmic
measurements for each cell and comparing that measurement to the cell’s baseline ohmic
measurement low-capacity cells can be identified and eliminated or the whole station battery
replaced to keep the station battery capable of performing as designed. Since the philosophy
behind internal ohmic measurement evaluation is based on the fact that each battery component
must be verified to be able to perform as designed, the interval for verification by this
maintenance activity must be shorter to catch individual cell/unit degradation.
It should be noted that even if a lead acid battery unit is composed of multiple cells where the
ohmic measurement of each cell cannot be taken, the ohmic test can still be accomplished. The
data produced becomes trending data on the multi-cell unit instead of trending individual cells.
Care must be taken in the evaluation of the ohmic measures of entire units to detect a bad cell
that has a poor ohmic value. Good ohmic values of other cells in the same battery unit can make
it harder to detect the poor ohmic measurement of a bad cell because the only ohmic
measurement available is of all the cells in the battery unit.
This first maintenance activity is applicable only for Vented Lead-Acid (VLA) and ValveRegulated Lead-Acid (VRLA) batteries; this trending activity has not shown to be effective for
NiCd batteries thus the only choices for owners of NiCd batteries are the performance tests of the
second activity (see applicable IEEE guideline for specifics on performance tests).
The second maintenance activity listed in Table 1-4 for verifying that a station battery can
perform as designed uses maximum maintenance intervals for capacity testing that were
designed to align with the IEEE battery standards. This maintenance activity is applicable for
Vented Lead-Acid, Valve-Regulated Lead-Acid, and Nickel-Cadmium batteries.
The maximum maintenance interval for discharge capacity testing is longer than the interval for
testing and evaluation of internal ohmic cell measurements. An individual component of a
station battery may degrade to an unacceptable level without causing the total station battery to
fall below its designed rating under capacity testing.
IEEE Standards 450, 1188, and 1106 for vented lead-acid (VLA), Valve-Regulated Lead-Acid
(VRLA), and Nickel-Cadmium (NiCd) batteries respectively (which together are the most
commonly used substation batteries on the BES) go into great detail about capacity testing of the
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entire battery set to determine that a battery can perform as designed or needs to be replaced
soon.
Why in Table 1-4 of PRC-005-2 is there a maintenance activity to inspect the structural
intergrity of the battery rack?
The three IEEE standards (1188, 450, and 1106) for VRLA, Vented Lead-Acid, and NickelCadmium batteries all recommend that as part of any battery inspection the battery rack should
be inspected. The purpose of this inspection is to verify that the battery rack is correctly installed
and has no deterioration that could weaken its structural integrity.
Because the battery rack is specifically designed for the battery that is mounted on it, weakening
of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the unintentional
ground that appears on the opposite pole that becomes problematic. Even then many systems are
designed to operate favorably under some unintentional DC ground situations. It is up to the
owner of the Protection System to determine if corrective actions are needed on detected
unintentional DC grounds. The Standard merely requires that a check be made for the existence
of Unintentional DC Grounds. Obviously a “check-off” of some sort will have to be devised by
the inspecting entity to document that a check is routinely done for Unintentional DC Grounds
because of the possible consequences to the Protection System.
Where the Standard refers to “all cells” is it sufficient to have a documentation method
that refers to “all cells” or do we need to have separate documentation for every cell? For
example do I need 60 individual documented check-offs for good electrolyte level or would
a single check-off per bank be sufficient?
A single check-off per battery bank is sufficient for documentation, as long as the single checkoff attests to checking all cells/units.
Does this Standard refer to Station batteries or all batteries, for example Communications
Site Batteries?
This Standard refers to Station Batteries. The drafting team does not believe that the scope of this
Standard refers to communications sites. The batteries covered under PRC-005-2 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part of
the Protection System. The SDT believes that a loss of power to the communications systems at
a remote site would cause the communications systems associated with protective relays to alarm
at the substation. At this point the corrective actions can be initiated.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how am I
expected to comply with the cell-to-cell ohmic measurement requirements on these units
that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1-4.
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What are cell/unit internal ohmic measurements?
With the introduction of Valve-Regulated Lead-Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead-Acid (VLA)
batteries were unable to be used on this new type of lead-acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells and
periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The inductive
reactance in the current path through the battery is so minuscule when compared to the huge
capacitive reactance of the cells that it is often ignored in most circuit models of the battery cell.
Taking the basic model of a battery cell manufacturers of battery test equipment have developed
and marketed testing devices to take measurements of the current path to detect degradation in
the internal path through the cell.
In the battery industry these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac conductance,
ac impedance, and dc resistance. They are defined by the test equipment providers and IEEE and
refer to the method of taking ohmic measurements of a lead acid battery. For example in one
manufacturer’s ac conductance equipment measurements are taken by applying a voltage of a
known frequency and amplitude across a cell or battery unit and observing the ac current flow it
produces in response to the voltage. A manufacturer of an ac impedance meter measures ac
current of a known frequency and amplitude that is passed through the whole battery string and
determines the impedances of each cell or unit by measuring the resultant ac voltage drop across
them. On the other hand dc resistance of a cell is measured by a third manfacturer’s equipment
by applying a dc load across the cell or unit and measuring the step change in both the voltage
and current to calculate the internal dc resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices there were no standards developed or used to mandate the test signals used
in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of measurement
devices. This diversity in test signals coupled with the three different types of ohmic
measurements techniques (impedance conductance and resistance) make it impossible to get the
same ohmic measurement for a cell with different ohmic measurement devices. However, IEEE
has recognized the great value for choosing one device for ohmic measurement, no matter who
makes it or the method to calculate the ohmic measurement. The only caution given by IEEE
and the battery manufacturers is that when trending the cells of a lead acid station battery
consistent ohmic measurement devices should be used to establish the baseline measurement and
to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
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internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need for
taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a base line
and trending it over time says, “depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary.
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries. The
standard also discusses the need to look for significant changes in the ohmic measurements, the
caution that measurement data will differ with each type of model of instrument used, and lists a
number of factors that affect ohmic measurements.
At the beginning of the 21st century EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as designed. By evaluation of the trending of the
ohmic measurements over time the owner could track the performance of the individual
components of the station battery and determine if a total station battery or components of it
required capacity testing, removal, replacement or in many instances replacement of the entire
station battery. By taking this approach these owners have eliminated having to perform
capacity testing at prescribed intervals to determine if a battery needs to be replaced and are still
able to effectively determine if a station battery can perform as designed.
Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in Table
1-4. These two required activities are to verify station dc supply voltage and float voltage of the
battery charger, and have different maximum maintenance intervals. Both of these voltage
verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove that
the charger has not been lost or is not malfunctioning. Low battery voltage below float voltage
indicates that the battery may be on discharge and if not corrected the station battery could
discharge down to some extremely low value that will not operate the Protection System. High
voltage, close to or above the maximum allowable dc voltage for equipment connected to the
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station dc supply indicates the battery charger may be malfunctioning by producing high dc
voltage levels on the Protection System. If corrective actions are not taken to bring the high
voltage down, the dc power supplies and other electronic devices connected to the station dc
supply may be damaged. The maintenance activity of verifying the float voltage of the battery
charger is not to prove that a charger is lost or producing high voltages on the station dc supply,
but rather to prove that the charger is properly floating the battery within the proper voltage
limits.
Why check for the electrolyte level?
In Vented Lead-Acid (VLA) and Nickel-Cadmium (NiCd) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1-4. Because
the electrolyte level in Valve-Regulated Lead-Acid (VRLA) batteries cannot be observed there is
no maintenance activity listed in Table 1-4 of the Standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCd station battery is a condition requiring
correction. Typically the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCd) by adding distilled or other approved-quality water to the cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to check
the electrolyte level. In many of the modern station batteries the jar containing the electrolyte is
so large with the band between the high and low electrolyte level so wide that normal
evaporation which would require periodic watering of all cells takes several years to occur.
However, because loss of electrolyte due to cracks in the jar, overcharging of the station battery
or other unforeseen events can cause rapid loss of electrolyte the shorter maximum maintenance
intervals for checking the electrolyte level are required. A low level of electrolyte in a VLA
battery cell which exposes the tops of the plates can cause the exposed portion of the plates to
accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
Why does it appear that there are two maintenance activities in Table 1-4(b) (for VRLA
batteries) that appear to be the same activity and have the same maximum maintenance
interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for Valve-Regulated Lead-Acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1-4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health of
the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for Vented Lead-Acid (VLA) due to some unique failure modes for VRLA batteries.
Some of the potential problems that VRLA batteries are susceptible to that do not affect VLA
batteries are thermal runaway, cell dry-out, and cell reversal when one cell has a very low
capacity.
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The other similar activity listed in Table 1-4(b) is “verify that the station battery can perform as
designed by evaluating the measured cell/unit internal ohmic values to station battery baseline.”
This activity allows an owner the option to choose between this activity with its much shorter
maximum maintenance interval or the longer maximum maintenance interval for the
maintenance activity to “Verify that the station battery can perform as designed by conducting a
performance, service, or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. A comparison and trending against the baseline new battery ohmic
reading can be used in lieu of capacity tests to determine remaining battery life. Remaining
battery life is analogous to stating that the battery is still able to "perform as designed". This is
the intent of the “capacity 6 month test” at Row 4 on Table 1-4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1-4b. In order to detect a cell in thermal runaway,
you need not have a formal trending program to track when a cell has reached a 25%
increase over baseline. Rather it will stick out like a sore thumb when compared to the other
cells in a string at a given point in time regardless of the age of all the cells in a string. In other
words, if the battery is 10 years old and all the cells are gradually approaching a 25% increase in
ohmic values over baseline, then you have a battery which is approaching end of life. You need
to get ready to buy a new battery but you do not have to worry about an impending catastrophic
failure. On the other hand, if the battery is five years old and you have one cell that has a
markedly different ohmic reading than all the other cells, then you need to be worried that this
cell is in thermal runaway and catastrophic failure is imminent.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this does
not eliminate the need to be concerned about thermal runaway – the entity still needs to do the 6
month readings and look for cells which are outliers in the string but they need not trend results
against the factory/as new baseline. Some entities will not mind the extra administrative burden
of having the ongoing trending program against baseline - others would rather just do the
capacity test and not have to trend the data against baseline. Nonetheless, all entities must look
for ohmic outliers on a 6 month basis.
It is possible to accomplish both tasks listed (trend testing for capacity and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of watching
the trend from baselines and watching for the oblique cell measurement.
15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested.
Besides the trip output and wiring to the trip coil(s) there is also a communications medium that
must be maintained.
Newer technologies now exist that achieve communications-assisted tripping without the
conventional wiring practices of older technology.
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For example: older technologies may have included Frequency Shift Key methods. This
technology requires that guard and trip levels be maintained.
The actual tripping path(s) to the trip coil(s) may be tested as a parallel trip path within the dc
control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals.
The requirements apply to the communicated signal needed for the proper operation of the
protective relay trip logic or scheme. Therefore this Standard is applied to equipment used to
convey both trip signals (permissive or direct) and block signals.
It was the intent of this Standard to require that a test be performed on any communicationsassisted trip scheme regardless of the vintage of technology.The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit interrupting
devices.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on-site integrity checking to be performed at least every three months
during a substation visit. Some examples are, but not limited to:
•
On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check-back test from one terminal.
•
Systems which use frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss-of-guard indication or alarm. For frequency-shift power-line carrier systems, the
guard signal level meter can also be checked.
•
Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
•
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
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For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms that
can be monitored remotely. Some examples are, but not limited to:
•
On-off power-line carrier systems can be shown to be operational by automated periodic
power-line carrier check-back tests, with remote alarming of failures.
•
Systems which use a frequency-shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored with
a loss-of-guard alarm or low signal level alarm.
•
Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
•
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
•
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
•
•
In many communications systems signal quality measurements including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
What is needed for the 3-month inspection of communications-assisted trip scheme
equipment?
The 3-month inspection applies to unmonitored equipment. An example of compliance with this
requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms, check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e. FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
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Does a fiber optic I/O scheme used for breaker tripping or control within a station, for
example - transmitting a trip signal or control logic between the control house and the
breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System Control Circuitry
and tested per the portions of Table 1 applicable to Protection System Control Circuitry rather
than those portions of the table applicable to communications equipment.
In Table 1-2, the Maintenance Activities section of the Protective System Communications
Equipment and Channels refers to the quality of the channel meeting “performance
criteria”. What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally
an alarm will be indicated. For unmonitored systems this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each protective system
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following are
some examples of protective system communications channel performance measuring:
•
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
•
An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check-back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes this
signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
•
Pilot wire relay systems use a hardwire communications circuit to communicate between
the local and remote ends of the protective zone. This circuit is monitored by circulating
a dc current between the relay systems. A typical level may be 1 mA. If the level drops
below the setting of the alarm monitor, the system will indicate an alarm.
•
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme commonly
used on transmission lines. The protective relays communicate current magnitude and
phase information over the communications path to determine if the fault is located in the
protective zone. Quantities such as digital packet loss, bit error rate and channel delay
are monitored to determine the quality of the channel. These limits are determined and
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set during relay commissioning. Once set, any channel quality problems that fall outside
the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This Standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so protective system channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment involved
in the maintenance program?
An entity determines the acceptable performance criteria depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre-determined performance criteria for that system then these results should be investigated
and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot and thus make it easier to read the
Tables 1-1 through 1-5. The alarms need to arrive at a site wherein a corrective action can be
initiated. This could be a control room, operations center, etc. The alarming mechanism can be a
Standard alarming system or an auto-polling system, the only requirement is that the alarm be
brought to the action-site within 24 hours. This effectively makes manned-stations equivalent to
monitored stations. The alarm of a monitored point (for example a monitored trip path with a
lamp) in a manned-station now makes that monitored point eligible for monitored status.
Obviously, these same rules apply to a non-manned-station, which is that if the monitored point
has an alarm that is auto-reported to the operations center (for example) within 24 hours then it
too is considered monitored.
15.6.1 Frequently Asked Question:
Why are there activities defined for varying degrees of monitoring a Protection System
component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the Standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this provision
makes the Standard technology-neutral. The Standard Drafting Team wants to avoid the need to
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revise the Standard in a few years to accommodate technology advances that may be coming to
the industry.
Does a fail-safe “form b” contact that is alarmed to a 24/7 operation center classify as an
alarm path with monitoring?
If the fail-safe “form-b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center then this can be classified as an alarm path with monitoring.
15.7 Examples of Evidence of Compliance
To comply with the requirements of this Standard an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team recognizes
that there are concurrent evidence requirements of other NERC Standards that could, at times,
fulfill evidence requirements of this Standard.
15.7.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the Requirement being documented, include but
are not limited to:
•
Process documents or plans
•
Data (such as relay settings sheets, photos, SCADA, and test records)
•
Database lists, records and/or screen shots that demonstrate compliance information
•
Prints, diagrams and/or schematics
•
Maintenance records
•
Logs (operator, substation, and other types of log)
•
Inspection forms
•
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
•
Check-off forms (paper or electronic)
•
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
If I replace a failed Protection System component with another component, what testing do
I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
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I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-005-2?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC-016 could work for the activity tracking requirements
under this PRC-005-2.
I maintain disturbance records which show Protection System operations. Can I use these
records to show compliance?
These records can be concurrently utilized as dc trip path verifications to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my components of my Protection System
components. Can I use these test reports to show that I have verified a maintenance
activity?
Yes.
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
16. References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power
Engineering Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group
C3 of Power System Relaying Committee of IEEE Power Engineering Society,
December 2006.
7. “Proposed Statistical Performance Measures for Microprocessor-Based TransmissionLine Protective Relays, Part I - Explanation of the Statistics, and Part II - Collection
and Uses of Data,” Working Group D5 of Power System Relaying Committee of
IEEE Power Engineering Society, May 1995; Papers 96WM 016-6 PWRD and
96WM 127-1 PWRD, 1996 IEEE Power Engineering Society Winter Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report
of CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
PSMT SDT References
10. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
11. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore,
2005
12. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – Components of Protection
Systems
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Figure 2: Typical Generation System
For information on components, see Figure 1 & 2 Legend – Components of Protection
Systems
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Figure 1 & 2 Legend – Components of Protection Systems
Number
in
Figure
Includes
Excludes
1
Protective relays
which respond
to electrical
quantities
All protective relays that use
current and/or voltage inputs from
current & voltage sensors and that
trip the 86, 94 or trip coil.
Devices that use non-electrical methods of
operation including thermal, pressure, gas
accumulation, and vibration. Any ancillary
equipment not specified in the definition of
Protection Systems. Control and/or monitoring
equipment that is not a part of the automatic
tripping action of the Protection System
2
Voltage and
current sensing
devices
providing inputs
to protective
relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that are not a
part of the Protection System, including synccheck systems, metering systems and data
acquisition systems.
Control circuitry
associated with
protective
functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber-optic systems that
carry a trip signal as well as hardwired systems that carry trip
current.
Closing circuits, SCADA circuits, other devices in
control scheme not passing trip current
4
Station dc
supply
Batteries and battery chargers and
any control power system which
has the function of supplying
power to the protective relays,
associated trip circuits and trip
coils.
Any power supplies that are not used to power
protective relays or their associated trip circuits
and trip coils.
5
Communications
systems
necessary for
correct operation
of protective
functions
Tele-protection equipment used to
convey specific information, in
the form of analog or digital
signals, necessary for the correct
operation of protective functions.
Any communications equipment that is not used to
convey information necessary for the correct
operation of protective functions.
3
Component
of Protection
System
Additional information can be found in References
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A-1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two-terminal pilot protection scheme to protect for line faults, and to avoid overtripping for faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors
report the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered
values of volts, amperes, plus Watts and VARs on the line. These metered values are
reported by data communications. For maintenance, the user elects to compare these
readings to those of other relays, meters, or DFRs. The other readings may be from
redundant relaying or measurement systems or they may be derived from values in
other protection zones. Comparison with other such readings to within required
relaying accuracy verifies Voltage & Current Sensing Devices, wiring, and analog
signal input processing of the relays. One effective way to do this is to utilize the
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
relay metered values directly in SCADA, where they can be compared with other
references or state estimator values.
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2).
Status indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by
the relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the
Protection System, so each carrier set has a connected or integrated automatic
checkback test unit. The automatic checkback test runs several times a day. Newer
carrier sets with integrated checkback testing check for received signal level and
report abnormal channel attenuation or noise, even if the problem is not severe
enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
1. The continuity of trip coils is verified, but no means is provided for validating the
ability of the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision
have been verified by internal monitoring. However, the trip circuit is actually
energized by the contacts of a small telephone-type "ice cube" relay within the line
protective relay. The microprocessor energizes the coil of this ice cube relay through
its output data port and a transistor driver circuit. There is no monitoring of the output
port, driver circuit, ice cube relay, or contacts of that relay. These components are
critical for tripping the circuit breaker for a fault.
3. The check-back test of the carrier channel does not verify the connections between
the relaying microprocessor internal decision programs and the carrier transmitter
keying circuit or the carrier receiver output state. These connections include
microprocessor I/O ports, electronic driver circuits, wiring, and sometimes telephonetype auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored,
but this does not confirm that the state change indication is correct when the breaker
or switch opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally-occurring faults are
demonstrations of operation that reset the time interval clock for testing of each breaker tripped
in this way. If faults do not occur, manual tripping of the breaker through the relay trip output via
data communications to the relay microprocessor meets the requirement for periodic testing.
PRC-005 does not address breaker maintenance, and its Protection System test requirements can
be met by energizing the trip circuit in a test mode (breaker disconnected) through the relay
microprocessor. This can be done via a front-panel button command to the relay logic, or
application of a simulated fault with a relay test set. However, utilities have found that breakers
often show problems during Protection System tests. It is recommended that Protection System
verification include periodic testing of the actual tripping of connected circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
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Appendix B — Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Mark Lucas
ComEd
Merle E. Ashton
Tri-State G&T
Al McMeekin
NERC Staff
North American Electric Reliability
Corporation
Bob Bentert
Florida Power & Light Company
Mark Peterson
Great River Energy
John Ciufo
Hydro One Inc
Leonard Swanson, Jr
National Grid USA
Sam Francis
Oncor
Eric A. Udren
Quanta Technology
Carol A. Gerou
Midwest Reliability Organization
Philip B. Winston
Southern Company Transmission
William D. Shultz
Southern Company Generation
John A. Zipp
ITC Holdings
Russell C. Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
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PRC-005-2
Protection System
Maintenance
Supplementary Reference & FAQ
Draft
April 12June 2, 2011
Prepared by the
Protection System Maintenance and Testing Standard
Drafting Team
1
PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Table of Contents
1.
Introduction and Summary ..................................................................................................... 4
2.
Need for Verifying Protection System Performance .............................................................. 5
2.1 Existing NERC Standards for Protection System Maintenance and Testing ....................... 5
2.2 Protection System Definition ................................................................................................ 6
2.3 Applicability of New Protection System Maintenance Standards ........................................ 6
2.3.1 Frequently Asked Questions: ............................................................................................ 7
2.4 Applicable Relays ................................................................................................................. 8
2.4.1 Frequently Asked Questions: ............................................................................................ 9
3.
Protection Systems Product Generations .............................................................................. 10
4.
Definitions............................................................................................................................. 11
5.
4.1 Frequently Asked Questions: .............................................................................................. 11
Time-Based Maintenance (TBM) Programs ......................................................................... 13
5.1 Maintenance Practices ........................................................................................................ 13
5.1.1 Frequently Asked Questions: .......................................................................................... 15
5.2 Extending Time-Based Maintenance .......................................................................... 16
5.2.1 Frequently Asked Question: ............................................................................................ 17
6.
Condition-Based Maintenance (CBM) Programs ................................................................. 18
6.1 Frequently Asked Questions: .............................................................................................. 19
7. Time-Based Versus Condition-Based Maintenance ............................................................. 20
8.
7.1 Frequently Asked Questions: .............................................................................................. 20
Maximum Allowable Verification Intervals ......................................................................... 25
8.1 Maintenance Tests .............................................................................................................. 25
8.1.1 Table of Maximum Allowable Verification Intervals ..................................................... 26
8.1.2 Additional Notes for Tables 1-1 through 1-5 .................................................................. 27
8.1.3 Frequently Asked Questions: .......................................................................................... 28
8.2 Retention of Records........................................................................................................... 33
8.2.1 Frequently Asked Questions: .......................................................................................... 33
8.3 Basis for Table 1 Intervals .................................................................................................. 36
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .............................. 36
9. Performance-Based Maintenance Process ............................................................................ 38
9.1 Minimum Sample Size........................................................................................................ 39
9.2 Frequently Asked Questions: .............................................................................................. 42
10.
Overlapping the Verification of Sections of the Protection System .................................. 54
10.1 Frequently Asked Question: ............................................................................................. 55
11.
Monitoring by Analysis of Fault Records .......................................................................... 55
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11.1 Frequently Asked Question: ............................................................................................. 56
12.
Importance of Relay Settings in Maintenance Programs ................................................... 57
12.1 Frequently Asked Questions: ............................................................................................ 58
13.
Self-Monitoring Capabilities and Limitations ................................................................... 60
13.1 Frequently Asked Question: ............................................................................................. 61
14.
Notification of Protection System Failures ........................................................................ 62
15.
Maintenance Activities ...................................................................................................... 63
15.1 Protective Relays (Table 1-1) ........................................................................................... 63
15.1.1 Frequently Asked Question: .......................................................................................... 64
15.2 Voltage & Current Sensing Devices (Table 1-3) .............................................................. 64
15.2.1 Frequently Asked Questions: ........................................................................................ 65
15.3 Control circuitry associated with protective functions (Table 1-5) .................................. 67
15.3.1 Frequently Asked Questions: ........................................................................................ 68
15.4. Batteries and DC Supplies (Table 1 Frequently Asked Questions:-4) .......................... 69
15.5 Associated communications equipment (Table 1-2) .. 15.4.1 Frequently Asked Questions:
............................................................................................................................................... 70
15.5.1 Frequently Asked Questions: ... 15.5 Associated communications equipment (Table 1-2)
................................................................................................................................................... 81
15.6 Alarms (Table 2) ......................................................... 15.5.1 Frequently Asked Questions:
............................................................................................................................................... 82
15.6.1 Frequently Asked Question: Alarms (Table 2) .............................................................. 85
15.7 Examples of Evidence of Compliance ......................... 15.6.1 Frequently Asked Question:
............................................................................................................................................... 85
15.7.1 Frequently Asked Questions: ......................... 15.7 Examples of Evidence of Compliance
................................................................................................................................................... 86
Yes.16. References .............................................................. 15.7.1 Frequently Asked Questions:
............................................................................................................................................... 86
16. References ............................................................................................................................ Yes.
....................................................................................................................................................... 87
Figures ......................................................................................................................16. References
....................................................................................................................................................... 88
Figure 1: Typical Transmission System .............................................................................. Figures
....................................................................................................................................................... 89
Figure 21: Typical GenerationTransmission System................................................................ 89
Appendix B — Protection System Maintenance Standard Drafting Team . Figure 2:
Typical Generation System ....................................................................................................... 90
Appendix B — Protection System Maintenance Standard Drafting Team ............... 95
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
This supplementary reference to PRC-005-2 is not mandatory and enforceable.
1. Introduction and Summary
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and address various aspects of maintenance and testing of Protection and Control systems.
These standards are:
PRC-005-1 — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for Protection
Systems, and that these entities must be able to demonstrate they are carrying out such a
program, there are no specifics regarding the technical requirements for Protection System
maintenance programs. Furthermore, FERC Order 693 directed additional modifications
respective to Protection System maintenance programs. PRC-005-2 combines and replaces PRC005, PRC-008, PRC-011 and PRC-017.
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
2. Need for Verifying Protection System
Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate their
performance until a fault or other power system problem requires that they operate to protect
power system elements, or even the entire Bulk Electric System (BES). Lacking faults, switching
operations or system problems, the Protection Systems may not operate, beyond static operation,
for extended periods. A misoperation - a false operation of a Protection System or a failure of the
Protection System to operate, as designed, when needed - can result in equipment damage,
personnel hazards, and wide area disturbances or unnecessary customer outages. Maintenance or
testing programs are used to determine the performance and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be visited
at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct plausible
age and service related degradation of the Protection System components such that a properly
built and commissioned Protection System will continue to function as designed over its service
life.
Similarly station batteries which are an important part of the station dc supply are not called
upon to provide instantaneous dc power to the Protection System until power is required by the
Protection System to operate circuit breakers or interrupting devices to clear faults or to isolate
equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC Standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC-005, briefly
restated as follows:
Purpose: To ensure all transmissiondocument and generationimplement programs for the
maintenance of all Protection Systems affecting the reliability of the Bulk Electric System (BES)
are maintained and testedso that these Protection Systems are kept in working order.
PRC-005-1 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC-005-2, the definition of Protection System was:
Protective relays, associated communications systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Requirements: The owner shall have a documented maintenance program with test intervals. The
owner must keep records showing that the maintenance was performed at the specified intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
•
Protective relays which respond to electrical quantities,
•
communications systems necessary for correct operation of protective functions,
•
voltage and current sensing devices providing inputs to protective relays,
•
station dc supply associated with protective functions (including station batteries, battery
chargers, and non-battery-based dc supply), and
•
control circuitry associated with protective functions through the trip coil(s) of the circuit
breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“… and that are designed to provide protectioninstalled for the purpose of detecting faults on BES.”
Elements (lines, buses, transformers, etc.).”
The drafting team intends that this Standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the element is a BES element then the Protection
System protecting that element should then be included within this Standard. If there is regional
variation to the definition then there will be a corresponding regional variation to the Protection
Systems that fall under this Standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the Standard language should simply be applicable to relays for BES elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions. See
the NERC glossary of terms for the present, in-force, definition. See the applicable regional
reliability organization for any applicable allowed variations.
While this Standard will undergo revisions in the future, this Standard will not attempt to keep
up with revisions to the NERC definition of BES but rather simply make BES Protection
Systems applicable.
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The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because
GO’s and TO’s have equipment that is BES equipment. The Standard brings in Distribution
Providers (DP) because depending on the station configuration of a particular substation, there
may be Protection System equipment installed at a non-transmission voltage level (Distribution
Provider equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would
apply to this equipment. An example is underfrequency load-shedding, which is frequently
applied well down into the distribution system to meet PRC-007-0.
As this Standard is intended to replace the existing PRC-005, PRC-008, PRC-011 and PRC-017,
those Standards are used in the construction of this revision of PRC-005-1. Much of the original
intent of those Standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example the original PRC-008 was
constructed quite differently than the original PRC-005. The drafting team agrees with the intent
of this and notes that distributed tripping schemes would have to exhibit multiple failures to trip
before they would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential lock-out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just fault clearing duty and therefore the distribution circuit breakers are
operated at least as frequently as any requirements that might have appeared in this Standard.
Additionally, since this Standard will now replace PRC-011 it will be important to make the
distinction between under-voltage Protection Systems that protect individual loads and
Protection Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had
been applicable under PRC-011 will now be applicable under this revision of PRC-005-1. An
example of an Under-Voltage Load Shedding scheme that is not applicable to this Standard is
one in which the tripping action was intended to prevent low distribution voltage to a specific
load from a transmission system that was intact except for the line that was out of service, as
opposed to preventing a cascading outage or transmission system collapse.
It had been correctly noted that the devices needed for PRC-011 are the very same types of
devices needed in PRC-005.
Thus a Standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems and replace some other Standards at the same time.
2.3.1 Frequently Asked Questions:
What, exactly, is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used
in Reliability Standards, and is not being modified within this draft Standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving only
load with one transmission source are generally not included in this definition.
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
Each Regional Entity implements a definition of the Bulk Electric System that is based on this
NERC definition, in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 1614, 2007 Informational Filing.
Why is Distribution Provider included within the Applicable Entities and as a responsible
entity within several of the requirements? Wouldn’t anyone having relevant facilities be a
Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-2 would apply to
this equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
We have an Under Voltage Load Shedding (UVLS) system in place that prevents one of our
distribution substations from supplying extremely low voltage in the case of a specific
transmission line outage. The transmission line is part of the BES. Does this mean that our
UVLS system falls within this Standard?
The situation as stated indicates that the tripping action was intended to prevent low distribution
voltage to a specific load from a transmission system that was intact except for the line that was
out of service, as opposed to preventing cascading outage or transmission system collapse.
This Standard is not applicable to this UVLS.
We have a UFLS scheme that sheds the necessary load through distribution-side circuit
breakers and circuit reclosers. Do the trip-test requirements for circuit breakers apply to
our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant as opposed to a single failure to trip of, for example, a
Transmission Protection System Bus Differential lock-out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just fault clearing duty and therefore the distribution circuit breakers are
operated at least as frequently as any requirements that might have appeared in this Standard.
We have a UFLS scheme that, in some locales, sheds the necessary load through non-BES
circuit breakers and occasionally even circuit switchers. Do the trip-test requirements for
circuit breakers apply to our situation?
If your “non-BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements and otherwise would not have been brought into this standard, then the answer is
that there are no trip-test requirements. For these devices that are otherwise non-BES assets,
these tripping schemes would have to exhibit multiple failures to trip before they would prove to
be as significant as (for example) a single failure to trip of a Transmission Protection System Bus
Differential lock-out relay.
2.4 Applicable Relays
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The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this Standard applies are those protective relays that respond to electrical quantities and
provide a trip output to trip coils, dc control circuitry or associated communications equipment.
This definition extends to IEEE device # 86 (lockout relay) and IEEE device # 94 (tripping or
trip-free relay) as these devices are tripping relays that respond to the trip signal of the protective
relay that processed the signals from the current and voltage sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration schemes
covered in this Standard?
No. As stated in Requirement R1, this Standard covers protective relays that use measurements
of electrical quantities to determine anomalies and to trip a portion of the BES. Reclosers,
reclosing relays, closing circuits and auto-restoration schemes are used to cause devices to close
as opposed to electrical-measurement relays and their associated circuits that cause circuit
interruption from the BES; such closing devices and schemes are more appropriately covered
under other NERC Standards. There is one notable exception: if a Special Protection System
incorporates automatic closing of breakers, the related closing devices are part of the SPS and
must be tested accordingly.
I use my protective relays only as sources of metered quantities and breaker status for
SCADA and EMS through a substation distributed RTU or data concentrator to the
control center. What are the maintenance requirements for the relays?
This Standard addresses only devices “that are applied on, or are designed to provide protection
for the BES.” Protective relays, providing only the functions mentioned in the question, are not
included.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2-2008 assigns the device number 94 to auxiliary tripping relays. Sudden
pressure relays are assigned device number 63. Sudden pressure relays are excluded from the
Standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded.
My mechanical device does not operate electrically and does not have calibration settings;
what maintenance activities apply?
You must conduct a test(s) to verify the integrity of the trip circuit. This Standard does not cover
circuit breaker maintenance or transformer maintenance. The Standard also does not cover
testing of devices such as sudden pressure relays (63), temperature relays (49), and other relays
which respond to mechanical parameters rather than electrical parameters.
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The Standard specifically mentions auxiliary and lock-out relays; what is an auxiliary
tripping relay?
An auxiliary relay, IEEE Device Number 94, is described in IEEE Standard C37.2-2008 as “A
device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate
tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should
open automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock-out relay, IEEE Device Number 86, is described in IEEE Standard C37.2 as “A device
that trips and maintains the associated equipment or devices inoperative until it is reset by an
operator, either locally or remotely.”
3. Protection Systems Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System, both depends on the technological generation of the relays as well as how long they
have been in service. Unlike many other transmission asset groups, protection and control
systems have seen dramatic technological changes spanning several generations. During the past
20 years, major functional advances are primarily due to the introduction of microprocessor
technology for power system devices such as primary measuring relays, monitoring devices,
control systems, and telecommunications equipment.
Modern microprocessor based relays have six significant traits that impact a maintenance
strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified periodically.
•
Ability to capture fault records showing how the Protection System responded to a fault
in its zone of protection, or to a nearby fault for which it is required not to operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-fault times. The relays can compute values such as MW and
MVAR line flows that are sometimes used for operational purposes such as SCADA.
•
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording, and measurement.
•
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages or from relay front
panel button requests.
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•
Construction from electronic components some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of Battery Chargers, Associated
Communications Equipment, Voltage and Current Measuring Devices and even the control
circuitry (in the form of software-latches replacing lock-out relays, etc).
Any Protection System component can have self-monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which
Protection System components are kept in working order and proper operation of malfunctioning
components is restored. A maintenance program for a specific component includes one or more
of the following activities:
•
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Restore — Return malfunctioning components to proper operation.
4.1 Frequently Asked Questions:
Why does PRC-005-2 not specifically require maintenance and testing procedures as
reflected in the previous Standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-2 requires
a documented maintenance program, and is focused on establishing requirements rather than
prescribing methodology to meet those requirements. Between the activities identified in the
tables 1-1 through 1-5 and Table 2 (collectively the “Tables”), and the various components of the
definition established for a “Protection System Maintenance Program”, PRC-005-2 establishes
the activities and time-basis for a Protection System Maintenance Program to a level of detail not
previously required.
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Please clarify what is meant by restore in the definition of maintenance.
The description of “Restore” in the definition of a Protection System Maintenance Program,
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R3 of the Standard does
require that the entity “initiate resolution of any identified maintenance correctable issues”.
Some examples of restoration (or correction of maintenance-correctable issues) include, but are
not limited to, replacement of capacitors in distance relays to bring them to working order;
replacement of relays, or other Protection System components, to bring the Protection System to
working order; upgrade of electro-mechanicalelectromechanical or solid-state protective relays
to micro-processor based relays following the discovery of failed components. Restoration, as
used in this context is not to be confused with Restoration rules as used in system operations.
Maintenance activity necessarily includes both the detection of problems and the repairs needed
to eliminate those problems. This Standard does not identify all of the Protection System
problems that must be detected and eliminated, rather it is the intent of this Standard that an
entity determines the necessary working order for their various devices and keeps them in
working order. If an equipment item is repaired or replaced then the entity can restart the
maintenance-time-interval-clock if desired, however the replacement of equipment does not
remove any documentation requirements that would have been required to verify compliance
with time-interval requirements; in other words do not discard maintenance data that goes to
verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that the
maintenance intervals had been in compliance. For example, a long range plan of upgrades might
lead an entity to ignore required maintenance; retaining the evidence of prior maintenance that
existed before any retirements and upgrades proves compliance with the Standard.
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5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which Protection Systems are maintained or verified
according to a time schedule. The scheduled program often calls for technicians to travel to the
physical site and perform a functional test on Protection System components. However, some
components of a TBM program may be conducted from a remote location - for example, tripping
a circuit breaker by communicating a trip command to a microprocessor relay to determine if the
entire Protection System tripping chain is able to operate the breaker. Similarly, all Protection
System components can have the ability to remotely conduct tests, either on-command or
routinely, the running of these tests can extend the time interval between hands-on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or testing
intervals are applied for components or groups of components. The intervals may have
been developed from prior experience or manufacturers’ recommendations. The TBM
verification interval is based on a variety of factors, including experience of the particular
asset owner, collective experiences of several asset owners who are members of a country
or regional council, etc. The maintenance intervals are fixed, and may range in number
of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time clock
can be reset for those components.
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•
PBM – Performance-Based Maintenance - intervals are established based on analytical or
historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses
accompanied by adjustments to maintenance intervals are used to justify continued use of
PBM-developed extended intervals when test failures or in-service failures occur
infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from
non-disruptive self monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what parts
are included as part of the self diagnostics. While the term “Condition-BasedMaintenance” (CBM) is no longer used within the Standard itself, it is important to note
that the concepts of CBM are a part of the Standard (in the form of extended time
intervals through status-monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored-basis-time-intervals” existing within the Standard the
explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor based Protection System components that perform continuous selfmonitoring verify correct operation of most components within the device. Selfmonitoring capabilities may include battery continuity, float voltages, unintentional
grounds, the ac signal inputs to a relay, analog measuring circuits, processors and
memory for measurement, protection, and data communications, trip circuit monitoring,
and protection or data communications signals (and many, many more measurements).
For those conditions, failure of a self-monitoring routine generates an alarm and may
inhibit operation to avoid false trips. When internal components, such as critical output
relay contacts, are not equipped with self-monitoring, they can be manually tested. The
method of testing may be local or remote, or through inherent performance of the scheme
during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours or even milliseconds between non-disruptive self monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
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PRC-005-2 Protection System Maintenance (Supplementary Reference and FAQ) Draft
•
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
•
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have been
subject to TBM.
•
Region 3: Optimal TBM intervals based on regions 1 and 2.
TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
5.1.1 Frequently Asked Questions:
The Standard seems very complicated, and is difficult to understand. Can it be simplified?
Because the Standard is establishing parameters for condition-based Maintenance (R1) and
Performance-Based Maintenance (R2) in addition to simple time-based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time-based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened time
intervals then it may, as long as the component has the listed monitoring attributes. If an entity
wishes to use historical performance of its Protection System components to perform
Performance-Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the Standard.
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We have an electromechanical (unmonitored) relay that has a trip output to a lockout relay
(unmonitored) which trips our transformer off-line by tripping the transformer’s high-side
and low-side circuit breakers. What testing must be done for this system?
This system is made up of components that are all unmonitored. Assuming a time-based
Protection System maintenance program schedule (as opposed to a Performance-Based
maintenance program), each component must be maintained per the most frequent hands-on
activities listed in the Tables 1-1 through 1-5.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time-based. Default time-based intervals are commonly
established to assure proper functioning of each component of the Protection System, when data
on the reliability of the components is not available other than observations from time-based
maintenance. The following factors may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self monitoring device), then the intervals may be extended or
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manual testing may be eliminated. This is referred to as condition-based maintenance or
CBM. CBM is valid only for precisely the components subject to monitoring. In the case
of microprocessor-based relays, self-monitoring may not include automated diagnostics
of every component within a microprocessor.
•
Previous maintenance history for a group of components of a common type may indicate
that the maintenance intervals can be extended while still achieving the desired level of
performance. This is referred to as Performance-Based Maintenance or PBM. It is also
sometimes referred to as reliability-centered maintenance or RCM, but PBM is used in
this document.
•
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor-based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a fault verifies the trip contact and trip path, but only through
the relays in series that actually operated; one operation of this relay cannot verify correct
calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is not
unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Question:
If I show the protective device out of service while it is being repaired then can I add it
back as a new protective device when it returns? If not, my relay testing history would
show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R3) (in essence) state “…shall implement and follow
its PSMP …” if not then actions must be initiated to correct the deviance. The type of corrective
activity is not stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device tested
bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information
available from modern microprocessor-based relays and other intelligent electronic devices
(IEDs) that monitor Protection System elements. These devices generate monitoring information
during normal operation, and the information can be assessed at a convenient location remote
from the substation. The information from these relays and IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
faults and disturbances, metered values, and binary input status reports. Some of these are
available on the device front panel display, but may be available via data communications
ports. Large files of fault information can only be retrieved via data communications.
These results comprise a mass of data that must be further analyzed for evidence of the
operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
1. Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
2. Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems by
incorrect operation before being caught in the next test round. The frequent or continuous
nature of CBM makes the effective verification interval far shorter than any required
TBM maximum interval.
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6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a 24-hour
attended control room. Does this qualify as an extended time interval condition-based
system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels of
monitoring as per Requirement R1.4 of the Standard, is it necessary to provide this
documentation about the device by listing of every component and the specific monitoring
attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible, it
is not necessary. Global statements can be made to document appropriate levels of monitoring
for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are Monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered Monitored and subject to the rows
for monitored equipment of Table 1-4 requirements as all substation dc supply battery
chargers are equipped with dc voltage alarms and ground detection alarms that are sent to the
manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered Monitored
and subject to the rows for monitored equipment of Table 1-4 requirements as all substation
dc supply battery chargers are equipped with dc voltage alarms and| File Type | application/pdf |
| Author | heenane |
| File Modified | 2013-02-26 |
| File Created | 2013-02-26 |